L-11-166, Reply to Request for Additional Information for the Review of the License Renewal Application, Batch 3 (TAC No. ME4640), and License Renewal Application Amendment No. 8

Reply to Request for Additional Information for the Review of the License Renewal Application, Batch 3 (TAC No. ME4640), and License Renewal Application Amendment No. 8

ML11159A132
Person / Time
Site:	Davis Besse
Issue date:	06/03/2011
From:	Allen B FirstEnergy Nuclear Operating Co
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
L-11-166, TAC ME4640
Download: ML11159A132 (205)

Text

FENOC 5501 North State Route 2 FirstEnergyNuclear OperatingCompany Oak Harbor,Ohio 43449 Barry S. Allen 419-321-7676 Vice President - Nuclear Fax: 419-321-7582 June 3, 2011 L-11-166 10 CFR 54 ATTN: Document Control Desk U. S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Davis-Besse Nuclear Power Station, Unit No. 1 Docket No. 50-346, License Number NPF-3 Reply to Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station, Unit No. 1, License Renewal Application, Batch 3 (TAC No. ME4640),

and License Renewal Application Amendment No. 8 By letter dated August 27, 2010 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML102450565), FirstEnergy Nuclear Operating Company (FENOC) submitted an application pursuant to Title 10 of the Code of Federal Regulations, Part 54 for renewal of Operating License NPF-3 for the Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS). By letters dated April 20, 2011 (ADAMS Accession No. ML110980718), and May 2, 2011 (ADAMS Accession No. ML111170204),

the Nuclear Regulatory Commission (NRC) requested additional information to complete its review of the License Renewal Application (LRA).

Based on discussion with Mr. Brian Harris, NRC Project Manager, on May 31, 2011, the submittal date for this letter was changed from June 1 to June 3, 2011. Attachment 1 provides the FENOC reply to 49 of the 79 NRC Batch 3 request for additional information (RAI) in NRC letter dated May 2, 2011. For those 49, the NRC request is shown in bold text followed by the FENOC response. By letter dated May 5, 2011 (ADAMS Accession No. ML11131A073), FENOC responded to three of the RAIs (3.6-1, 3.6-2 and 3.6-3).

The remaining 27 of 79 RAIs (3.3.2.3.14-3, 3.5.2.2.2-1, 4.1-1 through 4.1-3 inclusive, and 4.3-1 through 4.3-22 inclusive) were discussed with Mr. Brian Harris, NRC Project Manager, on May 31, 2011, and the responses to these requests were deferred to a mutually-agreeable submittal date of June 15, 2011.

By letter dated May 24, 2011 (L-1 1-153), FENOC responded to 24 of the 31 RAIs in NRC letter dated April 20, 2011. FENOC's responses to the remaining seven (of 31) RAIs (B.2.16-1 through B.2.16-7) are contained herein. Attachment 2 provides~the FENOC reply to those previously deferred seven RAIs. The NRC request is shown in bold text followed by the FENOC response.

AWV

Davis-Besse Nuclear Power Station, Unit No. 1 L-11-166 Page 2 The Enclosure provides Amendment No. 8 to the DBNPS LRA.

There are no regulatory commitments contained in this letter. If there are any questions or if additional information is required, please contact Mr. Clifford I. Custer, Fleet License Renewal Project Manager, at 724-682-7139.

I declare under penalty of perjury that the foregoing is true and correct. Executed on June .9 ,2011.

Sincerely, Barry S. Allen Attachments:

1. Reply to Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS), License Renewal Application, Batch 3, Sections 2.3, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, B.2.3 and B.2.9

2. Reply to Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS), License Renewal Application, Batch 2, Section B.2.16

Enclosure:

A. Amendment No. 8 to the DBNPS License Renewal Application cc: NRC DLR Project Manager NRC Region III Administrator cc: w/o Attachments or Enclosure NRC DLR Director NRR DORL Project Manager NRC Resident Inspector Utility Radiological Safety Board

Attachment 1 L-11-166 Reply to Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS), License Renewal Application, Batch 3 Sections 2.3, 3.0, 3.1, 3.2, 3.3, 3.4, 3.5, 3.6, B.2.3 and B.2.9 Page 1 of 69 Section B.2.3 Question 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.

RESPONSE RAI B.2.3-1 Although it is presented in LRA Section B.2.3 as an aging management program, the purpose of the Air Quality Monitoring Program, as described in response to Nuclear Regulatory Commission (NRC) Generic Letter 88-14, is to ensure that the Instrument Air (IA) System remains dry and free of contaminants so that components served by the IA System remain operable, i.e., that air-operated safety-related systems and components should not fail to perform their intended safety functions because of air supply system problems. The purpose of the program is not to prevent or mitigate aging degradation of IA System components themselves. The preventive actions of the program, i.e., periodic sampling with timely corrective actions to ensure that the air remains free of contaminants (including oil and moisture), are designed to prevent the adverse effects of such contaminants on downstream components such as safety-related air-operated valve actuators. As a consequence, however, for purposes of aging management review, the environment of the IA System is evaluated as "dried air,"

L-11-166 Page 2 of 69 whose quality is assured by the preventive actions of the Air Quality Monitoring Program.

The aging management review for the Davis-Besse IA System, as well as for those systems that are served by the IA System, was conducted with the guidance provided in EPRI Technical Report 1010639, "Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools," Revision 4 ("Mechanical Tools"). In accordance with the Mechanical Tools, a relevant condition (mechanism applicability criterion) required for nearly all aging effects/mechanisms to occur for metals exposed to an air/gas environment is that the environment is "not dried air, N 2 , 002, H2 , halon, or fluorocarbons." The only exceptions are as follows:

" Cracking due to hydrogen embrittlement requires a hydrogen environment, and is only applicable to RayChem Cryofit couplings.

" Loss of material due to crevice and/or pitting corrosion requires that the environment be a corrosive replacement gas for fluorocarbons (refrigerants) or halon (fire suppressants).

" Reduction of fracture toughness due to thermal embrittlement requires the environment's temperature to be greater than 400 degrees Fahrenheit (OF), and is only applicable to galvanized steel.

As such, the aging management reviews for the IA System, Makeup and Purification System, Service Water System, Main Feedwater System, and Main Steam System, concluded that, for components exposed to the "dried air" environment, there are no aging effects requiring management; therefore, no aging management program is required.

These conclusions are consistent with NUREG-1 801, "Generic Aging Lessons Learned (GALL) Report," which includes an "air, dry" (or "dried air") environment defined in Chapter IX, Table IX.D, "Environments," as air that has been treated to reduce its dew point well below the system operating temperature. NUREG-1801 Chapter VII, Table VII.J, indicates that for copper alloy (VII.J-3), stainless steel (VII.J-1 8), and steel (VII.J-22), there are no aging effects/mechanisms requiring management and no aging management program required in a dried air environment.

Question RAI B.2.3-2 In LRA Section B.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

L-11-166 Page 3 of 69 (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.

RESPONSE RAI B.2.3-2 Periodic testing of contaminants by the Air Quality Monitoring Program is performed each year.

The frequency of testing is based on the recommendations of Institute of Nuclear Power Operations (INPO) Supplemental Operating Experience Report (SOER) 88-1, "Instrument Air System Failures."

Question 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 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.

RESPONSE RAI B.2.3-3 The acceptance criteria for the Air Quality Monitoring Program are based on standard industry practices as recommended by ANSI/ISA-S7.3-1975, "Quality Standard for Instrument Air." Davis-Besse meets these standards.

L-11-166 Page 4 of 69 Question RAI B.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?

RESPONSE RAI B.2.3-4 For the 2007 air sample that exceeded the Preventive Maintenance limit, there were no corrective actions taken that resulted in program enhancements. The Preventive Maintenance limit was established as a threshold for further investigation. The single out-of-specification reading from 2007 was considered to be a long-term reliability issue because critical and non-critical air-operated valves are provided with 'point of use' air filter-regulators.

Since 2007, air samples have not exceeded the Preventive Maintenance limit. The air is sampled each year.

L-11-166 Page 5 of 69 Section B.2.9 Question RAI B.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-221 1, 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 general corrosion, but is not necessarily an acceptable method to detect crevice or pitting corrosion, and cracking.

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

RESPONSE RAI B.2.9-1 The plant-specific Collection, Drainage, and Treatment Components Inspection Program will utilize visual inspection (VT-1 or equivalent) techniques capable of detecting the aging effects under consideration, including loss of material due to pitting and crevice corrosion. LRA Section B.2.9, "Collection, Drainage, and Treatment Components Inspection Program," is revised to provide this clarification.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI B.2.9-2 In LRA Section B.2.9, "Collection, Drainage and Treatment Components Inspection Program," under the "acceptance criteria" program element, the

L-11-166 Page 6 of 69 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 B.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.

RESPONSE RAI B.2.9-2 The basis for the acceptance criteria associated with the Collection, Drainage, and Treatment Component Inspection Program is to maintain the intended functions under all current licensing basis (CLB) conditions. The qualitative description of the acceptance criteria is contained in that element of LRA Section B.2.9.

As described in LRA B.2.9, the elements that comprise the Collection, Drainage, and Treatment Components Inspection Program inspections (i.e., the scope of the inspections and inspection techniques) will be consistent with industry practice. For metallic surfaces, for example, any indications of relevant degradation detected are evaluated. For stainless steel surfaces, a clean, shiny surface is expected. Discoloration may indicate loss of material on the stainless steel surface. Any abnormal surface condition may be an indication of an aging effect for metals. Unacceptable inspection findings will include visual evidence of cracking, loss of material, or reduction in heat transfer that could result in a loss of component intended function during the period of extended operation. Acceptance criteria include design standards, procedural requirements, current licensing basis, industry codes or standards, and engineering evaluation. Industry and plant-specific operating experience will be considered in the development and implementation of this program. As additional operating experience is obtained, lessons learned will be incorporated, as appropriate.

The visual inspections associated with the Collection, Drainage, and Treatment Component Inspection Program will ensure that the existing environmental conditions are not causing cracking, loss of material, or reduction in heat transfer that could result in a loss of component intended function. The acceptance criteria for this program are consistent with NUREG-1 800 Section A.1.3.2.6, which indicates that acceptance criteria, which do allow degradation, are based on maintaining intended functions under all CLB conditions.

L-11-166 Page 7 of 69 As described in LRA B.2.9, indications or relevant conditions of degradation detected during the inspections will be compared to pre-determined acceptance criteria. If the acceptance criteria are not met, then the indications and conditions will be evaluated under the Corrective Action Program to assess the material condition and determine whether the component intended function is affected. 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.

Engineering evaluation prior to an opportunistic, or focused, inspection will determine the acceptance criteria for that inspection, with the basis of ensuring that intended function is maintained (for all current licensing basis conditions).

Section 2.3 Question 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.

L-11-166 Page 8 of 69 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.

RESPONSE RAI 2.3.3.18-2

1. The replacement frequency of the letdown coolers, DB-E25-1 and 2, is based on plant-specific operating experience that indicates this heat exchanger design has a tendency to develop leaks after seven-to-eight cycles (i.e., approximately 14-16 years). Therefore, replacement is based on a qualified life, and is scheduled every seven refueling outages (approximately every 14 years).

2. The need to replace the letdown coolers is attributed to fatigue cracking due to flow-induced vibration in the letdown coolers, which led to reactor coolant leakage into the Component Cooling Water System. The extent of condition review determined the design of the letdown coolers is unique, and there are no other similar heat exchangers installed at Davis-Besse. Corrective action was taken to generate a Preventive Maintenance task to periodically replace the letdown coolers, which was considered an acceptable alternative to nondestructive examination/testing requirements since suitable examination techniques could not be identified for the letdown coolers.

L-11-166 Page 9 of 69 Section 3.0 Question RAI 3.0 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-1 800, 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.

RESPONSE RAI 3.0 LRA Section A.1, "Summary Descriptions of Aging Management Programs and Activities,"

and LRA Table A-i, "Davis-Besse License Renewal Commitments," are revised to state that the FirstEnergy Nuclear Operating Company (FENOC) Quality.Assurance Program will be applied to the aging management programs for safety-related and nonsafety-related structures and components determined to require aging management.

See the Enclosure to this letter for the revision to the DBNPS LRA.

L-11-166 Page 10 of 69 Section 3.1 Question RAI 3.1.1.70-1 GALL Report Rev. 1, item IV.C2-1 addresses Class I 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 Xl 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 (IGA) 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.

RESPONSE RAI 3.1.1.70-1 The Small Bore Class 1 Piping Inspection Program is credited to manage cracking due to flaw growth, stress corrosion cracking, and intergranular attack of the stainless steel

L-11-166 Page 11 of 69 and cast austenitic stainless steel (CASS) valve bodies less than 4 inches NPS, as described below.

The stainless steel and CASS valve bodies are included in LRA Table 3.1.1, Item 3.1.1-70, under the category of piping, fittings, and branch connections, for piping less than 4 inches NPS. In LRA Table 3.1.2-3, the stainless steel and CASS valve bodies are listed as separate items.

As detailed in NUREG-1 801,Section IX.B (Definitions), the term "Piping, Piping Components, and Piping Elements" is defined as "This general category includes various features of the piping system that are within the scope of license renewal.

Examples include piping, fittings, tubing, flow elements/indicators, demineralizer, nozzles, orifices, flex hoses, pump casing and bowl, safe ends, sight glasses, spray head, strainers, thermowells, and valve body and bonnet." Therefore, LRA Table 3.1.1, Item 3.1.1-70 is consistent with LRA Table 3.1.2-3. Also, the facility of the Small-Bore Class 1 Piping Inspection Program to manage the aging of these stainless steel and CASS valve bodies is therefore appropriate.

As provided in FENOC Letter L-1 1-153 dated May 24, 2011, the Small Bore Class 1 Piping Inspection (B.2.37) program description states that "The Small Bore Class 1 Piping Inspection is a one-time inspection that will be designed to detect cracking of small bore ASME Code Class 1 piping less than 4 inches nominal pipe size (less than NPS 4) and greater than or equal to NPS 1, which includes pipe, fittings, and branch connections, and all full and partial penetration (socket) welds." By the definition listed in NUREG-1801,Section IX.B, this includes valve bodies.

In addition, the description of the Reactor Coolant System and Connected Lines (Pressurized Water Reactor) in NUREG-1 801,Section IV.C2, states that the section "consists of the reactor coolant system and portions of other connected systems generally extending up to and including the second containment isolation valve or to the first anchor point and including the containment isolation valves, the reactor coolant pump, valves, pressurizer, and the pressurizer relief tank." Therefore, the valve bodies are included under the category of piping components, and the rows for the stainless steel and CASS valve bodies in LRA Table 3.1.2-3 (Rows 230-232 and 237-239) are consistent with NUREG-1 801.

Question 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 B.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

L-11-166 Page 12 of 69 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.

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.

RESPONSE RAI 3.1.2.1.58-1 LRA Table 3.1.2-1, "Aging Management Review Results - Reactor Pressure Vessel,"

Row 99 (which lines up with NUREG-1 801 Item IV.A2-13), shows that loss of material of the upper reactor vessel head external surface is managed by the Boric Acid Corrosion Program. The Boric Acid Corrosion Program, consistent with NUREG-1 801 Section XI.M10, does not include consideration of evaluations and repair activities associated with ASME Code Case N-729-1. The evaluations and repair activities associated with ASME Code Case N-729-1 are included in the Nickel-Alloy Reactor Vessel Closure Head Nozzle Program, which states, "Inservice Inspections of all nickel-alloy reactor vessel closure head penetration nozzles, and associated reactor vessel closure head surfaces, will continue to be performed in accordance with ASME Code Case N-729-1 as modified by the Code of Federal Regulations, 10 CFR 50.55a Section (g)(6)(ii)(D)."

LRA Table 3.1.2-1, Row 99, is revised to include a plant-specific note to point to the Nickel-Alloy Reactor Vessel Closure Head Nozzle Program.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI 3.1.2.2-1 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

L-11-166 Page 13 of 69 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.

RESPONSE RAI 3.1.2.2-1 Reduction in fracture toughness of the CASS plenum cylinder reinforcing plate will be managed indirectly by inspection techniques of the PWR Reactor Vessel Internals Program as applied to the most susceptible components, in accordance with materials reliability project (MRP) guidance in MRP-227.

The plenum cylinder reinforcing plate is included in the plenum assembly portion of the Babcock & Wilcox (B&W) internals design characteristics description on page 3-3 of MRP-227. However, the plenum cylinder reinforcing plate is not one of the 41 sub-components characterized in MRP-227 as Category B or C (reactor vessel internals component requiring further evaluation). The NRC's safety evaluation report (SER) for MRP-227, Revision 0, addressed what it considered to be the deficiencies in the aging management strategies defined by MRP-227 in Section 4.1 of that SER. The NRC did not identify any deficiencies related to the plenum cylinder reinforcing plate.

Furthermore, in response to NRC RAI 4-15 for the review of MRP-227, dated October 29, 2010, the MRP identified B&W CASS components (in-core monitoring instrumentation (IMI) guide tube assemblies and control rod guide tube assembly

L-11-166 Page 14 of 69 spacer castings) as requiring plant-specific analysis. The plenum cylinder reinforcing plate is not identified as a CASS component that requires a plant-specific analysis to demonstrate that its structural integrity and functionality are maintained during the period of extended operation. Section 4.2.7 of the NRC's safety evaluation report (SER) for MRP-227, Revision 0, acknowledged the plant-specific analyses for these two components and does not request a plant-specific analysis for the plenum cylinder reinforcing plate.

The plenum cylinder reinforcing plate is neither identified in MRP-227 as requiring further evaluation nor requiring plant-specific analysis, which implies that no specific examination or analysis of this component will be performed. Rather, general visual examinations of the internals, including the plenum cylinder, will be relied upon to identify any problems with the plenum cylinder reinforcing plates.

Question 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.

• 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.

L-11-166 Page 15 of 69 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).

RESPONSE RAI 3.1.2.2.1-1 With one exception, the subject aging management review (AMR) line items are included with fatigue time-limited aging analysis (TLAA) discussions in LRA Section 4.3.

Considerations for cumulative fatigue damage of components identified by the subject AMR line items are clarified below:

" The Auxiliary Feedwater (AFW) thermal sleeve and header transition pieces listed in LRA Table 3.1.2-4, Row 67, is part of the once-through steam generator (OTSG) Auxiliary Feedwater Modification discussed in LRA Section 4.3.2.2.6.3.

• The secondary side Main Feedwater (MFW) spray head, header, and pipe caps listed in LRA Table 3.1.2-4, Rows 92, 86 and 110, respectively, are ANSI B31.1 components. As such, the components are included in the evaluation of non-Class 1 fatigue in LRA Section 4.3.3.1.

" The pressurizer support plate assembly listed in LRA Table 3.1.2-3, Row 164, is not a part of the reactor coolant pressure boundary. The pressurizer support plate assembly is associated with, and provides spacing for, the heater tube bundles. There is no specific fatigue analysis. Therefore, LRA Table 3.1.2-3 is revised to delete Row 164.

" The MFW header support plate and gusset listed in LRA Table 3.1.2-4, Row 84, are attached to the inside of the OTSG shell, on the secondary side. As such, the components are included in the general evaluation of OTSG fatigue in LRA Section 4.3.2.2.6.1.

Components for the subject AMR line items in LRA Table 3.1.2-4 (Rows 67, 84, 86, 92 and 110) are included in fatigue TLAA discussions in LRA Section 4.3, as clarified above. The cracking due to fatigue AMR line item in Table 3.1.2-3 (Row 164) was determined to be a conservative entry that has been deleted, as described above. As

L-11-166 Page 16 of 69 such, there are no additional fatigue TLAA requiring identification and disposition in LRA Section 4.3.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Section 3.2 Question 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 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.

L-11-166 Page 17 of 69 RESPONSE RAI 3.2.2.1.26-1

1. Amendment No. 7 to the DBNPS LRA (see FENOC Letter L-1 1-153, dated May 24, 2011) changed the following lines from "One-Time Inspection," to "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program," to manage the aging effects such as loss of material, cracking, or reduction in heat transfer for these component/material/environment combinations. Refer to the response to RAI 3.3.2.71-02 contained in FENOC Letter L-1 1-153 for additional details:

• LRA Table 3.2.2-1 Rows 26 and 28

" LRA Table 3.2.2-2 Row 35

• LRA Table 3.3.2-1 Rows 76, 77, 78, 79, 80, 84, 88, and 91

• LRA Table 3.3.2-8 Row 43

• LRA Table 3.3.2-12 Row 42

• LRA Table 3.3.2-30 Row 31 In response to RAI B.2.8-1, Amendment No. 7 to the DBNPS LRA (see FENOC Letter L-1 1-153, dated May 24, 2011) deleted LRA Table 3.2.2-2 Row 20.

One-Time Inspection is still credited to confirm the absence of aging effects for components exposed to the moist air environment at air-water interfaces. An appropriate aging management program (e.g., PWR Water Chemistry Program) is used to manage the surface below the respective interface, and the portion above the air-water interface is also managed by a periodic program. Therefore, while the fluid management program (e.g., PWR Water Chemistry Program) is expected to preclude aging effects at the air-water interface, One-Time Inspection will confirm the effectiveness of the associated programs at air-water interfaces. Refer to the response to RAI 3.3.2.71-02 contained in FENOC Letter L-1 1-153 for additional details.

• LRA Table 3.3.2-4 Rows 158 and 159

• LRA Table 3.3.2-5 Row 60

• LRA Table 3.3.2-26 Rows 76 and 83

• LRA Table 3.3.2-27 Row 38

• LRA Table 3.4.2-2 Row 8 LRA Table 3.3.2-14 Row 25 is for reduction in heat transfer on the external surface (steam environment) of the fire water storage tank heat exchanger (DB-E52) tubes.

In this case, the One-Time Inspection supplements the PWR Water Chemistry Program to confirm the absence of fouling on the heat exchanger tubes. LRA Table 3.3.2-14 is revised to include a new row to show that the One-Time Inspection is supplementing the PWR Water Chemistry Program.

L-11-166 Page 18 of 69

2. FENOC's response to RAI 3.3.2.71-02 (see FENOC Letter L-1 1-153 dated May 24, 2011) included an assessment of other Table 2 AMR line items containing similar material, environment, and aging effect combinations that were similarly affected, and included revised line items to ensure an appropriate aging management program was assigned.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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.

RESPONSE RAI 3.2.2.2.1-1 To provide the requested clarification, in lieu of justification, the LRA is revised to include lines items in LRA tables in Sections 3.2, 3.3, and 3.4 for systems in which temperatures exceed the fatigue threshold and the piping and in-line components are, therefore, included in the fatigue evaluation in LRA Section 4.3.3.1.

The TLAA evaluation in LRA Section 4.3.3.1 encompasses non-Class 1 piping and in-line components for which the maximum operating temperature exceeds the fatigue threshold. The evaluation concludes that the system piping fatigue analyses (stress

L-11-166 Page 19 of 69 range reduction factors) remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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.DI.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.

RESPONSE RAI 3.2.2.2.3.6-1 Amendment No. 7 to the DBNPS LRA (see FENOC Letter L-11-153, dated May 24, 2011) changed from "One-Time Inspection," to "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program," to manage loss of material due to crevice and pitting corrosion of stainless steel piping, piping components, piping elements, and tank internal surfaces exposed to internal condensation (i.e., LRA

L-11-166 Page 20 of 69 Table 2 lines that roll up to LRA Table 3.2.1, Item 3.2.1-08). For components exposed to moist air at an air-water interface, the One-Time Inspection will confirm the absence of aging effects or that the aging effect is progressing slowly such that it would not affect the subject component's intended function during the period of extended operation, which verifies the effectiveness of aging management programs credited for management of aging effects above and below the air/water interface.

Refer to the Response to RAI 3.3.2.71-02 in FENOC Letter L-1 1-153 for additional details.

Question 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 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

L-11-166 Page 21 of 69 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.

RESPONSE RAI 3.2.2.2.6-1 The aging management review for the High Pressure Injection (HPI) System did not identify loss of material due to erosion for stainless steel components exposed to the environment of treated borated water as an.aging effect requiring management.

Therefore, loss of material due to erosion is not expected to occur for the miniflow recirculation orifices associated with the HPI pumps. LRA Section 3.2.2.2.6 and Table 3.2-1 are revised accordingly.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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.

In the GALL Report, Revision 2, Tables V.E and VII.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).

L-11-166 Page 22 of 69 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.

RESPONSE RAI 3.2.2.3.4-1 Loss of material due to crevice or pitting corrosion could not be ruled out for aluminum components exposed to an outdoor air environment. The External Surfaces Monitoring Program has been revised to manage this aging effect. Through periodic visual inspections and surveillance activities, the External Surfaces Monitoring Program will manage the effects of aging of aluminum components exposed to an outdoor air environment such that these components will continue to perform their intended functions consistent with the current licensing basis during the period of extended operation.

LRA Tables 3.2.2-4 and 3.3.2-12, and LRA Section B.2.15 are revised to incorporate these changes.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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

L-11-166 Page 23 of 69 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.

RESPONSE RAI 3.2.2.3.4-2 This response addresses the air environments applicable to stainless steel components (those listed in LRA Tables 3.2.2-4, 3.2.2-5, 3.3.2-12, 3.3.2-17 and 3.3.2-30), and provides justification why stainless steel components in an "air" environment do not have aging effects requiring management. The stainless steel components in an "air-outdoor" environment (listed in LRA Tables 3.2.2-4, 3.2.2-5) were addressed in the response to RAI B.2.2-2 contained in FENOC Letter L-1 1-153, dated May 24, 2011.

The "air" environment identified in LRA Table 3.3.2-12 (Emergency Diesel Generators (EDG)) and 3.3.2-30 (Station Blackout Diesel Generator) is in the air start subsystem for each of the diesel engines. The majority of the air start subsystem has an internal environment of compressed air that is taken from inside the Auxiliary Building or the Station Blackout Diesel Building, and has been processed through moisture separators (and an air dryer for the EDG), but it may contain some amount of moisture.

Nonetheless, this "air" is not evaluated as a wetted environment because the moisture is not expected to condense except in specific locations, such as in air receiver drains.

The potentially wetted locations are evaluated and presented with a "condensation" environment in the LRA.

The "air" environment identified in LRA Table 3.3.2-17 (Instrument Air System) is in the lines between the Auxiliary Building essential header and the air-operated components of containment radiation monitors DB-RE4597AA, DB-RE4597AB, DB-RE4597BA and DB-RE4597BB. The normal environment of the Instrument Air System is expected to be dry and free of contaminants. However, with a moisture separator and associated drain trap included in the subject lines, some amount of moisture is expected. Nonetheless, this "air" is not evaluated as a wetted environment, except in drainage components where moisture might condense. The potentially wetted drainage components are evaluated and presented with a "condensation" environment in the LRA.

The aging management review for the Emergency Diesel Generators, Station Blackout Diesel Generator and Instrument Air Systems was conducted with the guidance provided in EPRI Technical Report 1010639 (the "Mechanical Tools"). In accordance with the Mechanical Tools, cracking and loss of material are applicable aging effects for stainless steel components exposed to air only if the air is a wetted environment.

L-11-166 Page 24 of 69 Therefore, no aging effects requiring management exist for the stainless steel components exposed to an "air" environment.

Section 3.3 Question 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 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 0C (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.

RESPONSE RAI 3.3.1.39-1 Davis-Besse aging management review has determined that cracking due to stress corrosion cracking (SCC) or intergranular attack (IGA) is not an aging effect requiring management for the stainless steel spent fuel storage racks exposed to treated water because SCC or IGA occurs through the combination of high stress (both applied and residual tensile stresses), a corrosive environment and temperature, which are not found in the spent fuel pool. The spent fuel pool water temperature is below the 140'F threshold for SCC during normal operation. As indicated in Davis-Besse Updated Safety Analysis Report (USAR), Sections 1.2.8.2.4 and 9.1.3.3.1, the Spent Fuel Pool Cooling System is designed to maintain the borated spent fuel pool water temperature below 125 0 F. In the case of a partial core discharge, the spent fuel pool temperature is maintained below 133 0F during maximum normal heat load conditions according to USAR Section 9.1.3.1, which is also below the 140'F threshold for SCC to occur.

L-11-166 Page 25 of 69 Davis-Besse plant-specific operating experience has not indicated instances of cracking due to SCC on the spent fuel storage racks.

Although cracking due to SCC or IGA is not an aging effect requiring management, as indicated in LRA Table 3.5.2-2, the stainless steel spent fuel storage racks exposed to treated borated water are managed by the PWR Water Chemistry Program for loss of material. This program manages the relevant conditions that could lead to the onset and propagation of a loss of material, cracking, or reduction in heat transfer through proper monitoring and control.

Question RAI 3.3.1.49-1 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.

RESPONSE RAI 3.3.1.49-1 The applicability criteria specified in the EPRI Mechanical Tools indicates that microbiologically influenced corrosion (MIC) is a potential aging effect in treated water when operating experience has shown a treated water system to be contaminated with the microbes necessary to cause MIC damage. FENOC conducted a review of the Davis-Besse plant-specific operating experience for License Renewal. The results of this review only identified instances of MIC in open cycle systems. The review verified there were no instances of MIC in closed cycle cooling systems. Therefore, loss of material due to MIC is not an age-related concern for treated water and closed cooling water environments, and does not require management.

L-11-166 Page 26 of 69 Question 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.

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.

RESPONSE RAI 3.3.1.54-1 Management of loss of material due to pitting and crevice corrosion for stainless steel Instrument Air System tubing exposed to internal condensation was changed from the One-Time Inspection to Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program by Amendment No. 7 to the DBNPS LRA in FENOC Letter L-1 1-153, dated May 24, 2011. Refer to the FENOC response to RAI 3.3.2.71-02 in that letter for additional details.

Question 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

L-11-166 Page 27 of 69 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.

RESPONSE RAI 3.3.1.68-1 The justification for using the Collection, Drainage, and Treatment Components Inspection Program is that the subject components which credit the program are not in the scope of the Fire Water Program or any other aging management program.

