ML15253A409

Forwards RAI Tracking Sys for Oconee License Renewal Application.Sys Consists of Compilation of RAIs That Were Sent to Duke Re Application & Will Be Used by NRC Staff & Duke to Track How Duke Responds to RAIs

ML15253A409
Person / Time
Site:	Oconee
Issue date:	01/11/1999
From:	Joseph Sebrosky NRC (Affiliation Not Assigned)
To:	NRC (Affiliation Not Assigned)
References
NUDOCS 9901120055
Download: ML15253A409 (54)

Text

January 11, 1999 NOTE TO:

Oconee Docket Files 50-269, 50-270, and 50-287 FROM:

Joe Sebrosky, Project Manager Division of Reactor Program Management Office of Nuclear Reactor Regulation

SUBJECT:

Oconee License Renewal Tracking System for Request for Additional Information (RAls)

The attached information is the RAI tracking system for the Oconee License Renewal application. The system is a compilation of the RAls that were sent to Duke concerning the application and will be used by the NRC staff and Duke to track how Duke responds to the RAls.

It should be noted that the attached is only a tracking system and all the RAls as well as their responses will appear on the docket under separate cover letters.

cc w/o attachment:

Chris Grimes Steve Hoffman L90120055 990111 f)ol 990R ADOCK q5000269 PD F DR

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 G1 Has Duke Energy committed to extending 10 CFR Part 50, Appendix B requirements 11/18/98D for "corrective actions, ".

.confirmation process," and "administrative controls" to cover non-safety-related structures and components subject to aging management review (AMR)? If not, what is Duke Power using to address these required elements of a program for non-safety related structures and components requiring an aging management review.

G-2 Sections 4.3.2, 4.3.3, and 4.3.8 all describe new one time inspection programs to 11/18/98D verify the presence or absence of various degradation mechanisms specific to certain components. These sections all deal with time dependent mechanisms. However, given that Oconee has been operating for approximately 24 years, discuss the rationale for delaying these inspections to the' time period between the issuance of a license; extension and the expiration of the existing license. The staff recognizes the financial constraints in the utility business, however, given some of the mechanisms specified, it is not clear why some programs are not advanced in schedule. What is the rationale for the schedule of the programs? Is there a plan for schedule or priority ranking among these various inspection programs? What is the rationale for this ranking?

G-3 Are there any parts of the systems, structures and components that are inaccessible for 11/18/98D inspection? If so, describe what aging management program will be relied upon to maintain the integrity of the inaccessible areas. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of, or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (a) Preventive actions that will mitigate or prevent aging degradation; (b) Parameters monitored or inspected relative to degradation of specific structure and component intended functions; (c) Detection of aging effects before loss of structure and component intended functions; (d) Monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions; (e)

Acceptance criteria to ensure structure and component intended functions; and (f)

Operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

G-4 Sections 4.3.4, 4.3.5, and 4.3.13 all describe new one-time inspection programs to 12/3/98A verify the presence or absence of various aging effects specific to certain components.

These sections all deal with time dependent effects. However, given that Oconee has been operating for approximately 24 years, discuss the basis for deferring performance of these inspections to the time period between the issuance of a license extension and the expiration of the existing license. Given some of the effects specified, it is not clear why some programs are not advanced in schedule. Discuss the rationale for the schedule and prioritization of the completion of these one-time inspection "programs".

Provide the rationale for the prioritization.

G-5 Are there any parts of the systems, structures and components that are inaccessible for 12/3/98A inspection? If so, describe what aging management program will be relied upon to maintain the integrity of the inaccessible areas. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of, or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (a) Preventive actions that will mitigate or prevent aging degradation; (b) Parameters monitored or inspected relative to degradation of specific structure and component intended functions; (c) Detection of aging effects before loss of structure and component intended functions; (d) Monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions; (e)

Acceptance criteria to ensure structure and component intended functions; and (f)

Operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

G-6 Discuss how jhe inspections for small bore piping and pressurizer detect aging effects 12/3/98A 12-16 RAI Status.doc Page 1 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 before there is a loss of the component intended functions? In your response, discuss how the scope of the inspections, the specific methods used, and basis for determining the frequency for the inspections supports your conclusions.

G-7 Please explain whether the inspections for small bore piping, and pressurizer provide 12/3/98A for sample expansion or require follow up inspections if unacceptable indications are found. If not, please justify.

G-8 Please discuss the confirmation process in the inspections for alloy 600, small bore 12/3/98A piping, and pressurizer, i.e., when corrective actions are completed, the follow up activities performed to confirm that the corrective actions are completed, root cause determination performed, and recurrence prevented. (The discussion of this element in the QA program was not clear, stating that it applied to "more significant events.")

G-9 For the Inspections for alloy 600, small bore piping, and pressurizer, discuss Oconee or 12/3/98A applicable industry operating experience from similar programs or inspection techniques used to develop this inspection program.

1.5.2-1 The application states that an aging management review is not required for the reactor 11/20/98E coolant pump seals because they are generally replaced "approximately every four operating cycles" or "approximately every two operating cycles" depending on the component. The license renewal rule allows a component to be eliminated from an aging management review if it is subject to periodic replacement, based on a qualified life or a specified time period. Please describe the controlled replacement program which establishes a specific replacement frequency or interval (or upper limit replacement interval), based on a qualified life or a specified time period.

1.5.5-1 Section 1.5.5.3 of the license renewal application indicates that additional 11/24/98A confirmatory research is ongoing at Oconee in support of the generic resolution of issues associated with Generic Safety Issue (GSI) 190, "Fatigue Evaluation of Metal Components for 60-year Plant Life."

The application further indicates that the Oconee study will apply the methodology developed in EPRI Report TR-105759, "An Environmental Factor Approach to Account for Reactor Water Effects in Light Water Reactor Pressure Vessel and Piping Fatigue Evaluations." Application of this methodology was discussed during a March 19, 1998, meeting between the industry and the staff. A letter from Christopher Grimes to NEI dated November 2, 1998, titled "Request for Additional Information on the Industry's Evaluation of Fatigue Effects for License Renewal", summarizes the staff's technical concerns regarding the methodology in EPRI Report TR-105759. Upon resolution of these concerns and when a final determination regarding GSI-190 has been made, you will be expected to address any particular action that may arise as a result of such determination.

Since the conclusion regarding GSI-190 in Section 1.5.5.4 of your application for license renewal relies on the conclusions from the referenced EPRI report, discuss how Oconee meets the relevant portion of Section 54.29 of the license renewal rule as discussed in the statement of considerations (SOC) (60 FR 22484, May 1995) in the absence of the staff's endorsement of EPRI Report TR-105759. Although the staff expects timely resolution of GSI-190, your response should address the situation in which GSI-190 is not resolved prior to the current license term. Consistent with the SOC, it is expected that Duke will "submit a technical rationale which demonstrates that the CLB [current licensing basics] will be maintained until some later point in time in the period of extended operation, at which time one or more reasonable options (e.g., replacement, analytical evaluation, or a surveillance/maintenance program) would be available to adequately manage the effects of aging...and briefly describe options that are technically feasible during the period of extended operation to manage the effects of aging...."

2-1 Various Oconee license renewal basis documents contained blocked "confirmation 12/1/98B required" annotations. However, the staff was informed during a site visit from October 27 through 30, 1998, that there were no formal administrative control processes in place to track these items to resolution. [OLRP-1001 Section 2.0]

Please describe the actions that have either been implemented or that Duke anticipates will be taken to resolve this issue dealing with QA-1 documentation.

2.2-1 Section 54.4(a)(3) requires that all plant systems, structures, and components relied on 11/30/98B in safety analyses or plant evaluations to demonstrate compliance with Commission's 12-16 RAI Status.doc Page 2 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 regulations for fire protection (10 CFR 50.48) be included within the scope of license renewal. Section 2.2.2. 1, "Fire Protection," of the license renewal application identifies that the applicant reviewed a number of NRC safety evaluation reports to determine the Oconee structures and mechanical systems relied upon to meet the requirements of Appendix R to 10 CFR Part 50. Section 2.2.2.1 of the license renewal application also states that the applicant identified the structures and mechanical systems required to demonstrate compliance with BTP 9.5-1 and Appendix R by reviewing the Oconee-specific documents addressing each topic and that a structure or mechanical system is within the scope of license renewal when a portion is relied upon for compliance with the NRC fire protection regulations. The applicant did not explicitly address whether or not it included all plant systems, structures, and components relied on to demonstrate compliance with 10 CFR 50.48 within the scope of license renewal for Oconee. The application also appears to be limited in scope in that it refers only to "structures and mechanical systems." Please provide the following information:

Verify that all plant systems, structures, and components relied on in safety analyses or plant evaluations to demonstrate compliance with 10 CFR 50.48 were included within the scope of license renewal for Oconee. (So that the staff can make an appropriate finding in its safety evaluation, please frame the response in the context of 10 CFR 50.48.)

Identify the specific types of licensee-controlled safety analyses, plant evaluations, and documentation (e.g., UFSAR, fire hazards analysis, safe shutdown analysis, etc.) that were used to identify the plant systems, structures, and components that were included within the scope of license renewal for Oconee.

Describe how the documents identified in Section 2.2.2.1 of the license renewal application and the documents identified in response to Question 1.b, above, were used to determine the systems, structures, and components, which are credited for compliance with 10 CFR 50.48, are within the scope of license renewal per 10 CFR 54.4(a)(3).

2.2-2 Verify that the fire protection scoping process has been updated since its inception and 11/30/98B that changes to the fire protection program documentation identified in response to Question Lb, above, have been reviewed and captured by the fire protection scoping process, as appropriate.

2.2-3 Identify the fire protection components that have been determined to be within the 11/30/98B scope of license renewal, per 10 CFR 54.4, but have been excluded from aging management review because they are subject to replacement based on qualified life or a specified time period as permitted under 10 CFR 54.21(a)(1)(ii).

2.2-4 Describe, in detail, how (a) the equipment and components relied upon for post-fire 11/30/98B cold shutdown and (b) the fire detection system were addressed in the system level scoping process and the aging management review process.

2.2-5 Fire protection equipment such as hoses, scott air packs, and fire extinguishers were 11/30/98B not considered in the license renewal application. These types of components appear to be within scope according to 10 CFR 54.4(a)(3). Please provide the justification for excluding these components from the scope of license renewal. In addition, the components appear to perform an intended function without moving parts or change in configuration or properties, and do not appear to be subject to replacement based on a qualified life or specified time period, per 10 CFR 54.21(a)(1). Therefore, justify exclusion of these components from aging management review.

2.2-6 In OLRP-1001, Section 2.2, "Identification of Systems, Structures, and Components 12/1/98B Within the Scope of License Renewal," the applicant identifies the methodology used to identify structures and mechanical systems at Oconee that are within the scope of license renewal. The methodology used to identify electrical components within the scope of license renewal and subject to aging management review is described in Section 2.6 of OLRP-1001.

In Subsection 2.2.1.1, "Mechanical Systems," the applicant states "Because Oconee was licensed before terms such as 'safety-related' were more precisely defined by the NRC, a list of the Oconee safety-related systems, structures, and components, in and

oslf, will not meet the intent of 10 CFR 54.4(a)(1). Because the criteria in 12-16 RAI Status.doc Page 3 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 10 CFR 54.4(a)(1) are the scoping criteria of many modern-day, regulatory-required programs, Oconee conducted a design study that validated all functions required for the successful mitigation of Oconee design basis events and identified the systems and components relied upon to complete those functions. The individual design basis event mitigation calculations produced as a result of the study contain a list of the system functions required to successfully mitigate each event. Duke determined that the systems that perform these functions are within the scope of license renewal."

During a site visit to review the Oconee license renewal scoping and screening process, which was conducted by the NRC staff on October 27 through 30, 1998, at Duke Power Corporate offices in Charlotte, North Carolina, the staff learned that the "design study" identified in Subsection 2.2.1.1 and the Oconee Safety-Related Designation Clarification (OSRDC) project were one and the same.

Specifically, in its November 4, 1983, response to Generic Letter (GL) 83-28, "Required Actions Based on Generic Implications of Salem ATWS Events" (July 1983), as supplemented by letters dated January 17, 1984, and June 9, 1987, Duke described the scope of the Oconee operational quality assurance (QA) program for safety-related equipment classification. The NRC staff approved the scope of the Oconee operational QA program via a safety evaluation dated November 4, 1987.

In a supplemental response to GL 83-28, dated April 12, 1995, Duke provided amplifying information on Oconee's QA-1 licensing basis, and on information provided to the NRC Region II staff during a February 6, 1995, meeting. In to this letter, "Supplemental Response to Subpart 1 of Section 2.2.1 of GL 83-28 General Criteria for Classifying QA-1 SSCs [structures, systems, and components]," Duke stated that the list of additional QA-1 SSCs would be developed through the OSRDC project by July 10, 1995. Also, in Attachment 4, "Oconee Licensing Position on Non QA-1 SSCs which are used to Mitigate Accidents," Duke committed to developing a new QA classification (QA-5) such that these SSCs can be identified "for testing and maintenance under selected Appendix B [to 10 CFR Part 50] criteria without procuring the SSCs per Appendix B." [OLRP-1001, Section 2.2]

Based on the above, the staff is requesting that Duke provide the following information:

a.

Please clarify the extent to which the Oconee license renewal process described in OLRP-1001 relied upon the OSRDC results.

b.

Please describe the specific process (and its current status) used by Duke to confirm that the OSRDC project has identified all Oconee structures, systems, and components (including electrical) that perform the functions identified in 10 CFR 54.4(a).

c.

Please identify and describe the administrative controls (and associated commitments) currently in place at Oconee to ensure that QA-5 structures, systems and components (identified through the OSRDC project), and subject to aging management review, will be adequately managed during the life of the renewed license. If such controls are not in place, please provide justification.

2.2-7 Radiation monitors typically perform safety-related functions, such as, providing 12/2/98E signals that isolate control room ventilation. Radiation monitors have not been identified as being within the scope of license renewal on Oconee OLRP-1002 drawings. Provide a basis why the radiation monitors are not considered within the scope of license renewal and, therefore, not subject to an aging management review.

Alternatively, identify where in the application these monitors have been addressed, if they have been addressed elsewhere.

2.2-8 Spent fuel pool (SFP) area ventilation and SFP coolant makeup are often credited in 12/2/98E maintaining stored fuel temperature within prescribed limits during loss of spent fuel pool cooling events. Portions of the heating, ventilation and air conditioning systems that provide for SFP area ventilation are not identified as being within the scope of license renewal in the Oconee integrated plant assessment. Provide a basis for this determination or include SFP area ventilation within the scope of license renewal and, therefore, subject to an aging management review. Alternatively, identify where in the application these functions are addressed, if they are addressed elsewhere.

12-16 RAI Status.doc Page 4 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 P2.2-9i Several components associated with fuel handling operations were not discussed in the 1//8 Oconee license renewal application. These components include, for example, heavy load handling equipment, cranes, structural supports for cranes (other than the rails and girders discussed in section 2.7), fuel upenders, etc. Identify where in the license renewal application this equipment is evaluated or justify its exclusion from the application.

2.3-1 For components, including weldments, which are identified as outside the scope of the July 6, 1998 evaluation boundary for the reactor building, please clarify where those components will be addressed in the Oconee Report OLRP-1001.

2.3-2 Section 2.2.II.B of the working draft standard review plan for license renewal (SRP-July 6, 1998 LR) dated September 1997, discusses that plant items that are intended to be used during normal operation and maintenance of a system or structure and are not replaced based on calendar frequency or a predetermined qualified life. These items include sealing materials, gaskets, 0-rings, and packing. The SRP-LR discusses that the applicant may either (1) identify these items as subject to aging management review, or (2) identify that degradation of these items may cause aging effects on the structure and component in which these items are installed and manage those aging effects accordingly. However, a plant item that specifically performs an intended function necessary for meeting 10 CFR 54.4 is to be identified as subject to an aging management review for renewal. Please discuss the treatment of items, such as tendon grease, seals, and joint sealants, for Oconee.

2.3-3 Section 2.3.1.3 of the report states, "the lower tendon access gallery does not support July 6, 1998 the intended functions of the Containment and is therefore not within the scope of the Rule." Please provide additional information regarding the seismic classification of the gallery and, if not seismic Class I, the effects of gallery degradation on the integrity of the reactor building.

2.3-4 Please provide a discussion regarding "miscellaneous attachments to the liner" as July 6, 1998 stated in Section 2.3.2.2 of the report. Also provide a figure showing some typical details and the "evaluation boundary."

2.3-5 Please discuss why Section 2.3.2.5 of the report does not indicate that the sump piping July 6, 1998 has an intended function to maintain the leak-tight boundary of the containment.

2.3-6 Please clarify the evaluation boundary for the electrical penetrations discussed in July 6, 1998 Section 2.3.2.6 of the report. Does it include all elements subject to containment internal pressure? If not, please justify any exclusion.

2.3-7 Section 2.3.2.5 of the report indicates that there are no expansion bellows used on July 6, 1998 mechanical penetrations. Please confirm that bellows are not used on any other type of Oconee containment penetration.

2.3-8 (Question refers to Section 2.3.2 of OLRP-1001) The tendon gallery provides access to 11/19/98 the bottom anchorages of the vertical tendons of containment's post-tensioning system. It also protects the anchorages from the direct influence of soil and ground water, which they would be subjected to if there were not a tendon gallery. It serves intended function 3 as defined in Table 2.3-1 of Duke Energy Corporation Report OLRP-1001, June 1998. Provide justification as to why it should not be within the scope of license renewal as per 10 CFR 54.4(a)(2).

In addition, please provide a discussion regarding what aging effects of water infiltration would be in the tendon gallery on the tendon anchorage system (e.g.,

tendon end caps, tendons, and basemat concrete) to ensure that the intended function of the tendon anchorage system is maintained during the period of extended operation.

2.3-9 to the Duke Power's letter of August 12, 1998, indicates that the 11/19/98 miscellaneous attachment welds to the liner are added to Sections 2.3.3.2 and 2.7.7. A review of Section 2.3.3.2 indicates that these welds are not considered within the boundary of containment, but they are addressed in Section 2.7.7 (Reactor Building Internal Structural components). Section 2.7.7 does not specifically address attachment welds to the liner. Provide justification as to why these and other attachments to the liner, which could influence the leak-tight integrity of the liner, should not be considered as part of the containment pressure boundary.

12-16 RAI Status.doc Page 5 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 2.3 -10 (Question refers to Section 2.3.3 of OLRP-1001) With the confirmation from Duke 11/19/98 that there are no bellows in Oconee containment penetrations, the staff had resolved RAI 2.3-7 (Draft Technical Evaluation Report for OLRP-1001, Brookhaven National Laboratory, July 1998). However, in Attachment 2 to Duke's Letter to NRC on containment review for renewed operating license, August 12, 1998, in response to RAI 2.3-7, Duke states, "No revisions to OLRP-1001 are required at this time."

Explain the phrase "at this time."

2.3-11 Provide justification why the ability to provide a sump was not considered an intended 12/1/98A function of the Reactor Building (Containment) as listed in Table 2.3-1 of OLRP 1001. Are the reactor building emergency and normal sumps included as one of the structures requiring aging management review? If not, provide the basis for their exclusion.

2.4-1 Dwg. #s OLRFD-107A-1.1, 2.1 and 3.1 of the submittal shows the pressurizer quench 11/30/98C tank with the sparger. Please clarify if the sparger nozzles are within the scope of license renewal. If they are not, provide the basis for their exclusion.

2.4-2 Page 4-51, Section 4.5.1.3.1, Oconee Updated Final Safety Analysis Report (UFSAR) 11/30/98C

[updated December 31, 1997], indicates that lifting lugs are provided for remote handling of the plenum assembly (Reactor Vessel Internals). These lifting lugs are welded to the cover grid. It was not clear from the submittal (Fig. 2.4-5) if these lifting lugs and attachment welds are within the scope of license renewal. Discuss whether these items are within the scope of license renewal or provide a basis for their exclusion.

2.4-3 Page 5-44, Section 5.3.1, UFSAR [updated December 31, 1997], indicates that guide 11/30/98C lugs are welded inside the reactor vessel's lower head which limit a vertical drop of the reactor internals and core to V2 inch or less and prevent rotation about the vertical axis in the unlikely event of a major internals component failure. It was not clear from the submittal (Figs. 2.4-2, 3 and 4) if these lugs and attachment welds are within the scope of license renewal. Discuss whether these items are within the scope of license renewal or provide a basis for their exclusion.

2.4-4 Page 4-10, Section 4.2.2.1.5 (UFSAR) [updated December 31, 1997], indicates that 11/30/98C attached to the upper end fitting (Reactor Vessel Internals) is a holddown spring, which provides a positive holddown margin to oppose hydraulic forces resulting from the flow of the primary coolant. It was not clear from the submittal (Fig. 2.4-5) if this spring is within the scope of license renewal. It is feasible that the holddown spring may loose its required force with extended age. Discuss whether this item is within the scope of license renewal or provide a basis for its exclusion.

2.4-5 Page 5-43, Section 5.3.1, UFSAR [updated December 31, 1997], indicates that test 11/30/98C taps are provided in the annulus between the two 0-rings to afford a means to leak test the vessel closure seal. It was not clear from the submittal (Figs. 2.4-2, 3, and 4) if these test taps are within the scope of license renewal. Discuss whether these items are within the scope of license renewal or provide a basis for their exclusion.

2.4-6 Figures 2.4-2, 3 and 4 of the submittal show the reactor vessel. However, these figures 11/30/98C do not show the closure head of the vessel. The following two questions are relevant to the vessel head:

The lifting lugs, which are used to lift the vessel head are welded to it. Please indicate if these lifting lugs and attachment welds are included within the scope of license renewal. If so, provide a cross reference to where these are addressed in the submittal.

If not, provide the basis for their exclusion.

In response to the Three Mile Island Lessons Learned Report, NUREG-0737, Item I.B.1, vents were to be added to the reactor vessel and to the pressurizer head. One of the intended functions of the vents is to ensure core cooling during loss-of-coolant accident. Please indicate if these vent systems are within the scope of license renewal.

If so, provide a cross reference to where these items are discussed in the submittal. If not, provide the basis for their exclusion.

2.4-7 Table 2.4-4 of the submittal lists RCS components and their intended functions.

11/30/98C Discuss why the following intended functions, for the specified components, were not considered as intended functions to be maintained for license renewal. Provide bases for your determinations. The components and their intended functions are given 12-16 RAI Status.doc Page 6 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 below:

ComponenIntended Function(s)

Reacor VsselIntenalsCapability to shutdown the reactor and maintain it in a safe shutdown condition.

Once Through Steam Generator Provide heat removal under abnormal operating conditions.

Additionally, verify that reactor coolant pumps do not have any intended functions credited for design basis events that meet the requirements of 10 CFR 54.4, other than the intended function cited for license renewal, i.e., pressure boundary function of the pump casing and flow-related coastdown function associated with the RCP flywheel, and are therefore not considered within the scope.

2.5.3-1 Flow Diagrams OLRFD-l 16E-1.1, 2.1 and 3.1 do not include the piping and ductwork 12/1/98A that supply air to the steam generator cavity and reactor vessel annulus and direct condensate to the reactor building sump. Discuss if this ductwork or piping is credited in any safety analyses. At a minimum, please, address the following analyses or assumptions: (1) initial or normal operating temperature assumed in the steam generator cavity and reactor vessel annulus for the purpose of equipment qualification, (2) normal operating temperature assumed to support the integrated exposure before a 10% reduction in sensitivity for the out-of-core neutron detectors as given by Table 7 4 of the Oconee Final Safety Analysis Report (FSAR), and (3) reactor building sump inventory. Considering the above discussion, clarify if this piping and ductwork is included within the scope of license renewal and subject to aging management review.