The Fire Water Program is not credited for any fire pump diesel engine and associated components, as shown in LRA Table 3.3.2-14, Rows 154-224. LRA Table 3.3.2-14, Rows 165, 178, 189, 192, 198, 200, 215, 217, and 219, associated with LRA Table 3.3.1, items 3.3.1-68, 3.3.1-69 or 3.3.1-70, are for components in the cooling circuit for the Fire Protection diesel engine (DB-K6-FP). The gear housing has an externally mounted oil cooler with water from the diesel fire pump (DB-P5-2) inside the tubes. The diesel coolant system (cooling circuit) contains a mixture of antifreeze and water. The radiator has the antifreeze and water mixture in the shell, and water from the diesel fire pump in the tubes.

L-11-166 Page 28 of 69 The Fire Water Program (a sub-program of the overall Fire Protection Program) applies to the fire water supply and water-based suppression systems, which include sprinkler heads (spray nozzles), fittings, valve bodies, hydrants, hose stations, standpipes, a water storage tank, and aboveground and underground piping and components.

Consistent with NUREG-1801,Section XI.M27, the flow tests and wall thickness considerations of the Fire Water Program are in accordance with the recommendations of National Fire Protection Association (NFPA) 25, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems." NFPA 25 does not include recommendations for addressing the condition of components in the cooling circuit of the diesel fire pump; rather, on supporting the functionality of the diesel fire pump.

Since components in the cooling circuit of the diesel fire pump engine are not in the scope of the Fire Water Program or any other aging management program, the plant-specific Collection, Drainage, and Treatment Components Inspection Program manages loss of material for those components through opportunistic or focused visual inspection of component internal surfaces.

Similarly, LRA Table 3.3.2-31, Row 33, associated with LRA Table 3.3.1, item 3.3.1-68, is for gray cast iron piping in the Station Plumbing, Drains, and Sumps System (SPDSS). The sump pumps and their associated discharge piping and piping components that are within the system evaluation boundaries of the SPDSS have an internal environment of untreated and uncontrolled water from the equipment, floor, and roof drain piping. This environment was evaluated as "raw water (internal)".

Since SPDSS piping is not in the scope of any other aging management program, is exposed to untreated and uncontrolled (drainage) water rather than fire suppression water, and is not pressurized, the plant-specific Collection, Drainage, and Treatment Components Inspection Program manages loss of material through opportunistic or focused visual inspection of component internal surfaces.

Question RAI 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 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

L-11-166 Page 29 of 69 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.2.10, "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.

RESPONSE RAI 3.3.1.74-1 Loss of material due to wear for crane rails is currently managed by visual inspection.

During the period of extended operation, crane rail loss of material due to wear is managed by the Cranes and Hoists Inspection Program using visual inspection, consistent with NUREG-1 801, Rev. 1. Visual inspection is conducted using Preventive Maintenance tasks according to applicable industry standards and good industry practice. However, no Table 2 Rows were assigned in the LRA for crane rail loss of material due to wear.

LRA Table 3.5.2-1, "Aging Management Review Results - Containment," Table 3.5.2-2, "Aging Management Review Results - Auxiliary Building," and Table 3.5.2-3, "Aging Management Review Results - Intake Structure, Forebay, and Service Water Discharge Structure," are revised to add new rows for loss of material due to wear for crane rails, aligned to LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1 801 ," item 3.3.1-74. LRA Table 3.3.1, item 3.3.1-74 "Discussion" column is revised to address loss of material due to wear.

L-11-166 Page 30 of 69 LRA Table 3.5.2-3, Row 2 is also revised to correct a typographical error in the "Table 1 Item" column.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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 justification 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.

RESPONSE RAI 3.3.1.75-1 Elastomers have been removed from the scope of One-Time Inspection. FENOC has committed to implement a new plant-specific Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage degradation of elastomeric components in a raw water (internal) environment.

Refer to the response to RAI 3.3.2.2.5-1 in FENOC Letter L-1 1-153, dated May 24, 2011, for additional details.

Question 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

L-11-166 Page 31 of 69 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.

RESPONSE RAI 3.3.1.80-1 Stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water are managed for loss of material due to MIC. Components that are aligned to LRA Table 3.3.1, items 3.3.1-78 and 3.3.1-79, are managed by the Collection, Drainage, and Treatment Components Inspection Program and the Open-Cycle Cooling Water Program. The Open-Cycle Cooling Water Program expressly manages loss of material due to MIC in the systems such as the Service Water System that are the most likely to have conditions necessary for MIC to occur. The Collection, Drainage, and Treatment Components Inspection Program manages loss of material, regardless of mechanism, of metals exposed to a raw water environment that are not addressed by another aging management program. Both programs consist of inspections and surveillances to detect and evaluate loss of material that could result in a loss of component intended function during the period of extended operation.

Additionally, the Open-Cycle Cooling Water Program includes chemical treatments and cleaning activities to minimize loss of material. These two programs will manage loss of material due to MIC of stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water during the period of extended operation.

Attachment I L-11-166 Page 32 of 69 In accordance with NEI 95-10, "Industry Guidelines For Implementing The Requirements of 10 CFR Part 54 - The License Renewal Rule," the review for consistency with NUREG-1801 line items was chosen based on component type, material, environment, and aging effect via the license renewal generic notes. Generic notes A through E do not require a match to the aging mechanism for a match to NUREG-1 801. LRA Table 3.3.1 items 3.3.1-78, 3.3.1-79, and 3.3.1-80 have similar component types, materials, environments, and aging effects, but rows in the Davis-Besse LRA Tables were only aligned to LRA Table 3.3.1 items 3.3.1-78 and 3.3.1-79.

Question 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.

RESPONSE RAI 3.3.1.85-1 The gray cast iron heat exchanger shell in the startup feed pump lube oil cooler (DB-E30) exposed to closed cycle cooling water (internal) in the Turbine Plant Cooling Water System is susceptible to selective leaching, which will be managed by the Selective Leaching Inspection. This approach is consistent with the aging management approach taken for the gray cast iron heat exchanger channel in the same cooler.

LRA Table 3.3.2-32 is revised to add a new row to identify the need to manage selective leaching for the gray cast iron heat exchanger shell in the startup feed pump lube oil cooler.

L-11-166 Page 33 of 69 As a result of the review for this response, changes were also identified for LRA Table 3.3.2-18, LRA Section 3.3.2.1.32, and LRA Section B.2.36. LRA Table 3.3.2-18, "Aging Management Review Results - Makeup and Purification System," is revised to add a plant-specific note to clarify that loss of material due to selective leaching is not an aging effect requiring management for copper alloy with greater than 15 percent zinc when the material is an inhibited copper alloy (admiralty brass). LRA Section 3.3.2.1.32, "Turbine Plant Cooling Water System," is revised to add listing of the Selective Leaching Inspection as a credited aging management program for the Turbine Plant Cooling Water System. LRA Section B.2.36, "Selective Leaching Inspection," is revised to include listing of the Turbine Plant Cooling Water System as a system which credits the Selective Leaching Inspection.

The response to RAI 3.3.2.71-2 in FENOC Letter L-1 1-153, dated May 24, 2011, revised LRA Table 3.3.2-3 to add a row to address loss of material due to selective leaching for copper alloy with greater than 15 percent zinc components (valve body) exposed to a treated water environment.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI 3.3.2.-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.

RESPONSE RAI 3.3.2.-1 LRA Table 3.3.2-3 Row 2 addresses copper alloy bolting in the Auxiliary Steam and Station Heating Systems. This bolting is ASTM B 98, which is a copper-silicon alloy that contains a maximum of one and one-half percent zinc and no aluminum. The

L-11-166 Page 34 of 69 plant-specific aging management review determined that these components are not susceptible to stress corrosion cracking, selective leaching, pitting corrosion, or crevice corrosion. That determination was considered to be consistent with NUREG-1 801, Items V.F-5 and VII.J-5, based on the aging effects shown for "Copper alloy <15% Zn" in an "Air with borated water leakage" environment. Based on the Definitions listed in NUREG-1801 Table IX.D, FENOC considered the "Air with steam or water leakage" environment to be a less-aggressive environment for "Copper alloy <15% Zn" than an "Air with borated water leakage" environment.

Question 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.

RESPONSE RAI 3.3.2.-2 The air-outdoor (internal) environment is evaluated in accordance with Appendix D (Air / Gas Environment) of EPRI 1010639 (the "Mechanical Tools"), which states that copper alloys must, in addition to other criteria, be subject to a wetted environment for loss of material due to selective leaching, galvanic corrosion (to provide an electrolyte),

pitting and crevice corrosion, or MIC to be an applicable aging effect that requires management. Additionally, the same wetted environment must be present for cracking due to SCC to be an applicable aging effect in an air-outdoor (internal) environment.

The air-outdoor (internal) environment in the Fire Protection (FP) System, LRA Table 3.3.2-14, is not a wetted environment since it is for sprinkler components in the FP System that are normally drained and have been vented to the atmosphere of the

L-11-166 Page 35 of 69 outdoor air in which the components are located. Therefore, the copper alloy components subject to an air-outdoor (internal) environment are not subject to loss of material or cracking.

The Emergency Diesel Generator and Station Blackout Diesel Generator aftercooler tubes are exposed to outside air that is ducted and filtered, which precludes the presence of water or rain. Therefore, those components are not susceptible to loss of material or cracking.

The air-outdoor (external) environment is evaluated in accordance with the Appendix E (External Surfaces) of the Mechanical Tools. Table 4-1 of this appendix states that, for cracking due to SCC to be an aging effect requiring management, the copper alloy components must be brass with greater than 15 percent zinc, or aluminum bronze with greater than eight percent aluminum. The External Surfaces Monitoring Program is revised to manage cracking for copper alloys with greater than 15 percent zinc with an external outdoor air environment. Through periodic visual inspections and surveillance activities the External Surfaces Monitoring Program will manage the effects of aging of copper alloy components with greater than 15 percent zinc exposed to an outdoor air environment such that these components will continue to perform their intended functions consistent with the current licensing basis during the period of extended operation.

Loss of material due to selective leaching is only applicable for copper alloy components subject to an air-outdoor (external) environment that are brass with greater than 15 percent zinc or aluminum bronze with greater than eight percent aluminum. The Selective Leaching Inspection is revised to detect and characterize the conditions on external surfaces of subject components with greater than 15 percent zinc that are exposed to air-outdoor. This one-time inspection provides direct evidence through visual inspection, material hardness measurement, or other appropriate examinations (such as chipping, scraping, or other mechanical means), of whether, and to what extent, loss of material due to selective leaching has occurred that could result in a loss of intended function. Implementation of the Selective Leaching Inspection will provide reasonable assurance that intended functions are maintained consistent with the current licensing basis for the period of extended operation.

Loss of material due to crevice and/or pitting corrosion cannot be ruled out for copper alloys subject to an air-outdoor (external) environment. The External Surfaces Monitoring Program is revised to manage loss of material for copper alloys with an external outdoor air environment. Through periodic visual inspections and surveillance activities, the External Surfaces Monitoring Program will manage the effects of aging of copper alloy components exposed to an outdoor air environment such that these components will continue to perform their intended functions consistent with the current licensing basis during the period of extended operation.

See the Response to RAI B.2.2-2 in FENOC Letter L-1 1-153 dated May 24, 2011, for related LRA revisions to the External Surfaces Monitoring Program.

L-11-166 Page 36 of 69 LRA Tables 3.3.2-14, 3.3.2-30 and A-I, and LRA Sections A.1.36, B.2.15 and B.2.36 are revised to incorporate the items addressed above.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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 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.

RESPONSE RAI 3.3.2.-3 The aging management review for the Fire Protection System was conducted with the guidance provided in EPRI Technical Report 1010639 (the "Mechanical Tools"). In accordance with the Mechanical Tools, copper alloys must have greater than 15 percent zinc or greater than eight percent aluminum and be subject to a wetted environment for loss of material due to selective leaching to be an applicable aging effect in an air or air-indoor uncontrolled environment. Additionally, ammonia, ammonia salts, or sulfur dioxide must be present for cracking due to stress corrosion cracking to be an applicable aging effect.

The air-indoor uncontrolled environment (external) is not evaluated as a wetted environment. Equipment and components located inside a building or structure, such that they are protected from atmospheric conditions and weather, are exposed to an indoor air environment, also referred to as a sheltered environment. Ambient conditions within this environment may or may not be controlled. Therefore, for a conservative

L-11-166 Page 37 of 69 identification of aging effects requiring evaluation, all indoor air environments are considered to be uncontrolled environments; i.e., humid air environments. However, equipment and components located in systems with external surface temperatures the same or higher than ambient conditions during normal plant operation, are expected to have relatively dry external surfaces (no wetting). Those components with external surface temperatures lower than ambient conditions during normal plant operation are evaluated to have a condensation (external) environment. Also, the indoor air environment does not contain detectable amounts of ammonia, ammonium salts, or sulfur dioxide. The air-indoor uncontrolled environments (external) in the Fuel Oil, Instrument Air and Station Blackout Diesel Generator (SBODG) systems are not wetted since they are at ambient or higher temperatures during normal operation.

The air (internal) environment is assigned for the compressed air of the Instrument Air System and the SBODG air start system. This air is reliably dry, although it may contain some amount of moisture. The environment is not evaluated as a wetted environment because the moisture is not expected to condense except in specific locations, such as the gray cast iron moisture separators and associated drain traps of the Instrument Air System and the carbon steel (steel) drains for the SBODG air receivers, which are evaluated with a condensation (internal) environment.

Question RAI 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.

RESPONSE RAI 3.3.2.1-1 Consistent with the guidance in NUREG-1 801,Section IX.C, copper alloy with greater than 15 percent zinc are susceptible to selective leaching with the exception of inhibited

L-11-166 Page 38 of 69 brass. The tubes for the Control Room Emergency Ventilation System (CREVS) water-cooled condensing units (DB-$33-1 and DB-S33-2) exposed to raw water are formed of admiralty brass, which is an inhibited copper alloy (brass). LRA Table 3.3.2-1, "Aging Management Review Results - Auxiliary Building HVAC System," Row 100, provides this information by reference to plant-specific Note 0303. Therefore, the CREVS water-cooled condensing unit tubes are not susceptible to selective leaching and do not require management for selective leaching.

Question 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 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 #3 resulted in releases of sulfur compounds that caused the extensive pitting of the demineralizer internal screen and the breakthrough of the

L-11-166 Page 39 of 69 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.

RESPONSE RAI 3.3.2.18-1

1. A review of Davis-Besse operating experience reveals that the stainless steel components in the Makeup and Purification System that were previously exposed to sulfur compounds have not experienced SCC.

Cracking due to SCC is not an aging effect requiring management for the stainless steel demineralizer tanks, including internal screens, and filter housing. The aging management review for the Makeup and Purification System was conducted with the guidance provided in EPRI Technical Report 1010639 (the "Mechanical Tools"). In accordance with the Mechanical Tools, SCC is an applicable aging mechanism for stainless steel and CASS exposed to treated water only if the temperature is greater than 140 0F. The subject components of the Makeup and Purification System have a normal operating temperature below 120 0 F.

Additionally, as described in the RAI, LER 1998-002-01 indicated that the screen mesh at the bottom of the demineralizer failed due to extensive pitting corrosion, likely as a result of exposure to sulfur compounds. The LER did not identify cracking as an apparent cause. As corrective actions, the letdown flowpath was flushed, and a resin control program was instituted to prevent recurrence. No additional operating experience has been identified to support the staff's concern that short-term exposure to sulfur compounds will result in cracking due to SCC in stainless steel components.

Therefore, cracking due to SCC is not an aging effect requiring management for the stainless steel demineralizer tanks, including internal screens, and filter housing.

L-11-166 Page 40 of 69

2. The stainless steel components in the Makeup and Purification System have not experienced SCC.

Question RAI 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.

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.

RESPONSE RAI 3.3.2.2.3.3-1 Stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust have been removed from the scope of One-Time Inspection.

FENOC has committed to implement a new plant-specific Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program for Davis-Besse to manage

L-11-166 Page 41 of 69 degradation of stainless steel piping, piping components and piping elements exposed to diesel exhaust. This new periodic inspection program will manage cracking due to stress corrosion cracking for these components.

For additional details, please refer to the response to RAI 3.3.2.71-02 in FENOC Letter L-1 1-153, dated May 24, 2011, Attachment A, pages 7 and 8; and page 34 of the Enclosure to the letter.

Question 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.

L-11-166 Page 42 of 69 RESPONSE RAI 3.3.2.2.7.3-1 Steel and stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust have been removed from the scope of One-Time Inspection. FENOC has committed to implement a new plant-specific Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program for Davis-Besse to manage 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 exposed to diesel exhaust.

For additional details, please refer to the response to RAI 3.3.2.71-2 in FENOC Letter L-1 1-153, dated May 24, 2011, Attachment A, pages 7 and 8; and page 35 of the Enclosure to the letter.

Question RAI 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.

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.

L-11-166 Page 43 of 69 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.

RESPONSE RAI 3.3.2.2.13-1

1. The in-scope elastomeric components exposed to the "Fuel oil (Internal)" and "Lubricating oil (Internal)" environments are within systems containing filters and thus hard abrasive particles are filtered out. Furthermore, the Fuel Oil Chemistry Program and Lubricating Oil Analysis Program maintain the oil environment in the mechanical systems to the required quality by managing particulates and other contaminants. Therefore, the in-scope elastomeric components exposed to the Fuel oil (Internal) and Lubricating oil (Internal) environments are not exposed to hard abrasive particles. The in-scope elastomeric components exposed to the "Air-indoor uncontrolled (Internal)," "Air-indoor uncontrolled (External)," "Raw water (Internal),"

"Air-outdoor (Internal)," and "Treated water > 600C (>140 0 F) (Internal)" environments are within systems in which the fluid medium is not expected to contain hard abrasive particles sufficient to cause loss of material due to wear; however, to be conservative, this aging effect will be managed for the in-scope elastomeric components within these environments.

2. The in-scope elastomeric components are not expected to be manipulated at a frequency sufficient to cause loss of material due to wear; however, this aging mechanism cannot be completely ruled out. Therefore, to be conservative, this aging effect will be managed for the in-scope elastomeric components.

3. Relative motion of the in-scope elastomeric components due to a loss of clamping force is not expected to be sufficient to cause loss of material due to wear for the in-scope elastomeric components. However, the aging mechanism cannot be completely ruled out. Therefore, to be conservative, this aging effect will be managed for the in-scope elastomeric components.

L-11-166 Page 44 of 69

4. For the in-scope elastomeric components exposed to the "Air-indoor uncontrolled (External)" environment, loss of material due to wear will be managed by the External Surfaces Monitoring Program through periodic visual examination.

For the in-scope elastomeric components exposed to the "Air-indoor uncontrolled (Internal)," "Air-outdoor (Internal)," "Raw water (Internal)," and "Treated water > 600C

(>140 0 F)(Internal)" environments, the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program will manage loss of material due to wear through opportunistic visual examination, when components are opened for maintenance, repair, or surveillance.

LRA Tables 3.2.2-1, 3.3.1, 3.3.2-1, 3.3.2-6, 3.3.2-12, 3.3.2-13, 3.3.2-14, 3.3.2-15, 3.3.2-21, 3.3.2-28 and 3.3.2-30, and LRA Sections 3.3.2.2.13, A.1.15, A.1.41, B.2.15 and B.2.41 are revised to address loss of material due to wear for in-scope elastomeric components.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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 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

L-11-166 Page 45 of 69 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 600 C.

RESPONSE RAI 3.3.2.2.4-1

1. As discussed in the response to RAI 2.3.3.18-2, above, the letdown coolers (DB-E25-1 and 2), which are the nonregenerative heat exchangers in the Makeup and Purification System, have a qualified life of every seven refueling outages.

Therefore, the letdown coolers are not subject to aging management review since they are short-lived, and will not be included in the sample of components to be inspected by the One-Time Inspection.

2. Since the letdown coolers are not subject to aging management review because they are short-lived, nondestructive examination (NDE) techniques will not be used to verify the effectiveness of the PWR Water Chemistry Program to manage cracking due to stress corrosion cracking of the stainless steel nonregenerative heat exchanger components.

L-11-166 Page 46 of 69

3. For the stainless steel nonregenerative heat exchangers, cracking due to cyclic loading is not identified as an aging effect requiring management for the reason stated above. There are no regenerative heat exchangers in the Makeup and Purification System. The only other stainless steel heat exchangers in the Makeup and Purification System are the seal return coolers (DB-E26-1 and 2). However, these heat exchangers are not subject to the high thermal differential temperature that nonregenerative and regenerative heat exchangers are, since the seal return coolers lower the fluid temperature from 200°F to 120 0 F. Therefore, cracking due to cyclic loading is not an aging effect requiring management for the seal return coolers.

For clarity, LRA Table 3.3.2-18 is revised to not credit Table 3.3.1 item 3.3.1-07 for cracking of the seal return coolers (DB-E26-1 and 2). This change also affects the discussion in LRA Section 3.3.2.2.4.1 and Table 3.3.1.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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.

RESPONSE RAI 3.3.2.3.12-2 As listed in LRA Tables 3.3.2-12, 3.3.2-14 and 3.3.2-15, the flexible connections are components within the Emergency Diesel Generators System, Fire Protection System and Fuel Oil System, respectively. The material of construction of the flexible connections exposed to fuel oil and lubricating oil in the Emergency Diesel Generators and Fire Protection systems is neoprene rubber. However, the material of construction of the flexible connections exposed to fuel oil in the Fuel Oil System is unknown.

L-11-166 Page 47 of 69 Therefore, LRA Table A-1 is revised to include a new license renewal future commitment that reads:

Establish a preventive maintenance task to periodically replace the flexible connections exposed to fuel oil in the Fuel Oil System.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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.

RESPONSE RAI 3.3.2.3.14-1 Loss of pre-load is not identified as an aging effect requiring management for the submerged steel bolting in the Fire Protection System that is exposed to a raw water environment, as described below.

The aging management review for the Fire Protection System was conducted with the guidance provided in EPRI Technical Report 1010639 (the "Mechanical Tools"). In accordance with the Mechanical Tools, loss of pre-load is an applicable aging effect as a result of thermal effects, gasket creep, embedment (including cyclic load embedment),

and/or self-loosening.

Loss of pre-load can be promoted by thermal effects (high temperature) through a process called stress relaxation. However, stress relaxation is only a concern at extremely high temperatures (above 700°F for low-alloy steels), although there may be bolting of some grades that could be susceptible to stress relaxation at temperatures slightly lower than 700 0 F. The submerged bolting in the Fire Protection System is associated with the diesel fire pump column that is submerged in raw water supplied by Lake Erie. The normal temperature of this water is no greater than 85 0F, which is well below the temperature at which stress relaxation occurs. Therefore, for the submerged steel bolting in the Fire Protection System, loss of pre-load due to thermal effects is not an aging effect requiring management.

L-11-166 Page 48 of 69 Loss of pre-load may occur as a result of gasket creep. However, gasket creep has a very small effect on pre-load (2 - 5%) and occurs, and will be evident, very soon after initial loading (10 - 20 minutes). Therefore, for the submerged steel bolting in the Fire Protection System, loss of pre-load due to gasket creep is not an aging effect requiring management.

Loss of pre-load may occur after initial loading as surfaces (e.g., threads in the bolts and joint members), which are initially in contact only on high spots, settle in together, a process called embedment. However, the effect of embedment is considered to be small and to have minimal effect on the integrity of the bolted connection. Additionally, bolted connections subjected to large cyclic loads will embed and relax more than those under static loads. However, the diesel fire pump is normally in a standby mode, and, being located in a relatively stagnant atmospheric pool, is not subject to large thermal, vibrational, or pressure-induced cyclic loading. Therefore, for the submerged steel bolting in the Fire Protection System, loss of pre-load due to embedment is not an aging effect requiring management.

Loss of pre-load due to self-loosening may occur as a result of vibration, flexing of the joint, cyclic shear loads, thermal cycles and other factors. In addition to the discussions of these factors above, self-loosening is precluded by good bolting practices and, if it occurs, is usually detected and corrected early in the service life of the component, as during maintenance activities. Therefore, for the submerged steel bolting in the Fire Protection System, loss of pre-load due to self-loosening is not an aging effect requiring management.

Question 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.

L-11-166 Page 49 of 69 RESPONSE RAI 3.3.2.3.14-2 Enhanced visual inspections will not detect cracking of components under water, and will not be used in a raw water environment. Rather, opportunistic visual inspections will be performed, such as during maintenance when components are disassembled or drained, and these visual inspections will be supplemented by enhanced visual inspections as warranted for detection of cracking. If an opportunistic inspection has not been conducted prior to the period of extended operation, a focused inspection will be conducted prior to entering the period of extended operation.

LRA Table 3.3.2-14 Rows 12 and 199 list cracking in a raw water external environment for steel bolts associated with the diesel fire pump (DB-P5-2) casing and for copper alloy with greater than 15 percent zinc diesel fire pump heat exchanger (radiator) tubes, respectively.

If there is no maintenance of the diesel fire pump (DB-P5-2) that provides access to the subject bolting prior to the period of extended operation, then a focused visual inspection of the bolting will be conducted prior to entering the period of extended operation. Preventive maintenance of the diesel fire pump heat exchanger (radiator) includes a partial visual inspection of the heat exchanger tubes through available openings. If there is no additional visual inspection of the heat exchanger tubes prior to the period of extended operation, then a focused visual inspection of the accessible (by removal of the tube bundle) heat exchanger tubes will be conducted prior to entering the period of extended operation.

Opportunistic inspections, when surfaces are accessible during maintenance will ensure that the existing environmental conditions in collection, drainage, and treatment service are not causing material degradation that could result in a loss of component intended function during the period of extended operation. If an opportunistic inspection has not been conducted prior to the period of extended operation, a focused inspection will be conducted prior to entering the period of extended operation.

Evidence of degradation that could lead to a loss of component intended function will be documented and evaluated through the Corrective Action Program to determine the need for subsequent inspections, expansion of the sample size, and for monitoring and trending the results.

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

L-11-166 Page 50 of 69 GALL Report Revision 2, item VII.E1.AP-114 addresses cracking due to SCC of the stainless steel high-pressure pump casing in the chemical and volume control system, which is exposed to treated borated water greater than 601C. 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 Xl Inservice 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.

RESPONSE RAI 3.3.2.2.4.3-1 For the stainless steel high-pressure pump casings (makeup pumps DB-P37-1 and 2) in the Makeup and Purification System, cracking due to stress corrosion cracking is not an aging effect requiring management, as described below. However, cracking due to cyclic loading is an aging effect requiring management for the stainless steel high-pressure pump casings in the Makeup and Purification System, and the LRA is amended as described below.

The aging management review for the Makeup and Purification System was conducted with the guidance provided in EPRI Technical Report 1010639 (the "Mechanical Tools").

In accordance with the Mechanical Tools, cracking due to stress corrosion cracking is not an aging effect requiring management for stainless steel in a treated water environment if the temperature is less than 1400 F. The stainless steel makeup pumps are exposed to treated borated water that is maintained 120°F or below. Therefore,

L-11-166 Page 51 of 69 cracking due to stress corrosion cracking is not an aging effect requiring management for the stainless steel makeup pumps (DB-P37-1 and 2).

LRA Tables 3.3.1, 3.3.2-18 and A-I, and LRA Sections 3.3.2.2.4.3 and B.2.30, are revised such that cracking due to cyclic loading of the stainless steel makeup pumps (DB-P37-1 and 2) is managed. This aging effect will be managed by the PWR Water Chemistry Program with the One-Time Inspection providing verification of the absence of cracking due to cyclic loading.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question 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 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

L-11-166 Page 52 of 69 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.

RESPONSE RAI 3.3.2.3.12-1 The air intake filters for the emergency diesel generator and fire pump diesel engines are oil bath type filters. The oil environment for the air intake filters functions only as filter media to remove contaminants from the engine intake (outside) air. This oil does not serve as an environment for any components that provide engine lubrication. The oil in the intake air filters serves to accumulate contaminants, including water, therefore the air intake filter bodies require different aging management than the components in the engine lubricating oil environments. Although the oil in the air intake filter bodies is subject to regular replacement this does not preclude the potential for water from the intake air to accumulate at low points in the filter body. Therefore, loss of material is an aging effect requiring management.

Because the oil in the air intake filters functions as filter media, and is independent of the oil that provides for engine lubrication, it is not subject to the Lubricating Oil Analysis Program. The potential for accumulation of water requires management for loss of material in the carbon steel filter bodies. Aging management for these components will be performed by the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program is a new plant-specific program developed in response to RAI 3.3.2.71-2.

The adjacent filter body line items in LRA Table 3.3.2-12 (item numbers 19 and 20) represent filters in the lubrication oil subsystem for the emergency diesel generators.

The engine lubricating oil subsystem is subject to the Lubricating Oil Analysis Program.

Therefore the filter bodies in the engine lubricating oil subsystem are age managed differently than the filter bodies in the diesel engine air intake subsystem.

L-11-166 Page 53 of 69 Section 3.4 Question 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 0 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 212OF (100 0 C) throughout their service life 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 0 C), please state how loss of material due to general corrosion will be managed for the subject components.

RESPONSE RAI 3.4.2.3-1 For the external surfaces of the Main Feedwater System which may be exposed to temperatures below 212°F (1000C), loss of material due to general corrosion will be managed by the External Surfaces Monitoring Program. The LRA is revised to include loss of material due to general corrosion as an aging effect requiring management for external surfaces of steel components of the Main Feedwater System that are exposed to an air-indoor uncontrolled environment due to the possibility of surface temperatures being less than 212°F during extended outages. As an extent of condition, the LRA is

L-11-166 Page 54 of 69 also revised to address components in the Main Steam System, as it is the only other system to which this condition applies.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI 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 B.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

L-11-166 Page 55 of 69 of the Lubricating Oil Analysis Program for managing loss of material due to selective leaching.

RESPONSE RAI 3.4.2.2.5-1 Selective leaching of gray cast iron and copper alloy with greater than 15 percent zinc exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. LRA Sections A.1.26 and B.2.26, both titled "Lubricating Oil Analysis Program," are revised to specifically mention loss of material due to selective leaching.

The Lubricating Oil Analysis Program manages loss of material due to selective leaching by controlling the conditions necessary for the aging effect to occur.

Specifically, lubricating oil is monitored for the presence of water. Water is a contaminant that is maintained within acceptance limits to preserve the lubricating qualities of the oil and to prevent corrosion of the components. As water in lubricating oil is treated as a contaminant, it is not expected to be present, and corrective actions are initiated when water is detected. The detection of water outside of the acceptance limits requires an evaluation of the condition.