If not, provide the basis for their exclusion.

2.5.3-2 Section 9.4.6.2 of the Oconee FSAR states that the fusible links holding the dropout 12/1/98A plates provided in the ductwork below the coils melt and drop off, assuring that a positive path for recirculation of the Reactor Building atmosphere is available.

Discuss how fusible dropout registers and links can be classified as non-nuclear safety related when they are credited in the post accident containment heat removal safety analysis. Based on the above, clarify if the fusible links are considered within the scope of and subject to aging management review. If not, provide the basis for their exclusion.

2.5.3-3 Figure 6.2, "Flow Diagram of Reactor Building Spray System," of the Oconee FSAR 12/1/98A shows valve LP-16 being supplied by Decay Heat Removal Pump A. This is not consistent with Flow Diagrams OLRFD-102A-1.2, 2.2 and 3.2 which show this valve being supplied by Decay Heat Removal Pump B. Please clarify this inconsistency.

2.5.3-4 Figure 6.2, "Flow Diagram of Reactor Building Spray System," of the Oconee FSAR 12/1/98A shows two valves that isolate the reactor building spray pumps from the spray headers, 1(ES) and 2(ES). This is not consistent with Flow Diagrams OLRFD-102A-1.2, 2.2 and 3.2 which show the valves as ES-7 and ES-8. Please clarify this inconsistency.

2.5.3-5 Clarify why Flow Diagrams OLRFD-102A-1.2, 2.2 and 3.2 which illustrate all the 12/1/98A components shown on Figure 6.2, "Flow Diagram of Reactor Building Spray System,"

of the Oconee FSAR have not been included in Table 2.5-2, "Flow Diagrams Indicating Evaluation Boundaries of Containment Heat Removal Systems."

Specifically, the diagrams that show valves LP-15 and LP-16 and the supply from the decay heat removal pumps are not included in Table 2.5-2 of OLRP-1001.

2.5.3-6 Section 15.15.1 of the Oconee FSAR states that the Reactor Building Spray System is 12/1/98A credited with removal of a portion of the remaining iodine from the building atmosphere. In order to credit this removal mechanism, it is common practice to provide for the addition of a spray additive such as trisodium phosphate or sodium hydroxide. Clarify if such an additive is used at Oconee and if so justify why the spray additive system has not been included within the scope of license renewal and subject to aging management review.

2.5.4-1 Clarify whether all the containment isolation valves listed in Figure 6-9, "Containment 12/1/98A Isolation Valves," of the Oconee FSAR are subject to an aging management review.

For any valves that are not, provide the basis for their exclusion.

12-16 RAI Status.doc Page 7 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 tank, the major components in low pressure injection are constructed of stainless steel.

The borated water storage tank is made of carbon steel with an interior phenolic coating to protect it from corrosion and deterioration. Clarify if the coating is relied upon to ensure the intended function of the borated water storage tank for the period of extended operation. If it is, describe the program to maintain the coating. If not, provide the basis for its exclusion.

2.5.5-2 Boric acid solution is stored in heated and insulated tanks and is piped in heat-traced I1130/98C and insulated lines to preclude precipitation of the boric acid. Clarify if the insulation material is within the scope of license renewal. If so, provide a cross reference to where these items are discussed in the submittal. If not, provide the basis for their exclusion.

2.5.5-3 Containment sump suctions of the ECCS pumps are enclosed by particulate screens, 11I/30/98C whose intended function is to prevent debris from entering into the pumps. Clarify if these screens are within the scope of license renewal? If so, provide a cross reference to where these items are discussed in the submittal. If not provide the basis for their exclusion. Additionally, provide a discussion of the intended functions these items might perform for license renewal.

2.5.5-4 Flow restriction orifices are installed in several pipes in order to limit the mass flow 1 1/30/98C rate during an accident. Clarify if these orifices are within the scope of license renewal? If so, provide a cross reference to where these items are discussed in the submittal. If not, provide the basis for their exclusion. Additionally, provide a discussion of the intended functions these items might perform for license renewal.

2.5.5-5 Dwg. #s OLRFD-103A-1.1, 2.1 and 3.1 of the submittal shows the Low Pressure 11I/30/98C Injection system that provides water to the Reactor Building (Containment) Spray system. Clarify if the nozzles of this spray system are within the scope of license renewal? If so, provide a cross reference to where these items are discussed in the submittal. If not, provide the basis for their exclusion.

2.5.6-1 General Note:

All flow diagrams referenced in this request for additional 12/2/98C information relate to the OLRFD series of drawings provided in OLRP-1002.

Note:

Questions 2.5.6-1 and 2.5.6-2 apply to the Spent Fuel Pool Cooling System.

For valves SF1 and 2 (e.g., 104A-1.1, K10 and J9 for Unit 2), the drawing is not clear on whether they are within the scope of license renewal (WSLR). Piping up to the valves has been highlighted, yet the valves themselves are not highlighted. Indicate whether these valves are WSLR, and if not, provide a justification for their exclusion.

2.5.6-2 Table 2.5-9 does not include the blank flanges that isolate the spent fuel pool transfer 12/2/98C tube during plant operation. The components are indicated as being WSLR on flow diagram 104A-1.1, for example. Indicate whether these blank flanges are within scope, and if not, provide a justification for their exclusion.

2.5.6-3 Note:

Question 2.5.6-3 applies to the Auxiliary Service Water System.

12/2/98C Diagram 121D-1.2 illustrates valves 3CCW-438 and 3CCW-98 and connected piping for Unit 3 and valves ICCW-438 and ICCW-244 and connected piping as WSLR; however, valves 2CCW-438 and 2CCW-246 are not highlighted WSLR for Unit 2.

Indicate whether these valves are within scope, and if not, provide justification for their exclusion.

2.5.6-4 Note:

Questions 2.5.6-4 through 2.5.6-8 apply to the Condenser Circulating Water 12/2/98C (CCW) System.

The following components are highlighted as being WSLR, yet not included on Table 2.5-9:

- Main Condenser cooling coil (e.g., 133A-1.2, location J2)

- Emergency Feedwater pump turbine oil cooler (e.g., 133A-1.2, location Il4)

- Condensate Coolers (e.g., 133A-1.3, location F4)

Indicate whether these components are within the scope of license renewal or, if not, 12-16 RAI Status.doc Page 8 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 provide a justification for their exclusion.

2.5.6-5 On Diagram 133A-3. 1, in section D-5, valve 3CCW-341 separates sections of the 12/2/98C CCW system WSLR and not WSLR. This valve is normally open. The valve itself is not designated as WSLR. How can the pressure boundary (i.e., intended function) be assured without this valve being WSLR?

2.5.6-6 On flow diagram 133A-3.1 section B5, piping downstream of valve 3CCW-342 is 12/2/98C designated Duke class F piping, but is not highlighted WSLR? Please justify the exclusion of this piping.

2.5.6-7 On flow diagram 133A-1.4, the Unit I recirculating cooling water (RCW) coolers are 12/2/98C highlighted as WSLR, yet on flow diagram 133A-3.1, the Unit 3 RCW coolers are not highlighted as WSLR. Table 2.5-9 includes the Recirculated Cooling Water Heat Exchanger as a mechanical component and lists its intended function. Indicate whether the Unit 3 RCW coolers are WSLR, and if not, provide a justification for their exclusion.

2.5.6-8 On flow diagram 133A-3.2 at location J-14, downstream of valve 3CCW-363 there is 12/2/98C a blind flange that is not listed on Table 2.5-9, yet it is highlighted. Please indicate whether this pressure boundary component is WSLR, and include it in your evaluation for aging management, or justify its exclusion.

2.5.6-9 Note:

Question 2.5.6-9 applies to the High Pressure Service Water (HPSW) 12/2/98C System.

The following components are not listed on Table 2.5-9, yet are identified as WSLR on the flow diagrams included in the parentheses:

- HPSW Pump A Air Cooler (K6, 124C-1.1),

- Flow restricting orifice (FI0, 124C-1.1),

- Annubar tube (E10, 124C-1.2),

- Elevated storage tank (El, 124C-1.4), and

- Quick disconnects (e.g., C8, 124C-2.2).

Indicate whether these components are within the scope of license renewal or, if not, provide a justification for their exclusion.

2.5.6-10 Note:

Question 2.5.6-10 through 2.5.6-13 apply to the Low Pressure Service Water 12/2/98C (LPSW) System.

The following components are not listed on Table 2.5-9, yet are identified as WSLR on the flow diagrams included in the parentheses:

- Bearing and motor air coolers on the RCPs (e.g., L9, 100A-1.3),

- Marbo tap (e.g., J8, 124B1.1), and

- Quick disconnects (e.g., 124B-2.1, 15).

Indicate whether these components are within the scope of license renewal or, if not, provide a justification for their exclusion.

2.5.6-11 The motor driven emergency feedwater pump motor air cooler piping down stream of 12/2/98C the IA and 1B coolers is not included in the components WSLR. This piping is shown on flow diagram 124A-1.3 at location K4. Include these components on Table 2.5-9 or provide a justification for their exclusion.

2.5.6-12 On flow diagram 124B-2.1, at location Kl4, LPSW system piping from the discharge 12/2/98C of the high pressure injection (HPI) pump motor bearing cooling jackets transitions from WSLR to not WSLR. Details of the piping downstream of this transition are available on flow diagram 124B-1.6, which was not included in the application.

Please provide a copy of the flow diagram 124B-1.6 with the portion of LPSW system WSLR highlighted, or justify why this portion of the LPSW system is not WSLR.

2.5.6-13 Radiation monitor heat exchangers and piping supporting cooling system flow is not 12/2/98C included WSLR as indicated on flow diagram 124B-L.5. Please provide ajustification why these components and piping are not considered WSLR, or indicate where in the application these components are addressed.

2.5.6-14 The following intended functions do not appear in Table 2.5-9, "Components of 12/2/98C Auxiliary Systems and their Intended Functions." Please review this list and discuss 12-16 RAI Status.doc Page 9 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 whether the following componntene ded functions should be included as functions to be maintained for license renewal or provide justification why they should not.

Spent Fuel Pool Cooling Component Intended Function Filter:

Filter Orifice:

Restrict flow or throttle Spent Fuel Coolers:

Heat Transfer Condenser Circulating Water System Component Intended Function Orifice:

Restrict flow or throttle RCW Heat Exchanger Heat Transfer HP Service Water Component Intended Function Filter Filter Mulsifyer Spray Strainer Filter Low Pressure Service Water System Component Intended Function Filter:

Filter Annubar Tube Throttle Strainer Filter Component Coolers Heat Transfer 2.5.7-1 Table 2.5-11 of the submittal lists the components in the process auxiliaries and their 11/30/98C intended functions. Discuss why the following intended function, for the specified component, was not considered as an intended function to be maintained for license renewal. Provide the basis for your determination. The component and its intended function is given below:

Component Intended Function(s)

Spray nozzles Ability to spray water as designed 2.5.7-2 Flow restriction orifices are installed in several pipes in order to limit the mass flow 11/30/98C rate during an accident. Clarify if these orifices are within the scope of license renewal. If so, provide a cross reference to where these items are discussed in the submittal. If not, provide the basis for their exclusion. Additionally, provide a discussion of the intended functions these items might perform for license renewal.

2.5.8-1 NOTE:

All references to flow diagrams in this request for additional information 11/24/98C relate to the Oconee license renewal flow diagram (OLRFD) series of drawings provided in OLRP-1002.

Section 2.5.8 text states that the mechanical components and their intended functions for the systems are identified in Table 2.5-13. However, Oconee's Final Safety Analysis Report Figures 9-24, Control Room Area Ventilation and Air Conditioning System; 9-27, Auxiliary Building Ventilation System; and 9-29, Reactor Building Purge and Cooling System show components beyond those identified in Table 2.5-13.

Discuss whether the additional components and their supports, as listed below, are within scope for license renewal in the heating, ventilation, and air conditioning (HVAC) systems or provide the basis for excluding them:

Damper, damper operator, gravity damper, bird screen, fan and its enclosure (supply and exhaust), coil (heating and cooling), compressor, valve (control, check, and hand),

and air dryer. (Note: Similar question asked by RAI 2.5.13-1 from November 20, 1998, letter to Duke) 2.5.8-2 Note: The following questions apply to Section 2.5.8.1 11/24/98C Discuss whether the exhaust air from the served areas including the hot machine shop and spent fuel pool areas are filtered prior to release to the plant vents to conform with 10 CFR Part 20 and 10 CFR Part 100 requirements. Provide a description of those components and their intended functions (i.e., filtration) discussed above with applicable flow diagrams, as needed, necessary for meeting the requirements of 10 CFR Part 20 and 10 CFR Part 100 or provide justification why they should not be 12-16 RAI Status.doc Page 10 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 considered within the scope of license renewal.

2.5.8-3 Indicate whether the following are within the scope of license renewal, and if not, 1/298 provide a justification for their exclusion:

a.

Flow Diagram 116G-1.1: Supply and return/exhaust ductwork up to the co-ordinate L-2 (supply) and B-3 (exhaust) are highlighted as within the scope of license renewal, yet the ductwork beyond that is not highlighted.

b.

Flow Diaeram 116G-1.2: Ductwork for exhaust from the lower levels to the exhaust fan plenum and supply and return/exhaust to and from the ventilation equipment area and janitorial storage areas are not highlighted.

c.

Flow Diaeram I 16G-L.3: Units 1 and 2 battery room exhaust ductworks (for exhaust fan with back draft damper and bird screen Units 1VS AH0031C and 2VS AHOO31C) are highlighted within the boundaries identified by dotted red rectangles and inward pointing "LR" scoping arrows. However, the outward pointing "LR" scoping arrows are also shown away from these rectangles without any interface information.

d.

Flow Diagram 116G-1.4: Exhaust from the condenser steam air ejectors and the sample hood exhaust to the specific vent stack of Units 1, 2 and 3 are not highlighted. Also, the filter discharges to specific vent stack of Units 1 and 3 are not highlighted.

e.

Flow Diazram 116G-2.1: Supply and return/exhaust ductwork up to the co-ordinate L-2 (supply) and C-5 (exhaust) are highlighted as within the scope of license renewal, yet the ductwork beyond that are not highlighted.

f.

Flow Diagram 116G-3.1: Return/exhaust ductwork up to the co-ordinate E-4 is highlighted as within the scope of license renewal, yet the exhaust/return ductwork from other areas are not highlighted.

g.

Flow Diagram 116G-3.2: The supply air ductwork to serve the lower levels, beyond co-ordinate J-2, is not highlighted. Also, the supply air (from AHU 3-9) and return/exhaust (from served areas by AHU 3-9) ductwork are not highlighted.

2.5.8-4 Note: The following question applies to Section 2.5.8.2 11/24/98C Are sealant materials used to control the unfiltered inleakages? If so, explain why they should or should not be included within the scope of license renewal and considered for aging management review.

2.5.9-1 Note: Referenced drawings are contained in OLRP-1002, License Renewal Flow 1 1/21/98A Diagrams.

Section 2.5.9.1 states that the portions of the main steam system piping within the scope of license renewal are designed and constructed to the requirements of Oconee System Piping Class F and G. However, in reviewing the main steam system piping drawings identified in Table 2.5-14, the staff finds that most of Class G piping are not included in the scope of license renewal.

It is not clear why certain portions of Class G piping are included in the scope and the others are not. Explain the basis for your determination of which portions of Class G piping are within the scope and which portions are not.

2.5.9-2 In Drawing No. OLRFD-122A-1.1 (Main Steam System) Locations J2, J3, 12, 13, E2, 1 1/21/98A E3, D2, D3, there are a variety of instruments (such as "MS P," "MS CR," "MS RD,"

"MS SC") which appear to be excluded from the scope of license renewal. For each of the instrument types on this drawing as examples, provide the basis for excluding those instrumentation from the scope of license renewal in accordance with 10 CFR 54.4.

2.5.9-3 It shows in Drawing No. OLRFD-122A-1.4 (Emergency Feedwater (FDW) Pump 1 1/21/98A Turbine Steam Supply and Exhaust) that the emergency FDW pump turbine is included within the scope of license renewal. Provide the basis for excluding the main FDW pump turbines in Drawing No. OLRFD-122A-1.3 (Main FDW Pump Turbines IA & IB) from the scope of license renewal in accordance with 10 CFR 54.4 2.5.9-4 In Drawing No. OLRFD-121A-1.7 (Condensate System), it shows that upper surge 1 1/21/98A 12-16 RAI Status.doc Page 11 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 tanks 1A and 1B are included within the scope of license renewal.

a.

Provide the basis for excluding the upper surge tank dome (located between the above two tanks) from the scope of license renewal in accordance with 10 CFR 54.4.

b.

Provide the basis for excluding the condensate storage tank from the scope of license renewal in accordance with 10 CFR 54.4.

2.5.9-5 In Drawing No. OLRFD-121A-1.4 (Condensate System), it shows that the piping 11/21/98A within the scope of the license renewal (highlighted in blue) stops at Locations F3, E9, and F9. Provide the bases for your determination that piping downstream of these locations is not considered within the scope of license renewal.

2.5.9-6 In Drawing No. OLRFD-121A-1.6 (Condensate System), it shows that the piping I 1/21/98A within the scope of the license renewal (highlighted in blue) stops at Location F5, D5, and B5. Provide the bases for your determination that piping downstream of these locations is not considered within the scope of license renewal.

2.5.9-7 In Drawing No. OLRFD-121B-1.3 (Feedwater System), provide the bases why the 11/21/98A piping considered within the scope of license renewal (highlighted in blue) stops at valve No. 1FW-41 (Location J6) and No. IFW-32 (Location D6). [see also RAI No.

2.5.9-1].

2.5.10-1 Flow Diagrams OLRFD-1 10A-1.3, 2.3 and 3.3 show the hydrogen analyzers to be 12/1/98A within the scope of license renewal. The hydrogen analyzers, however, are not included as one of the mechanical components in Table 2.5-17, "Components of Post Accident Hydrogen Control Systems and Their Intended Functions," of OLRP-1001.

2.5.10-2 Clarify why Flow Diagram OLRFD-107B-1.1 was excluded from Table 2.5-16, "Flow 12/1/98A Diagrams Indicating Evaluation Boundaries of Post-Accident Hydrogen Control Systems," of OLRP-1001. Clarify this inconsistency.

2.5.10-3 Regulatory Guide 1.97 recommends under Type E variables the capability to sample 12/1/98A the primary coolant, sump and containment atmosphere. Justify why the pressure boundary tubing for the post-accident containment atmosphere sampling system, as shown on Flow Diagrams OLRFD-11OA-1.3, 2.3 and 3.3, was not included within the scope of license renewal.

2.5.13-1 Section 2.5.13 states that the license renewal flow diagrams listed in Table 2.5-22 11/20/98F show the evaluation boundaries for the portions of the Keowee systems that are within the scope of license renewal. Further, it states that the mechanical components and their intended functions for the systems in this section are identified in Table 2.5-23.

In a conference call on November 3, 1998, Duke Energy stated that the components subject to aging management review (AMR) are listed in Table 2.5-23. In the scoping process, it is important to be able to distinguish between the components that are within the scope of license renewal (in accordance with 10 CFR 54.4) and a subset of components that are subject to AMR (in accordance with 10 CFR 54.21) (i.e., those that are long-lived and perform an intended function without moving parts or change in configuration or properties). However, it is not clear from the statement in Section 2.5.13, describing Table 2.5-23, whether the components listed in Table 2.5-23 are within the scope of license renewal or those specifically subject to AMR.

Commensurate with the items discussed in the conference call on November 3, 1998, clarify and confirm that the components listed in Table 2.5-23 are those subject to AMR. This comment also applies to the other sections of Chapter 2 (i.e., clarify that structures and components contained in Chapter 2 tables, consistent with the RAI above regarding Table 2.5-23, are subject to AMR).

2.5.13-2

a.

The Keowee Hydroelectric Station provides a unique emergency power source for 11/20/98F Oconee. However, the description of Keowee in the application does not discuss the major components that are necessary for the generation of the emergency power in sufficient detail for the staff to determine whether the appropriate structures and components have been included in the scope of license renewal.

Describe in more detail the major components relied upon for the generation of emergency power (for example, the turbine, turbine housing, associated piping, pumps, valves, the generator, synchronizing equipment generator output breakers, control circuitry, protective relaying, the exciter/voltage regulator, and auxiliary power for Keowee Hydroelectric Station) and whether Duke determined these 12-16 RAI Status.doc Page 12 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 components to be within the scope of license renewal in accordance with 10 CFR 54.4. Otherwise, provide justification of why those components are excluded from the scope of license renewal.

b.

In the conference call on November 3, 1998, the licensee indicated that certain Keowee Hydroelectric Station components were determined not to be subject to an AMR. Therefore, the licensee concluded that those components do not need to be addressed in OLRP-1001. For those structures and components determined to be within the scope of license renewal for the Keowee Hydroelectric Station discuss the conclusions reached on whether an AMR should be performed. For example, OLRP-1001 does not address the turbine in the description of Keowee and the flow diagrams listed in Table 2.5-22 do not include the turbine. The staff believes that the turbine is within the scope of license renewal and the turbine casing should be subject to AMR. Therefore, discuss if the turbine is within the scope of license renewal and provide the rationale for excluding the turbine casing from the AMR.

2.5.13-3 In Drawing No. KLRFD-105A-1.1 (Governor Oil System), the component of governor 11/20/98F (Location F14) is highlighted in blue as being within the scope of license renewal.

However, in Table 2.5-23, "Components of Keowee Hydroelectric Station Systems and Their Intended Functions," the "governor" is not included. Provide the bases for excluding it.

2.6-1 Section 2.6.1 of the application describes the scoping process to identify electrical 11/25/98A components subject to an aging management review. This scoping process is based on installed location first and then system function. This differs from the mechanical scoping process which evaluates systems, structures, and components based on 10 CFR 54.4 (a)(1),(2), and (3) criteria. As such, the electrical component scoping is highly dependent upon the accuracy of the identification of Class 1, Class 2, and Class 3 structures to identify the scope of electrical components for license renewal. With the above electrical component scoping process discuss how the list of electrical components subject to an aging management review is determined to be complete and accurate. In addition, provide a list of the license renewal basis documents that were used for scoping based on location and system function including summary information from each document that supports the process and methodology for electrical scoping.

2.6-2 The scoping of systems, structures, and components required by the license renewal 1 1/25/98A rule and the maintenance rule are similar. Provide a comparison of the scope of electrical systems and components for these rules and describe the significant differences, if any.

2.6-3 Section 2.6.1 of the application identified electrical buses, insulated cables and 11/25/98A connections, insulators, and transmission conductors as the electrical components that are subject to an aging management review. 10 CFR 54.21 (a)(1)(i) lists electrical and mechanical penetrations as components that are subject to an aging management review. Identify any non-EQ electrical penetration assemblies that are subject to an aging management review and describe their intended functions.

2.6-4 Section 2.6.6.1.2 of the application identified insulated cables and connections used 11/25/98A for fire detectors as part of the fire detection system and excluded them from an aging management review on the grounds that they are replaced based on a performance or condition program. The Commission has concluded in the statements of consideration for 10 CFR Part 54, Section m.d.(vi) that fire protection components that perform active functions can be generally excluded from an aging management review on the basis of performance or condition-monitoring programs. Since electrical cables and connectors are identified in 10 CFR 54.21 as being subject to an aging management review because they perform their intended function without moving parts or without a change in configuration or properties, describe how the fire detector insulated cables are different from other electrical cables.