Loss of material due to general, crevice, or pitting corrosion or selective leaching requires the presence of sufficient water contamination such that the water can settle or "pool" to result in a potential corrosive environment. The One-Time Inspection confirms that loss of material due to general, pitting, or crevice corrosion for gray cast iron and copper alloy with greater than 15 percent zinc in lubricating oil is not occurring. The One-Time Inspection does not inspect for loss of material due to selective leaching in lubricating oil since effective water removal precludes the aging effect. Loss of material due to selective leaching is a slow-acting corrosion process, and therefore would require long periods of exposure to pooled water in a lubricating oil environment. As the conditions for selective leaching are not expected, inspections for loss of material due to selective leaching in lubricating oil are not planned. Identification of degradation as a result of general, pitting, or crevice corrosion inspections using the One-Time Inspection would require additional evaluation using the FENOC Corrective Action Program as to whether selective leaching is occurring for components susceptible to selective leaching.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Section 3.5 Question 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

L-11-166 Page 56 of 69 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 ANSI/ASCE 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.

RESPONSE RAI 3.5.2.1-1

1. For in-scope structure concrete that is below grade elevation, change in material properties was determined to be an aging effect requiring management because of plant-specific operating experience of groundwater in-leakage and aggressive groundwater. LRA Table 3.5.2-1 Rows 61 and 62 are for the Containment foundation, LRA Table 3.5.2-2 Rows 65 and 66 are for the Auxiliary Building pipe

L-11-166 Page 57 of 69 tunnel, and LRA Table 3.5.2-3 Rows 34 and 25 are for the Intake Structure and Forebay Retaining Walls.

For concrete components below grade, change in material properties due to leaching of calcium hydroxide is an aging effect requiring management because water leakage has been observed at the plant from operating experience.

Efflorescence is a surface phenomenon and consists of salt deposits that have been leached from the concrete and are crystallized on subsequent evaporation of the water. The presence of efflorescence indicates leaching is taking place and water has found a direct path or is being absorbed through the concrete.

For concrete components below grade, loss of material and change in material properties due to aggressive chemicals are aging effects requiring management because Davis-Besse groundwater chemistry is considered aggressive. Site groundwater level ranges from 570 to 575 feet International Great Lakes Datum. The Containment, Auxiliary Building, Intake Structure and Forebay Retaining Wall Foundations are below the groundwater elevation; therefore, they are in contact with groundwater.

2. The material properties of interest for concrete are change in material properties due to leaching of calcium hydroxide and aggressive chemical attack. The applicable aging effects and recommended aging management program covered by change in material properties are the same as the NUREG-1 801, Chapter III items II1.A1-5 and II1.A1-7 for the Containment, items II1.A3-5 and II1.A3-7 for the Auxiliary Building, and items II1.A6-3 and II1.A6-6 for water-control structures. For water-control structures, the Structures Monitoring Program encompasses and implements the Water Control Structures Inspection as indicated in LRA Section A.1.39.

The concrete aging effect of change in material properties is managed by the Structures Monitoring Program using visual inspection methods. Visual inspection is the method used for monitoring structural degradation. Inaccessible below grade concrete will be inspected via opportunistic inspections and with the special below-grade inaccessible concrete components inspection described below in Item 3. See also the response to RAI B.2.39-3 in FENOC Letter L-11-153, dated May 24, 2011.

3. The selection of material properties is justified by plant and industry operating experience.

The inspection properties and techniques using ACI 349.3R guidance as committed for the Structures Monitoring Program in LRA Table A-I, Item number 20, and in the response to RAI B.2.39-6 provided in FENOC Letter L-1 1-153, dated May 24, 2011, are consistent with the NUREG-1801 recommendation for managing the change in material properties aging effect due to leaching of calcium hydroxide and aggressive chemical attack.

L-11-166 Page 58 of 69 LRA Table A-1 .Item number 20 and the response to RAI B.2.39-6 (in FENOC Letter L-1 1-153) have committed the Structures Monitoring Program to be enhanced to follow the guidance of ACI 349.3R for detection of aging effects and acceptance criteria. NUREG-1801 XI.S6 Structures Monitoring Program indicates that ACI 349.3R provides an acceptable basis for addressing detection of aging effects and acceptance criteria for concrete structural elements.

NUREG-1801 Chapter III items Ill.A1-5, II1.A3-5 and II1.A6-3 also recommend for plants with aggressive groundwater/soil, and/or where the concrete structural elements have experienced degradation, that a plant-specific aging management program be implemented to manage concrete aging to account for the extent of the degradation expected during the period of extended operation. In the response to RAI B.2.39-3 (see FENOC Letter L-1 1-153), FENOC has committed to enhance the Structural Monitoring Program to obtain and evaluate for degradation a concrete core bore from a representative inaccessible concrete component of an in-scope structure subjected to aggressive groundwater prior to the period of extended operation. Based on the results of the initial core bore sample, FENOC committed to evaluate the need for collection and evaluation of representative concrete core bore samples at additional locations that may be identified during the period of extended operation as having aggressive groundwater infiltration. The selection of additional core bore sample locations would be based on the duration of observed aggressive groundwater infiltration. The Corrective Action Program would be used to document concrete or rebar degradation.

For leaching of calcium hydroxide, ACI 349.3R Chapter 4.2.8 recommends that a visual survey identify any contributory effects, the coloration and consistency of leached material, the presence of groundwater or other fluid, and any local damage evident in the affected concrete.

For aggressive chemical attack, ACI 349.3R Chapter 4.2.2, recommends that a visual survey quantify loss of concrete cover accompanied by staining and cracking or spalling as manifestation of chemical attack. The visual survey should also quantify the effects of damage, including any steel reinforcement corrosion, and identify possible sources and composition of the aggressive chemical.

Quantification of acceptance criteria is detailed in ACI 349.3R Chapter 5 and includes inspection attributes such as cracking, spalling, popouts, scaling, corrosion of rebar, groundwater seepage, water stains, rust stains, and efflorescence, which are contributory effects for leaching of calcium hydroxide and aggressive chemical attack.

Question 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

L-11-166 Page 59 of 69 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 that; stainless steel must be subject to both high temperature (> 1401F) and an aggressive chemical environment. The applicant also stated that SCC 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 SCC 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.

RESPONSE RAI 3.5.2.2.1.7-1 The two water leakage events (above and below grade) addressed as operating experience in LRA Section 3.5.2.2.1.10 were determined not to be conducive to stress corrosion cracking for stainless steel penetration sleeves and bellows. The above grade leakage is due to refueling cavity leakage inside Containment during refueling. This refueling cavity leakage is not in the vicinity of and cannot leak onto any containment penetration sleeves or bellows.

The below grade leakage is due to a recurring issue of groundwater intrusion into the annulus between the Containment and the Shield Building. A 2002 condition report identified that the two stainless steel bellows and flanges for the containment emergency sump recirculation valves had a rusty appearance. Corrective action directed sampling of the water and repairs to identify and correct the source of the leakage. Evaluation of the residue on the bellows identified that it contained calcium.

The calcium was a result of ground water seepage around the pipe jacket seal and concrete (between the annulus and the Auxiliary Building). The leakage of the body

L-11-166 Page 60 of 69 jacket wall penetrations were not considered a concern since the piping and bellows are stainless steel. Cracking due to stress corrosion cracking is not an applicable aging effect for these bellows since the normal temperature of these components is less than 140 0 F. A review of plant-specific operating experience confirmed that no other containment penetration bellows have been affected by groundwater intrusion. A further review of plant-specific operating experience using keywords "bellow," "crack", "stress corrosion" and "SCC" did not reveal any occurrence of cracking of penetration sleeves or cracking of bellows. Although cracking due to stress corrosion cracking of stainless steel penetration sleeves and bellows was not determined to be a credible aging effect, cracking of primary containment pressure boundary penetrations is an inspection attribute within the credited Inservice Inspection Program - IWE.

Question 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 I 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 I1.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?

L-11-166 Page 61 of 69

2. If no CLB fatigue analysis exists, explain the apparent contradiction of the AMR Containment Vessel penetrations excluded from fatigue analysis with the IIA3-4, which is recommended only if there is a CLB fatigue analysis.

RESPONSE RAI 3.5.2.3.1-1

1. Davis-Besse does not have a current licensing basis 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 as indicated in LRA Section 4.6.2.

2. For a Pressurized Water Reactor (PWR) plant with steel containment, NUREG-1 801 item I1.A3-4 is the only item that provides a pointer to the LRA time-limited aging analysis (TLAA) section as the recommended aging management program within NUREG-1801 Section II.A2 or II.A3. The listings of NUREG-1801 item I1.A3-4 in LRA Table 3.5.2-1 were for the Containment Vessel and the Permanent Reactor Cavity Seal Plate (i.e., not the same component as listed in NUREG-1801 item I1.A3-4), and a generic note "C" was used to indicate that the component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. The aging management program is consistent with the recommended NUREG-1 801 aging management program evaluation of fatigue as a TLAA. The usage of NUREG-1801 item I1.A3-4 in the LRA was intended to serve as a pointer to indicate that these two components, Containment Vessel in LRA Section 4.6.1 and the Permanent Reactor Cavity Seal Plate in LRA Section 4.6.3, have been evaluated as TLAA for meeting the requirements of 10 CFR 54.21 (c)(1), and were dispositioned in accordance with 10 CFR 54.21(c)(1)(i) and (iii), respectively. Therefore, the usage of NUREG-1801 item II.A3-4 with a note "C" is not a contradiction of the aging management review of Containment Vessel penetrations excluded from fatigue analysis; rather, it was intended to point to the appropriate LRA section for TLAA disposition by means of plant-specific notes 0513 and 0514.

Question RAI 3.5.2.3.12-1 The GALL Report (e.g., Item I1.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.

L-11-166 Page 62 of 69 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 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.

RESPONSE RAI 3.5.2.3.12-1

1. Loss of material was not identified as an aging effect applicable for the Emergency Diesel Generator (EDG) Fuel Oil Tank (or Fuel Oil Storage Tank) Hold Down Restraints in a structural backfill environment. However, as indicated in LRA Table 3.5.2-12 Row 8, the Structures Monitoring Program will be used to confirm the absence of significant aging effects for the period of extended operation. The buried EDG Fuel Oil Tanks are supported by a reinforced concrete foundation and are covered with compacted material that qualifies as Seismic Category I structural backfill. The centerline of the horizontal buried tanks is located at elevation 584 feet, which is grade elevation. The structural backfill built around the storage tanks forms a truncated pyramid providing tornado missile protection above the tanks and extends eleven feet above grade elevation. The buried EDG Fuel Oil Tanks are restrained from uplift by the EDG Fuel Oil Tank Hold Down Restraints, which are wire ropes attached to embedded eye bolts. The lower portions of EDG Fuel Oil Tank Hold Down Restraints are in lean concrete fill, with part of the wire rope above the lean concrete fill, buried by structural backfill. The structural backfill is mostly above grade and the lowest elevation of the wire rope exposed to structural backfill is at elevation 582 feet, 10 inches International Great Lakes Datum. This lowest elevation is above the site's groundwater elevation (groundwater level ranges from elevation 570 to 575 feet International Great Lakes Datum), therefore the hold down restraints are not postulated to be in contact with groundwater.

Neither EPRI 1015078, the license renewal "Structural Tools," nor NUREG-1 801 lists a structural backfill environment for steel components. However, the Structural Tools does describe an industry study regarding corrosion of driven steel piles which documents that the type and amount of corrosion observed on steel pilings driven into undisturbed natural soil, regardless of the soil characteristics and properties, is not sufficient to significantly affect the strength of pilings as load bearing structures.

The examined test installations had pile depths of up to 136 feet and time of exposure varying from 7 to 50 years in a wide variety of soil conditions. A parallel

L-11-166 Page 63 of 69 conclusion can be drawn that degradation of the EDG Fuel Oil Tank Hold Down Restraints in a structural backfill environment would not be detrimental. A minimum of 4 feet 6 inches of structural backfill plus 6 inches of top soil provide cover for the wire rope and restraints.

2. The Structures Monitoring Program will monitor aging of components in structural backfill during opportunistic inspections. Existing procedural measures are in place when excavation work uncovers normally inaccessible below-grade concrete; inspections shall be performed as required by site-specific procedures. The Structures Monitoring Program procedure further enhanced this requirement as indicated in LRA Table A-I, Commitment 20 (LRA Page A-66), by specifying that, upon notification that a below-grade structural wall or other concrete structural component would become accessible through excavation, a follow-up action is initiated to the responsible engineer to inspect the exposed surfaces for age-related degradation. Such inspections will include concrete examination using acceptance criteria from NUREG-1801 XI.S6 Program, Element 6. Any degradation found exceeding the acceptance criteria will be trended and processed through the FENOC Corrective Action Program.

The EDG Fuel Oil Tanks Backfill is also within the scope of license renewal and is managed by the Structures Monitoring Program as indicated in LRA Table 3.5.2-12 Row 171 (LRA page 3.5-135). Degradation such as loss of form (e.g., erosion, slope stability) on the truncated pyramid backfill would cause appropriate corrective action to be taken under the Corrective Action Program. Corrective action may include reworking the structural backfill, rain water seepage monitoring, or other actions appropriate for the condition to ensure the backfill, the EDG Fuel Oil Tanks and foundation perform their intended functions.

Question 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.

L-11-166 Page 64 of 69 Explain how the Structures Monitoring Program will be utilized to manage loss of material during the period of extended operation.

RESPONSE RAI 3.5.2.3.12-2 The Structures Monitoring Program will monitor aging of components in structural backfill during opportunistic inspections. The Structures Monitoring Program also uses information from other aging management programs, such as the Buried Piping and Tank Inspections Program.

The wave protection dike corrugated pipe casings are assembled corrugated pipe casings that surround and protect buried conduit, electrical enclosures, Service Water System piping and pipe supports in the wave protection dike adjacent to and near the south wall of the Intake Structure. This category of structural components includes protective enclosures made from carbon steel plate that were installed as part of the same project. The wave protection dike piles are "H" Piles that are installed on both sides of the Service Water System pipe route near the Intake Structure for backfill stability in the wave protection dikes. The "H" Piles span from elevation 579 feet down to bedrock.

The Service Water System piping is subjected to the Buried Piping and Tank Inspections Program as indicated in LRA Table 3.3.2-26; therefore, inspections of the pipe casings and "H" piles can be accomplished during opportunistic inspections of the buried piping. The Structures Monitoring Program will be enhanced as indicated in existing LRA Table A-I, Commitment 20 (LRA Page A-66), by specifying that, upon notification that a below-grade structural wall or other concrete structural component will become accessible through excavation, a follow-up action is initiated to the responsible engineer to inspect the exposed surfaces for age-related degradation. Any degradation found exceeding the acceptance criteria will be trended and processed through the Corrective Action Program.

Question 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

L-11-166 Page 65 of 69 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.

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.

RESPONSE RAI 3.5.2.3.13-1 The Davis-Besse aging management review process did not include a review of in-room heat-up analyses for the identification of specific credited thermal insulation, but rather conservatively included all piping and mechanical equipment insulation for aging management review. The Davis-Besse specification for the installation of insulation ensures that insulation jacketing is properly installed to prevent water intrusion into the insulation.

The configuration of the installed jacketing is in accordance with the Davis-Besse specification for the installation of insulation. The specification lists installation requirements that prevent water from intruding into the insulation, as follows:

L-11-166 Page 66 of 69

" Aluminum jacketing for piping sizes up to 10 inches shall have a 2-inch overlap, and for piping over 10 inches in size, a 3-inch overlap is required.

• Longitudinal joints on horizontal runs of pipe shall be lapped downward with joint located approximately 45 degrees off the bottom to shed water. Joints in vertical runs of pipe shall have the upper section of jacket overlap the lower section.

• In cases where aluminum jacketing is used over fiberglass, the joints shall overlap.

" Aluminum jacketing for equipment shall have at least a 3 inch overlap.

" All openings through the jacketed finish shall be flashed watertight or caulked.

Wetting of insulation is not expected. However, as indicated in LRA Table 3.5.2-13, insulation jacketing is subject to aging management. The Structures Monitoring Program is credited to manage piping and mechanical equipment insulation jacketing. In addition, the Boric Acid Corrosion Program also manages insulation jacketing in areas that contain borated systems.

Section 3.6 Question RAI 3.6-1 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.

L-11-166 Page 67 of 69 RESPONSE RAI 3.6-1 The response to this RAI was provided by FENOC Letter dated May 5, 2011 (ADAMS Accession No. ML11131A073).

Question RAI 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 3.6.2.2 2 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 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.

RESPONSE RAI 3.6-2 The response to this RAI was provided by FENOC Letter dated May 5, 2011 (ADAMS Accession No. ML11131A073).

Question RAI 3.6-3 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

L-11-166 Page 68 of 69 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.

RESPONSE RAI 3.6-3 The response to this RAI was provided by FENOC Letter dated May 5, 2011 (ADAMS Accession No. ML11131A073).

Question RAI 3.6-4 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 appropriate elastomer AMP should include manual

L-11-166 Page 69 of 69 manipulation or an explanation of why manual manipulation of elastomers is unnecessary.

RESPONSE RAI 3.6-4 The cable bus enclosure assemblies do not have elastomer components. Cable buses are utilized to connect the bus tie transformers and the 4160 VAC essential switchgear buses. There are metallic flanges between the enclosure sections. The covers are ventilated. As shown in LRA Table 3.5.2-13, "Aging Management Review Results - Bulk Commodities," Row 50, "Electrical Cable Bus Ducts," aging effects for the cable bus enclosure assemblies, which includes associated support structures, will be managed by the Structures Monitoring Program.

Attachment 2 L-11-166 Reply to Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS), License Renewal Application, Batch 2 Section B.2.16 Page 1 of 18 Section B.2.16 Question RAI B.2.16-1 LRA Section B.2.16, "Fatigue Monitoring Program," states that it manages fatigue of select primary and secondary components, including the reactor vessel, reactor internals, pressurizer, and steam generators, by tracking thermal cycles as required by Technical Specification (TS) 5.5.5, "Component Cyclic or Transient Limit." LRA Section 4.3 states that the 14 original design transients for the RCS are found in USAR Table 5.1-8. Furthermore, the design cycles that are significant contributors to fatigue usage are included in the Fatigue Monitoring Program and are provided in LRA Table 4.3-1.

The staff reviewed the applicant's program implementation procedure for tracking transients during its on-site audit. After reviewing the applicant's procedure, TS 5.5.5, USAR Table 5.1-8, and LRA Table 4.3-1 the staff noted that various transients, descriptions, and cycle counts were not consistent with each other. In order to verify which transients are monitored and are fatigue-significant, the connection between the applicant's procedure, LRA Table 4.3-1, TS 5.5.5, and the USAR need to be consistent.

The staff noted that TS 5.5.5, Amendment 279 (Adams Accession No.

ML053110490), was titled "Allowable Operating Transient Cycles Program," which is not consistent with the title "Component Cyclic or Transient Limit" as described in LRA Section B.2.16. It is not clear to the staff which revision of TS 5.5.5 is currently in place.

The staff requests the following information:

1. Clarify and justify the discrepancies between the program implementation procedure, TS 5.5.5, USAR Table 5.1-8, and LRA Table 4.3-1 with respect to the transient descriptions, transients monitored, and all cycle limits. In lieu of a justification, amend the appropriate documents such that the transients being monitored by the Fatigue Monitoring Program and the transients used in the related fatigue time-limited aging analyses (TLAAs) are consistent (e.g., TS, USAR, LRA and program implementation procedure). Clarify if there are transients that require monitoring by TS 5.5.5 and USAR Section 5 that are not or will not be monitored by the Fatigue Monitoring Program. If these types of transients exist, justify why

L-1 1-166 Page 2 of 18 these transients do not need to be monitored currently and during the period of extended operation, as required by TS 5.5.5 and USAR Section 5.

Update USAR Section 5, as needed, to ensure that the basis for not monitoring these required transients is documented.

RESPONSE RAI B.2.16-1 FENOC conducted a review of the Allowable Operating Transient Cycles (AOTC)

Program, Section 5 of the Updated Safety Analysis Report (USAR) (including Table 5.1-8), the RCS Functional Specification and LRA Table 4.3-1 for consistency relative to transients, descriptions and cycle counts. The review identified several inconsistencies in the AOTC Program, USAR Table 5.1-8 and LRA Table 4.3-1 as compared to transients and descriptions provided in the Davis-Besse RCS Functional Specification; the RCS Functional Specification is the primary source of design transients for the Babcock and Wilcox (B&W)-supplied RCS components.

The 14 original Nuclear Steam Supply System (NSSS) design transients for the RCS are listed in USAR Table 5.1-8. Over the life of the plant, additional transients have been identified, including analyzed transients for new components, such that the RCS Functional Specification now consists of 25 transients. In addition, Table 5.1-8 contains estimated actual cycles that are not consistent with LRA Table 4.3-1. These estimated actual cycles are historical data. The proposed change to USAR Table 5.1-8 includes all transients listed in the RCS Functional Specification. For transients that will not be monitored, justification is provided in the footnotes to USAR Table 5.1-8. Proposed changes to USAR Table 5.1-8 are provided as follows:

USAR Table 5.1-8, Transient Cycles Design Life 1 No. Description (ASME Category) Design Cycles 1 Heatup from cold shutdown and cooldowns to cold shutdown 1A- Heatup from 70F to 8% Full Power (Normal)"2 240 1 B- Cooldown from 8% Full Power (Normal) 2,' 240 1C-Natural Circulation Cooldown (Emergency)3 '6 20 2 Power change 0 to 15% and 15% to 0% (Normal) 1,440 3 Power loading 8% to 100% power (Normal) 4 1,800 4 Power unloading 100% to 8% power (Normal) 4 1,800 5 10% Step Load Increase (Normal) 8,000 6 10% Step Load Decrease (Normal) 8,000 7 Step Load Reduction (100% to 8%) (Upset) 7A-Resulting from turbine trip 160 S7B-Resulting from electrical load reduction 150

L-11-166 Page 3 of 18 USAR Table 5.1-8, Transient Cycles Design Life 1 No. Description (ASME Category) Design Cycles 8 Reactor Trip (Upset) 8A-Low RC flow directly causes Rx trip (Upset) 40 8B-High RC outlet temperature, high RC pressure or overpower 160 trip-assumes a turbine trip occurs without automatic control system action. (Upset) 8C-High RC pressure resulting from loss of feedwater (Upset) 88 8D-Other trips, including the following (Upset): 112 (1) Any reactor trip which meets the definition of another transient classification (e.g., Transients 11, 15, 16, and 17) will also be recorded under 8D.

(2) Any reactor trip which does not fit into any other category will be classified 8D.

8E-Similar to 8A but RC pumps are tripped (emergency) 3' 6 20 9 Rapid Depressurizations 9A-Rapid RCS Depressurization (Upset) 40 9B-Rapid RCS Depressurization, trip RC Pumps (Emergency) 3'6 10 10 Change of reactor coolant flow (typical change of flow transient is 20 loss of one RCP) without Reactor Trip (Upset) 11 Rod withdrawal accident (Upset) 40 12 Hydrotests (Test) 12A-RCS Components Except OTSG Secondary (includes 5 20 shop tests) 12B-OTSG Secondary (includes 10 shop tests) 35 13 Deleted (formerly Steady State Power Variations) Not Applicable 14 Control Rod Drop (Upset) 40 15 Loss of Station Power (Upset) 40 16 Steam line failure (Faulted) 1 17 Steam generator boiling dry 17A-Loss of feedwater to one steam generator (Upset) 20 17B-Stuck open turbine bypass valve (Emergency)3 10 18 Loss of feedwater heater (Upset) 40 19 Feed and bleed operations (Normal) 4 4,000 20 Makeup and Pressurizer spray transients 20A-Makeup flow Transient 1 (Normal) 4 30,000 20B-Makeup flow Transient 2 (Normal) 4 4.OE+6 20C-Spray Valve/Pressurizer Spray Nozzle (Normal) 4 20,000 21 Loss of coolant accident (LOCA) (Faulted) 1 22 Test Transients 22A1-High pressure injection system (Normal) 12 40 22A2-HPI System Pressure Isolation Integrity Test 13 (Nozzles 1-1 and 1-2) 40 (Nozzles 2-1 and 2-2) 22B-Core flooding check valve (Normal) 240

L-11-166 Page 4 of 18 USAR Table 5.1-8, Transient Cycles Design Life1 No. Description (ASME Category) Design Cycles 23 Steam generator filling, draining, flushing and cleaning (Normal) 23A-Steam generator secondary side filling Condition 11,11 120 Condition 2811 120 23B-Steam generator primary side filling Condition 1 9 ," 120 Condition 2 1o, 11 120 23C-Steam generator flush" 40 23D-Steam generator chemical cleaning"1 20 24 Hot functional testing (Normal) 1 25 Decay Heat Removal Swapping Transient13 20 Footnotes:

1. Table 5.1-8 includes thermal design cycles only. Component design calculations also consider mechanical loads including 650 cycles of the maximum probable earthquake (also known as, Operational Basis Earthquake (OBE)); the reactor cavity seal plate is designed for 50 OBE cycles.

2. Reactor cavity seal plate limited to 50 Heatup (HU)/Cooldown (CD) cycles. For once-through steam generator (OTSG) welded plugs, the limiting plug is analyzed using 33 HU/CD cycles.

3. ASME Classification is Emergency and is not required to be considered for calculation of peak stress and cumulative usage (ASME III, NB-3224.4).

4. Transient cycles not counted due to large number of design cycles.

5. Auxiliary feedwater bolted nozzles are limited to 875 transient cycles (An RCS heatup and cooldown is considered to be one transient cycle. Bolting/unbolting of the nozzles is considered to be one transient cycle. Also, an event or procedure that initiates auxiliary feedwater to the steam generator is analyzed for a transient cycle.).

6. For reactor vessel head vent line only.

7. Primary side: -5200*F, 0 - 485 psig; Secondary side: M140 *F, 0 psig; Feedwater: 50 - 225 *F

8. Primary side: -5120 °F, 0 - 485 psig; Secondary side: ->60 F, 0 psig; Feedwater: 50 - 225 *F

9. Primary fill water: 50 *F, 0 psig; Secondary side: 140 °F, 0 psig

10. Primary fill water: 140 °F, 0 psig; Secondary side: 50 'F, 0 psig

11. 11 .Transient is not counted as it is not a fatigue significant event.

12. Transient is not applicable to Davis-Besse. High pressure injection pumps recirculate back to the Borated Water Storage Tank during the High Pressure Injection System Test; therefore, no inventory is added to the Reactor Coolant System.

13. The significant transients which affect the restrictor and weld of the core flood nozzles are heatup and cooldown (transient numbers 1A and 1B), core flooding system periodic test (transient number 22B), and decay heat removal (DHR) swapping (transient number 25). For transient number 25, the transient cycles are not counted. The DHR Swapping Transient was established to address historical practices related to the DHR train swap. Current Davis-Besse procedures dictate that the RCPs are run during plant cooldown to approximately 160OF RCS temperature. The DHR trains are not swapped until the RCS temperature has been significantly reduced and therefore, a DHR Swapping Transient does not occur.

L-11-166 Page 5 of 18 LRA Table 4.3-1 is revised to include transient numbers 1C, 8C, 9A, 9B and 25 (AOTC Program Transient 33). Previous listed transients 9A through 9D are renamed as the HPI System Pressure Isolation Integrity Tests, and are now grouped under transient number 22 A2 (HPI Nozzles 1-1, 1-2, 2-1 and 2-2). The Rapid RCS Depressurization (Upset) event is now monitored as transient 9A, and the Rapid RCS Depressurization, trip RCS Pumps (Emergency) event is now monitored as transient 9B. LRA Table 4.3-1 is further revised to provide clarification and align transient descriptions with the RCS Functional Specification and the AOTC Program.

LRA Sections A.1.16 and B.2.16, both titled "Fatigue Monitoring Program," are revised to show the title of Davis-Besse Technical Specifications Section 5.5.5 as "Allowable Operating Transient Cycles Program."

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI B.2.16-2 The "scope of program" program element of GALL (NUREG 1801, Rev. 2)

AMP X.M1 recommends that the program should include, for a set of sample reactor coolant system components, fatigue usage calculations that consider the effects of the reactor water environment. This sample set should include the locations identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they may be more limiting than those considered in NUREG/CR-6260.

During its audit and review of LRA Section B.2.16, "Fatigue Monitoring Program,"

and supporting program basis documents, the staff did not find any identification of additional component locations other than those from NUREG/CR-6260, or a confirmation that the NUREG/CR-6260 locations were bounding for the applicant's site. 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. This may include locations that are limiting or bounding for a particular plant-specific configuration, or that have calculated cumulative usage factor (CUF) values that are greater when compared to the locations identified in NUREGICR-6260.

The staff requests the following information:

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

L-1 1-166 Page 6 of 18

2. Confirm and justify that the locations selected for environmentally assisted fatigue analyses in LRA Table 4.3-2 consists of the most limiting locations for the plant (beyond the generic components 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. If the identified limiting location consists of nickel alloy, state whether the methodology used to perform the environmentally-assisted fatigue calculation for nickel alloy is consistent with NUREG/CR-6909. If not, justify the method chosen.

RESPONSE RAI B.2.16-2

1. The locations listed in LRA Table 4.3-2 are consistent with NUREG/CR-6260 generic limiting locations evaluated in Section 5.3 of NUREG/CR-6260 for B&W plants. With respect to limiting locations, NUREG/CR-6260, Section 4.1, states that, for both pressurized water reactor (PWR) and boiling water reactor (BWR) plants, these components are not necessarily the locations with the highest design cumulative usage factors (CUFs) in the plant, but were chosen to give a representative overview of components that had higher CUFs and/or were important from a risk perspective. For example, the reactor vessel shell (and lower head) was chosen for its risk importance.