2.6-5 For cables that are stored onsite for the purpose of rewiring plant equipment following 11/25/98A a design basic event in order to meet the 72-hour cold shutdown requirement, discuss the stressors these cables are exposed to, the resulting aging effects, and the need for aging management review.

12-16 RAI Status.doc Page 13 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 2.6-6 Section 2.6.6.5 of the application concludes that resistance temperature detectors 11/25/98A (RTDs) do not perform their function without moving parts or without a change in configuration or properties and thus not subject to an aging management review. The industry guidance for license renewal in NEI 95-10, Revision 0, Appendix B, recommends that RTDs should be subject to an aging management review. Provide an aging management review for the RTDs, or provide a more detailed basis for their exclusion.

2.6-7 Section 2.6.6.6 of the application concludes that thermocouples do not perform their 11/25/98A function without moving parts or without a change in configuration or properties. The industry guidance for license renewal in NEI 95-10, Revision 0, Appendix B recommends that thermocouples should be subject to an aging management review.

Provide an aging management review for the thermocouples or provide a more detailed basis for their exclusion.

2.6-8 Section 2.6.7 of the application states that the electrical component integrated plant 11/25/98A assessment is a component-based review where component characteristics are compared to their service conditions. Describe the methodology for determining the service conditions, including measured parameters and operational experience, that the components are exposed to and the criteria that are used to determine whether a component is subject to an aging management review based on its location.

2.6-9 OSS-0274.00-00-0006 dated September 10, 1998, Revision 0, excludes uninsulated 11/25/98A ground conductors in Section 11 from an aging management review on the basis of system function. In addition, it is stated that there are no failures of uninsulated ground conductors that could prevent satisfactory accomplishment of any of the functions identified in 10 CFR Part 54.4 (a)(1)(i), (ii), or (iii). Provide the basis for this statement and discuss whether a failure mode and effects analysis was performed to arrive at this conclusion.

2.6.1-1 Note:

While reviewing various Oconee license renewal basis documents (including 12/1/98B OSS-0274.00-00-0006, "Oconee Electrical Component Aging Management Review for License Renewal," Rev. 0) during the October 27-30, 1998, site visit, the staff developed the following four questions.

OSS-0274.00-00-0006, Subsection 3.1.4.2, "Scoping Based on System Function,"

states, in part, that "[t]he second part of electrical component scoping is performed by looking at the system functions performed by the electrical components and comparing these system functions to the functions identified in 10 CFR 54.4." Therefore, at this stage of the process, electrical components are determined to require an aging management review only if the system-level function performed by the component meets the scoping criteria in 10 CFR 54.4.

Section 54.21(a)(1) states, in part, that "[s]tructures and components subject to an aging management review shall encompass those structures and components -- (i)

[t]hat perform an intended function, as described in 10 CFR 54.4, without moving parts or without a change in configuration or properties." Accordingly, the staff and the industry (in NEI 95-10, Subsection 4.1.2, "Determining Structures and Components Subject to Aging Management Review and Their Intended Functions")

have interpreted this requirement to mean that the selection of components subject to an aging management review should be based on component-level intended function(s) and not system-level functions. Specifically, NEI 95-10, Subsection 4.1.2, states, in part, that "[tihe structure or component intended function(s) is the specifc function of the structure or component that supports the system intended function."

[OLRP-1001 Section 2.6.1]

a.

Please describe the process used by Duke to identify the system function(s) performed by electrical components and how this process confirms that the intended function(s) (as defined in NEI 95-10) of electrical components has been identified.

b.

Please provide a justification for using system-levelfunctions to exclude electrical components from requiring an aging management review.

2.6.1-2 OSS-0274.00-00.0006, Subsection 3.1.4.2.1, "Bounding The Actual Set of In-Scope 12/1/98B Components," states that "[w]hen applying the 10 CFR 54.4 scoping criteria to the electrical components, it is necessary to identify the higher level system functions 12-16 RAI Status.doc Page 14 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 performed by the electrical component type and compare these system functions - in the context of the Oconee current licensing basis (CLB) - to the functions identified in 10 CFR 54.4." However, this subsection also adds: "When component identification per 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2) is not clear or workable, a larger, bounding set of electrical components is identified." [OLRP-1001 Section 2.6.1]

a.

Please explain why "component identification per 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2) is not clear or workable at Oconee" and describe how Duke can demonstrate compliance with the scoping requirements of 10 CFR 54.4(a) when this is the case.

b.

Please describe the extent to which the OSRDC results were used by Duke when component identification per 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(2) was not clear or workable. If the OSRDC results were not used, please provide justification.

2.6.1-3 OSS-0274.00-00.0006, Subsection 3.2.1, "10 CFR 54.21(a)(1)(i) Determination,"

12/1/98B states that "[t]he starting point of this determination is the generation of the list of all electrical component types along with identification of the basic component functions." Subsection 3.2.2, 10 CFR 54.4, "Scoping," adds: "The system function scoping is performed based strictly on the functions the component performs within its system as described in Oconee current licensing basis (CLB) documents."

Section 54.21(a)(1) states, in part, that "[s]tructures and components subject to an aging management review shall encompass those structures and components -- (i)

[t]hat perform an intended function, as described in 10 CFR 54.4, without moving parts or without a change in configuration or properties." Accordingly, the staff and the industry (in NEI 95-10, Section 4.0 and Section 4.1.2) have interpreted this requirement to mean that the active/passive determination should be performed using component-level intended function that is based on the criteria under 10 CFR 54.4(a).

[OLRP-1001 Section 2.6.1]

a.

Based on the above, the staff requests that Duke provide its basis for concluding that the approach described in OSS-0274.00-00.0006, Subsection 3.2.1, is consistent with the requirements of the rule.

b.

Regarding the system function scoping approach described in OSS-0274.00 00.0006, Subsection 3.2.1, please describe the extent to which the OSRDC results were used by Duke. If such results were not used, please provide justification.

2.6.1-4 OSS-0274.00-00.0006, Subsection 3.1.5, "Determine Which Electrical Components 12/1/98B Are Subject To Replacement Based On A Qualified Life Or Specified Time Period,"

states that "[tihis step is accomplished by investigating each electrical component type within scope to determine if any plant program or procedure identifies a time-based component life and has provisions to replace the component prior to the end of its lie.

Section 54.21(a)(1) states, in part, that "[s]tructures and components subject to an aging management review shall encompass those structures and components -- (ii)

That are not subiect to replacement based on a qualified life or specified time period." [OLRP-1001 Section 2.6.1]

Please describe the difference, if any, between the requirements.of the rule and the language in OSS-0274.00-00.0006, Subsection 3.1.5, regarding the identification of structures and components not subject to replacement based on a qualified life or specified time period. Specifically:

a.

Describe the criteria used by Duke for determining that an electrical component type has a time-based component life.

b.

Define what constitute provisions [in any plant program or procedure] to replace the component prior to the end of its life.

c.

Identify the difference, if any, between the term "time-based component life" as used in OSS-0274.00-00.0006, Subsection 3.1.5, and the term "qualified life" as used in 10 CFR 54.21(a)(1)(ii).

2.6.7-1 Note: Question 2.6.7-1 applies to Sections 2.6.7 and 2.7.1 of OLRP-1001.

12/1/98B In Appendix A, "Scoping Electrical Components Based on Their Installed Location,"

12-16 RAI Status.doc Page 15 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 to OSS-0274.00-00.0006, electrical components associated with the 100kV transmission line and Transformer CTS were excluded from the scope of license renewal based solely (apparently) on the determination that structures associated with the 100kV transmission line and Transformer CT5 were not classified as Class 1 or Class 2 in the Oconee UFSAR, and therefore, are considered Class 3.

Appendix A states that "[tihere are Class 1, Class 2, and Class 3 structures where Class 1 and Class 2 structures are within license renewal scope and Class 3 structures are not within license renewal scope [Reference 10, Chapter 3]. Appendix A also adds that "there is reasonable assurance that if a structure is not identified as required to demonstrate compliance with the regulated events identified in 10 CFR 54.4(a)(3), it does not support any electrical components needed to meet the requirements of 10 CFR 54.4(a)(3)." [OLRP-1001 Sections 2.6.7 and 2.7.1]

a.

Please describe the extent to which the OSRDC project results were used to reach the conclusion that structures associated with Transformer CT5 and the 100kV transmission line are Class 3. If such results were not used, please provide justification. This justification should address the role of Transformer CT5 and the 100kV transmission line in the Oconee Technical Specifications and Emergency Operating Procedures.

b.

Please describe the methodology used during the scoping process of Oconee structures to identify all electrical components that perform the functions identified in 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3). If the electrical components were not explicitly identified during this process, please.

provide justification for Duke's reliance on installed location for scoping electrical components.

c.

Please describe the extent to which the OSRDC project results were used during the scoping process of Oconee structures to identify all electrical components that perform the functions identified in 10 CFR 54.4(a)(1), 10 CFR 54.4(a)(2), or 10 CFR 54.4(a)(3). If the OSRDC project results were not used, please provide justification.

2.6.7-2 In OLRP-1001, Subsection 2.6.7, "Structures and Areas Containing Electrical 12/1/98B Components Subject to Aging Management Review," Duke states, in part, that "[b]y eliminating structures and areas that do not contain any electrical components that are within the scope of license renewal and by adding direct buried cables as part of Yard Structures, the structures and areas that contain electrical components within the scope of license renewal are identified." [OLRP-1001 Section 2.6.7]

a.

Please describe in detail the process used by Duke to identify all the Oconee "structures and areas that do not contain any electrical components that are within the scope of license renewal."

b.

Please describe the extent to which the OSRDC project results were used in this process. If they were not used, please provide justification.

2.7-1 Section 2.7.2 of OLRP-1001 provides a list of concrete structural and steel 11/118/98A components that are within the scope of license renewal and subject to aging management review (AMR). With regard to the scoping of structures and structural components (concrete and steel), address the following questions:

a.

Are there any electrical duct banks and steel structural frames at Oconee? If yes, provide basis for not including these structural components in the scope of AMR.

b.

Provide basis for not including crane columns, trolleys and mechanical cables in the scope of AMR.

c.

Section 2.7.2.2.1 provides a description of various types of pipe supports. Are there any safety-related piping systems supported by structural frames? If yes, provide an explanation how these frames are covered in the AMR.

d.

Provide basis for not considering the steel bracings between steel columns as steel components in an air environment in the AMR.

2.7-2 In Section 2.7.2 of the application, pipe piles (Section 2.7.2.1), piles (Section 2.7.2.2),

11/18/98A and masonry block and brick walls (Section 2.7.2.1) are listed as structure components that are within the scope of license renewal and are subject to aging management r

1 12-16 RAI Status.doc Page 16 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 review. Tables 2.7-1 through 2.7-8 of the application describe the intended functions of these structure components. Also, Section 2.7.9.1 (Switchgear Enclosures as part of the turbine building) of the application includes a statement that the transformer and switchgear enclosure is supported by battered pipe piles. The pipe piles were filled with concrete during construction of the structure. With regard to the description of structures and structure components, address the following questions:

a.

In the description of structures and structure components (Sections 2.7.3 through 2.7.10), provide discussion of piles and masonry block and brick walls regarding their use (including the design information) and how they are included in the AMR. Have piles (not pipe piles) been used to support equipment or structures?

If not, why are they included in the scope of license renewal?

b.

As stated above, a description is provided in Section 2.7.9.1 ( that the transformer and switchgear enclosure is supported by battered pipe piles. Provide a clarification why the intended functions of pipe piles are listed in Table 2.7-8 (yard structure components), but not in Table 2.7-7 (Switchgear Enclosures as part of the turbine building).