As discussed in the closeout of GSI-190, "Fatigue Evaluation of Metal Components for 60-year Plant Life," the Pacific Northwest National Laboratory (PNNL) performed calculations of the probability of component failure and the Core Damage Frequency (CDF) associated with these failures. PNNL performed probabilistic fatigue calculations on 47 sample components from six locations in five PWR and two BWR plants using the pc-PRAISE code. PNNL made use of the previous and most recent testing performed to develop fatigue design curves in simulated light water reactor environmental conditions. The results of the probabilistic analyses, along with the sensitivity studies performed, the interactions with the industry (NEI and EPRI), and the different approaches available to the licensees to manage the effects of aging, lead to the conclusion that no generic regulatory action was required for operation to 40 years. This conclusion was based primarily on the negligible calculated increases in CDF in going from 40-year to 60-year lives. However, the calculations supporting resolution of this issue, which included consideration of environmental effects and the nature of age-related degradation indicated the potential for an increase in the frequency of pipe leaks as plants continue to operate. Therefore, environmentally-assisted fatigue (EAF) is required to be evaluated for license renewal in accordance with Section 4.3.1 of NUREG-1800.

The locations evaluated in Section 4.3.4 of the Davis-Besse LRA are consistent with the locations evaluated in NUREG/CR-6260, which was used to support the close-out of GSI 190. GSI-190 closeout focused on piping and not on thick-walled vessels.

L- 11-166 Page 7 of 18 Consistent with NUREG/CR-6260, Davis-Besse evaluated the pressurizer surge line piping for environmental effects. Due to the temperature differential between the pressurizer and hot leg and associated thermal stratification, the pressurizer surge line is the most fatigue-sensitive piping in the reactor coolant system during normal operation. The main coolant large bore piping (28-inch and 36-inch) are not subject to thermal stratification. Ancillary system piping attached to RCS large bore piping and to RCS components are typically stagnant during normal operation with the exception of RCS letdown and makeup and the continuous vent line (CVL). The makeup and letdown and CVL see continuous flow and are not subject to thermal stratification during normal operation. Therefore, by evaluating the pressurizer surge line, Davis-Besse has evaluated the most limiting piping location relative to EAF for the period of extended operation.

2. As discussed in the response to question 1 above, FENOC evaluated the generic limiting locations provided in NUREG/CR-6260 and provided the results in LRA Table 4.3-2. Following submittal, FENOC compiled a listing of all design CUFs multiplied by a maximum environmentally-assisted fatigue correction factor (Fen) to obtain a list of bounding EAF CUF values. Bounding EAF CUF values were obtained by multiplying design CUFs by the following bounding Fen for a PWR reactor coolant environment.

" Low Alloy Steel (LAS): Fen max of 2.54 based on NUREG/CR-6583

" Carbon Steel (CS): Fen max of 1.74 based on NUREG/CR-6583

" Stainless Steel (SS): Fen max of 15.35 based on NUREG/CR-5704

• Nickel-Based Alloy (NBA): Fen max of 4.52. applied to new design curve from NUREG/CR-6909 A summary of RCS pressure boundary locations with EAF CUF values greater than 1.0 that are not evaluated as NUREG/CR-6260 locations in the LRA are provided by material type below.

Low Alloy Steel Locations (Fen max of 2.54 based on NUREG/CR-6583)

• Steam Generator Primary Inlet Nozzle (nozzle to upper head weld)

Carbon Steel Locations (Fen max of 1.74 based on NUREG/CR-6583)

" Steam Generator (SG) Primary Outlet Nozzles

" Hot leg piping (reactor vessel outlet Node 111 and surge line area Node 71)

" Decay heat nozzle Stainless Steel (Fen max of 15.35 based on NUREG/CR-5704)

" Control rod drive mechanism (CRDM) Housing (flanges and vent line flange)

" Reactor Coolant (RC) pump cover (cooling hole ligament and bearing cavity)

L-11-166 Page 8 of 18 0 Pressurizer spray nozzle internal pipe

• Pressurizer heater bundle closure (diaphragm plate and seal weld)

• Pressurizer spray line (valve inlet, valve outlet, near pressurizer) a RC drain line 0 RC letdown line

• High pressure injection lines

• Core flood lines

• Pressurizer safety/relief valve line a RC Loop 1 cold leg drain line weld overlay repair 0 Continuous vent line Nickel-Based Alloy Locations (Fen max of 4.52 applied to new design curve from NUREG/CR-6909).

" SG Primary Remote Tube Plug

" RC drain line weld overlay repair As stated above, FENOC performed a review of design basis ASME Code Class 1 fatigue evaluations to determine locations where bounding EAF CUFs exceed 1.0 that were not evaluated for EAF in the LRA. Based on this review, FENOC identified additional locations that require further evaluation for environmental effects.

Therefore, LRA Sections A. 1.16 and B.2.16, and Table A-1 are revised to include an enhancement and corresponding license renewal future commitment in the Fatigue Monitoring Program as follows:

Evaluate additional plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than those considered in NUREG/CR-6260. This evaluation will include identification of the most limiting fatigue location exposed to reactor coolant for each material type (i.e., CS, LAS, SS, and NBA) and that each bounding material/location will be evaluated for the effects of the reactor coolant environment on fatigue usage. Nickel based alloy items will be evaluated using NUREG/CR-6909. This evaluation will be submitted to the NRC one year prior to the period of extended operation.

See the Enclosure to this letter for the revision to the DBNPS LRA.

L-11-166 Page 9 of 18 Question RAI B.2.16-3 LRA Section B.2.16, "Fatigue Monitoring Program," states that it uses the systematic counting of plant transient cycles to ensure that the design cycles are not exceeded, thereby ensuring that component fatigue usage limits are not exceeded. The acceptance criterion is to maintain the number of counted transient cycles below the design cycles for each transient.

The preventive actions" program element of GALL (NUREG 1801, Rev. 2)

AMP X.M1 recommends the program to ensure that the fatigue usage does not exceed the Code design limit of 1.0. The number of actual plant transients exceeding the numbers used in the fatigue analyses or the actual transient severity exceeding the bounds of the design transient definitions can cause the fatigue usage to exceed the Code design limit.

The "detection of aging effects" program element of GALL (NUREG 1801, Rev. 2)

AMP X.M1 recommends that the fatigue monitoring program provide for periodic updates of the fatigue usage calculations, on as-needed basis, if an allowable cycle limit is approached. The staff noted that this ensures that the fatigue usage calculations remain valid and the Code design limit is not exceeded.

Based on the applicant's description of the Fatigue Monitoring Program, it only keeps track of cycle counts; therefore, it is not clear to the staff how the applicant's program confirms that the severity of actual transients is bounded by the severity assumed in the design analysis. Also, it is not clear how the program accounts for any differences in the number of "design cycles," as listed in LRA Table 4.3-1, and the number of cycles that were used in a fatigue analyses.

During its audit, the staff noted that the applicant's plant procedure, implementing the Fatigue Monitoring Program, describes that, when the count for a transient reaches a certain fraction of the corresponding "design cycles,"

Design Engineering is contacted for re-evaluation of the allowed cycles. However, the specific actions that would be taken, and in what timeframe, with regard to the updating of allowable cycles, or an alternate course of action, were not discussed. There may be a potential for exceeding the number of cycles used in the analysis if they are less than the "design cycles" listed in LRA Table 4.3-1.

The staff requests the following information:

1. Provide the details and basis for the process used to verify that the severity of an actual transient is bound by the severity of the design transient. If this process is not in place, justify how the actual severity of a transient is confirmed to be bounded by the design severity, to ensure that the fatigue analysis remains valid.

L-11-166 Page 10 of 18

2. Confirm that the severity of all transients that have occurred to date, since initial plant operation, have been bounded by the design severity. If there have been instances where the actual severity exceeded the design severity, discuss the actions taken to assure that the Code design limit has not been exceeded and that the fatigue analysis remains valid.

3. Confirm that the "design cycles" monitored by the Fatigue Monitoring Program," are in fact the ones used in the fatigue analysis. If not, justify why the "design cycles" listed in LRA Table 4.3-1 are monitored by the Fatigue Monitoring Program, to ensure that the fatigue usage limit is not exceeded in a given analysis.

4. Clarify the actions or measures taken as part of the Fatigue Monitoring Program if the actual transient severity exceeds the design severity and if the actual cycle count approaches or exceeds the number of cycles used in the analysis.

RESPONSE RAI B.2.16-3

1. The RCS components are designed to withstand the operating transients as defined (i.e., maximum rates of change of temperatures, pressures, flows, etc.) in the Davis-Besse RCS Functional Specification. The Fatigue Monitoring Program, which is consistent with the RCS Functional Specification, counts the actual number of transient cycles. In determining a transient classification, operational data is compared to the event data as defined in the RCS Functional Specification.

2. As provided above, the RCS components are designed to withstand the operating transients as defined (i.e., maximum rates of change of temperatures, pressures, flows, etc.) in the Davis-Besse RCS Functional Specification. NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification," required the re-evaluation of the cyclic fatigue of the Pressurizer Surge Line. Topical Report BAW 2127 and its Supplements describe the results of the revised evaluation. As part of this evaluation (Supplement 3 to BAW-2127) the Davis-Besse heatup and cooldown transients were redefined. Other transients were modified to include thermal stratification and striping. In addition to these changes, a number of transients were added and other modifications were made to the existing transients based on a review of the plant operating history and operating procedures.

3. The 14 original design transients for the RCS are found in USAR Table 5.1-8. Over the life of the plant, additional transients have been identified, including analyzed transients for new components. The design cycles that are significant contributors to fatigue usage are included in the Fatigue Monitoring Program and are provided in Table 4.3-1. As provided in the response to RAI B.2.16-1, above, FENOC conducted a review of the AOTC Program, Section 5 of the USAR (including

L-11-166 Page 11 of 18 Table 5.1-8), the RCS Functional Specification and LRA Table 4.3-1 for consistency relative to transients, descriptions and cycle counts. The review identified several inconsistencies in the AOTC Program, USAR Table 5.1-8 and LRA Table 4.3-1 as compared to transients and descriptions provided in the RCS Functional Specification, which is the primary source of design transients for the B&W-supplied RCS components. Included with the response to RAI B.2.16-1 is an updated LRA Table 4.3-1.

4. The RCS components are designed to withstand the operating transients as defined (i.e., maximum rates of change of temperatures, pressures, flows, etc.) in the Davis-Besse RCS Functional Specification. The Fatigue Monitoring Program, which is consistent with the RCS Functional Specification, counts the actual number of transient cycles. In determining a transient classification, operational data is compared to the event data as defined in the RCS Functional Specification.

However, clarification is needed relative to actions taken if an allowable cycle limit is approached. Therefore, LRA Table A-I, Commitment 9, and Section B.2.16 are revised to provide an enhancement to the Fatigue Monitoring Program as follows:

Provide for updates of the fatigue usage calculations on an as-needed basis if an allowable cycle limit is approached. When the number of accrued cycles is within 75% of the allowable cycle limit for any transient, a condition report will be generated. For any transient whose cycles are projected to exceed the allowable cycle limit by the end of the next plant operating cycle (Davis-Besse operating cycles are normally two years in duration), the program will require an update of the fatigue usage calculation for the affected component(s).

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI B.2.16-4 LRA Section B.2.16, "Fatigue Monitoring Program," proposes an enhancement to the "preventive action" program element which states that for locations, including NUREG/CR-6260 locations, projected to exceed a CUF of 1.0, the program may implement an option that will "manage the effects of aging due to fatigue at the affected locations by an inspection program that will be reviewed and approved by the Nuclear Regulatory Commission (NRC) (e.g., periodic non-destructive examination of the affected locations at inspection intervals to be determined by a method acceptable to the NRC)."

The objective of GALL AMP X.M1 is to ensure that the fatigue usage does not exceed the Code design limit during period of extended operation. It is not clear to the staff how the proposed option of managing the aging due to fatigue by an

L-11-166 Page 12 of 18 inspection program is consistent with the objective in GALL AMP X.M1, to prevent cumulative fatigue usage from exceeding the Code design limit.

Furthermore, the enhancement implies that it encompasses all locations, including the NUREG/CR-6260 specific locations. However, during its audit, the staff noted that this enhancement may only be applicable to the NUREG/CR-6260 specific locations.

The staff requests the following information:

1. Provide the basis for using an inspection program, as an option, to manage fatigue usage for during period of extended operation.

2. Clarify how the use of an inspection program is consistent with the objective of GALL AMP X.M1, to maintain fatigue usage below the Code design limit. Clarify how the use of this option will be used as a preventative action and how this is consistent with the "preventive action" program element. Clarify if the options described in the enhancement are meant to be corrective actions if the Fatigue Monitoring Program provides indications that the CUF may exceed 1.0.

3. Clarify if the options described in this enhancement are applicable only for the NUREG/CR-6260 locations, and, if so, specify and justify the actions taken if the CUF exceeds 1.0 for all other locations.

RESPONSE RAI B.2.16-4 In lieu of responding to the individual subcomponents of the RAI, LRA Table A-i, Commitment 9, and Section B.2.16 are revised to delete the subject enhancement, and to include the following enhancement:

Establish an acceptance criterion for maintaining the cumulative fatigue usage below the Code design limit of 1.0 through the period of extended operation, including environmental effects where applicable.

In addition, LRA Sections A. 1.16 and B.2.16 are revised to provide clarification that the Fatigue Monitoring Program prevents the fatigue TLAAs from becoming invalid by assuring that the fatigue usage resulting from actual operational transients does not exceed the Code design limit of 1.0, including environmental effects where applicable.

See the Enclosure to this letter for the revision to the DBNPS LRA.

L-11-166 Page 13 of 18 Question RAI B.2.16-5 LRA AMP B.2.16, "Fatigue Monitoring Program," includes an enhancement to the "parameters monitored and inspected" program element of GALL AMP X.M1 which states "The Fatigue Monitoring Program will be enhanced to monitor any transient where the 60-year projected cycles were used in an environmentally-assisted fatigue evaluation and to establish an administrative limit that is equal to or less than the 60-year projected cycles."

The need for the first part of this enhancement is not clear to the staff since consistency with the GALL AMP X.M1 ensures monitoring of all plant transients that are fatigue-significant and not just those transients where the 60-year projected cycles were used in an environmentally-assisted fatigue evaluation.

The second part of this enhancement deals with establishing an administrative limit and it is not clear to the staff why such a limit is to be established only for those transients used in the environmentally-assisted fatigue evaluations. Also, establishing a limit solely on the 60-year projected cycles, without referencing the CUF value, may not ensure that the acceptance criterion for CUF will be met through the period of extended operation. In particular, if the environmental or transient strain rate conditions are adversely exceeded for some duration, and/or the actual cycles analyzed are less than the design limit cycles.

The staff requests the following information:

1. Clarify if monitoring any transient that was used in an environmentally assisted fatigue evaluation with 60-year projected cycles should be an enhancement to GALL AMP X.M1, which recommends monitoring all transients that are significant contributors to fatigue usage.

2. Justify why establishing the administrative limit only for those transients used in an environmentally assisted fatigue evaluation is adequate to ensure that the acceptance criterion for CUF will be met through the period of extended operation.

3. Justify why establishing the administrative limit solely on the basis of 60-year projected cycles, without reference to the actual analyzed cycles and the CUF value/estimation that may be affected by possible adverse environmental or strain rate conditions, is sufficient to ensure that the acceptance criterion for CUF will be met through the period of extended operation, consistent with the GALL AMP X.MI.

L-11-166 Page 14 of 18 RESPONSE RAI B.2.16-5 In lieu of responding to the individual subcomponents of the RAI, LRA Table A-i, Commitment 9, and Section B.2.16 are revised to delete the subject enhancement, and to include the following enhancement:

Establish an acceptance criterion for maintaining the cumulative fatigue usage below the Code design limit of 1.0 through the period of extended operation, including environmental effects where applicable.

In addition, LRA Sections A.1.16 and B.2.16 are revised to provide clarification that the Fatigue Monitoring Program prevents the fatigue TLAAs from becoming invalid by assuring that the fatigue usage resulting from actual operational transients does not exceed the Code design limit of 1.0, including environmental effects where applicable.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI B.2.16-6 LRA Section B.2.16, "Fatigue Monitoring Program," discusses the operating experience associated with fatigue issues focusing, primarily, on industry initiatives and NRC/vendor information that caused the applicant to assess thermal stratification of the pressurizer surge line which resulted in changes to the fatigue analyses of record and to the cycles being counted under its Fatigue Monitoring Program.

During its audit, the staff reviewed the applicant's operating experience and condition reports and noted that in-service fatigue issues had occurred, such as thermal sleeve cracking and welded plug cracking, that were identified by the existing program. The staff noted that LRA Section B.2.16 did not discuss these in-service fatigue issues, the corrective actions taken and how the existing Fatigue Monitoring Program was modified based on the operating experience.

Justify the effectiveness of the existing Fatigue Monitoring Program with examples and sufficient details from plant-specific experience to demonstrate that timely identification of observed fatigue degradation was achieved, and the corrective actions taken to prevent the recurrence of such failures. Discuss any improvements that were incorporated into the Fatigue Monitoring Program based on this plant-specific experience.

RESPONSE RAI B.2.16-6 LRA Section B.2.16 is revised to include additional plant-specific operating experience in the operating experience program element for the Fatigue Monitoring Program. The

L-1 1-166 Page 15 of 18 operating experience is associated with the High Pressure Injection Nozzles, the Steam Generator welded plugs and the Pressurizer Surge Line.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Question RAI B.2.16-7 LRA Sections 4.7.1.1, 4.7.4, 4.7.5.1, and 4.7.5.2 credit the applicant's Fatigue Monitoring Program to manage the aging effects associated with the TLAA. In accordance with 10 CFR 54.21 (c)(1)(iii), the effects of aging on the intended functions will be adequately managed for the period of extended operation.

LRA Section B.2.16 states:

The Fatigue Monitoring Program is an existing program that, with enhancement, will be consistent with the 10 elements of an effective aging management program as described in NUREG-1801,Section X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."

The applicant includes the aforementioned enhancement in Commitment No.9, which is associated with the applicant's cycle counting activities, action limits and corrective actions for those components that are included in the applicant's cumulative usage factor (CUF) calculations. The applicant's UFSAR Supplement for the Fatigue Monitoring Program in LRA Section A.1.16 is also associated with the program's cycle counting activities for design basis CUFs and the environmentally-adjusted CUFs.

The staff noted that the applicant's Fatigue Monitoring Program is based on GALL AMP X.M1, which is limited to the use of cycle counting for CUF analyses (e.g. ASME Code Section III CUF analyses and environmentally-assisted CUF analyses). The use of cycle counting to manage flaw growth of either a postulated or existing macro flaw is not covered by GALL AMP X.MI.

The applicant has expanded its Fatigue Monitoring Program to use cycle counting for fatigue flaw growth analyses (described in LRA Sections 4.7.1, 4.7.4, 4.7.5.1, and 4.7.5.2) without the inclusion of enhancements to the applicable program elements (e.g. "scope of program," "parameters monitored or inspected," "monitoring and trending," "acceptance criteria," or "corrective action"). These enhancements should provide justification for all cycle counting design transients thatwere assumed in these fatigue flaw growth or cycle dependent flaw tolerance analyses.

L-11-166 Page 16 of 18 It is not clear to the staff if the applicant's basis for cycle counting design transients has been captured in the applicable documents (e.g. Technical Specification, UFSAR. and cycle counting procedure) describing the management of fatigue flaw growth during the period of extended operation. In addition, LRA Section A.1.16 does not currently discuss the use of cycle counting for these fatigue flaw growth or cycle dependent flaw tolerance analyses in LRA Sections 4.7.1, 4.7.4, 4.7.5.1, and 4.7.5.2.

The staff requests the following information:

1. Clarify all fatigue flaw growth, cycle-dependent flaw tolerance or fracture mechanics TLAAs that are dispositioned in accordance with 10 CFR 54.21 (c)(1)(iii) and credit the Fatigue Monitoring Program. For each identified analysis: (a) provide the reference in the CLB that forms the basis for the analysis; and (b) identify the transients that were assumed and, for each transient, provide the assumed cumulative number of cycles.

2. Justify the use of cycle counting, as described in the Fatigue Monitoring Program. for the analyses identified in request (1) and dispositioning the associated TLAA in accordance with 10 CFR 54.21(c)(1)(iii) without: (a) an update to the applicable documents (e.g. Technical Specification, UFSAR, and cycle counting procedure). and (b) the inclusion of enhancements to the applicable program elements (e.g. "scope of program," "parameters monitored or inspected," "monitoring and trending," "acceptance criteria,"

or 'corrective action").

If enhancements and applicable commitments in LRA Appendix A are necessary, provide the following for each analysis: (a) justification for the use of cycle counting activities, (b) definition of the transients that need to be monitored when implementing cycle counting of design transients that were assumed, (c) action limits associated with the assumed transients, and (d) corrective action(s) that will be taken if an action limit is reached.

(c) Justify why LRA Section A.1.16 does not include a summary description on the use of the Fatigue Monitoring Program's cycle counting activities for the design transients that were assumed in the fatigue flaw growth or cycle dependent flaw tolerance analyses described in the LRA Section 4.

RESPONSE RAI B.2.16-7

1. The only flaw growth or fracture mechanics TLAA that credit the Fatigue Monitoring Program (cycle counting) for managing the TLAA in accordance with 10 CFR 54.21 (c)(1)(iii) are those described in LRA Section 4.7 (leak before break, high pressure injection thermal sleeves, steam generator flaw evaluation). Rather

L-11-166 Page 17 of 18 than extend the Fatigue Monitoring Program to cover non-CUF analyses, FENOC revises the disposition of the TLAAs in LRA Sections 4.7.1.1, 4.7.4., and 4.7.5.2 to eliminate reliance on management by the Fatigue Monitoring Program. LRA Section 4.7.5.1 does not contain a flaw growth TLAA. Each TLAA disposition is discussed separately below.

4.7.1.1, Leak before break By letter dated April 20, 2011 (ADAMS Accesssion number ML11112A078), FENOC revised the disposition of the Leak Before Break (LBB) analyses from 10 CFR 54.21(c)(1)(iii) to 10 CFR 54.21(c)(1)(i) in Response to RAI 4.7.1.1-4.

4.7.4, HPI nozzle thermal sleeves FENOC will replace all four Davis-Besse makeup nozzle thermal sleeves prior to the period of extended operation. The commitment to replace these thermal sleeves is found in LRA Table A-i, Commitment 23. Based on this commitment, the makeup nozzle thermal sleeves are short-lived (not 40-year) components; therefore, this analysis is not a TLAA. LRA Table 4.1-1, "Time-Limited Aging Analyses," is revised to show the disposition as "Not a TLAA."

4.7.5.1, RCS cold leg drain flaw As provided in LRA Section 4.7.5.1, the overlay repair is designed as a full structural overlay that assumes the as-found flaw propagates to a 100 percent through-wall 360-degree crack rather than performing a crack growth analysis of the as-found flaw. Thus, there is no time dependency in the weld overlay design relative to the crack growth analysis.

In LRA Section 4.7.5.1, only the weld overlay fatigue analysis is a TLAA. Therefore, no change to the LRA is required.

4.7.5.2, OTSG flaw As provided in LRA Section 4.7.5.2, the simplified evaluation of fatigue crack growth was based on 240 heatup and cooldown cycles. As shown in LRA Table 4.3-1, the 60-year projected cycles for heatup and cooldown is 128, and is bounded by the analyzed number of 240 cycles. Therefore, the analysis of the OTSG flaw growth will remain valid through the period of extended operation. LRA Table 4.1-1 is revised to show the analysis of steam generator flaw growth will remain valid through the period of extended operation, and the TLAA disposition as 10 CFR 54.21 (c)(1)(i).

2. With the changes defined above, the Fatigue Monitoring Program is no longer used to manage TLAA associated with non-CUF analyses, and therefore no justification is required for using the program for this purpose.

Attachment 2 L-11-166 Page 18 of 18 (c) As the Fatigue Monitoring Program is no longer used to manage non-CUF analyses, no change to LRA Sections A.1.16 or B.2.16 are required.

See the Enclosure to this letter for the revision to the DBNPS LRA.

Enclosure Davis-Besse Nuclear Power Station, Unit No. 1 (DBNPS)

Letter L-11-166 Amendment No. 8 to the DBNPS License Renewal Application Page 1 of 116 License Renewal Application Sections Affected Section 3.1 Table 3.3.2-10 Section 4 Table 3.1.2-1 Table 3.3.2-12 Table 4.1-1 Table 3.1.2-3 Table 3.3.2-13 Section 4.3.1.2 Table 3.1.2 P-S Notes Table 3.3.2-14 Table 4.3-1 Table 3.3.2-15 Section 4.7.4 Section 3.2 Table 3.3.2-16 Section 4.7.5.2 Section 3.2.2.2.6 Table 3.3.2-18 Table 3.2.1 Table 3.3.2-21 Appendix A Table 3.2.2-1 Table 3.3.2-24 Section A. 1 Table 3.2.2-4 Table 3.3.2-25 Section A.1.15 Table 3.2.2 P-S Notes Table 3.3.2-28 Section A.1.16 Table 3.3.2-30 Section A.1.26 Section 3.3 Table 3.3.2-32 Section A.1.36 Section 3.3.2.1.12 Table 3.3.2 P-S Notes Section A. 1.41 Section 3.3.2.1.14 Section A.2.6.2 Section 3.3.2.1.32 Section 3.4 Section A.2.7.4 Section 3.3.2.2.13 Table 3.4.2-1 Table A-1 Section 3.3.2.2.4.1 Table 3.4.2-3 Section 3.3.2.2.7.1 Table 3.4.2-4 Appendix B Table 3.3.1 Table 3.4.2 P-S Notes Section B.2.9 Table 3.3.2-1 Section B.2.15 Table 3.3.2-3 Section 3.5 Section B.2.16 Table 3.3.2-6 Table 3.5.2-1 Section B.2.26 Table 3.3.2-8 Table 3.5.2-2 Section B.2.30 Table 3.3.2-9 Table 3.5.2-3 Section B.2.36 Section B.2.41 The Enclosure identifies the change to the License Renewal Application (LRA) by Affected LRA Section, LRA Page No., and Affected Paragraph and Sentence. The count for the affected paragraph, sentence, bullet, etc., starts at the beginning of the affected Section or at the top of the affected page, as appropriate. Below each section the reason for the change is identified, and the sentence affected is printed in italics with deleted text fined '-t and added text underlined.

Enclosure L-11-166 Page 2 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.1.2-1 Page 3.1-59 Row 99 Based on the response to RAI 3.1.2.1.58-1, to add a plant specific note pointing to the Nickel-Alloy Reactor Vessel Closure Head Nozzle Program for the upper reactor vessel head external surface, Row 99 of Table 3.1.2-1 is revised to read:

Table 3.1.2-1 Aging Management Review Results - Reactor Pressure Vessel Row Component Intended Aging Effect Aging NUREG-Row Componen Fntendd Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Ai Maaemn ihManagement Prora Program 12 Volume Item _

Item

_

Steel w. Arwt 99 Upper Head Pressure SS borated water Loss of Boric Acid IV.A2-13 3.1.1-58 A (Dome) boundary i leakage material Corrosion 0113 Cladding (a (External) I I

Enclosure L-11-166 Page 3 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.1.2-3 Page 3.1-146 Row 164 Based on the response to RAI 3.1.2.2.1-1, Row No. 164 of Table 3.1.2-3 is revised to read:

Table 3.1.2-3 Aging Management Review Results - Reactor Coolant System and Reactor Coolant Pressure Boundary IAging Effect NUREG-Row Component Intended Material Environment Requiring Aging Management 1801, Table I Notes No. Type Function(s) Management Program Volume Item 2 Item 1SU64 wi A r-k t 164 Plate SUppe,,4 Stee/ imWnf

-her-ted-,,t *,kig

.G M i,4 0, 11 leakage Not used.

Enclosure L-11-166 Page 4 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.1.2 Page 3.1-187 New Plant-Specific Note 0113 Plant-Specific Notes In response to RAI 3.1.2.1.58-1, to add a plant-specific note pointing to the Nickel-Alloy Reactor Vessel Closure Head Nozzle Program for the upper reactor vessel head external surface, new Plant-Specific Note No. 0113 is added to Table 3.1.2 "Plant-Specific Notes" as follows:

Plant-Specific Notes:

0113 1 See the Nickel-Alloy Reactor Vessel Closure Head Nozzle Programfor activities associated with ASME Code Case N-729-1.

Enclosure L-11-166 Page 5 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.2.2.2.6 Page 3.2-10 First paragraph In response to RAI 3.2.2.2.6-1, the first paragraph of Section 3.2.2.2.6 is revised to read:

Loss of material due to erosion could occur in the stainless steel high pressure safety injection pump miniflow recirculation orifice exposed to treated borated water. At Davis-Besse, the safety-related high pressure injection pump is not used for normal charging and is normally in standby. Therefore, the a-ging effect of loss of materialdue to erosion is not applicable to the stainless steel hiqh pressure safety iniection pump miniflow recirculationorifice exposed to treated water. Noma! chaging p.o.ided Ws by the .nnSaf9ty related makeup pump..LoG86 of ateialdu toeroioninthe makeup pum~p mqiniflow ecirculation orifcs; for-the high pressuroe 4niection PUMP miniflow recirculation oifice, thatar expose,9ed totre9ated hPora;;ted wa4ter-is managed by the PW'R Water- chemi'StrY Pro~gram through period-ic MonQitoGig an-d ruontrol -ofwonta~minants.

Enclosure L-11-166 Page 6 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.2.1 Page 3.2-20 Item 3.2.1-12, "Discussion" column Text in "Discussion" column is revised based on the response to RAI 3.2.2.2.6-1. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary System Evaluated in Chapter VII of NUREG-1 801," is revised to read:

Table 3.2.1 Summary of Aging Management Programs for Engineered Safety Features Systems Evaluated in Chapter Vill of NUREG-1801 Item Aging Aging Management EaFurther Number Component/Commodity 3.2.1-12 Stainless steel high-pressure I

Effect/Mechanism Programs Loss of material due A plant-specific aging Evaluation Recommended Yes, plant Discussion Not applicable.

safety injection (charging) pump to erosion management program is specific At Davis-Besse, the high miniflow orifice exposed to to be evaluated for pressure injection pump is not treated borated water erosion of the orifice due used for normal chargingand is to extended use of the normally in standby. Norma centrifugal HPSI pump .hrging is provided by the for normal charging. meakeup pump. eFo ...

lbs mater4a! due to erosion in the high preSSUre injetionend m~akeup pum~p m~inifeo roc&rcuiation orfices, reqf-ert Item Number 3.2.1 409.

Further evaluation is documented in Section 3.2.2.2.6.

Enclosure L-11-166 Page 7 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.2.2-1 Page 3.2-50 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.2.2-1 as follows:

Table 3.2.2-1 Aging Management Review Results - Containment Air Cooling and Recirculation System Row Component Intended AigEfc Aging Effect Aging gn NUREG-81 al Row Cmponen Fnctiond Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Maaeet PormVolume Item Management Program 2 Item Air-indoor Inspection of Flexible Pressure Elastomer Andoor Loss of Internal Surfaces in VIIFI-6 3.3.1-34 E Connection boundary (Internal) material Miscellaneous I I Piping and Ductingi Flexible Pressure Loss of External Surfaces miVII.-5 3.3.1-34 E boundar Elastomer uncontrolled

""Connection

_Connection boundary (External) material Monitoring

Enclosure L-11-166 Page 8 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.2.2-1 Page 3.2-50 New Row Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, a new row is added to Table 3.2.2-1 as follows:

Table 3.2.2-1 Aging Management Review Results - Containment Air Cooling and Recirculation System Aging Effect Aging NUREG-Row Component Intended Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Malagenent Program Volume Item Management Program 2 Item Pressure A'rindoor A Piing boundary Steel uncontrolled Crackinq TLAA VII.EI-18 3.3.1-02 0-214 (internal)

Enclosure L-1 1-166 Page 9 of 116 Affected LRA Section LRA Paae No. Affected Paragraph and Sentence Table 3.2.2-4 Page 3.2-90 Row 142 Based on the response to RAI 3.2.2.3.4-1, to credit the External Surfaces Monitoring Program to manage loss of material due to crevice and/or pitting corrosion of aluminum components subject to an outdoor air environment, Row No. 142 of Table 3.2.2-4 is revised to read:

Table 3.2.2-4 Aging Management Review Results - Decay Heat Removal and Low Pressure Injection System Row Component Intended MateAging Effect Aging NUREG- T I Row Compoen Functionded Material Environment Requiring Management 10, Tbe1 Notes No. Type Function(s) Management Program Volume Item 2 Item 142 Valve Body Pressure boundary AlmnmAir-outdoor Aluminum (External)

None

___

Loss of T___I None External Surfaces N/A N/A G boundar Imaterial (Externa) Monitorinq

Enclosure L-11-166 Page 10 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.2.2-4 Page 3.2-93 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.2.2-4 as follows:

Table 3.2.2-4 Aging Management Review Results - Decay Heat Removal and Low Pressure Injection System Aging Effect Aging NUREG-Row Component Intended Aging Magint 1801, Table 1 No. Type Function(s) Material Environment Requiring Management Volume Item Notes

_2Management Program 2Item Treated A

Pressure boundar Stainless eel tel0213 > 60C (>water borated Cracking 'onar TLAA V.Dl-27 3.2.1-01 A 140F)

(Internal)

Treated

-Orifice Throttling Stainless borated water Of Steel > 60C (> Cracking TLAA V.D1-27 3.2.1-01 A 140F)

(Internal)

Treated nboundary Pressure Stainless Steel bonar tel0213 > 60C (>water borated Cracking TLAA V.D1-27 3.2.1-01 A 140F)

(Internal)

Enclosure L-11-166 Page 11 of 116 Table 3.2.2-4 Aging Management Review Results - Decay Heat Removal and Low Pressure Injection System Component Intended Aging Effect Aging NUREG-Row Row C poe Intended Material Environment Requiring Management 1801, Table I Notes No. Type iFunction(s) Maaeet Management PormVolume Program 2 Item Item Treated Structural Pi Stainless borated water A itnrgtu Si > 60C (> Cracking TLAA V.DI-27 3.2.1-01 A

""

• integritySteel Steel 140F) 0213 (Internal)

Cast Treated water borated Pressure Austenitic > wa Cr C Separator boundary Stainless > 60C (> Crackiq TLAA V.D1-27 3.2.1-01 0213 Steel .140F)

(Internal)

Treated Tu Pressure Stainless borated water A q

Tubingur Stel > 60C (> Cracking TLAA V.DI-27 3.2.1-01 A boundary Steel 140F) 0213 (Internal)

Treated Structural Stainless borated water A Tubingtrut Steel > 60C (> Cracking TLAA V.DI-27 3.2.1 --ntegrity Steel 140F) 0213 (Internal)

Treated Pressure Stainless borated water A Valve Body Steel > 60C (> Cracking TLAA V.DI-27 3.2.1 -- Val y boundary Steel 140F) 0213 (Internal)

Enclosure L-1 1-166 Page 12 of 116 Table 3.2.2-4 Aging Management Review Results - Decay Heat Removal and Low Pressure Injection System Row Component Intended Aging Effect Aging NUREG-Row Compoen Functionded Material Environment Requiring Management 10, TbeI Notes No. Type Function(s) Management Program Volume Item 2 Item Treated

-- Valve Body i Steel > 60C (> Cracking TLAA V.DI-27 3.2.1-01 0213 140F)

(Internal)

Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.2.2 Page 3.2-118 New Plant-Specific Notes Plant-Specific Notes Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new plant-specific notes are added to Table 3.2.2 "Plant-Specific Notes" as follows:

Plant-Specific Notes:

0213 Fatique TLAA is evaluated in LRA Section 4.3.3.1, for piping and (in-line) piping components.

0214 Conservatively,DiDing and piDing components in the Containment Air Cooling and Recirculation System can see temperatures up to 264°F (i.e., following a design basis transient), which is above the threshold for fatique of steel components. Fatigue TLAA is evaluated in LRA Section 4.3.3.1. for piping and (in-line)piping components.

Enclosure L-11-166 Page 13 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.3.2.1.12 Page 3.3-17 "Aging Management Programs" section In response to RAI 3.3.2.3.12-1, the "Aging Management Programs" subsection of Section 3.3.2.1.12 is revised to read:

Aging Management Programs The following aging management programs manage the aging effects for subject mechanical components of the Emergency Diesel Generators System:

• Bolting Integrity Program

• Buried Piping and Tanks Inspection Program

" Closed Cooling Water Chemistry Program

" External Surfaces Monitoring Program

" Fuel Oil Chemistry Program

" Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program

" Lubricating Oil Analysis Program

• One-Time Inspection

" Selective Leaching Inspection

Enclosure L-11-166 Page 14 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.3.2.1.14 Page 3.3-19 "Aging Management Programs" section In response to RAI 3.3.2.3.12-1, the "Aging Management Programs" subsection of Section 3.3.2.1.14 is revised to read:

Aging Management Programs The following aging management programs manage the aging effects for subject mechanical components of the Fire Protection System:

• Aboveground Steel Tanks Inspection Program

" Bolting Integrity Program

• Boric Acid Corrosion Program

" Buried Piping and Tanks Inspection Program

" Collection, Drainage, and Treatment Components Inspection Program

" External Surfaces Monitoring Program

" Fire Water Program

" Fuel Oil Chemistry Program

" Inspection of Internal Surfaces in Miscellaneous Pipinq and Ducting Pro-gram

" Lubricating Oil Analysis Program

" One-Time Inspection

" PWR Water Chemistry Program

• Selective Leaching Inspection

Enclosure L-11-166 Page 15 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.3.2.1.32 Page 3.3-39 "Aging Management Programs" section In response to RAI 3.3.1.85-1, the "Aging Management Programs" subsection of Section 3.3.2.1.32 (previously amended by LRA Amendment No. 7 in FENOC Letter L-1 1-153, dated 5/24/11, in response to RAI B.2.28-1) is revised to read:

The following aging management programs manage the aging effects for subject mechanical components of the Turbine Plant Cooling Water System:

• Bolting Integrity Program

" Closed Cooling Water Chemistry Program

" External Surfaces Monitoring Program

" Selective Leaching Inspection Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.3.2.2.4.1 Page 3.3-40 Entire section In response to RAI 3.3.2.2.4-1, to not credit 3.3.1-07 to manage cracking of seal return coolers (DB-E26-1 and 2), Section 3.3.2.2.4.1 is revised to read:

Cracking due to stress corrosion cracking and cyclic loading could occur in stainless steel pressurized water reactor (PWR) nonregenerative heat exchanger components exposed to treated borated water greater than 60°C (> 140'F) in the chemical and volume control system. At Davis-Besse, the seal ret'r-Gcolers in the Makeup and;PurificGa*t System con;ist of stainless stol heat exchangew compenents exposed to treated berated water-greate than 602G .. 14 02*. .

Cracking du1e*Gto strs-- corrosion -; (SCC)

,rackingin stainless steel hesi excGhanger-component-s th-at aRre extposedf to tresate-d- bopratedl water Igreater than 602G (>4l4 0 2F) is m~an-aged by the PW4R WaterF Chemistry Progam The PRU Wa4-ter Chemistry Pro9gram m~anages cracking through periodic monitoring andl centre! of contam~inant-s. The One Time 1npGecffoi WX FOVide vePrification of the9 11 effectiveness of the PWR44 W4ater chemgistry Proegram to m~anage cracking.Th One~~ nsecio Tie i I eletedI in lieu Of eddy c-Urrent te6sting of tubes.

Temperature and radioactivty mo0nitoring Of Shell Side w~ater- s p-e~bmged by instaledistruentaton. racki-ng due to cyclic loading is not identifed as an

Enclosure L-11-166 Page 16 of 116 aging e°ffet requiring managemsent for the stainless steel heat exchange; comeponents that are exposed to treated borateddwatergreaterthan 60C

(>4 4OR2F the Auxiliary Systems do not contain stainless steel nonre-generative heat exchanger components that are exp~osed to treated berated water greater than 60*C (> 140°0F) and subiect to aging management review; therefore, this item is not applicable to Davis-Besse.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.3.2.2.4.3 Page 3.3-41 Entire section In response to RAI 3.3.2.2.4.3-1 regarding cracking of stainless steel due to cyclic loading, Section 3.3.2.2.4.3 is revised to read:

3.3.2.2.4.3 Stainless Steel PWR High PressurePump Casings- Treated Borated Water Greater"Than 602G (> 140RF)

Cracking due to stress corrosioncracking and cyclic loading could occur for the stainless steel pump casing for the PWR high-pressurepumps in the chemical and volume control system. At Davis-Besse, cracking due to stress corrosion cracking and cyci*c loading is not identified as an aging effect requiring management for the stainless steel pump casing for the high-pressurepumps in the Makeup and Purification(chemical and volume control) System because the casing is exposed to treated borated water that is maintainedat 120°F or below, therefore, this item i not applicable to Dais, Beg se. Cracking due to cyclic loading of the stainless steel Pump casinq of the hiqh-Pressurepumps in the Makeup and PurificationSystem will be managed by the PWR Water Chemistry Program with the One-Time Inspection providing verification of the absence of cracking due to cyclic loading.

Enclosure L-11-166 Page 17 of 116 Affected LRA Section LRA Page No. Affected Paraoraoh and Sentence 3.3.2.2.7.1 Page 3.3-42 Entire section In response to RAI 3.3.2.3.12-1 1, a new paragraph is added to the end of Section 3.3.2.2.7.1 as follows:

Lubricating oil is used as the filter media in the steel intake airfilter for the emergency diesel generatorsand for the fire pump diesel engine. The lubricating oil is periodicallyreplaced and is not controlled under the Lubricating Oil Analysis Program. The Inspection of Internal Surfaces in Miscellaneous Pipingand Ducting Programis credited for aginq management.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence 3.3.2.2.13 Page 3.3-47 Entire section In response to RAI 3.3.2.2.13-1, Section 3.3.2.2.13 is revised to read:

Loss of material due to wear could occur in elastomer seals and components exposed to air indoor uncontrolled (internal or external). At Davis-Besse, loss of material due to wear of elastomer components exposed to air-indooruncontrolled (internaland external) will be managed by the plant-specific Inspection of Internal Surfaces in Miscellaneous Pipingand Ducting Programinternallyand the External Surfaces Monitoring Program externally. Wear of elastomr-r se4/ls nd com4ponentS exposed to air is not identifed as an gi gefct reqUiWrig mIanagement at Davis B*aoe. Ls* s of material dlo to erIs t reult I of t moion btween4-.P NAG su-rfaces-q- in otat HOw4ever-, wear-occurs&during the performanco of an active function; as a result of improeper dfesign, application, et operation; orF to a very small degree with insinifiant consequen~ess. The-re foro, loss of material due to wear-is n-ot an aging effect requiin mana-gem~ent fo; elaStOmer, exposed to airl indoor ucnrle Lossof materi due

, to-O'1,,al a

could occUr ýi the ela;tome

,.eals and eompenents exposed to air ndoo; uncontrolled (internal or oxtorpnal.

Enclosure L-1 1-166 Page 18 of 116 Affected LRA Section LRA Pane No. Affected ParaaraDh and Sentence Table 3.3.1 Page 3.3-51 Row 3.3.1-07, "Discussion" column Text in "Discussion" column is revised based on the response to RAI 3.3.2.2.4-1. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 ," is revised to read:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 I Further Evaluation Discussion Item Aging Aging Management Number Component/Commodity Effect/Mechanism Programs Recommended 3.3.1-07 Stainless steel non-regenerative Cracking due to Water Chemistry and a Yes, plant Gcnsistent with NUREG 1901.

heat exchanger components stress corrosion plant-specific verification specific Craking due to SCC foF exposed to treated borated water cracking and cyclic program. An acceptable .t...t. .... het an g..

>60°C (>1 40 0 F) loading verification program is to .. m..n. nt..............iary include tem perature and ... te s tht.e ...... to i ...e.......

radioactivity monitoring e...ted hated wate r,

• tr tra___;__ o_*__ . ......

___ _ >,

of the shell side water, 0 and eddy current testing (> .4 .F* is managed by the of tubes. P. .R Wa...ter. C . .hemi .st.yProG ram.

The* O"ne9 Tm, Ins*,*,t;n* 1i41 provido ve -rifiqt-io-nof t-he os o-f the PW.R Wate

_...o_.t-,

Chemgistry Proegram to m~anage G~aGking Temgperaturo and radioactivit monitoring of she#l side water-i perfbrmed by installed i~nstM rumen-Ptaitieon.

Enclosure L-11-166 Page 19 of 116 Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 Further Item Aging Aging Management Evaluation Discussion Number Component/Commodity Effect/Mechanism Programs Recommended aking due to cyplicleadg is not identified as an aging effoel reqirig mnagement for the tainlneeeratiol heat exchanger components that are exposed to Not appnicable.

The Auxiliary Systems do net (140°~F) stainless adsbett steel gn contain nonre~generative heat exchanger components that are exposed to treated berated water > W0C

(> 140 0F) and subiect to a-zin-q management review.

Further evaluation is documented in Section 3.3.2.2.4.1.

Enclosure L-11-166 Page 20 of 116 Affected LRA Section LRA Page No. Affected ParaaraDh and Sentence Table 3.3.1 Page 3.3-52 Row 3.3.1-09, "Discussion" column Text in "Discussion" column is revised based on the response to RAI 3.3.2.2.4.3-1. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 ," is revised to read:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 j Evaluation

- -

Further Discussion Item Aging Aging Management Number Component/Commodity Effect/Mechanism Programs E uRecommended 3.3.1-09 Stainless steel high-pressure Cracking due to Water Chemistry and a Yes, plant Jet-appiea pump casing in PWR chemical stress corrosion plant-specific specific Consistent with NUREG-1801.

and volume control system cracking and cyclic verification program.

loading The AMP is to be Cracking due to SCC and-ayclic augmented by verifying leaddi is not identified as an the absence of cracking aging effect requiring due to stress corrosion management for the stainless cracking and cyclic steel high-pressurepump casings loading. A plant specific in the Makeup and Purification aging management (chemical and volume control) program is to be System.

evaluated. Cracking due to cyclic loadinq of the stainless steel Pump casing of the high pressure pumps in the Makeup and PurificationSystem will be managed by the PWR Water Chemistry Programwith the One-Time Inspection Providing verification of the absence of cracking due to cyclic

Enclosure L-11-166 Page 21 of 116 Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 Item Item Aging IFurther Aging Management Fute Number Component/Commodity Effect/Mechanism Programs Evaluation Discussion Recommended IoadinQ.

Further evaluation is documented in Section 3.3.2.2.4.3.

Enclosure L-11-166 Page 22 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.1 Page 3.3-56 Row 3.3.1-14, "Discussion" column Text in "Discussion" column is revised based on the response to RAI 3.3.2.2.4.3-1. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801," is revised to read:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems

_ _ _Evaluated in Chapter VII of NUREG-1801 Further Discussion Item Aging Aging Management Evaluation Component/Commodity Effect/Mechanism Programs Recommended Number 3.3.1-14 Steel piping, piping component, Loss of material due Lubricating Oil Analysis Yes, detection of Consistent with NUREG-1801.

and piping elements exposed to to general, pitting, and One-Time aging effects is to lubricating oil and crevice corrosion Inspection be evaluated Loss piping omaterans piping component, and piping elements that are exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. The One-Time Inspection will provide verification of the effectiveness of the Lubricating Oil Analysis Program to manage loss of material.

This item is also applied to steel tanks, and bearing and gear housings, in the Auxiliary Systems that are exposed to lubricating oil.

This item is also applied to

Enclosure L-11-166 Page 23 of 116 Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems I _ _Evaluated in Chapter VII of NUREG-1801 Further Numermopnn~omdt Aging Aging Management Evaluation Discussion Number Component/Commodity Effect/Mechanism Programs Recommended steel intake air filter bodies exposed to lubricating oil in the diesel systems. The Inspection of Internal Surfaces in MiscellaneousPiping and Ducting Programis credited for aging management.

Further evaluation is documented in Section 3.3.2.2.7.1.

Enclosure L-11-166 Page 24 of 116 Affected LRA Section LRA Paae No. Affected Paragraph and Sentence Table 3.3.1 Page 3.3-73 Rows 3.3.1-34 and 3.3.1-75, "Discussion" column Text in "Discussion" column is revised based on the response to RAI 3.3.2.2.13-1. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801," is revised to read:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 Aging Aging Management EuatoD i Item Number Component/Commodity Effect/Mechanism Programs Evaluation Discussion Recommended 3.3.1-34 Elastomer seals and Loss of material due A plant specific aging Yes, plant Net-apph/abl components exposed to air - to wear management program is specific LOSS

.Ofmatera* l dUo to W.a. Wa.

indoor uncontrolled (internal or to be evaluated. not identified as an aging affe..

external) .......... m.nagement f" .

iqlastemor seals and com~ponent inAuxiliary Systems thatar exposed to air indoor Unecontroled.

Consistent with NUREG-1801.

Loss of materialdue to wear of elastomer components exposed to air-indooruncontrolled (internal and external)will be managed b the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Program internallyand the External Surfaces Monitoring Programexternally.

Enclosure L-11-166 Page 25 of 116 Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems

___ _Evaluated in Chapter VII of NUREG-1 801 Im Ag Further Nuem Component/Commodity ging Aging Management Evaluation Discussion Number Effect/Mechanism Programs jRecommended Further evaluation is documented in Section 3.3.2.2.13.

3.3.1-75 Elastomer seals and Hardening and loss Open-Cycle Cooling No Consistent with NUREG-1 801, but components exposed to raw of strength due to Water System a different aging management water elastomer program is assigned.

degradation; loss of Loss of material due to wear and material due to Jhardening and loss of strength for elastomer components that are exposed to raw water will be managed by the Inspection of InternalSurfaces in Miscellaneous Piping and Ducting Program.

Enclosure L-1 1-166 Page 26 of 116 Affected LRA Section LRA Paae No. Affected Paraqraph and Sentence Table 3.3.1 Page 3.3-98 Row 3.3.1-74, "Discussion" column Text in "Discussion" column is revised based on the response to RAI 3.3.1.74-1. LRA Table 3.3.1, "Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 ," is revised to read:

Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 InMa t Further Nuem Numbr Component/Commodity Efft/canin ging anagemen Efect/echnismProgamsRecommended Evaluation Discussion 3.3.1-74 Steel cranes - rails exposed to Loss of material due Inspection of Overhead No Not-pliGa fe air - indoor uncontrolled to wear Heavy Load and Light Loss of material d'c to woar 1 s (external) Load (Related to not identi,,ed as an aging effe"t Refueling) Handling . mnagement forF Systems "arbon t-o-P F.ane bridge&,

trolleys, rFaIs, and grdrs that are exposed to air-in-door-L'flcntrolled (external).

Consistent with NUREG-1801 Loss of materialdue to wear is identified as an aging effect requiringmanagement for carbon steel crane rails that are exposed to air-indoor uncontrolled(external).

Enclosure L-11-166 Page 27 of 116 Affected LRA Section LRA Page No. Affected ParagraDh and Sentence Table 3.3.2-1 Page 3.3-144 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-1 as follows:

Table 3.3.2-1 Aging Management Review Results - Auxiliary Building HVAC Systems Agin Effct AingNUREG-Row Component Intended Aging Effect Aging 1801, Table 1 No. Type Function(s) Material Environment Management Volume Item Notes M{anagement Program 2 Item Air-indoor Inspection of Flexible Pressure Elastomer Andoor Loss of Internal Surfaces in VIIFI-6 3.3.1-34 E Connection boundary nonteral)l material Miscellaneous Piping and Ducting Flexible Pressure Air-indoor Loss of External Surfaces Connection boundary Euncontrolled material Monitoring

- ________ Ex~ternal)

Air-indoor Inspection of Mechanical Pressure Elastomer Andoor Loss of Internal Surfaces in VIIFI-6 3.3.1-34 E Sealant boundary (Internal) material Miscellaneous Piping and Ducting Mechanical Pressure Air-indoor Loss of External Surfaces Sealant boundary uncontrolled material Monitoring 3

- ______ External)

Enclosure L-11-166 Page 28 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-1 Page 3.3-132 Various Rows Based on the response to RAI 3.3.2-2, various rows of Table 3.3.2-1 are revised to read:

Neae Pressure Air-outdoor Loss of External Surfaces boundary (External) material Monitoring

Enclosure L-1 1-166 Page 29 of 116 Affected LRA Section LRA Pane No. Affected Paragraph and Sentence Table 3.3.2-1 Page 3.3-144 New Rows Based on the response to RAI 3.3.2-2, new rows are added to Table 3.3.2-1 as follows:

Table 3.3.2-1 Aging Management Review Results - Auxiliary Building HVAC Systems Row Component Aging Effect Aging NUREG-Intended AgnIfetAin 81 al Row Cmponen Fnctiond Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Maaeetj rga Volume Item Management Program 2 Item Pressure Copper Air-outdoor External Surfaces Boundar Alloy> (External) Crackin Monitoring NIA NIA G

-- Tubinq Boundary 15% Zn Tubin Pressure Copper Air-outdoor Loss of Selective Leaching N/A N/A G

-- Boundary Alloy > (External) material Inspection 15% Zn Pressure Copper Air-outdoor Crackin External Surfaces N/A N/A G Valve Body Boundary Alloy> (External) Monitoring 15% Zn Pressure Copper Air-outdoor Loss of Selective Leaching N/A N/A G

-- Valve Body Boundary Alloy> (External) material Inspection N 15% Zn

Enclosure L-11-166 Page 30 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-3 Page 3.3-186 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-3 as follows:

Table 3.3.2-3 Aging Management Review Results - Auxiliary Steam and Station Heating System Aging Effect Aging NUREG-Row Type Intended Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Management Program Volume Item 2 Item Treated water Orifice Structural Stainless > 60C (> A integrit Steel 140F) ____ racing TLAA ____0337 VII.E3-14 3.3.1-02 A (Internal)

Structural Stainless Steam A Orifice integrit Steel (Internal) Cracking TLAA VII.E3-14 3.3.1-02 -337 Treated water

-- ing Structural Steel >40 60C (> Cracking TLAA VIII.B1- 3.4.101-3 3.4.1-01 A integrity 140F) 10 0337 (Internal)

Structural Steam VIII.BI1- A Piping Steel Steam Cracking TLAA 10 3.4.1-01 -

inte~grity (Internal) 10 0337 Treated water Tubin Structural > 60C (> VIII.B1- 3.4.1-01 A Tubing1SteelCracking TLAA 1310 01337 (Internal)

Enclosure L-11-166 Page 31 of 116 Table 3.3.2-3 Aging Management Review Results - Auxiliary Steam and Station Heating System Component Intended Aging Effect Aging NUREG-Row Row Typo Funtended Material Environment Requiring Management 1801, Table I Notes No. Type iFunction(s) Maaeet PormVolume Item Management Program 2 Item Structural Steam VIII. B1- A Steritu Steel Steam Cracking TLAA 1._0 3.4.1 -- Tubin integrity (Internal) 10 0337 Structural Stainless Treated

> 60C (>A water itritl Steel 140FC Cracking TLAA VII.E3-14 3.3.1-02 A

-- Valve Body Steel

_ 140)0337 (Internal)

Treated water

-- Valve Body Structural ineqiv Steel > 60C (>

10 Cracking TLAA VIII.B1- 3.4.1-01 A 3.4.1-01-33 inte~grity 140F) 10 0337 (Internal)

Structural Steam VIII. B1- A S Steel Steam Cracking TLAA 1. 3.4.1 -- Valve Body inte~grity (Internal) 10 0337

Enclosure L-11-166 Page 32 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-6 Page 3.3-232 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-6 as follows:

Table 3.3.2-6 Aging Management Review Results - Circulating Water System Component Intended Aging Effect Aging NUREG-Row Rojopnnt Itne Material Environment Reurn Mage nt 1801, Table 1 Notes No. Type Function(s) equiring anagement Volume Item SManagement Program 2 Item Inspection of Flexible Structural Elastomer Raw water Loss of InternalSurfaces in Vl1.C1-2 3.3.1-75 E

" Connection inte-ritv (Internal) material Miscellaneous Piping and Ducting Flexible Structural Air-indoor Loss of External Surfaces Connection integrity uncontrolled material Monitoring 3.

-I _ _ I__ (Ex~ternal) I_ __ _I__ _I_

Enclosure L-11-166 Page 33 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-8 Page 3.3-268 New Row Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, a new row is added to Table 3.3.2-8 as follows:

Table 3.3.2-8 Aging Management Review Results - Containment Hydrogen Control System Row Component Intended Aging Effect Aging NUREG-Row Componen Fntendd Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) MaaeetIrga Volume Item Management Program _2 Item Presure Pressboundrey Steel Ste P Air-indoor uncontrolled (Internal) Cracking _02 TLAA VII.El-18 3.31-02 341

Enclosure L-11-166 Page 34 of 116 Affected LRA Section LRA Page No. Affected Paraaraph and Sentence Table 3.3.2-9 Page 3.3-270 New Row Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, a new row is added to Table 3.3.2-9 as follows:

Table 3.3.2-9 Aging Management Review Results - Containment Purge System Row No.

Component Typo Type IowIntended Funtended iFunction(s)

Material Environment Aging Effect Requiring Maaeet Aging Management PormVolume NUREG-1801, Table 1 Item Notes Management Program 2 Item Air-indoor Pipin bosunre boundar Steel uncontrolled (Internal) Crackinq TLAA VII.E-18 3.3.1-02

Enclosure L-11-166 Page 35 of 116 Affected LRA Section LRA Parle No. Affected Paragraph and Sentence Table 3.3.2-10 Page 3.3-272 New Row Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, a new row is added to Table 3.3.2-10 as follows:

Table 3.3.2-10 Aging Management Review Results - Containment Vacuum Relief System Row No.