2.7-3 Section 2.7.3 (Auxiliary Buildings) of the application includes a statement that all 11/18/98A below grade construction joints in exterior walls are protected by cast in place water stops. It is the staffs interpretation that water stops are included in the scope of license renewal and are subject to the AMR. Regarding the AMR for the water stops, address the following questions:

a.

Why are water stops not listed in Section 2.7.2 (structure components within the license renewal scope) nor described in Table 2.7-1 (intended functions of structure components of the auxiliary buildings)?

b.

Based on the staff's review experience of other operating plants, water stops are commonly used in the embedded exterior walls of reinforced concrete structures.

Explain why water stops were only described in Section 2.7.3 for the auxiliary buildings.

c.

Describe the aging effects on these structure components and provide a discussion of how the aging effects will be addressed for the extended period of operation.

(Water stops are not addressed in Section 3.7 of the application).

2.7-4 With regard to Table 2.7-3 of OLRP-001, address the following:

11/18/98A

a.

Trash racks and screens and some component supports are listed as "steel in fluid environment" that require aging management review. Are there any anchorages and embedments (with exposed surfaces and submerged in the water) to which these trash racks and screens and equipment component supports are attached? If yes, provide basis for not considering these anchorages and embedments as "steel in fluid environment" in the aging management review.

b.

Provide an explanation why the intake structure reinforced concrete roof slab is not subject to aging management review.

2.7-5 During the Oconee license renewal scoping and screening process overview meeting 11/18/98A held on October 1, 1998, the staff was informed that tanks (including the vertical tanks erected in the field) are considered as mechanical components. However, the tank foundation and anchorage systems are considered as structural components. With regard to the scoping process for the vertical tanks, address the following concerns:

a.

Provide a basis for not including tank supports in the discussion of OLRP Section 2.7.2, "Structural Components."

b.

Provide the definition of the boundary (or interface) between tanks (mechanical components) and tank supports (structural components) which are usually welded to the tanks.

2.7-6 As a common industry practice, the portions of piping between the boundary of the 11/18/98A safety-related piping and non-safety related piping and the first seismic anchors (or equivalent) beyond the boundary are treated as piping segments that provide structural supports. Provide clarification on how these segments of piping will be included and evaluated in the aging management review.

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Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 2.7-7 In Table 2.7-5, the reinforced concrete beams, etc. (under concrete components) 1118/98A includes primary and secondary shield walls. Explain why the intended function 1, (i.e., provides pressure boundary/or fission product barrier) is not applicable to these components.

2.7-8 Section 2.7.7.4 states that the post-tensioning components (i.e., tendon wires and 11/18/98A anchorages) of the secondary shield wall (SSW) are subjected to aging management review. In addition, the operating experience database described in Section 3.7.7.4.3 related to the SSW post-tensioning system describes significant degradation of tendon wires. Provide justification why the prestressing forces in the tendons and prestressing losses should not be subjected to time-limited aging analysis (TLAA).

2.7-9 Provide justification why the settlement (and differential settlement) of in-scope 11/18/98A structures and their consequences should not be considered in the aging management review.

2.7-10 Provide sketches of the in-scope structures showing boundaries of the structures 11/18/98A included in the AMR (e.g., Intake Structure with other water control structures and buried service water piping).

3.2-1 Section 3.2 of the application identified thermal, radiation, and moisture as the service 11/25/98A environment stressors in which components operate that may result in aging effects of concern for license renewal. In addition to the above identified service environment stressors, discuss the potential aging effects that may occur at Oconee for license renewal due to humidity, water spray, steam, water immersion, chemicals, (including sprays) vibration and seismic motion and operational stressors produced by equipment operation.

3.2-2 Oconee operating experience has indicated that certain portions of the structures and 11/25/98B structural components are subjected to moisture/water exposure on a sustained basis, whether from natural sources (such as ground and river water) or operating conditions (system leakages), that have resulted in material degradation. Provide justification as to why moisture/water (Section 3.2.2.3) should not be considered an applicable aging effect that would warrant an aging management review for the structures and structural components subjected to this environment. Event driven corrective actions do not appear to be an aging management process sufficient to address this issue in a comprehensive manner for the extended period of operation.

3.2-3 Table 3.2-2 provides assessments of structures for 40 year and 60 year radiation 11/25/98B exposure in terms of the integrated doses in 'rads.' However, the important parameters affecting the structural properties are high-flux neutrons and integrated gamma doses.

Provide the Table in terms of these parameters. For the reactor cavities, the steam generator cavities, and the spent fuel pools (Auxiliary Buildings) provide an assessment of synergistic effects of temperatures and radiation on the structural properties of the structures and components (e.g., concrete walls, concrete reactor supports, steel supports, and anchor bolts) and address as such as part of the aging management programs in these areas.

3.3-1 Section 3.3.1.1.2 of the report concludes that there are no applicable aging effects for July 6,1998 containment concrete components. The proposed justification is largely based on concrete construction meeting design codes and standards. The report indicated that NUREG-1522 and NUREG/CR-6424 were reviewed.

However, NUREG-1522, Appendix A, documented containment concrete degradation in plants constructed to similar codes and standards. In addition, NUREG/CR-6424 states, "The performance of reinforced concrete structures in Nuclear Power Plants has been good. However, as these structures age, incidences of degradation due to environmental stressor effects are likely to increase to potentially threaten their durability."

Further, 10 CFR 50.55a requires concrete containments be inspected according to Subsections IWE and IWL of the ASME Section XI Code.

Section 3.3.II.B of the SRP-LR contains information on applicable aging effects for concrete containment components.

Thus, the staff disagrees that there are no applicable aging effects on containment concrete components. The applicant should revise the assessment of applicable aging 12-16 RAI Status.doc Page 18 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 effects for Oconee concrete components and propose aging management for the applicable aging effects.

3.3-2 Discuss any containment steel components that are not protected by coatings or July 6, 1998 encased in concrete. Describe how corrosion will being managed for those components?

3.3-3 The report indicates that Subsections IWE and IWL of the ASME Section XI Code are July 6, 1998 necessary for managing aging for renewal. Please specify the code "examination categories" for all of the referenced ASME Section XI inspections relied on for aging management.

3.3-4 The report discusses that Section XI "will continue to be maintained through the July 6, 1998 consensus process of the ASME Code" and are "expected to be effective in managing" aging during the period of extended operation. In addition, the report states, "the Commission's process of reviewing Editions and Addenda of the ASME Boiler and Pressure Vessel Code, and incorporating them into 50.55a with limitations and modifications as required, provide reasonable assurance that required activities will adequately manage the aging effects." The report should identify the specific edition and addenda of the ASME code for staff review. Also, if certain paragraphs of 10 CFR 50.55a are relied on to manage aging for renewal, these paragraphs and the year of publication should be cited.

3.3-5 Discuss the aging management programs to be relied on for inaccessible areas of steel July 6, 1998 components regarding corrosion and cracking.

3.3-6 Section 3.3.2.2.1 of the report discusses loading cycles for the liner. However, Section July 6, 1998 3.3.1.1.1.2 of the report indicates that "the periodic Type A Integrated Leak Rate tests are the major sources of load changes." Where are the Type A loads included in Section 3.3.2.2.1?

3.3-7 Section 2.3.2.2 of the report indicates that the polar crane brackets and other July 6, 1998 miscellaneous attachments are within the scope of this report. Discuss whether there are periodic loads on these structures that need to be evaluated as part of the time limited aging analysis in Section 3.3.2.2.1.

3.3-8 Section 3.3.2.2.1 of the report indicates that the projected number of heatup and July 6, 1998 cooldown cycles would not exceed the originally assumed 360 number even for 60 years. Please provide information on the number of heatup and cooldown cycles already experienced and the methodology for projecting them to 60 years.

3.3-9 Fretting and lockup of the personnel airlock and equipment hatch could result from July 6, 1998 mechanical wear. Provide appropriate aging management for these and any other aging effects applicable to the airlock.

3.3-10 Discuss whether expansion joint sealants have ever deteriorated causing degradation of July 6, 1998 the liner below the floor and, if so, what actions were taken.

3.3-11 Discuss whether corrosion has ever been observed in crevices where the coating ends July 6, 1998 and steel is exposed and, if so, what actions were taken.

3.3-12 Was a corrosion allowance specified for the liner? Describe any liner thickness July 6, 1998 2

surveys that have been conducted and, if conducted, the estimated corrosion rate from those surveys?

3.3-13 Section 4.5 of the SRP-LR considers metal corrosion allowance as a time-limited July 6, 1998 aging analysis. Discuss whether this is applicable to the containment steel components.

3.3-14 Section 3.3.3.1.2 of the report indicates that "minor grease leakage through the July 6, 1998 concrete shell and at anchorages have been observed.... The grease leakage is being monitored and there exists no evidence to date to show that the bulk-fill grease has any detrimental effect on concrete." Provide additional information on how the aging effects of grease leaked into concrete is being managed and discuss how the elements in Section 3.0.II.C of the SRP-LR are met by the program.

Also, discuss the potential effects of grease on the shear load capability of the concrete structure.

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Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.3-15 Section 3.3.E.C.4 of the SRP-LR indicates that an increase in temperature increases July 6, 1998 the prestress loss in prestressed tendons. It identifies sun exposure or proximity to hot penetrations as potential contributors. Please discuss management of this potential aging effect for renewal.

3.3-16 Section 3.3.3.1.3.1 of the report uses words "similar" and "similarities." Please July 6, 1998 discusses the intent of this wording and whether there are any differences between the selection of words.

3.3-17 Section 3.3.3.1.1 of the report indicates that loss of materials due to corrosion is the July 6, 1998 only applicable aging effect for tendons. However, other aging effects have been observed at operating plants such as stress corrosion cracking, hydrogen embrittlement, stress relaxation of prestressing wire, and shrinkage creep that could result in loss of prestress. Revise the report to discuss these additional potentially applicable aging effects for the tendons.

3.3-18 Section 3.3.2.1.1.4 of the report discusses Oconee's "existing coating maintenance July 6, 1998 procedures." However, Table 3.3-1 of the report does not include this as an aging management program for renewal. If coatings are credited for preventing or minimizing corrosion of the coated steel, the coating maintenance procedure is considered an aging management program. Please clarify whether the coating procedure is credited as an aging management program, and. if so, discuss how the elements in Section 3.0.II.C of the SRP-LR are met.

3.3-19 (Question refers to Section 3.3.1 of OLRP-1001) In view of the fact that expansion 11/19/98 joints, caulking, and sealants associated with containment structure integrity (e.g.

moisture barrier at the junction of liner plate and basemat fill concrete) are not subjected to replacement based on qualified life or specified time period, explain why they should not be considered for aging management review [see 10 CFR 54.21(a)(1)(ii)] and addressed in this Section.

3.3-20 Section 3.3.2.3 indicates that the degradation mechanisms applicable to cracking of 11/19/98 concrete in the Oconee containments are as per Ref. 3.3-5 (ACI-201) of OLRP-1001.

However, the Oconee containments are subjected to significant compression and splitting tensile stresses at the locations of post-tensioning anchorages (buttresses, top and side of ring-girders, bottom of the basemat in tendon galleries). Environmental effects such as freeze-thaw and temperature, and material characteristics such as alkali-silica reaction can accentuate the mechanically induced cracking. Explain why such synergistic effects should not be considered as contributing to cracking in Oconee containments and addressed as such as part of the aging management programs for the containments..

3.3-21 In response to RAI 3.3-1 (Attachment 2 to Duke's letter to NRC on containment 11/19/98 review for renewed operating license, August 12, 1998) you state that Section 3.3.2.7 has been revised to address inaccessible areas of containment concrete components.

Your OLRP-1001, Section 3.3.2.6 indicates one sentence related to symptomatic evidence of cracking and leaching. Provide an explanation for why the below ground areas of concrete surfaces and embedded areas of liner plate (the inaccessible areas) should not be explicitly considered for aging management review based on the evidence cited in Sections 3.3.2.6 and 3.3.3.6.