Component Typo Type IowIntended Funtended IFunction(s)

Material Environment Aging Effect Requiring Maaeet Aging Management Program NUREG-1801, Volume Table I Item Notes Management P2 Item

-- _Iboundary Steel Air-indoor uncontrolled (Internal)

Cracking TLAA VII.El-18 3.3.1-02 0341

Enclosure L-11-166 Page 36 of 116 Affected LRA Section LRA Page No. Affected Paraoraah and Sentence Table 3.3.2-12 Page 3.3-282 Row 21 Based on the response to RAI 3.3.2.3.12-1, Row 21 of Table 3.3.2-12 are revised to read:

Table 3.3.2-12 Aging Management Review Results - Emergency Diesel Generators System Row Component Intended Aging Effect Aging NUREG-Row Type Intended Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Management Maaeet Program PormVolume VIteme Ite Item 2 Item Neoe N/A N/A 4 21 Filter Body Pressure Steel Lubricating oil Inspection of E boundary (Internal) Loss of Internal Surfaces in VII.H2-20 3.3.1-14 material Miscellaneous 0325 Pipingi and Ductincq

Enclosure L-11-166 Page 37 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-12 Page 3.3-283 Rows 24 and 25 Based on the response to RAI 3.2.2.3.4-1, to credit the External Surfaces Monitoring Program to manage loss of material due to crevice and/or pitting corrosion of aluminum components subject to an outdoor air environment, Rows 24 and 25 of Table 3.3.2-12 are revised to read:

Table 3.3.2-12 Aging Management Review Results - Emergency Diesel Generators System Row Component Intended Aging Effect Aging NUREG-Row Type Intended Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Maaeet Management PormVolume Program 2 Item IItem

~4eneNone 24 Flame Arrestor Pressure boundary Aluminum Air-outdoor (Internal) Loss of External Surfaces N/A N/A G material Monitoring Nnee None Flame Pressure Air-outdoor Arrestor boundary (External) Loss of External Surfaces N/A N/A G material Monitoring

Enclosure L-11-166 Page 38 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-12 Page 3.3-307 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-12 as follows:

Table 3.3.2-12 Aging Management Review Results - Emergency Diesel Generators System Row Row Component Componen Intended Fntende Material Environment TAging Effect Requiring Aging Management NUREG- I 1801, Table I Notes No. Type Function(s) Managee~rnt rga Volume Item M{anagement Program 2 Item Inspection of Flexible Pressure Air-outdoor Loss of Internal Surfaces in N/A N/A H Connection boundary (Internal) material Miscellaneous Pipinq and Ductincq Flexible Pressure Air-indoor Loss of External Surfaces Connection boundary uncontrolled material Monitoring3

- ________ (xternal)

Enclosure L-11-166 Page 39 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-12 Page 3.3-307 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-12 as follows:

Table 3.3.2-12 Aging Management Review Results - Emergency Diesel Generators System Component Intended Aging Effect Aging NUREG-Row Row Type Intended Material Environment Requiring Management 1801, ItemTable I Notes No. Type Function(s) Management Maaeet Program PormVolume Volu2 Item 2 Item Flexible Pressure Stainless Diesel exhaust Crackin TMA N/A N/A H

" Connection boundary Steel (Internal) 0337 Pressure Diesel exhaust H

"- Pboundary Steel (Internal) Cracking TLAA N/A N/A 0337 Silencer Pressure Diesel exhaust H

- (exhaust) boundary Steel (Internal) Cracking TLAA N/A N/A 0337 Tubing Structural Stainless Diesel exhaust Crackin TMA N/A N/A H

--

integrity Steel (Internal) 0337 Pressure Diesel exhaust H

-- Valve Body boundary Steel (Internal) Cracking TLAA N/A N/A 0337

Enclosure L-11-166 Page 40 of 116 Affected LRA Section LRA Paue No. Affected Paragraph and Sentence Table 3.3.2-13 Page 3.3-312 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-13 as follows:

Table 3.3.2-13 Aging Management Review Results - Emergency Ventilation System Component Intended Aging Effect Aging NUREG-Row Row Typonet Fntended Material Environment Requiring Management 1801, Table Notes No. Type Function(s) Management Program Volume Item 2 Item Air-indoor Inspection of Flexible Pressure Elastomer Andoor Loss of Internal Surfaces in VILFI-6 3.3.1-34 E Connection boundary (Interoal) material Miscellaneous Piping and Ducting Flexible Pressure Air-indoor Loss of External Surfaces Connection boundary Euncontrolled material Monitoring

- ________ Externalj Air-indoor Inspection of Mechanical Pressure Elastomer Andoor Loss of Internal Surfaces in VIIFI-6 3.3.1-34 E Sealant boundary (Internal) material Miscellaneous Piping and Ducting Mechanical Pressure Air-indoor Loss of External Surfaces Sealant boundary Euncontrolled material Monitoring I

- ______ (~~External)_____

Enclosure L-11-166 Page 41 of 116 Affected LRA Section LRA Page No. Affected Paraciralh and Sentence Table 3.3.2-14 Page 3.3-334 Row 167 Based on the response to RAI 3.3.2.3.12-1, Row 167 of Table 3.3.2-14 are revised to read:

Table 3.3.2-14 Aging Management Review Results - Fire Protection System Row Component Intended Aging Effect Aging N1801, Table Function(s) Material Environment Requiring Management Volume Item Notes No. Type Management Program 2 Item None NIA N/A 4 Steel Lubricating oil Inspection of E 167 Filter Body Pressure boundary (Internal) Loss of Internal Surfaces in VII.H2-20 3.3.1-14 material Miscellaneous 0325 Piping and Ductinq

Enclosure L-11-166 Page 42 of 116 Affected LRA Section LRA Paae No. Affected Paragraph and Sentence Table 3.3.2-14 Page 3.3-332 New Rows and 342 Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-14 as follows:

Table 3.3.2-14 Aging Management Review Results - Fire Protection System I I NUREG-1801, Aging Effect Aging Requiring Management Volume Management Program 2 Item Fire Protection System Raw water Crackin TMA N/A N/A H (Internal) 0339 Raw water Cki TMA N/A N/A H (Internal) racing TLAA N/A N/A 0339 Fire Pump Diesel Engine and Associated Components Flexible Pressure Stainless Diesel exhaust H

- Connection boundary Steel (Internal) Cracking TLAA N/A N/A 0337 Pressure Diesel exhaust H

-- P boundary Steel (Internal) Cracking TLAA N/A N/A 0337 Silencer Pressure Diesel exhaust H

- (exhaust) boundary Steel (Internal) Cracking TLAA N/A N/A 0337

Enclosure L-11-166 Page 43 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-14 Page 3.3-342 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-14 as follows:

Table 3.3.2-14 Aging Management Review Results - Fire Protection System Aging Effect Aging NUREG-Row Component Intended I gg 1801, Table I Notes No. Type Function(s) Material Environment Requiring Management Volume Item SManagement Program 2 Item Air-indoor Inspection of Flexible Pressure Elastomer Andoor Loss of Internal Surfaces in VIIFI-6 3.3.1-34 E Connection boundary (Internal) material Miscellaneous Piping and Ducting Inspection of Flexible Pressure Raw water Loss of Internal Surfaces in VII. C1-2 3.3.1-75 E

- Connection boundary (Internal) material Miscellaneous Piping and Ducting Flexible Pressure Air-indoor Loss of External Surfaces boundary Euncontrolled material Monitoring 3 Connection

- ______ External)

Enclosure L-11-166 Page 44 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-14 Page 3.3-342 New Row Based on the response to RAI 3.2.2.1.26-1, to explicitly credit the PWR Water Chemistry Program in conjunction with the One-Time Inspection for reduction in heat transfer of the fire water storage tank heat exchanger (DB-E52) tubes, a new row is added to Table 3.3.2-14 as follows:

Table 3.3.2-14 Aging Management Review Results - Fire Protection System Row Component Intended Aging Effect Aging NUREG-Row Componen Fntendd Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Maaeet PormVolume Item Management Program 2 Item Heat Exchanger (tubes) - Fire Stainless Steam Reduction in PWR Water water storage Heat transfer Steel (External) heat transfer Chemistry NA NIA G tank heat exchanger LDB-E5 2

Enclosure L-11-166 Page 45 of 116 Affected LRA Section LRA Page No. Affected ParaaraDh and Sentence Table 3.3.2-14 Page 3.3-324 Various Rows Based on the response to RAI 3.3.2-2, various rows of Table 3.3.2-14 are revised to read:

Table 3.3.2-14 Aging Management Review Results - Fire Protection System Row Row No.

Component Typo Type Intended Funtended Function(s)

Material Environment Aging Effect Requiring 4nManProgram Aging Management NUREG-1801, Volume 2 Item Table I Item Notes Pressure Copper Air-outdoor NePe NeRe 82 Spray Nozzle boury Alloy > (External) Loss of External Surfaces N/A N/A G boundary 15% Zn material Monitoring Structural Copper Air-outdoor None NGRe 92 Spray Nozzle Strutu Alloy > (External) Loss of External Surfaces N/A N/A G integrity 15% Zn material Monitoring Pressure Copper Air-outdoor Nene None 128boundary Alloy (External) Loss of External Surfaces N/A N/A G material Monitoring Structural Copper Air-outdoor Nene None 1 integrity V Alloy (External) Loss of material External Surfaces Monitoring N/A N/A G

Enclosure L-11-166 Page 46 of 116 Affected LRA Section LRA Page No. Affected ParaaraDh and Sentence Table 3.3.2-14 Page 3.3-332 New Rows Based on the response to RAI 3.3.2-2, new rows are added to Table 3.3.2-14 as follows:

{fe Table 3.3.2-14 Aging Management Review Results - Fire Protection System Row Component Intended IAging Effect Aging NUREG-Material c agin 1801, Table 1 N No. Type Function(s) Environment Requiring Management Volume Item otes Management Program 2 Item Pressure Copper Air-outdoor External Surfaces Spray Nozzle boundary Alloy> (External) Crackin Monitoring NA NIA G 15% Zn Pressure eboundary Copper Alloy> Air-outdoor (External) Loss of material InspectionLeaching Selective N/A NI N/A -

S15% Zn Structural Copper Air-outdoor External Surfaces Spray Nozzle integrity Alloy> (External) Cracking Monitoring NA NIA G 15% Zn Structural Copper Air-outdoor Loss of Selective Leaching N/A N/A G

-- Spray Nozzle ______ Alloy> (External) material Inspection N 15% Zn

Enclosure L-11-166 Page 47 of 116 Affected LRA Section LRA Pane No. Affected Paragraph and Sentence Table 3.3.2-15 Page 3.3-349 New Rows Based on the response to RAI 3.3.2.2.13-1, a new row is added to Table 3.3.2-15 as follows:

Table 3.3.2-15 Aging Management Review Results - Fuel Oil System Component Intended Aging Effect Aging NUREG-Row Row Compoen Fnctiond Material Environment Requiring Management 1801, Table I Notes No. Type Function(s)Management Program Volume Item

_________ _________j________ Maagemet Prgram2 Item ____

Flexible Pressure Air-indoor Loss of External Surfaces Euncontrolled material Monitoring Connection

_ _

boundary

_ _ _ _ I ___ (~~External) _ __ _ _ _

Enclosure L-11-166 Page 48 of 116 Affected LRA Section LRA Pane No. Affected Paragraph and Sentence Table 3.3.2-16 Page 3.3-359 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-16 as follows:

Table 3.3.2-16 Aging Management Review Results - Gaseous Radwaste System Component Intended Aging Effect Aging NUREG-Row Row Cmponen Fnctiond Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Maaeet Program Volume Item Management P2 Item Structural Stainless H

-- Orifice integrit Steel Gas (Internal) Cracking TLAA N/A N/A 0340 Pressure Stainless H

-- boundary Steel Gas (Internal) Cracking TLAA N/A N/A 0340 Structural Stainless Gas (Internal) Crackin TLAA N/A N/A H

-- _ *integrit Steel 0340 Pressure Stainless H

-- Tubing boundary Steel Gas (Internal) Cracking TLAA N/A N/A 0340 Tubing Structural Stainless H integrit Steel Gas (Internal) Cracking TLAA N/A N/A 0340 Pressure Stainless H

-- Valve body boundary Steel Gas (Internal) Cracking TLAA N/A N/A 0340

Enclosure L-11-166 Page 49 of 116 Table 3.3.2-16 Aging Management Review Results - Gaseous Radwaste System Row Component Intended Material Environment SAgi ng Effect Requiring Aging Management NUREG-1801, Table 1 Notes No. Type Function(s) M anagequ ntgPrnaemnt Volume Item Management Program 2 Item Structural Stainless Gas (Internal) Cracking TLAA N/A NIA H Valve body integrit Steel _ 0340

Enclosure L-11-166 Page 50 of 116 Affected LRA Section LRA Page No. Affected Paragraoh and Sentence Table 3.3.2-18 Page 3.3-368 Various Rows Based on the response to RAI 3.3.2.2.4-1, various rows of Table 3.3.2-18 are revised to read:

Table 3.3.2-18 Aging Management Review Results - Makeup and Purification System Row No.

Component Heat Type Intended Function(s)

Material Environment Treated SAgiRequiring ng Effect Malagenent Management Aging Management Manam Program NUREG-1801, Volume 2 Item Table 1 Item I Notes Exchanger borated water 24 (channel) - Pressure Stainless > 60b C (> Cracking One-Time VII.EI-9 3.3.1-07 E Seal return boundary Steel 140 0F Inspection 20 90 0315 coolers (DB- (internal)

E26-1 & 2)

Heat Treated Exchanger borated water 25 PWR Water VII.EI-9 3.3. 1-07 C C (>

Stainless >140 60b0C Cracking Seal return-(channel) Pressure boundary Steel Chemistry 20 90 coolers (DB- (Internal)

E26-1 & 2)

Heat Treated Exchanger borated water (tubes) - Pressure Stainless borated(wat r One-Time VII.EI-9 3.3.1-07 E Seal return boundary Steel > 60°C (> Cracking Inspection 20 90 0315 coolers (DB- (Internal)

E26-1 & 2) (Intrnal Heat Treated Exchanger borated water 5 (tubes) -

Seal return Pressure boundary Stainless Steel >

borated(wat 60°C (> r Cracking PWR Water Chemistry VlI.E1-9 20 3.3.1-07 90 C coolers (DB- (internal)

E26-1 & 2) (Internal)

Enclosure L-11-166 Page 51 of 116 Table 3.3.2-18 Aging Management Review Results - Makeup and Purification System Row Component Typo No.Management IowIntended Funtended Material Environment Aging Effect Requiring Aging Management Program NUREG- T 1801, Volume 2 Item Table 1 Item Notes Heat Treated Exchanger borated water Cracking One-Time VII.E.-9 3.3.1- -W E 58 (tubesheet) -

Seal return Pressure boundary Stainless Steel 140 F0 (>

> 600C Inspection 20 90 0315 coolers (DB- (internal)

E26-1 & 2) (Internal)

Heat ExchangerTrae Treated Exch ngerborated water 5 (tubesheet) - Pressure Stainless borated(wat r PWR Water VII.E-,9 3.3.1 Seal return boundary Steel > 60°C (> Cracking Chemistry 20 90 coolers (DB- (Internal)

E26-1 & 2) (Internal)

Enclosure L-11-166 Page 52 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-18 Page 3.3-374 Row 46 Based on the response to RAI 3.3.1.85-1, to add a plant specific note, Row 46 of Table 3.3.2-18 is revised to read:

Table 3.3.2-18 Aging Management Review Results - Makeup and Purification System Row Row Component Coponet Intended Fnctiond TAging Effect fetAin Ign Aging NUREG-81 al Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Mangeen Program Volume Item Management Pro m 2 Item Heat Exchanger (tubes) -

Makeup Pressure Copper Closed cycle Loss of Closed Cooling B 46 pump lube oil bound Alloy > cooling water material Water Chemistry VII.E1-2 3.3.1-51 0303 coolers (DB- ary 15% Zn (External)

E188-1, 2 &

DB-E212-1, 2)

Enclosure L-11-166 Page 53 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-18 Page 3.3-397 New Rows Based on the response to RAI 3.3.2.2.4.3-1, two new rows are added to Table 3.3.2-18 as follows:

Table 3.3.2-18 Aging Management Review Results - Makeup and Purification System Row No.

Component Typo Type IowIntended Funtended Function(s)

Material Environment Aging Effect Requiring Maaeet Aging Management PormVolume NUREG-1801, Table I Item Notes Management Program 2 Item Pump Casing Treated

- Makeup Pressure Stainless One-Time VII-7 3.3.1-09 E

- pumps (DB- boundary Steel borated water Cracking Inspection - 0336 P37-1 & 2) (Internal)

Pump Casing Treated

- Makeup Pressure Stainless Trated PWR Water VIIEI-7 3.3.1-09 A

-- pumps (DB- boundary Steel borated water Cracking Chemistry P37-1 & 2) (Internal)

Enclosure L-11-166 Page 54 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-18 Page 3.3-397 New Row Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, a new row is added to Table 3.3.2-18 as follows:

Table 3.3.2-18 Aging Management Review Results - Makeup and Purification System Component Intended Aging Effect Aging NUREG-Row Row Componen Fntendd Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Maaeet Program Volume Item Management P2 Item Treated Pressure Stainless borated water A boundar Steel > 60C (> Cracking TLAA VII.EI-16 3.3.1-02 l140F 0337 (Internal)

Enclosure L-11-166 Page 55 of 116 Affected LRA Section LRA Paae No. Affected Paragraph and Sentence Table 3.3.2-21 Page 3.3-417 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-21 as follows:

Table 3.3.2-21 Aging Management Review Results - Miscellaneous Liquid Radwaste System Component Intended Aging Effect Aging NUREG-Row Row Typoen Inctinde Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) eq ngProgram Volume Item 2 Item Inspection of Flexible Structural Elastomer Raw water Loss of InternalSurfaces in V11.C1-2 3.3.1-75 E

- Connection inte-jrit' (Internal) material Miscellaneous Piping and Ducting Flexible Structural Air-indoor Loss of External Surfaces Connection integrity Euncontrolled material Monitoring 3

- ________ ______ (xternal)

Enclosure L-11-166 Page 56 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-24 Page 3.3-444 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-24 as follows:

Table 3.3.2-24 Aging Management Review Results - Reactor Coolant Vent and Drain System Component Intended Aging Effect Aging NUREG-Row Row Typo Funtended Material Environment Requiring Management 1801, Table 1 Notes No. Type IFunction(s) Maaeet Management Program Porm2 Volume Item Item Pressure Stainless Treated A PiPinure Stele borated water Cracking TLAA VII.EI-16 3.3.1-02 0

--

• boundary Steel (Internal) 0338 Structural Stainless Treated A Pipin borated water Cracking TLAA VII.EI-16 3.3.1-02

-interty. Steel (Internal) 0338

Enclosure L-11-166 Page 57 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-25 Page 3.3-464 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-25 as follows:

Table 3.3.2-25 Aging Management Review Results - Sampling System Aging Effect Aging NUREG-Row Component Intended Mt 1801, Table I Notes No. Type Function(s) equiring Managemen Volume Item SManagement Program 2 Item Treated Structural Stainless borated water A Tubing i Steel > 60C (> Cracking TLAA VII.El-16 3.3.1 140F 0337 (Internal)

Treated Structural Stainless borated water A Valve Sodyv Steel > 60C (> Cracking TLAA VII.EI-16 3.3.1-02 140F) 0337 (Internal)

Enclosure L-11-166 Page 58 of 116 Affected LRA Section LRA Page No. Affected Paraqraph and Sentence Table 3.3.2-28 Page 3.3-502 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-28 as follows:

Table 3.3.2-28 Aging Management Review Results - Spent Resin Transfer System Component Intended Aging Effect Aging NUREG-Row Row Coponet Fnctiond Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Maaeeti rga Volume Item Management Program 2 Item Treated water Inspection of Flexible Structural Elt > 60WC Loss of Internal Surfaces in N/A N/A H

- Connection integrity (>140'F) material Miscellaneous (Internal) Piping and Ductinq Flexible Structural Air-indoor Loss of External Surfaces Connection integrity Euncontrolled material Monitoring 3

- _________ (LExternal)_ ____

Enclosure L-11-166 Page 59 of 116 Affected LRA Section LRA Pange No. Affected Paragraph and Sentence Table 3.3.2-30 Page 3.3-530 New Rows Based on the response to RAI 3.3.2.2.13-1, new rows are added to Table 3.3.2-30 as follows:

Table 3.3.2-30 Aging Management Review Results - Station Blackout Diesel Generator System Row Component Intended Aging Effect Aging NUREG-Row Type Intended Material Environment Requiring Management 1801, Table 1 Notes Management Program Volume Item 2 Item Inspection of Flexible Pressure Air-outdoor Loss of Internal Surfaces in N/A N/A H Connection boundary (Internal) material Miscellaneous Pipingand Ducting Flexible Pressure Elastomer Andor Loss of ExternalSurfaces VII.FI-5 3.3.1-34 E Connection boundary uncontrolled material Monitoring 3 (External)

Enclosure L-11-166 Page 60 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-30 Page 3.3-530 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.3.2-30 as follows:

Table 3.3.2-30 Aging Management Review Results - Station Blackout Diesel Generator System Row Component Intended Aging Effect Aging NUREG-Row Cmponen Fnctiond Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Maaemn Program P2 Volume Item Item Management Flexible Pressure Stainless Diesel exhaust Crackin TL N/A N/A H

- Connection boundary Steel (Internal) 0337 PrssreDiesel exhaustH

-- *boundary Pressure Steel (intel (Internal) Cracking TLAA N/A N/A 03 0337

"" *boundary Pressure Steel Air (Internal) Cracking"0337 TLAA N/A N/A H Silencer Pressure Steel Diesel exhaust Cracking TLAA N/A N/A H

- (exhaust) boundary (Internal) 0337 PrssreDiesel exhaustH Steel (intel Cracking TLAA N/A N/A 03

-- Tubing

-boundary Pressure (Internal) ' 0337 PrssreDiesel exha ustH

--Vle oy boundary Steel Dintel (Internal) Cracking TLAA N/A N/A 03 0337 Valve Bod Pressure

Enclosure L-11-166 Page 61 of 116 Affected LRA Section LRA Page No. Affected Paraaraph and Sentence Table 3.3.2-30 Page 3.3-517 Row 66 Based on the response to RAI 3.3.2-2, row 66 of Table 3.3.2-30 is revised to read:

Table 3.3.2-30 Aging Management Review Results - Station Blackout Diesel Generator System Aging Effect Aging NUREG-Row Component Intended Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Malagenent Management Manam Program Volume 2 Item Item Heat Exchanger Pressure Copper Air-outdoor NOne NI1e 66 (tubes) - boundary Alloy > (External) Loss of ExternalSurfaces N/A N/A G Radiator (DB- 15% Zn material Monitoring E211 )

Enclosure L-1 1-166 Page 62 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-30 Page 3.3-530 New Rows Based on the response to RAI 3.3.2-2, new rows are added to Table 3.3.2-30 as follows:

Table 3.3.2-30 Aging Management Review Results - Station Blackout Diesel Generator System Row No.

Component Type Tow Intended Funtended iFunction(s)

Material Environment Aging Effect Requiring Maaeet Aging Management PormVolume NUREG-1801, Table 1 Item Notes Management Program 2 Item Heat Exchanger Pressure Copper Air-outdoor External Surfaces

-- (tubes) - Alloy > (Exte al) Monitorin Radiator(DB- boundary 15% Zn E21 1)

Heat

-- (tubes)- Press-ure Coe Air-outdoor Loss of Selective Leaching N/A N/A G Radiator(DB- boundary 15% Zn (External) material Inspection N E21 15 (

Raiao __

Enclosure L-11-166 Page 63 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2-32 Page 3.3-544 New Row Based on the response to RAI 3.3.1.85-1, to address aging management for selective leaching for the gray cast iron heat exchanger shell in the startup feed pump lube oil cooler (DBE30), a new row is added to Table 3.3.2-32 as follows:

Table 3.3.2-32 Aging Management Review Results - Turbine Plant Cooling Water System SAging Effect Aging NUREG-Row Component Intended Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Malageneq nt Manam Volume Item Management Program 2 Item Heat Exchanger (shell) - Structural Gray Closed cycle Loss of Selective Leaching3

-- Startup feed cooling water atVIIF3-18 3.3.1-85 Q pump lube oil r Cast Iron (internal) rial Inspection cooler (DB-E30)

Enclosure L-11-166 Page 64 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2 Page 3.3-549 Plant Specific Note 0325 Plant-Specific Notes In response to RAI 3.3..2.3.12-1, Plant Specific Note No. 0325 in Table 3.3.2 "Plant-Specific Notes" is revised to read:

Plant-Specific Notes:

0325 The-..';'

a _~'_'"÷

.. F."

6*."! ...

n a lubricating oil environment a o

• p# in the air intake filter bodies in rof the diesel systems functions as filer media and is not monitored by the Lubricating Oil Analysis Program. Therefore, a plant-specific program is credited du to,,

÷,t h,* lr.,.,I-Jrepl,,,M I_4. O.f t'h, Ih,-11b ;i,..in oil.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2 Page 3.3-549 New Plant Specific Note 0336 Plant-Specific Notes In response to RAI 3.3.2.2.4.3-1 regarding cracking of stainless steel due to cyclic loading, new Plant Specific Note No. 0336 is added to Table 3.3.2 "Plant-Specific Notes" as follows:

Plant-Specific Notes:

0336 The One-Time Inspection will provide verification of the absence of cracking due to cyclic loading.

Enclosure L-11-166 Page 65 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.3.2 Page 3.3-549 New Plant-Specific Notes Plant-Specific Notes Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new plant-specific notes are added to Table 3.3.2 "Plant-Specific Notes" as follows:

Plant-Specific Notes:

0337 Fatigue TLAA is evaluated in LRA Section 4.3.3.1. for piping and (in-line) piping components.

0338 Piping and piping components in the Reactor Coolant Vent and Drain System may be exposed to temperaturesabove the threshold temperaturefor fatique, though normal operating temperaturesare below the threshold. Fatique TLAA is evaluated in LRA Section 4.3.3.1, for piping and (in-line) piping components.

0339 The raw water in the piping from the Fire Water Storage Tank Heat Exchanger to the Fire Water Storage Tank is Periodicallyat temperaturesthat exceed the threshold for fatique. Fatique TLAA is evaluated in LRA Section 4.3.3.1, for piping and (in-line) Piping components.

0340 The temperatureof gas vented from the reactorcoolant drain tank will exceed fatique thresholdtemperaturesimmediately after a safety valve or power operated relief valve lift. Fatigue TLAA is evaluated in LRA Section 4.3.3.1, for piping and (in-line) piping components.

0341 Conservatively, piping in the containment air systems can see temperaturesup to 264TF (i.e., following a desiqn basis transient),

which is above the threshold for fatique of steel components. Fatique TLAA is evaluatedin LRA Section 4.3.3.1. for piping and (in-line) piping components.

Enclosure L-11-166 Page 66 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.4.2-1 Page 3.4-53 New Row Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, a new row is added to Table 3.4.2-1 as follows:

Table 3.4.2-1 Aging Management Review Results - Auxiliary Feedwater System Row Component Intended AigEfc Aging Effect Aging gn NUREG-81 al Row Componen Fntendd Material Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Maaeet PormVolume Item Management Program _2 Item Treated water Pressure Steel > 60C (> Cracking TL VIG-37 3.4.1-01 A boundary 140F) I 0411 (Internal)

Enclosure L-11-166 Page 67 of 116 Affected LRA Section LRA Paae No. Affected Paragraph and Sentence Table 3.4.2-3 Page 3.4-69 Rows 68 and 140 Based on the response to RAI 3.4.2.3-1, to state that loss of material due to general corrosion will be managed by the External Surfaces Monitoring Program for the external surfaces of steel components in the Main Feedwater System which may be exposed to temperatures below 212°F (1000C), Rows 68 and 140 of Table 3.4.2-3 are revised to read:

Table 3.4.2-3 Aging Management Review Results - Main Feedwater System Component Intended Aging Effect Aging NUREG-Row Row Typo Funtended Material Environment Requiring Management 1801, Table I Notes No. Type IFunction(s) Maaemn Manaemen Proram Prga 2 Item Volume Item 68 Not used. bou.da.... St, 0408 Valv BG4 Pressur--e 4 140 Not used. b..ndar

.... Wo 0408

Enclosure L-11-166 Page 68 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.4.2-3 Page 3.4-80 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.4.2-3 as follows:

Table 3.4.2-3 Aging Management Review Results - Main Feedwater System Row No.

Component Type Intended Function(s)

Material Environment Aging Effect Requiring Maanlgememn Management Aging Management Proria rogram NUREG-1801, Volume 2 Item Table I Item J Notes Treated water Pressure Steel > 60C (> A Piin boundary 140F) Crackin TLAA VIII.D-7 3.4.1-01 0410 (Internal)

Treated water Pressure Stainless > 60C (> A Tubing boundary Steel 140F) Cracking TLAA VII.E3-14 3.3.1-02 410 (Internal)

Treated water Pressure Steel > 60C (> Crackin TLAA VIIDI-7 3.4.1-01 A Valve Body boundary 140F) 0410 (Internal)

Enclosure L-11-166 Page 69 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.4.2-4 Page 3.4-93 Various Rows Based on the response to RAI 3.4.2.3-1, to state that loss of material due to general corrosion will be managed by the External Surfaces Monitoring Program for the external surfaces of steel components in the Main Steam System which may be exposed to temperatures below 212'F (1OOC), various rows of Table 3.4.2-4 are revised to read:

Enclosure L-11-166 Page 70 of 116 Table 3.4.2-4 Aging Management Review Results - Main Steam System Row Component Intended Aging Effect Aging NUREG-No. Type Function(s) Material Environment Requiring Management 1801, Table I Notes

__ Management Program Volume Item 94 Trap Body Structural integrity Steel uncontrolled Loss of materialVIII.H-7 External Surfaces 2Item 3.4.1-28 A (External)

Pressure Air-indoor Loss of External Surfaces 3 142 Valve Body boundary Steel uncontrolled materialVIII.H-7 3.4.1-28 0405 (Internal) m4i 155 Valve Body Structural integrity Air-indoor Loss of External Surfaces 3 Steel uncontrolled mtraMoirngVIII.1--7 3.4.1-28 0405 (introll material Monitoring040

Enclosure L-11-166 Page 71 of 116 Affected LRA Section LRA Pagie No. Affected ParagraDh and Sentence Table 3.4.2-4 Page 3.4-109 Various Rows Based on the response to RAI 3.4.2.3-1, to state that loss of material due to general corrosion will be managed by the External Surfaces Monitoring Program for the external surfaces of steel components in the Main Steam System which may be exposed to temperatures below 212°F (1000C), rows that were added by LRA Amendment No. 5 in FENOC Letter L-11-131, dated 4/29/11, to Table 3.4.2-4 are revised to read:

Table 3.4.2-4 Aging Management Review Results - Main Feedwater System Row Component Intended Aging Effect Aging NUREG-Row Componen Fntendd Material Environment Requiring Management 1801, Table 1 No. Type Function(s) Notes Management Program Volume Item

_~ _ ~~~~~ ~ ~

_ __~~ _ _ _ _ _ _ I _ _ _ _ _ _Item _ _ __

Structural Air-indoor Loss of External Surfaces 3 Drain Pan integrity Steel uncontrolled materialVIII.H-7 3.4.1-28 0405 (Internal) material04M9 Structural Loss of External Surfaces A Drain Pan integrity Steel uncontrolled (External) materialVIII.H-7 material 3.4.1-28 Monitoring

Enclosure L-11-166 Page 72 of 116 Affected LRA Section LRA Page No. Affected Paracraah and Sentence Table 3.4.2-4 Page 3.4-109 New Rows Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new rows are added to Table 3.4.2-4 as follows:

Table 3.4.2-4 Aging Management Review Results - Main Steam System Row Component Intended Material Environment SAgiRequiring ng Effect Aging Management NUREG-1801, Table I Notes No. Type Function(s) Malagenent Manam Volume Item Management Program 2 Item Pressure Steam VIII.B1- A

"" __ boundary Steel (Inteal) Cracking TLAA 10 3.4.1-01 0410 Treated water Pressure Steel > 60C (> VIII.B1- 3.4.1-01 A

-- P boundary 140F) Cracking TLAA 10 01410 (Internal)

Structural Steam VIII.B1- A

-- Png Steel (Internal) Cracking TLAA 10 3.4.1-01 0410 Pressure Steam VIII.BI1- A boure Steel Steam Cracking TLAA 1._0 3.4.1 -- Trap Body boundary (Internal) 10 0410

-- Tubing Pressure Stainless Steam Cracking TLAA VII.E3-14 3.3.1-02 A boundary Steel (Internal) 01 Treated water Pressure Stainless > 60C (> Cracking TLAA VII.E3-14 3.3.1-02 A Tubing boundar Steel 140F) 0410 (Internal)

Enclosure L-11-166 Page 73 of 116 Row Row Component Typo Table 3.4.2-4 Intended Funtended Aging Management Review Results - Main Steam System Aging Effect Aging NUREG- I No. Type iFunction(s)

Material Environment jMangmn Requiring Management Management Program Prog2 1801, Volume Item Table I Item Notes Tubin Structural Stainless Steam Crackin T VIIE314 3.3.1-02 A inte.grity Steel (Internal) - 0cT4 410 Treated water Tubin Structural Stainless > 60C (> A integrity Steel 140F)

___0410 Cracking"__ TLAA VII.E3-14 3.3.1-02 A (Internal)

Pressure Stainless Steam A

-- Valve Sody boundary Steel (Internal) Cracking TLAA VII.E3-14 3.3.1-02 0410 Pressure Steam VIII.B1- A boundary Steel (Internal) Cracking TLAA 10 0410 Treated water Valve Sod Pressure Steel > 60C (> VIII.BI- 3.4.1-01 A

- Vleboundary 140F) Cracking TLAA 10 01410 (Internal)

Valve Body Structural integrit Steel Steam (Internal) Cracking TLAA VIII.

10 B 1- A

-- 3.4.1-01 0410

Enclosure L-11-166 Page 74 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.4.2 Page 3.4-111 Plant Specific Note Nos. 0408 and 0409 Plant-Specific Notes In response to RAI 3.4.2.3-1, Plant Specific Notes Nos. 0408 and 0409 of Table 3.4.2 "Plant-Specific Notes" are revised to read:

Plant-Specific Notes:

0408 Not used.

Except for the.e mo-tor dr-hvon feedwater*pump (MDFP) and staAp fged pump (S/I-FP p';ions of the Main Feedwater- System, the contrel air SUPPly comgponents a8sociate9d With the maRin an9d 6tart Up control valves, and boltng exposed to "asir- with Steam Or water leakage ' loss of matqrial due to gen-era croso is not an aging effect r-eqirn maagment for the exrtern-al SUrfacGes of steel compnePn@ts i n thie Ma-;in Feedwater- System that are exposed to the "air-i. unotold" because the sur-face tmpor~ature is.

"Gdo1r greater- than 21 nd the surface is eX-pected to b9 dhjxr.

qhrfoe, 0409 Not used.

This aging effect is applicable f,, cOMponeRtS With te,1 peratUrem Rnly ir e thAn 212*-F

Enclosure L-11-166 Page 75 of 116 Affected LRA Section LRA Page No. Affected Para-graph and Sentence Table 3.4.2 Page 3.4-111 New Plant-Specific Notes Plant-Specific Notes Based on the response to RAI 3.2.2.2.1-1, to include AMR line items for cracking due to fatigue evaluated by TLAA for steel and/or stainless steel (including cast austenitic stainless steel) piping and (in-line) piping components included in the fatigue evaluation of LRA Section 4.3.3.1, with a plant-specific note for clarity, new plant-specific notes are added to Table 3.4.2 "Plant-Specific Notes" as follows:

Plant-Specific Notes:

0410 Fatique TLAA is evaluated in LRA Section 4.3.3.1. for piping and (in-line) piping components.

0411 Fatigue TLAA is evaluated in LRA Section 4.3.3.1. for Piping (including in the Auxiliary FeedwaterSystem near the steam generators).

Enclosure L-11-166 Page 76 of 116 Affected LRA Section LRA Paae No. Affected Paraqraph and Sentence Table 3.5.2-1 Page 3.5-75 New Row Based on the response to RAI 3.3.1 74-1, a new row is added to Table 3.5.2-1 as follows:

Table 3.5.2-1 Aging Management Review Results - Containment component Intended Aging Effect Aging NUREG-Row Row Coponen Fnctiond Material Environment Requiring Management 1801, Table I Notes No. Type Function(s) Maaeet PormVolume Item Management Program 2 Item

--

--

__

Crane Rails

_re _

SNS, SSR

_aisSNS, S ICarbon Steel Air-indoor A dmaterial Loss of Cranes and Hoists Inspection I.B-1 VIIB-1 3.3.1-74 3.3.1-74 _

A Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 3.5.2-2 Page 3.5-85 New Row Based on the response to RAI 3.3.1.74-1, a new row is added to Table 3.5.2-2 as follows:

Table 3.5.2-2 Aging Management Review Results - Auxiliary Building Row Row Component Cmponen Intended Fnctiond Material IAging Environment Effect Requiring Aging Management NUREG-1801, Table I Notes No. Type Function(s) Maaeet PormVolume Item Management

_ Program 2 Item

-- Crane Rails

_a iSteel SNS, SSR ICarbon Air-indoor A omaterial Loss of Cranes and Hoists Inspection VIIB-1 3.3.1-74

_ _

A

Enclosure L-11-166 Page 77 of 116 Affected LRA Section LRA Pane No. Affected Paragraph and Sentence Table 3.5.2-3 Page 3.5-86 Row 2 Table 3.5.2-3 Page 3.5-93 New Row Based on the response to RAI 3.3.1.74-1, a typographical error is corrected in Row 2 and a new row is added to Table 3.5.2-3 as follows:

Table 3.5.2-3 Aging Management Review Results - Intake Structure, Forebay, and Service Water Discharge Structure Aging Effect Aging NUREG-RowMaterial Environment Requiring Management 1801, Table 1 Notes No. Type Function(s) Materiaent Manam Volume Item Management Program 2 Itemj Cranes, including 2 Bridge, SNS Carbon Air-outdoor Loss of Cranes and VII.B-3 =3.4-37 A Trolley, Steel material Hoists Inspection 3.3.1-73 0529 Rails, and Girders Crane Rails SNS Carbon Air-outdoor Loss of Cranesand VIIBi 33174 A

--

Steel material Hoists Inspection 0529

Enclosure L-11-166 Page 78of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table 4.1-1 (continued) Page 4.1-4 "High Pressure Injection / Makeup Nozzle Thermal Sleeves - life prediction" and "OTSG 1-2 flaw evaluations" row In response to RAI B.2.16-7, the "High Pressure Injection / Makeup Nozzle Thermal Sleeves - life prediction" and "OTSG 1-2 flaw evaluations" rows of Table 4.1-1 are revised to read:

54.21(c)(1) LRA Results of TLAA Evaluation by Category Paragraph Section High Pressure Injection / Makeup Nozzle (-#)-Not a TLAA 4.7.4 Thermal Sleeves - life prediction OTSG 1-2 flaw evaluations #q fL1 4.7.5.2 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 4.3.1.2 Page 4.3-1 Second paragraph, first sentence In response to RAI B.2.16-1, the first sentence of the second paragraph of Section 4.3.1.2 is revised to read:

Transients 22 A2 (HPI Nozzle 2-1), 22 A2 (HPI Nozzle 2-2)O, -9D, and 32 are the only transientsaffecting Class I components where the 60-year projected cycles exceed the design cycles, and are discussed in some detailbelow.

Enclosure L-11-166 Page 79 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 4.3.1.2 Page 4.3-1 "Transient 9 (A through D)"

subsection In response to MAl B.2.16-1, the "Transient 9 (A through D)" subsection of Section 4.3.1.2 is revised to read:

Transient 22 A29 (A0 4 .th. gh P).

Transient 22 A2 counts HPI flow tests individually for each of the four HPI/makeup nozzles. In addition, RCS Rapid Depressurizationevents (Transients No. 9A and 9B) are included in the count for Transient Number 22 A2. Both transients cause temperature swings on the HPI nozzles. Transien 9 origially countod rapid dopressurizations of the RCS becauso ofth tomperatur-e transients a rapid doprossurizmatio-n wo90Uld impose on the high pressUro ;,injton -HPIl/makup no.zz.es.

It was

.. c.gni.ed

.... that HPI t..'g also caused temperatur swngo theg URI nozLEs, of fl9w teting 9nayce wore added to this event. Today this transien~t counflts URI flow4 te-stS individually for each of the four- HPI/makoup nozzles.

Forty (40) cycles of HPI flow testing were analyzed to determine the effect of HPI flow testing on the cumulative usage factor (CUF) of the HPI nozzles. See Section 4.3.2.3.1 below for discussion of the HPI/makeup nozzle CUFs. The analysis of the HPI nozzles determined that the elbowlets in HPI nozzles 1-1 and 1-2 were limited to 13 cycles each, Transient

• and- -B, r-eapectively.

Davis-Besse is currently monitoring these nozzles against a limit of 13 design cycles. Current cycles are at 9 and 8 for nozzles 1-1 and 1-2, respectively.

Current test practicesdo not cycle these nozzles and the 60-year proiected cycles for these nozzles are bounded by the 13 cycle limit ,";.,v. ..... ,9v9GG_

an, th÷*'a, the cycles W.. lengain at the currant levels1 forF 40 years an or6 ears oe GpeFaftgn.

HPI nozzles 2-1 and 2-2 are limited to 40 cycles; Transients 22 A2 (HPI Nozzle 2-1) and 22 A2 (HPI Nozzle 2-2)--9C,-and D, respectively. Current test practices cycle these nozzles. The 60-year cycle projection for these nozzles exceeds the design cycle number of 40. Because these nozzles may be reanalyzed for other reasons such as the planned modification to replace the nozzle safe ends and thermal sleeves, Davis-Besse will manage fatigue of these nozzles for the period of extended operation rather than reanalyze for the possible additional cycles at this time. Davis-Besse has committed (see Appendix A) to replace the nozzle safe ends and thermal sleeves prior to the period of extended operation rather than reanalyze for the possible additional cycles.

Enclosure L-11-166 Page 80 of 116 Affected LRA Section LRA Pane No. Affected Paragraph and Sentence Table 4.3-1 Page 4.3-3 Entire table Based on the response to RAI B.2.16-1, Table 4.3-1 is replaced in its entirety to read:

Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Design Transient Transient Cycles To Projection Cycles Notes

1. 2/19/2008 Cycles 1 A RCS Heatup from 70F to 8% Full Power 65 128 240 None (Normal) [USAR Transient # 1A]

1 B RCS Cooldown from 8% Full Power (Normal) 64 128 240 As Davis-Besse was operating at the time of the latest

[USAR Transient # 1B] cycle count, there is one more heatup than cooldown.

To reflect complete cycles, the cooldown projection was raised to match the heatup projection.

1 C Natural Circulation Cooldown (Emergency) 1 2 20 None

[USAR Transient # 1C]

2 A Power change 0 to 15% (Normal) 104 205 1440 None

[USAR Transient # 2]

2 B Power change 15 to 0% (Normal) 48 94 1440 None

[USAR Transient # 2]

3 Power Loading 8% to 100% (Normal) NA NA 1800 Transient cycles are not counted due to large number of

[USAR Transient # 3] design cycles. Davis-Besse is not a load following plant and therefore; transients 3 and 4 could not credibly 4 Power Unloading 100-8% (Normal) NA NA 1800 approach the number of design cycles during the period

[USAR Transient # 4] of extended operation.

5 10% Step Load Increase (Normal) 34 67 8000 None

[USAR Transient # 5]

6 10% Step Load Decrease (Normal) 71 140 8000 None

[USAR Transient # 6]

Enclosure L-1 1-166 Page 81 of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Transient Transient Cycles To Projection esNotes

1. 2/19/2008 Cycles Cycles 7 A Step Load Reduction 100-8% from Turbine 4 8 160 None Trip (Upset)

[USAR Transient # 7A]

7 B Step Load Reduction 100-8% from Electrical 2 4 150 None Load Rejection (Upset)

[USAR Transient # 7B]3 8 A Reactor Trip - Low RCS flow directly causes 2 4 40 None Rx trip (Upset)

[USAR Transient # 8A]

8 B Reactor Trip - High RCS outlet temperature, 24 47 160 None high RCS pressure or overpower trip (assumes a turbine trip occurs without automatic control system action) (Upset)

[USAR Transient # 8B]

8 C Reactor Trip - High RCS pressure resulting 13 26 88 None from loss of feedwater (Upset)

[USAR Transient # 8C]

8 D Reactor Trip - Other trips, including the 56 110 112 None following (Upset):

(1) Any reactor trip which meets the definition of another transient classification (e.g.,

Transients 11, 15, 16, and 17) will also be recorded under 8D.

(2) Any reactor trip which does not fit into any other category will be classified 8D.

[USAR Transient # 8D]

8 E Reactor Trip - Similar to 8A but RC pumps 0 20 20 Transient 8E has not occurred; therefore the are tripped (emergency) mathematical projection is zero. The number of 60-year

[USAR Transient # 8E] projected cycles has been set to the number of design cycles to allow for future occurrence.

9 A Rapid RCS Depressurization (Upset) 2 4 40 None

[USAR Transient # 9A] I

Enclosure L-11-166 Page 82 of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Transient Transient Cycles To Projection DesignNotes

1. 2/19/2008 Cycles Cycles 9 B Rapid RCS Depressurization, trip RC Pumps 0 10 10 Transient 9B has not occurred; therefore the (Emergency) mathematical projection is zero. The number of 60-year

[USAR Transient # 9B] projected cycles has been set to the number of design cycles to allow for future occurrence.

10 Change of reactor coolant flow (typical 5 10 20 None change of flow transient is loss of one RCP) without Reactor Trip (Upset)

[USAR Transient # 10]

11 Rod withdrawal accident (Upset) 0 40 40 Transient 11 has not occurred; therefore the

[USAR Transient # 111 mathematical projection is zero. The number of 60-year projected cycles has been set to the number of design cycles to allow for future occurrence.

12 A Hydrotest - RCS components except OTSG 7 9 20 In addition to the 2 field tests that have been performed, Secondary (includes 5 shop tests) (Test) 5 shop tests are included with the number of accrued

[USAR Transient # 12A] cycles and with the number of 60-year projected cycles.

12 B Hydrotest- OTSG Secondary (includes 10 12 14 35 In addition to the 2 field tests that have been performed, shop tests) (Test) 10 shop tests are included with the number of accrued

[USAR Transient # 12B] cycles and with the number of 60-year projected cycles.

13 Deleted. (formally applicable to Steady State NA NA N/A None Power Variations)

[USAR Transient # 13]

14 Control Rod Drop (Upset) 9 18 40 None

[USAR Transient # 14]

15 Loss of Station Power (Upset) 3 6 40 None

[USAR Transient # 15]

16 Steam Line Failure (Faulted) 0 NA 1 Steam line failure is not considered in fatigue evaluations.

[USAR Transient # 16] 1Therefore, projected cycles are not provided.

17 A Steam Generator Boiling Dry from loss of 3 6 20 None feedwater to one steam generator (Upset)

[USAR Transient # 17A]

Enclosure L-11-166 Page 83of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Design Transient Transient Cycles To Projection Design Notes

1. 2119/2008 Cycles Cycles 17 B Steam Generator Boiling Dry from stuck 1 NA 10 Transient 17B is an emergency condition and is not open turbine bypass valve (Emergency) considered in fatigue evaluations; therefore, it is not

[USAR Transient # 17B] necessary to project cycles.

18 Loss of Feedwater Heater (Upset) 0 40 40 Transient 18 has not occurred; therefore the

[USAR Transient # 18] mathematical projection is zero. The number of 60-year projected cycles has been set to the number of design cycles to allow for future occurrence.

19 Feed and Bleed Operations (Normal) NA NA 4000 Transient cycles are not counted due to large number of USAR Transient # 19] design cycles.

20 A Makeup flow Transient 1 (Normal) NA NA 30000

[USAR Transient # 20A]

20 B Makeup flow Transient 2 (Normal) NA NA 4.OE+6 Transient cycles are not counted due to large number of

[USAR Transient # 20B] design cycles.

20 C Spray Valve/Pressurizer Spray Nozzle NA NA 20000 (Normal)

[USAR Transient # 20C]

21 Loss of Coolant Accident (LOCA) (Faulted) 0 NA 1 Transients 21 is a faulted condition and is not

[USAR Transient # 21] considered in fatigue evaluations. Therefore, projected cycles are not provided.

22 Al Test Transients - High Pressure Injection NA NA 40 Transient 22A is not applicable to Davis-Besse. High System (Normal) pressure injection pumps recirculate back to the

[USAR Transient # 22A1] Borated Water Storage Tank during the High Pressure Injection System Test and therefore, no inventory is added to the Reactor Coolant System.

Enclosure L-11-166 Page 84 of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Transient Transient Cycles To Projection DesignNotes

1. 2/19/2008 Cycles Cycles 22 A2 Test Transient - HPI System Pressure 9 11 13 Both HPI System Pressure Isolation Integrity Tests and Isolation Integrity Test HPI Nozzle 1-1 RCS Rapid Depressurization events (Transients No. 9A (Normal) and 9B) are included in the count for Transient Number

[USAR Transient # 22A2] 22A2.

22 A2 Test Transient - HPI System Pressure 8 10 13 Isolation Integrity Test HPI Nozzle 1-2 The projection rate of future cycles for HPI Nozzles 1-1, (Normal) 1-2, 2-1 and 2-2 are based on the five-year period from

[USAR Transient # 22A2] 1/25/2003 to 2/19/2008, to include only the current test methodology. Accrued cycles as of 1/25/2003 for HPI Nozzles 1-1, 1-2, 2-1 and 2-2 were respectively 9, 8, 17, and 14. This current test methodology does not cycle nozzles 1-1 and 1-2. Therefore the 60-year projection cycles for HPI Nozzles 1-1 and 1-2 are equal to the cycles that occurred before 1/25/2003 plus the two occurrences of rapid RCS Rapid Depressurization events (See Transient Number 9A).

22 A2 Test Transient - HPI System Pressure 21 44 40 60-year projected cycles for HPI Nozzles 2-1 and 2-2 Isolation Integrity Test HPI Nozzle 2-1 are projected to exceed the number of design cycles.

(Normal) See LRA Table A-i, commitment number 23.

[USAR Transient # 22A2]

22 A2 Test Transient - HPI System Pressure 19 48 40 Isolation Integrity Test HPI Nozzle 2-2 (Normal)

[USAR Transient # 22A2]

22 B Test Transient - Core flooding check valve 1- 13 26 240 None 1 (Normal)

[USAR Transient # 22B]

22 B Test Transient - Core flooding check valve 1- 13 26 240 None 2 (Normal)

[USAR Transient # 22B]

Enclosure L-11-166 Page 85 of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Design Transient Transient Cycles To Projection Design Notes

1. 2/19/2008 Cycles Cycles 23 A Steam generator secondary side filling NA NA 120 Steam generator secondary side filling is not counted as (Condition 1) (Normal) it is not a fatigue significant event.

[USAR Transient # 23A]

23 A Steam generator secondary side filling NA NA 120 Condition 1: Primary side: <200 'F, 0 - 485 psig; (Condition 2) (Normal) Secondary side" >140 'F, 0 psig; Feedwater: 50 - 225

[USAR Transient # 23A] °F Condition 2: Primary side: <120 'F, 0 - 485 psig; Secondary side: ?60 °F, 0 psig; Feedwater: 50 - 225

°F 23 B Steam generator primary side filling NA NA 120 Steam generator primary side filling is not counted as it (Condition 1) (Normal) is not a fatigue significant event.

[USAR Transient # 23B]

23 B Steam generator primary side filling NA NA 120 Condition 1: Primary fill water: 50 'F, 0 psig; Secondary (Condition 2) (Normal) side: 140 °F, 0 psig

[USAR Transient # 23B]

Condition 2: Primary fill water: 140 °F, 0 psig; Secondary side: 50 °F, 0 psig 23 C Steam generator flush (Normal) NA NA 40 Steam generator flush is not counted as it is not a fatigue

[USAR Transient # 23C] significant event.

23 D Steam generator chemical cleaning (Normal) NA NA 20 Steam generator chemical cleaning is not counted as it

[USAR Transient # 23D] is not a fatigue significant event.

24 Hot Functional Testing (Normal) 1 1 1 There will be no further Hot Functional Tests; therefore

[USAR Transient # 24] Transient 24 projection is zero additional cycles.

25 A Pressurizer Heaters NA NA 5000 Pressurizer heater cycles are not counted as they are 25 B Pressurizer Heaters NA NA 20000 not fatigue events.

26 A Pressurizer Code Safeties 0 30 30 Transient 26A has not occurred; therefore the mathematical projection is zero. The number of 60-year projected cycles has been set to the number of design cycles to allow for future occurrence.

26 B Pressurizer Electromatic Relief >=4000 F 49 96 270 None

Enclosure L-1 1-166 Page 86 of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Design Transient Transient Cycles To Projection Notes

1. 2119/2008 Cycles Cycles 26 C Pressurizer Electromatic Relief < 4000 F 21 25 25 No cycles have been accrued for Transient 26C in the last 20 years due to plant modifications to keep the loop seal continuously drained and prevent this transient from occurring. Therefore, the number of 60-year projected cycles is set to the number of design cycles.

27 Generator Abnormal Frequency 0 NA 1 Generator abnormal frequency is not considered in fatigue evaluations. Therefore, projected cycles are not I _provided.

28 Maximum Probable Earthquake (Upset) 0 650 650 The OBE allowable of 650 cycles assumes 30

[USAR Table 5.1-8, footnote number 1] earthquakes with a total of 650 cycles. Transient 28 has not occurred; therefore the mathematical projection is zero. The number of 60-year projected cycles has been set to the number of design cycles to allow for future occurrence.

29 Pressurizer Spray Nozzle and Spray Line 5 10 25 None Delta Temperature >3000 F 30 A Auxiliary Feedwater Bolted Nozzle 1-1 196.5 387 875 An RCS heatup and cooldown is considered to be one 30 B Auxiliary Feedwater Bolted Nozzle 1-2 224.5 442 875 transient cycle. Bolting/unbolting of the nozzles is considered to be one transient cycle. Also, an event or procedure that initiates AFW to the steam generator is analyzed for a transient cycle.

31 A Permanent Canal Seal Plate 7.5 51 50 The permanent canal seal plate was installed on (Heatup/Cooldown) 1/25/2003. Transient 31A is counted from that date. A Reactor Coolant System heatup and cooldown is one transient cycle. Transient 31A is projected to exceed the number of design cycles prior to the end of the period of extended operation. Davis-Besse manages fatigue of this plate using the Fatigue Monitoring Program.

Enclosure L-11-166 Page 87 of 116 Table 4.3-1 60-Year Projected Cycles Program Accrued 60-year Design Transient Transient Cycles To Projection Design Notes

1. 2/19/2008 Cycles Cycles 31 B Permanent Canal Seal Plate (Operating 0 50 50 Transient 31 has not occurred; therefore the Basis Earthquake) (Upset) mathematical projection is zero. The number of 60-year projected cycles has been set to the number of design cycles to allow for future occurrence.

32 OTSG Welded Plug (limiting plug is Remote 17.5 64 33 The limiting plug (remote welded plug 2A) was installed Welded Plug 2A 79-68) (Heatup/Cooldown) on 5/23/2003. A Reactor Coolant System heatup and cooldown is one transient cycle. Transient 32 is projected to exceed the number of design cycles prior to the end of the period of extended operation. Davis-Besse manages fatigue of these plugs using the Fatigue Monitoring Program.

33 Decay Heat Removal Swapping Transient N/A N/A 20 The significant transients which affect the restrictor and (Normal) weld of the core flood nozzles are heatup and cooldown

[USAR Transient # 25] (transient numbers 1A and 1B), core flooding system periodic test (transient number 22B), and decay heat removal (DHR) swapping (transient number 33). For transient number 33, the transient cycles are not counted. The DHR Swapping Transient was established to address historical practices related to the DHR train swap. Current Davis-Besse procedures dictate that the RCPs are run during plant cooldown to approximately 160*F RCS temperature. The DHR trains are not swapped until the RCS temperature has been significantly reduced and therefore, a DHR Swapping Transient does not occur.

Enclosure L-11-166 Page 88 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 4.7.4 Page 4.7-5 Second paragraph and "Disposition" subsection In response to RAI B.2.16-7, the second paragraph and the "Disposition" subsection of Section 4.7.4 are revised to read:

Since that analysis, Davis-Besse had an extended (approximately two year)

Cycle 13 refueling outage, converted to a 24-month fuel cycle, and performed a measurement uncertainty recapture power uprate. The correspondingpredicted end-of-life for the HPI/makeup nozzle thermal sleeve is approximately 2022, based on the predictednumber of makeup thermal cycles. The current operating license for Davis-Besse will expire in April of 2017. Davis-Besse will replace all four HPI/makeup nozzle thermal sleeves prior to the period of extended operation.The commitment to replace these thermal sleeves is found in Appendix A to this application.

Disposition: Not a TLAA Cracr-king of the HPI/makeup thermal 160 CER _54.24(()9 slee11, will b49 mranaged n ,e fhrough the peried of extended operation by the FatigUe Monitoring Pro9gram. In addition, a-Based on this commitment, the HPI/makeup nozzle thermal sleeves are short lived (not 40-year)dparts and therefore this analysis is not a TLAA.

The FENOC commitment to replace the thermal sleeves prior to the period of extended operation is containedin Appendix A of the License Renewal Application.

Enclosure L-11-166 Page 89 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence 4.7.5.2 Page 4.7-6 Second paragraph and "Disposition" subsection In response to RAI B.2.16-7, the second paragraph and the "Disposition" subsection of Section 4.7.5.2 are revised to read:

Simplified evaluation of fatigue crack growth, based on 240 heatup and cooldown cycles, concluded that there would be only slight crack growth, and the indications were found to be acceptable by ASME Section XI, IWB-3612 standards. Because these analyses are based on a specific number of cycles, they are TLAAs. The Fatigue M.nitoring. Program, anages the effects of fatigue on steam geneart flaw evaluations b t t h4e thermal cycl.s icRUrred As shown in LRA Table 4.3-1, the 60-year proiected cycles for heatup and cooldown are 128 and are bounded by the analyzed number of 240. Therefore, the steam generatorflaw growth analyses will remain valid through the period of extended operation.

Disposition: 10 CFR 54.21(c)(1)49fJ, Thee "rff,-Qcts of fatigue on the..ste.am generator- Afa grow~th I IA)il be managed 9fothe periGd Of @exteded operation by the Fatigue Montoing Pr;gram... The steam generatorflaw growth analyses will remain valid throuqh the period of extended operation.

Enclosure L-11-166 Page 90 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.1 Page A-9 Second paragraph, last sentence The Quality Assurance Program applies to aging management programs for safety-related and nonsafety-related structures and components determined to require aging management for the period of extended operation. Based on the response to RAI 3.0, the last sentence of the second paragraph of Section A.1 is revised to read:

The corrective actions, confirmation process,and administrative controls in the QualityAssurance ProgramManual, to be applied to the credited aging management programs and activities for safety-related and nonsafety-relatedthe structures and components determined to require aging management, are consistent with the related discussionsin the Appendix on QualityAssurance for Aging Management Programsin NUREG-1801, Volume 2.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.1.15 Page A-14 Third paragraph In response to RAI 3.3.2.2.13-1, the third paragraph of Section A.1.15 is revised to read:

Also, the External Surfaces Monitoring Program,supplemented by the Inspection of Internal Surfaces of Miscellaneous Pipingand Ducting Program,includes inspection and surveillance of elastomersand polymers that are exposed to air-indoor uncontrolled and air-outdoorenvironments, but are not replacedon a set frequency or interval (i.e., are long-lived), for evidence of cracking and change in materialproperties (hardeningand loss of strength), and loss of materialdue to wear.

Enclosure L-11-166 Page 91 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.1.15 Page A-14 First paragraph In response to RAI 3.3.2-2, the first paragraph of Section A.1.15 is revised to read:

The External Surfaces Monitoring Programis a condition monitoring program that consists of periodic visual inspections and surveillance activities of in-scope mechanical component external surfaces to manage crackinQ and loss of material, including loss of material for internalsurfaces where the environment is the same as the external environment.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.1.16 Page A-14 Entire section In response to RAIs B.2.16-1, B.2.16-3, B.2.16-4, B.2.16-5, B.2.16-6 and B.2.16-7, Section A.1.16 is replaced in its entirety to read:

The Fatigue Monitoring Program manages fatigue of select primary and secondary components, including the reactor vessel, reactor internals, pressurizer, and steam generators by monitoring and tracking the number of critical thermal and pressure transients as required by Technical Specification 5.5.5, "Allowable Operating Transient Cycles Program." The scope includes those components that have been identified to have a fatigue TLAA.

The program prevents the fatigue TLAAs from becoming invalid by assuring that the fatigue usage resulting from actual operational transients does not exceed the Code design limit of 1.0, including environmental effects where applicable.

The program uses the systematic counting of transient cycles and the evaluation of operating data to ensure that the allowable cycle limits are not exceeded, thereby ensuring that component fatigue usage limits are not exceeded.

Transient documentation is updated at least once per plant operating cycle.

When the accumulated cycles approach the allowable cycles, corrective action is taken that includes an engineering evaluation to ensure the Code design limit of 1.0 is not exceeded. The program provides for updates of the fatigue usage calculations on an as-needed basis if an allowable cycle limit is approached.

When the number of accrued cycles is within 75% of the allowable cycle limit for

Enclosure L-11-166 Page 92 of 116 any transient, a condition report shall be generated. For transient cycles that are projected to exceed the allowable cycle limit by the end of the next plant operating cycle (Davis-Besse operating cycles are normally two years in duration), the program requires an update of the fatigue usage calculation for the affected component(s). Acceptance criterion is to maintain the cumulative fatigue usage below the Code design limit of 1.0 through the period of extended operation, including environmental effects where applicable.

For license renewal, the effects of the reactor coolant environment on component fatigue life have been addressed by assessing the impact of the environment on a sample of critical components as identified in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components." Environmental effects were evaluated 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." Components identified in NUREG/CR-6260 were evaluated using material specific guidance presented in NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low Alloy Steels," and in NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels." Nickel-based alloy components were evaluated using material specific guidance presented in NUREG/CR-6909, "Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials."

In addition, the Fatigue Monitoring Program will evaluate additional plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than those considered in NUREG/CR-6260. This evaluation will include identification of the most limiting fatigue location exposed to reactor coolant for each material type (i.e., CS, LAS, SS, and NBA) and that each bounding material/location will be evaluated for the effects of the reactor coolant environment on fatigue usage. Nickel-based alloy items will be evaluated using NUREG/CR-6909. This evaluation will be submitted to the NRC one year prior to the period of extended operation.