3.4.3-1 Note:

Question 3.4.3-1 is a duplicate of question 3.4.4-1 that was issued in a 12/2/98D November 20, 1998, letter to Duke. The question applies to both Sections 3.4.3 and 3.4.4. Because it applies to two Sections it is repeated below to ensure that it is clear that the staff is expecting an answer that will address both reactor coolant piping and the pressurizer.

Section 3.4.3 of the license renewal application references report BAW-2243A.

Section 3.4.4 references BAW-2244A. These reports do not address specific time limited aging analyses for the reactor coolant system piping or for the pressurizer. It is left up to the individual plant to address this issue. Therefore, for Oconee Units 1, 2, and 3, we request that you provide a demonstration that the ASME Code Section I cumulative usage factor for all Reactor Coolant System Piping and Pressurizer Class 1 components will be less than or equal to 1.0 for 60 years of plant operation.

3.4.4-1 Section 3.4.3 of the license renewal application references report BAW-2243A.

I 1/20/98A Section 3.4.4 references BAW-2244A. These reports do not address specific time 12-16 RAI Status.doc Page 20 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 limited aging analyses for the reactor coolant system piping or for the pressurizer. It is left up to the individual plant to address this issue. Therefore, for Oconee Units 1, 2, and 3, we request that you provide a demonstration that the ASME Code Section III cumulative usage factor for all Reactor Coolant System Piping and Pressurizer Class I components will be less than or equal to 1.0 for 60 years of plant operation.

3.4.5-1 The following general issue with respect to plant aging needs to be addressed:

11/20/98G Based on its evaluation of operating experience, the NRC has determined that potential aging effect mechanisms in components of pressurized water reactor vessels are as indicated in the Table 3.1-3 of the Draft Standard Review Plan for License Renewal. Table 3.1-3 identifies components that are considered part of the reactor pressure vessel (RPV) and identifies the associated aging effects for the components.

Identify the equivalent components in the Oconee reactor pressure vessels and identify the aging effects (identified as significant or unresolved in Table 3.1-3) applicable to these components and where they are addressed in the application. For those aging effects that are not addressed explain why they are not applicable.

3.4.5-2 Note:

Questions 3.4.5-2 through 3.4.5-8 discuss how the Oconee license renewal 11/20/98G application relates to BAW-2251. There are aspects of the questions that involve sections 3.4.5, 4.24, and 5.4.2 of Oconee's license renewal application. The questions have all been placed in this section for convenience.

The following are action items to be addressed by a plant-specific license renewal application when incorporating by reference the Babcock & Wilcox Owners Group (B&WOG) topical report, BAW-2251. Provide the following:

a)

The license renewal applicant is to verify that its plant is bounded by the topical report. Further, the renewal applicant is to commit to programs described as necessary in the topical report to manage the effects of aging during the period of extended operation on the functionality of the reactor vessel components. Duke Energy, the applicant for license renewal will be responsible for verifying that any such commitments are subject to appropriate regulatory control. As such, identify any deviations from the aging management programs described in Topical Report BAW-225 1. Evaluate any deviations on a plant-specific basis in accordance with 10 CFR 54.21 (a)(3) and (c)(1).

b) B&WOG has determined that the lower control rod drive mechanism (CRDM) service support structure, including the weld that connects the lower CRDM service support skirt to the reactor vessel closure head, and the reactor vessel support skirt, including the weld that connects the reactor vessel support skirt to the transition forging, are subject to an aging management review for license renewal. However, the B&WOG has decided to exclude them from the scope of the Topical Report BAW-225 1. Identify which aging effects are applicable to these components and describe your aging management program for these components in the license renewal application.

3.4.5-3 Note:

Additional plant-specific open Items that need to be addressed relative to the 11/20/98G contents of the license renewal application and Topical Report BAW-2251 are discussed in question 3.4.5-3 through 3.4.5-8.

Intended Function of Reactor Vessel Components Identify whether the intended function of the reactor vessel internals is to maintain the capability to shut down the reactor and maintain it in a safe-shutdown condition.

3.4.5-4 Flow Stabilizers Subiect to Aging Management Review 11/20/98G The staff has concerns about whether the flow stabilizers should be excluded from an aging management review for license renewal. Although the flow stabilizers themselves do not have safety-related functions, they were installed to address flow induced vibration (FIV) problems experienced during hot functional testing. Thus, cracking of the attachment weld may cause the reactor vessel shell to crack thereby affecting its intended functions. Indicate if an aging management program is provided to manage the aging effects on the flow stabilizers. If so, provide the details of such a program; if not justify why such a program is not needed to ensure the integrity of these stabilizers over the extended life for the units.

3.4.5-5 Wear of Core Guide Lues 11/20/98G The staff considers loss of material due to mechanical wear of the core guide lugs a 12-16 RAI Status.doc Page 21 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 potential applicable aging effect that should be managed for license renewal. This potential aging effect is discussed in Section 3.1 of the working draft standard review plan for license renewal. Indicate if an aging management program is provided to manage the aging effects on the lugs. If so, provide the details of such a program; if not justify why such a program is not needed to ensure the integrity of the lugs over the extended life for the units.

3.4.5-6 Underclad Cracking 11/20/98G Cracking has been detected under the austenitic stainless steel weld cladding in reactor vessel forgings. When cracks are detected, the licensee performs a time-limited aging analysis (TLAA) to evaluate the integrity of the reactor vessel. However, the staff considers the potential for underclad cracks to grow during plant operation an applicable aging effect to be managed for license renewal. Indicate if an aging management program is provided to manage the aging effects on the stainless steel cladding in the forgings. If so, provide the details of such a program. If not, justify why such a program is not needed to ensure the integrity of reactor vessel forgings.

3.4.5-7 Reactor Vessel Materials Surveillance Proaram 11/20/98G To ensure that the results of fracture toughness tests remain valid during the extended license period, describe the operating limitations necessary for ensuring that each plants' operating conditions (temperature and neutron fluence) do not invalidate the results of fracture toughness tests conducted on surveillance capsules removed from the Oconee reactor pressure vessels during the original 40-year license periods for the plants.

3.4.5-8 Additional Limitations on Pressure-temperature (P-T') Limits and Reactor Coolant,

11/20/98G Pump Seal Limits Based on the projected P-T limits at the end of the extended license period and other plant operating limits (e.g., limits of pump seal pressure), identify whether the operating windows for the Oconee units will be sufficient to start up and shut down the units at the end of the extended license period. If the operating windows are insufficient, provide aging management programs to increase the operating windows or reduce the amount of neutron embrittlement to the Oconee RPVs.

3.4.6-1 Section 3.4.6.1 states that "Oconee Reactor Coolant System chemistry is maintained in 11/20/98C accordance with the Oconee Chemistry Control Program." Provide a description of the extent and frequency of excursions from the primary coolant chemistry parameters for each plant. What is the impact of these excursions on the RVI components?

Explain the basis for this conclusion.

3.4.6-2 Section 3.3 of BAW-2248 indicates that crevice corrosion is not expected to be a 11/20/98C concern, unless the internals are exposed to a series of long outages which have stagnation and high impurity levels. Has Oconee exceeded the impurity levels and cumulative outage time required to cause concern for crevice corrosion? What components are potentially affected?

3.4.7-1 It is stated in Section 3.4.7.1 of the license renewal application that the once through 11/18/98B steam generator (SG) is designed to accommodate all service loadings (i.e., Levels A through D); however, operation under Levels A and B service conditions contribute to the normal aging stresses for the once through SG items. The Oconee units have not been subjected to Levels C or D events. It is the staff's understanding that the tubes in Oconee Unit 3 were subjected to stresses slightly beyond the allowable values during an event in August 1994 involving the injection of cold feedwater into a hot, dry SG.

Discuss whether or not this event contributed to the aging of the SG tubes. Describe the procedures that are used to evaluate the impact of such events on the adequacy of aging management programs.

3.4.7-2 It is stated in Section 3.4.7.2.3 of the license renewal application that mechanical 11/18/98B distortion is an applicable aging effect for the once through SG. The installation of sleeves in the SG tubes cause a distortion of the tube at the expansion joint of the sleeve. The increased stress in the tube makes it susceptible to circumferential cracking at this location. Discuss whether current measures to manage this aging effect during plant operation are considered adequate and sufficient to manage anticipated further aging during the extended period of operation of the SGs. If additional measures are planned to deal with this aging mechanism during the license renewal period, we request that you identify and discuss such measures in detail.

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Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.4.7-3 It is stated in Section 3.4.7.2.1 of the license renewal application that fretting and 11/18/98B sliding wear of SG tubes at the tube support locations has occurred in the industry.

The forces imposed on the tubes by the secondary fluid cause high frequency vibration of the tubes and interaction with the tube support structures. The degradation of the supports due to loss of material can result in excessive vibration and eventual failure of the tubes due to fatigue or fluid elastic instability. Discuss whether current measures to manage this aging effect during plant operation are considered adequate and sufficient to manage potential further aging during the extended period of operation of the SGs. If additional measures are planned to deal with this aging mechanism during the license renewal period, we request that you identify and discuss such measures in detail.

3.4.7-4 Discuss why tube support plates and upper and lower cylindrical baffles are not within 12/3/98A the scope of license renewal.

3.4.7-5 Discuss why outside-diameter stress corrosion cracking is not considered an applicable 12/3/98A aging effect for the OTSG tubes at Oconee. Discuss how this aging effect is managed, if different from those mechanisms already discussed for this component.

3.4.8-1 It is stated in Section 3.4.8.3, page 3.4.22 of the license renewal application that the 11/18/98B results of the review of NRC generic communications for the Reactor Coolant System piping report (BAW-2243A, Demonstration of the Management of Aging Effects for the Reactor Coolant Piping) are also applicable to the reactor coolant pump (RCP). Identify the parts of the RCP for which fatigue is considered plausible.

Describe the review process used to evaluate these parts for fatigue.

3.4.8-2 Identify any subcomponents of the RCP for which fatigue usage is monitored. Also, 11/18/98B describe how the monitored parameters are compared to the fatigue analysis of record.

3.4.8-3 Identify any modifications in the RCP or other components that may have had an 11/18/98B impact on the fatigue usage of the subcomponents of the RCP. Also, describe the impact of the modification, if any, on the computation of previous fatigue usage and projection of fatigue usage to 60 years.

3.4.8-4 Note: The following two questions (3.4.8-4, 3.4.8-5) apply to both sections 3.4.8 and 12/3/98A 3.4.9.

Discuss why the aging management program for Reactor Coolant System (RCS)

Operational Leakage Monitoring described in section 4.23 would include within its scope the reactor coolant pump components but that this program is not credited in section 3.4.8.

3.4.8-5 Discuss why the Chemistry Control Program cited in section 4.23 to be used in 12/3/98A conjunction with RCS operational leakage monitoring is not credited for managing aging effects for the Reactor Coolant Pumps (3.4.8) or for the Control Rod Drive Tube Motor Housings (section 3.4.9).

3.4.10-1 It is stated in Section 3.4.10.4 of the license renewal application that during a reactor 11/18/98B trip, the increased flow through the letdown cooler caused severe thermal and vibrational stresses on the tubes that eventually caused the tubes to crack. Two of the letdown coolers have been replaced and the other four have been repaired and the operating procedures have been changed. Describe the repairs which were performed on the damaged letdown coolers. Also, describe the specific analyses which were performed to assure that thermal and vibrational stresses during normal and off-normal operation will not cause fatigue failure during the projected period of operation.

3.4.10-2 Describe the specific maintenance and inspection activities which are performed on 11/18/98B the letdown coolers to manage fatigue damage due to excessive vibrational stresses which might occur during off-normal operation.