Enclosure L-11-166 Page 93 of 116 Affected LRA Section LRA Page No. Affected Para-raph and Sentence A.1.26 Page A-18 First paragraph, second sentence In response to RAI 3.4.2.2.5-1, to include loss of material due to selective leaching in the program description for the Lubricating Oil Analysis Program, the second sentence of the first paragraph of Section A.1.26 is revised to read:

The program requiresmanagement of the relevant conditions that could lead to the onset and propagationof loss of materialdue to crevice, galvanic, general, or pitting corrosion, selective leaching, or reduction in heat transfer due to fouling, through monitoring of the lubricatingoil consistent with various manufacturers' recommendationsand industry standards.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.1.36 Page A-23 First sentence In response to RAI 3.3.2-2, the first sentence of Section A.1.36 is revised to read:

The Selective Leaching Inspection detects and characterizesthe conditions on internaland external surfaces of subject components exposed to air-outdoor,raw water, treated water, soil, and moist air (including condensation) environments.

Enclosure L-11-166 Page 94 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.1.41 Page A-25 First paragraph In response to RAIs 3.3.2.2.13-1 and 3.3.2.3.12-1, the first paragraph of Section A.1.41 is revised to read:

The Inspection of InternalSurfaces in Miscellaneous Pipingand Ducting Program manages loss of material, cracking, and reduction in heat transfer of aluminum, copper alloy (including copper alloy with greaterthan 15 percent zinc), stainless steel, and steel (includinggray cast iron) components that are exposed to air, condensation, diesel exhaust, lubricatingoil, or moist air. The program also manages hardeningand loss of strength of non-metallic, flexible (elastomeric) components, and loss of materialdue to wear.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.2.6.2 Page A-46 Third paragraph In response to RAI B.2.16-7, the third paragraph of Section A.2.6.2 is revised to read:

The effectS of fatigue on the ateam ganerQatr flaw14 evalutions wXil be managed by the Fatigue M.nitorng Progra.m for the pe..od of extended operationin

.ccrdance wi.t*h 10,GCFM 54.2.1(c()'*.; The 60-year Droiected cycles for 0GR heatup and cooldown are 128 and are bounded by the analyzed number of 240. Therefore, the analyses of the steam generatorflaw growth will remain valid throuqh the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

Enclosure L-11-166 Page 95 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence A.2.7.4 Page A-49 Second and third paragraph In response to RAI B.2.16-7, the second and third paragraphs of Section A.2.7.4 are revised to read:

Since that analysis, Davis-Besse had an extended (approximately two year)

Cycle 13 refueling outage, converted to a 24-month fuel cycle, and performed a measurement uncertainty recapture power uprate. The corresponding predicted end-of-life for the HPI/MU nozzle thermal sleeve is approximately 2022, based on the predicted number of makeup thermal cycles. The current operating license for Davis-Besse will expire in April of 2017. However, FENOC has committed (see Table A-I, Item 23) to replace the HPI/MU nozzle safe end and associated

.Aey 92:!92 w/e/ thermal sleeves for all four HPI nozzles prior to entering the period of extended operation.

T-he TL" asAsociatedG Wilthrarc1nking of the high pressure

• nVjGtion / makeup nozzle thermal l/eevesP wMil b managed by the Fatigue Monitoring Pr;,gram, fo the period of extended oprFation in accordance w!t4I OCFR 54.21%cq(I)Cq)

Based on this commitment, the HPI/makeup nozzle thermal sleeves are short lived (not 40-year) Darts and therefore this analysis is not a TLAA.

Enclosure L-11-166 Page 96 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table A-1 Page A-59 Commitment No. 8 Based on the response to RAI 3.3.2-2, the following enhancement is added to license renewal future Commitment 8 in LRA Table A-i, "Davis-Besse License Renewal Commitments:"

Table A-1 Davis-Besse License Renewal Commitments Item ImplementationRead A Number Commitment Schedule Source Section No./

Comments 8

• Manage cracking of copper alloys with greaterthan 15 percent Priorto LRA A.1.15 zinc and stainless steel components exposed to an outdoor air April 22, 2017 B.2.15 environment through plant system inspections and walkdowns for evidence of leakage. Specify acceptance criteria of no FENOC Response to unacceptable visual indicationsof cracks that would lead to Letter NRC RAI loss of function priorto the next scheduled inspection. L-11-166 3.3.2-2 from NRC Letter dated May 2, 2011

Enclosure L-11-166 Page 97 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table A-1 Page A-59 Commitment No. 9 Based on the responses to RAI B.2.16-3, B.2.16-4 and B.2.16-5, the existing enhancements are deleted and two new enhancements are added to license renewal future Commitment 9 in LRA Table A-i, "Davis-Besse License Renewal Commitments," as follows:

Table A-1 Davis-Besse License Renewal Commitments Item Implementation Related LRA Iter Number Commitment Sheme Schedule Source Section Cmet No./

Comments 9 Enhance the Fatigue Monitoring Program to: Priorto LRA A.1.16

" For locations,, including N1 (DREG,4 locations, p...ectod

,G,6260 April 22, 2017 B.2.16 to exceed a Gum.ulat.ve usage factor (*UF of 1..0, the pr-og.am FENOC Responsesnto wil implement one or,Imo-r of thin folowing.: (1) Refine the Lte R A

.... .......................

f.tigue analyses =......

to dotormin. valid QC19s .Ie th'n.0.....g Letter L-11-166 NRC RAI B.2.16-3, an NRC app.ov.d ver.ion of the ASME= cd. o. NRC approved B. 2.16-4 and alternative (e.g., NRC approved .......... code*v' case),

"'/ (2)

' Manage. the9

• /......* ... B.2. 16-5 from B.2.16-4 andm effect.s of aging due to fatigue at the affeted.locations by a NRC Letter insction pro.g.am that has been roview.d and approved b. dated th . (IC . .di nn dcctructiv. examination of thoe April20, 2011 affectedloaions -"-P.at inspotion intepmias tobe determined by a method acceptablo to the NRC), (3 Repair or-replac.ment o

" M.oe*n.ito*r any transient where the 60 year preted cyls we,.

used in an environmentally assistd fatigue evaluation and establish an administrative limit that is equal to or loss than the 60 year-prolected cycles.

Enclosure L-1 1-166 Page 98 of 116 Table A-1 Davis-Besse License Renewal Commitments Related LRA Item Commitment Implementation Source Section No./

Number Schedule Cmet Comments

• Provide for updates of the fatigue usage calculationson an as-needed basis if an allowable cycle limit is approached.

When the number of accrued cycles is within 75% of the allowable cycle limit for any transient,a condition report will be generated.For any transientwhose cycles are proiected to exceed the allowable cycle limit by the end of the next plant operating cycle (Davis-Besse operating cycles are normally two years in duration), the program will require an update of the fatigue usage calculation for the affected component(s).

• Establish an acceptance criterion for maintainingthe cumulative fatique usage below the Code desiqn limit of 1.0 through the period of extended operation, including environmental effects where applicable.

Enclosure L-11-166 Page 99 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table A-1 Page A-63 Commitment No. 13 Based on the response to RAI 3.3.2.2.4.3-1, license renewal future Commitment 13 in LRA Table A-I, "Davis-Besse License Renewal Commitments," is revised as follows:

Table A-1 Davis-Besse License Renewal Commitments Item I T~~~ImplementationRead Related LRAA Item Commitment SIpeme Source Section No./

Number Schedule Cmet Comments 13 Implement the One-Time Inspection as described in LRA Section Priorto LRA A. 1.30 B.2.30. Enhance the One-Time Inspection to: April 22, 2017 B.2.30 0 Include visual and volumetric inspections to detect and FENOC Response to characterize cracking of copper alloy > 15% zinc exposed to raw Letter NRC RAI water. The one-time inspections will provide direct evidence as L-11-166 3.3.2.2.4.3-1 to whether, and to what extent, cracking has occurred. Cracking from NRC of copper alloy > 15% zinc exposed to raw water is not Letter dated addressed by another aging management program.

May 2, 2011

• Include visual inspections to detect and characterize cracking due to cyclic loading of the stainless steel makeup pump casings (DB-P37-1 and 2) of the Makeup and Purification System. The one-time inspections will provide verification of the absence of cracking due to cyclic loading.

Enclosure L-11-166 Page 100 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table A-1 Page A-69 Commitment No. 24 Based on the response to RAI 3.0, license renewal future Commitment 24 in LRA Table A-I, "Davis-Besse License Renewal Commitments," is revised as follows:

Table A-1 Davis-Besse License Renewal Commitments Item Number j

e Commitment IRelated Implementation Schedule Source LRA Section No./

Cmet Comments 24 The elements of corrective actions, confirmation process, and Priorto LRA A. 1 administrativecontrols in the Quality Assurance ProgramManual April 22, 2017 Response to will be applied to the credited aging management programsand NRC RAI 3.0 activities for safety-related and nonsafety-related#hestructures and FENOC from NRC components determined to require aging management for the Letter Letter dated period of extended operation. L-11-166 May 2. 2011

Enclosure L-11-166 Page 101 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence Table A-1 Page A-69 New Commitment Based on the response to RAI 3.3.2.3.12-2, a new license renewal future Commitment is added to LRA Table A-I, "Davis-Besse License Renewal Commitments," as follows:

Table A-1 Davis-Besse License Renewal Commitments m Im Related LRA Item Commitment Implementation Source Section No./

Number Schedule Cmet Comments 41 Establish a preventive maintenance task to Periodicallyreplace the Priorto FENOC Response to flexible connections exposed to fuel oil in the Fuel Oil System. April 22, 2017 Letter NRC RAI L-11-166 3.3.2.3.12-2 from NRC Letter dated May 2, 2011

Enclosure L-11-166 Page 102 of 116 Affected LRA Section LRA Page No. Affected ParaaraDh and Sentence Table A-1 Page A-69 New Commitment Based on the response to RAI B.2.16-2, the following enhancement is added as a new license renewal future commitment in LRA Table A-i, "Davis-Besse License Renewal Commitments." This new commitment is not included with the other Fatigue Monitoring Program enhancements in Commitment 9 because the Implementation Schedule date is one year prior to entering the period of extended operation. LRA Table A-1 is revised to read:

Table A-1 Davis-Besse License Renewal Commitments Item Im Related LRA Iter Commitment Imp le Source Section No./

Comments 42 Enhance the Fatique Monitoring Programto: Priorto FENOC Response to April 22, 2016 Letter NRC RAI

. Evaluate additionalplant-specific component locations in the reactorcoolant pressureboundary that may be more limitinq L-11-166 B. 2.16-2 from than those consideredin NUREG/CR-6260. This evaluation NRC Letter dated will include identification of the most limiting fatique location April 20, 2011 exposed to reactorcoolant for each material type (i.e., CS, LAS, SS, and NBA) and that each bounding material/location will be evaluated for the effects of the reactorcoolant environment on fatique usage. Nickel based alloy items will be evaluated using NUREG/CR-6909. This evaluation will be submitted to the NRC one year prior to the period of extended operation.

Enclosure L-11-166 Page 103 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.9 Page B-49 "Detection of Aging Effects" subsection, third paragraph. first sentence In response to RAI B.2.9-1, the first sentence of the third paragraph of the "Detection of Aging Effects" subsection of Section B.2.9 is revised to read:

The inspections will be conducted using visual (-V-T-3 VT-I or equivalent) inspection methods performed by qualified personnelfollowing procedures consistent with the ASME Code and 10 CFR 50, Appendix B.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.15 Page B-72 "Program Description" section, second paragraph, second sentence In response to RAI 3.2.2.3.4-1, the second sentence of the second paragraph of the "Program Description" section of B.2.15 is revised to read:

The program includes components located in plant systems within the scope of license renewal that are constructed of aluminum, copper alloy (copper,brass, bronze, and copper-nickel), stainless steel (including cast austenitic stainless steel), and steel (carbon and low-alloy steel and cast iron) materials.

Enclosure L-11-166 Page 104 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.15 Page B-72 "Program Description" section, third paragraph In response to RAI 3.3.2.2.13-1, the third paragraph of the "Program Description" subsection of Section B.2.15 is revised to read:

The External Surfaces MonitoringProgram,supplemented by the Inspection of InternalSurfaces of Miscellaneous Pipingand Ducting Program,includes inspection and surveillance of elastomersand polymers that are exposed to air-indooruncontrolledand air-outdoorenvironments, but are not replaced on a set frequency or interval (i.e., are long-lived), for evidence of cracking and change in materialproperties(hardeningand loss of strength), and loss of material due to wear.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.15 Page B-73 "Scope, Parameters Monitored/Inspected, Detection of Aging Effects, Acceptance Criteria" subsection of the "Enhancements" section, first paragraph In response to RAI 3.3.2.2.13-1, the first paragraph of the "Scope, Parameters Monitored/Inspected, Detection of Aging Effects, Acceptance Criteria" subsection of the "Enhancements" section of Section B.2.15 is revised to read:

The External Surfaces MonitoringProgram,supplemented by the Inspection of InternalSurfaces of Miscellaneous Pipingand Ducting Program, will perform inspection and surveillance of elastomers and polymers exposed to air-indoor uncontrolled or air-outdoorenvironments, but not replaced on a set frequency or interval (i.e., are long-lived), for evidence of cracking and change in material properties (hardeningand loss of strength), and loss of materialdue to wear.

Acceptance criteria for these components will consist of no unacceptable visual indications of cracks or discoloration that would lead to loss of function prior to the next scheduled inspection.

Enclosure L-11-166 Page 105 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.15 Page B-73 "Scope, Parameters Monitored/inspected, Detection of Aging Effects, Acceptance Criteria" subsection of the "Enhancements" section, new paragraph In response to RAI 3.3.2-2, a new enhancement is added to the end of the "Scope, Parameters Monitored/Inspected, Detection of Aging Effects, Acceptance Criteria" subsection of the "Enhancements" section of Section B.2.15 as follows:

The External Surfaces Monitoring Program will also manage cracking of copper alloys with greaterthan 15 percent zinc and stainless steel components exposed to an outdoor air environment throuqh plant system inspections and walkdowns for evidence of leakage. Acceptance criteriafor surfaces consist of no unacceptable visual indications of cracks that would lead to loss of function prior to the next scheduled inspection.

Enclosure L-11-166 Page 106 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.16 Page B-75 Entire section In response to RAIs B.2.16-1, B.2.16-3, B.2.16-4, B.2.16-5, B.2.16-6 and B.2.16-7, Section B.2.16 is replaced in its entirety to read:

Program Description The Fatigue Monitoring Program manages fatigue of select primary and secondary components, including the reactor vessel, reactor internals, pressurizer, and steam generators by monitoring and tracking the number of critical thermal and pressure transients as required by Technical Specification 5.5.5, "Allowable Operating Transient Cycles Program." The scope includes those components that have been identified to have a fatigue TLAA.

The program prevents the fatigue TLAAs from becoming invalid by assuring that the fatigue usage resulting from actual operational transients does not exceed the Code design limit of 1.0, including environmental effects where applicable.

The program uses the systematic counting of transient cycles and the evaluation of operating data to ensure that the allowable cycle limits are not exceeded, thereby ensuring that component fatigue usage limits are not exceeded.

Transient documentation is updated at least once per plant operating cycle.

When the accumulated cycles approach the allowable cycles, corrective action is taken that includes an engineering evaluation to ensure the Code design limit of 1.0 is not exceeded. The program will provide for updates of the fatigue usage calculations on an as-needed basis if an allowable cycle limit is approached.

When the number of accrued cycles is within 75% of the allowable cycle limit for any transient, a condition report shall be generated. For transient cycles that are projected to exceed the allowable cycle limit by the end of the next plant operating cycle (Davis-Besse operating cycles are normally two years in duration), the program will require an update of the fatigue usage calculation for the affected component(s). Acceptance criterion is to maintain the cumulative fatigue usage below the Code design limit of 1.0 through the period of extended operation, including environmental effects where applicable.

For license renewal, the effects of the reactor coolant environment on component fatigue life have been addressed by assessing the impact of the environment on a sample of critical components as identified in NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components." Environmental effects were evaluated 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." Components identified in NUREG/CR-6260 were evaluated using

Enclosure L-11-166 Page 107 of 116 material specific guidance presented in NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low Alloy Steels," and in NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels." Nickel-based alloy components were evaluated using material specific guidance presented in NUREG/CR-6909, "Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials."

In addition, the Fatigue Monitoring Program will evaluate additional plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than those considered in NUREG/CR-6260. This evaluation will include identification of the most limiting fatigue location exposed to reactor coolant for each material type (i.e., CS, LAS, SS, and NBA) and that each bounding material/location will be evaluated for the effects of the reactor coolant environment on fatigue usage. Nickel-based alloy items will be evaluated using NUREG/CR-6909. This evaluation will be submitted to the NRC one year prior to the period of extended operation.

NUREG-1801 Consistency The Fatigue Monitoring Program is an existing program that, with enhancement, will be consistent with the 10 elements of an effective aging management program as described in NUREG-1801,Section X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."

Exceptions to NUREG-1801:

None.

Enhancements:

The following enhancements will be implemented in the identified program elements prior to the period of extended operation.

• Scope Evaluate additional plant-specific component locations in the reactor coolant pressure boundary that may be more limiting than those considered in NUREG/CR-6260. This evaluation will include identification of the most limiting fatigue location exposed to reactor coolant for each material type (i.e., CS, LAS, SS, and NBA) and that each bounding material/location will be evaluated for the effects of the reactor coolant environment on fatigue usage. Nickel-based alloy items will be evaluated using NUREG/CR-6909. This evaluation will be submitted to the NRC one year prior to the period of extended operation.

Enclosure L-11-166 Page 108 of 116

• Detection of Aging Effects Provide for updates of the fatigue usage calculations on an as-needed basis if an allowable cycle limit is approached. When the number of accrued cycles is within 75% of the allowable cycle limit for any transient, a condition report will be generated. For any transient whose cycles are projected to exceed the allowable cycle limit by the end of the next plant operating cycle (Davis-Besse operating cycles are normally two years in duration), the program will require an update of the fatigue usage calculation for the affected component(s).

• Acceptance Criteria Establish an acceptance criterion for maintaining the cumulative fatigue usage below the Code design limit of 1.0 through the period of extended operation, including environmental effects where applicable.

Operating Experience Based on review of plant-specific and industry operating experience, the identified aging effects require management for the period of extended operation.

Industry experience has been factored into the Fatigue Monitoring Program through consideration of NRC documents (information notices, bulletins, regulatory issue summaries, and regulatory guides), Vendor notices, Industry documents (NEI, INPO and EPRI), and other utility License Renewal Applications. Specific examples of that experience showing how the Davis-Besse program has remained responsive to emerging issues and concerns, are provided below. Continued program improvements based on industry experience provide evidence that the program will remain effective for managing cumulative fatigue damage for passive components.

NRC document RIS 2008-30 dealt with the use of single dimension stress factors in on-line fatigue analyses. Davis-Besse reviewed RIS 2008-30 and determined that no changes were required to the Fatigue Monitoring Program. Davis-Besse has no on-line fatigue analyses. Davis-Besse's fatigue analyses of record evaluate multi-dimensional stresses and analyzed the dimensions appropriate to each component.

Plant-specific Operating Experience In 1987, an engineering evaluation determined that implementation of the High Pressure Injection (HPI) System Pressure Isolation Integrity Test Back-to-Back Check Valves was required to be counted as a cycle against HPI nozzles used in makeup service. Only HPI nozzles being used for RCS normal makeup are affected by the reverse flow test, because normal makeup to the RCS is

Enclosure L-11-166 Page 109 of 116 temporarily isolated to perform the test. This condition creates a thermal cycle on the associated makeup nozzle/piping. Based on these conclusions, it was determined that implementation of the HPI System Pressure Isolation Integrity Test Back-to-Back Check Valves was required to be counted as a cycle against the HPI nozzle in makeup service. The AOTC Program was updated accordingly.

HPI Nozzle 2-1 was the makeup nozzle for Cycles 1 through 6. Since the Cycle 6 refueling outage, HPI Nozzle 2-2 has been the makeup nozzle.

NRC and vendor information caused Davis-Besse to assess thermal stratification of the pressurizer surge line. NRC Bulletin 88-11, "Pressurizer Surge Line Thermal Stratification," required the re-evaluation of the cyclic fatigue of the Pressurizer Surge Line. Topical Report BAW 2127 and its Supplements describe the results of the revised evaluation. As part of this evaluation (Supplement 3 to BAW-2127) the Davis-Besse heatup and cooldown transients were redefined.

Other transients were modified to include thermal stratification and striping. In addition to these changes, a number of transients were added and other modifications were made to the existing transients based on a review of the plant operating history and operating procedures. The number of design cycles for Ramp Loading and Unloading (15-100-15%) was significantly reduced because the plant is operated as a base loaded plant.

As part of a B&W Owners Group (BWOG) Steam Generator Project, the fatigue evaluations and stress reports associated with the Once Through Steam Generators (OTSGs) welded plugs were updated. As defined by the applicable stress report, the taper weld plugs have a 113 transient cycle limit. Per review of the Allowable Operating Transient Cycle (AOTC) Program status log, as of 02/14/05 the limiting OTSG taper weld plug has 30.5 total events. The events (heatup/cooldown cycle) is defined as Transient No. 01 in the RCS Functional Specification No. 18-1149327-00. Transient No. 1 is the RCS heatup from ambient temperature and pressure to 8% power and cooldown from 8% power to refueling temperature and pressure. As defined by the applicable stress report, the MK-500 taper weld plugs have a 171 transient cycle limit. Per review of the AOTC Program status log as of 02/14/05 the limiting OTSG MK-500 taper weld plug has 61.5 total events. As defined by the applicable stress report, the remote welded plugs have a 33 transient cycle limit. Per review of the AOTC Program status log as of 02/14/05 the limiting remote weld plug has 14.5 total events. As a result of the review of the subject stress reports, the AOTC Program procedure was updated to document a 113 transient cycle limit for the OTSG taper weld plugs, a 171 transient cycle limit for the OTSG MK-500 taper weld plugs, and a 33 transient cycle limit for the OTSG remote welded plugs.

During the Program Review phase of the Cycle 13 refueling outage (the outage ended March 27, 2004) restart effort it was discovered that the Fatigue Monitoring Program (a.k.a., Allowable Operating Transient Cycles Program) had not been updated or reviewed for a period of approximately four years. The

Enclosure L-11-166 Page 110 of 116 Corrective Action Program was used to document deficiencies in various aspects of the Fatigue Monitoring Program. This item in the Corrective Action Program was processed as a significant condition adverse to quality with a root cause analysis performed in order to provide the appropriate level of attention to the Fatigue Monitoring Program deficiencies. As a result of the root cause analysis, several program changes were made including the addition of a requirement to perform periodic self-assessments. Other corrective actions included evaluation of monitored transients against the RCS Functional Specification to verify the cycle limit and basis, update of transient cycle counts, comparison of accrued cycles to allowable cycles (none of the allowable cycles were exceeded),

preparation of a Job Familiarization Guide (JFG) to address program owner qualification requirements, and performance of a program self-assessment.

The self-assessment report was completed on October 11, 2005. The purpose of this assessment was to determine the effectiveness of the changes made to the Allowable Operating Transient Cycles Program due to implementation of the Corrective Action Program corrective actions. In summary, the assessment determined that the procedure changes have been effective in driving the collection, documentation and evaluation of the required transient data. The programmatic changes have been shown to be effective in providing management involvement in the program through oversight and qualification of the program owner. Updates to the Allowable Operating Transient Cycles status log/event log were evident and submittals to Records Management had been within the allowable time period.

The FENOC Corrective Action Program and continued implementation of the Fatigue Monitoring Program provides reasonable assurance that effects of aging will be managed so that components crediting this program can perform their intended function consistent with the current licensing basis during the period of extended operation.

Conclusion The Fatigue Monitoring Program uses the systematic counting of plant transient cycles to ensure that the numbers of allowable cycles are not exceeded, thereby ensuring that component fatigue usage limits are not exceeded. When the accumulated cycles approach the allowable cycles, corrective action is taken to maintain the cumulative fatigue usage below the Code design limit of 1.0 through the period of extended operation, including environmental effects where applicable.

Enclosure L-11-166 Page 111 of 116 Affected LRA Section LRA Page No. Affected Paraqraph and Sentence B.2.26 Page B-108 "Program Description" section, first paragraph third sentence In response to RAI 3.4.2.2.5-1, to include loss of material due to selective leaching in the program description for the Lubricating Oil Analysis Program, the third sentence of the first paragraph of Section B.2.26 is revised to read:

The program requiresmanagement of the relevant conditions that could lead to the onset and propagationof loss of materialdue to crevice, galvanic, general, or pitting corrosion, selective leaching, or reduction in heat transfer due to fouling, through monitoring of the lubricatingoil consistent with various manufacturers' recommendationsand industry standards.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.30 Page B-121 "Scope" subsection of the "Enhancements" section, new paragraph In response to RAI 3.3.2.2.4.3-1 regarding cracking of stainless steel due to cyclic loading, a new paragraph is added to the end of the "Scope" subsection of the "Enhancements" section of Section B.2.30, and the section is revised to read (note - Section B.2.30 was previously revised, in its entirety, in FENOC Letter L-11-153, dated May 24, 2011):

The One-Time Inspection will also include visual and volumetric inspections to detect and characterizecracking due to cyclic loadinq of the stainless steel makeup Pump casings (DB-P37-1 and 2) of the Makeup and PurificationSystem.

The one-time inspections will provide verification of the absence of cracking due to cyclic loading.

Enclosure L-11-166 Page 112 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.30 Page B-122 "Scope" subsection of the "Aging Management Program Elements" section, new paragraph In response to RAI 3.3.2.2.4.3-1 regarding cracking of stainless steel due to cyclic loading, a new paragraph is added to the end of the "Scope" subsection of the "Aging Management Program Elements" section of Section B.2.30, and the section is revised to read (note - Section B.2.30 was previously revised, in its entirety, in FENOC Letter L-1 1-153, dated May 24, 2011):

The One-Time Inspection will also include visual and volumetric inspections to detect and characterizecrackinq due to cyclic loadinq of the stainless steel makeup pump casings (DB-P37-1 and 2) of the Makeup and PurificationSystem.

The one-time inspections will provide verification of the absence of crackinq due to cyclic loading.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.30 Page B-122 Exceptions to NUREG-1801 Section B.2.30 was previously revised, in its entirety, in FENOC Letter L-1 1-153, dated May 24, 2011. In that revision the "Exceptions to NUREG-1 801" section was inadvertently omitted, and is herewith replaced. Section B.2.30 is revised to add the following between "NUREG-1 801 Consistency" and "Enhancements:"

Exceptions to NUREG-1801 None.

Enclosure L-11-166 Page 113 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.36 Page B-143 "Scope" subsection of the "Aging Management Program Elements" section In response to RAI 3.3.1.85-1, to include listing of the Turbine Plant Cooling Water System, as a system applicable to the inspection, the "Scope" subsection of the "Aging Management Program Elements" section of Section B.2.36 is revised to read:

The aging management activity is credited for the following systems:

• Auxiliary Building Chilled Water System

• Auxiliary Building HVAC System

" Auxiliary Steam and Station Heating System

" Decay Heat Removal (DH) and Low Pressure Injection System (LPI)

• Emergency Diesel Generators (EDG)

• Fire Protection Diesel (DFP)

• Fire Protection System (FP)

" High Pressure Injection System

• Instrument Air System

" Main Steam System (MS)

• Makeup Water Treatment System

" Miscellaneous Liquid Radwaste System

" Service Water System (SW)

" Station Air System

• Station Blackout Diesel Generator (SBODG)

• Station Plumbing, Drains, and Sumps System (SPDSS)

• Turbine Plant Coolinq Water System

Enclosure L-11-166 Page 114 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.36 Page B-142 "Program Description" section, first paragraph. first sentence In response to RAI 3.3.2-2, the first sentence of the first paragraph of the "Program Description" section of Section B.2.26 is revised to read:

The Selective Leaching Inspection will detect and characterize the conditions on internaland external surfaces of subject components that are exposed to air-outdoor,moist air (including condensation), raw water, soil (buried), and treated water (including closed cycle cooling water).

Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.36 Page B-143 "Scope" subsection of the "Aging Management Program Elements" section, first paragraph, fourth sentence In response to RAI 3.3.2-2, the fourth sentence of the first paragraph of the "Scope" subsection of the "Aging Management Program Elements" section of Section B.2.36 is revised to read:

The components are exposed to air-outdoor,moist air (including condensation),

raw water, soil (buried), and treatedwater (including closed cycle cooling water and steam) environments during normal plant operations.

Enclosure L-11-166 Page 115 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.41 Page B-165 "Program Description" subsection, first paragraph, second sentence In response to RAI 3.3.2.3.12-1, the second sentence of the first paragraph of the "Program Description" subsection of Section B.2.41 is revised to read:

The program will consist of inspections of the internalsurfaces of aluminum, copper alloy (including copper alloy with greaterthan 15 percent zinc), stainless steel, and steel (includinggray cast iron) components exposed to air, condensation, diesel exhaust, lubricatinqoil, or moist air, and external cooling coil surfaces.

Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.41 Page B-165 "Program Description" subsection, second paragraph In response to RAI 3.3.2.2.13-1, the second paragraph of the "Program Description" subsection of Section B.2.41 is revised to read:

The program will manage loss of material, cracking of susceptible stainless steel components, hardeningand loss of strength of non-metallic, flexible (elastomeric) components, loss of materialdue to wear, and reduction in heat transferof cooling coil tubes and fins.

Enclosure L-11-166 Page 116 of 116 Affected LRA Section LRA Page No. Affected Paragraph and Sentence B.2.41 Page B-165 "Scope" subsection of the "Aging Management Program Elements" section of B.2.41, first paragraph In response to RAI 3.3.2.3.12-1, the first paragraph of the "Scope" subsection of the "Aging Management Program Elements" section of Section B.2.41 is revised to read:

The scope of the Inspection of InternalSurfaces in Miscellaneous Pipingand Ducting Programincludes the external surfaces of cooling cools and the internal surfaces of aluminum, copper alloy (including copper alloy with greaterthan 15 percent zinc), stainless steel, and steel (including gray cast iron) components exposed to air, condensation, diesel exhaust, lubricatingoil, or moist air, and the internaland external surfaces of non-metallic, flexible (elastomeric)components that are not included in other aging managementprograms.