3.4.10-3 Indicate whether or not the fatigue evaluation of the letdown cooler subcomponents 11/18/98B was performed by treating it as a separate mechanism or in combination with other age-related degradation mechanisms such as corrosion and fouling.

3.4.10-4 Identify any modifications of the letdown coolers or related components which may 11/18/98B have an impact on the projected fatigue usage of the subcomponents of the letdown coolers during the extended period of operation.

12-16 RAI Status.doc Page 23 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.4.11-1 What action did you take in response to Generic Le~tter 91-17, Generic SafetIsu29 109/82148 "Bolting Degradation or Failure in Nuclear Power Plants?"

3.4.11-2 Based on the staff's experience, degradation of bolted connections (e.g., loose bolts) 10/29/98 12/14/98 potentially caused by vibration loading, is a common type of aging effect of component supports with bolted connections. Clarify whether this loading effect has been considered in the aging review for the Class I component supports, and (if this effect is excluded) provide the basis for excluding this effect.

3.4.11-3 Table 3.4-1 does not identify any applicable aging effects for the reactor coolant pump 10/29/98 12/14/98 motor vertical and lateral support assemblies due to loading from rotating/reciprocating machinery. However, the loss of preload due to rotating/reciprocating machinery has been identified as a potentially applicable aging effect for component supports and, in particular, for the reactor coolant pump motor vertical and lateral support assemblies. Identify the specific location in the license renewal application (LRA) that the loss of preload and the related aging management program(s), and demonstration are discussed, or provide a technical justification for not identifying loss of preload due to rotating/reciprocating machinery as an applicable aging effect for reactor coolant pump motor vertical and lateral support assemblies.

3.4.11-4 Are there any parts of Class 1 component supports described in Section 3.4.11 that are 10/29/98 12/14/98 inaccessible for inspection? If so, describe what aging management program will be relied upon to maintain the integrity of inaccessible areas. If the aging management program for inaccessible areas relies on an evaluation of the acceptability of conditions in surrounding accessible areas, please provide information to show that conditions that exist in accessible areas reasonably reflect those conditions that are likely to exist in inaccessible areas. If different aging effects or aging management techniques are needed for inaccessible areas, please provide a summary of your actions to address the following elements concerning inaccessible areas: (1) preventive actions that will mitigate or prevent aging degradation; (2) parameters monitored or inspected relative to degradation of specific structure and component intended functions; (3) detection of aging effects before loss of structure and component intended functions; (4) monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions; (5) acceptance criteria to ensure fulfillment of structure and component intended functions; and (6) operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

3.4.11-5 Table 3.4-1 indicated that the potential aging effect of cracking of lubrite pads for the 10/29/98 12/14/98 once-through steam generator (OTSG) upper lateral support structure will be managed by the OTSG lateral support inspection program. Section 4.3.6 indicated that the subject inspection program is a one time inspection and it will be completed by February 6, 2013 (the end of the initial license of Oconee Unit 1). It is also stated that lubrite pads that are found cracked will be replaced with new pads. Provide the basis for not performing periodic inspections to track any future potential pad cracking due to radiation effects during the period of extended operation. If applicable, please include a discussion of how the plant operating and maintenance history support this conclusion.

3.4.11-6 Are there any Class 1 component supports described in Section 3.4.11 containing pins, 10/29/98 12/14/98 springs, or sliding plates? If so, provide the basis for excluding mechanical wear as a potential aging effect for those component supports.

3.4.11-7 Section 3.4.3.4 indicated that there was an instance of cracking of a weld in a drain 10/29/98 12/14/98 line off the pressurizer surge line. It further stated that the root cause of the weld cracking was determined to have been a combination of stress corrosion and mechanical vibration. Provide a summary description of the subsequent corrective actions to prevent the mechanical vibration for the subject piping systems, as well as their associated supports, that may be affected by mechanical vibration. Also, indicate if these corrective actions are applicable to the period of extended operation. If not, provide the basis for your determination.

3.5.2-1 Discuss why cracking of stainless steel is considered an applicable aging effect when it 12/3/98A is exposed to a treated water environment (section 3.5.2.5) but not when it is exposed to a raw water environment (section 3.5.2.4).

12-16 RAI Status.doc Page 24 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.5.2-2 The application stated that no aging management programs are required for brass, 12/3/98A carbon steel and stainless steel components that are embedded in concrete due to the presence of the protective concrete cover on their external surfaces (section 3.5.2.7.5).

Since concrete has been observed to degrade (crack, spall) resulting in exposed embedded components, describe the aging management program in place that ensures the concrete is maintained or provide the justification for no aging management of the concrete. Additionally, the ingress of water through these concrete cracks (e.g.,

foundation slabs) may lead to aging degradation of the embedded brass, carbon steel and stainless steel components. Discuss how the aging effects due to ingress of water through concrete cracks will be managed.

3.5.3-1 Identify any portions of the Containment Heat Removal System piping within the 11/18/98B scope of license renewal that are not designed to withstand the effects of a design basis earthquake. Clarify the piping segments within the category of "Seismic II over r' (a non-seismic Category I system, structure or component whose failure could cause loss of safety function of a seismic Category I system, structure, or component) that are included within Oconee's current licensing basis and would be subject to aging management review. Additionally, clarify which aging management program will address these structures and components and specifically discuss implementation of the program for these segments of piping systems to manage applicable aging effects during the period of extended operation.

3.5.3-2 Thermal fatigue has not been identified as an applicable aging effect for the 11/18/98B components of the Containment Heat Removal System. Identify the Code Class requirements for which these components were designed. Also, discuss the engineering analysis for this system including the specific design temperatures, operating conditions, and thermal cycles, which were used in the analysis to make the determination that the assumption of less than 7000 cycles is valid for all locations during the extended period of operation.

3.5.3-3 Discuss how loss of material due to boric acid wastage is managed for the aluminum, 12/3/98A 90-10 copper-nickel, and galvanized steel in the Reactor Building Cooling System.

Clarify the relevant components included within the scope of the Boric Acid Wastage Surveillance Program for this system and the specific methods used for addressing loss of material for components made from these materials.

3.5.3-4 Clarify why the Reactor Building Cooling System is not included in the systems list in 12/3/98A Section 3.5.2.4, "Applicable Aging Effects for a Raw Water Environment."

3.5.3-5 Clarify why the Reactor Building Spray System is not included in the systems list in 12/3/98A Section 3.5.2.6, "Applicable Aging Effects for a Ventilation Air Environment."

3.5.3-6 For the Reactor Building Cooling Unit Tubing inspection mentioned in Table 4.3-1, 12/3/98A Preventative Maintenance Activities, provide the following information: inspection scope, inspection technique (e.g., visual, eddy current, ultrasonic), inspection personnel qualification, inspection timing and frequency (i.e., when is it performed and how often is it performed), acceptance criteria and basis for acceptance criteria, sample size (i.e., will all units be inspected or will a representative number be inspected?). Discuss the basis for concluding the above inspection elements will detect degraded conditions before there is a loss of component function. Discuss why this inspection activity is not considered an aging management program unto itself.

Confirm that the inspection manages aging effects associated with both the ventilation air environment and the raw water environment.

3.5.3-7 The aging effect listed in Table 4.3-1, "Preventive Maintenance Activities" for the 12/3/98A Reactor Building Cooling Unit Tubing Inspection does not parallel the discussion of aging effects discussed in section 3.5.3.1, "Reactor Building Cooling System." For example, boric acid wastage of the copper alloy tubing was not identified as an applicable aging effect for the cooling units while fouling was identified but is not included in the Table description. Clarify these discrepancies.

3.5.3-8 In Section 3.5.2.6, "Applicable Aging Effects for a Ventilation Air Environment,"

12/3/98A aging effects were not identified for stainless steel components. This is not consistent with the discussion in Section 3.5.3.2, "Reactor Building Spray System" and Table 3.5-1, "Applicable Aging Effects for Components of Containment Heat Removal Systems," nor is it consistent with the description of the cited aging management program described in Section 4.3.9, "Reactor Building Spray System Inspection."

12-16 RAI Status.doc Page 25 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 Clarify these discrepancies.

3.5.4-1 Based on the staff's experience, degradation of piping systems (e.g., cracking of 11/24/98B welds) may potentially be caused by vibration (mechanical or hydrodynamic) loading.

Clarify whether this loading effect has been considered in the aging review for the containment isolation systems discussed in Section 3.5.4, and, if this effect is excluded, provide the basis for its exclusion.

3.5.5-1 Show that the ASME Code Section I cumulative usage factor for all High Pressure 11/20/98A Injection (HPI) System Class I piping and components in Oconee Units 1, 2, and 3, will be less than or equal to 1.0 for 60 years of plant operation, considering the thermal cycling effects of the following events:

a.

Unanticipated outleakage in HPI/El (emergency injection) lines, described in NRC Bulletin 88-08.

b.

"Warming" make-up flow in HPI/NMU (normal makeup) lines, described in NRC Information Notice 97-46.

3.5.5-2 Section 3.5.5 of the application discusses aging management programs for the core 12/3/98A flood system and the high pressure injection system. In both cases, the chemistry control system of chapter 4.6 is credited for managing any aging effects that might be caused by internal aqueous corrosion. The chemistry program discusses the various chemical parameters that are monitored to ensure the chemistry requirements of the various systems are met. It is not clear when or if any physical inspection of these systems are conducted to confirm that the stated water chemistry controls are in fact accomplishing what they are intended to do. Please reference the physical condition monitoring program that is performed to verify the actual condition of the system components. Provide any past operating experience demonstrating the effectiveness of this chemistry control program.

3.5.5-3 Section 3.5.5.2 credits the Chemistry Control Program and RCS Operational Leakage 12/3/98A Monitoring programs for managing the effects of cracking on stainless steel components in this section. However, page 3.5-59 states that the Chemistry Control Program is only for the reactor coolant pump seal return coolers only. Clarify if reliance on leakage detection alone is credited for the other stainless steel components in this system.

3.5.6-1 Based on the staff's experience, degradation of piping systems (e.g., cracking of weld) 11/18/98C may potentially be caused by vibration (mechanical or hydrodynamic) loading. Clarify whether this loading effect has been considered in the aging review for the auxiliary systems discussed in Section 3.5.6, and, if this effect is excluded, provide the basis for its exclusion.

3.5.6-2 Section 2.5.6 indicates that some portions of the auxiliary systems within the scope of 11/18/98C license renewal are not designed to withstand the effects of a design basis earthquake.

Clarify which components and piping segments within the category of "Seismic II over I" (a nonseismic Category I system, structure, or component whose failure could cause loss of safety function of a seismic Category I system, structure, or component) would be subject to aging management review. Additionally, clarify which aging management program will address these components and piping segments and specifically discuss implementation of the program to manage the applicable aging effects during the period of extended operation.

3.5.7-1 Based on the staff's experience, degradation of piping systems (e.g., cracking of weld) 11/18/98C may potentially be caused by vibration (mechanical or hydrodynamic) loading. Clarify whether this loading effect has been considered in the aging review for the process auxiliaries discussed in Section 3.5.7, and, if this effect is excluded, provide the basis for its exclusion.

3.5.7-2 Section 2.5.7 indicates that some portions of the process auxiliaries within the scope of 11/18/98C license renewal are not designed to withstand the effects of a design basis earthquake.

Clarify which components and piping segments within the category of "Seismic II over r (a nonseismic Category I system, structure, or component whose failure could cause loss of safety function of a seismic Category I system, structure, or component) would be subject to aging management review. Additionally, clarify which aging management program will address these components and piping segments and I specifically discuss implementation of the program to manage the applicable aging 12-16 RAI Status.doc Page 26 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 effects during the period of extended operation.

3.5.8-1 Section 3.5.8 of OLRP-1001 includes a statement that the heating ventilation and air 1/298 conditioning (HVAC) systems are those systems designed to maintain the ambient air conditions within the auxiliary building and include the auxiliary building ventilation (ABV) system, control room pressurization and filtration (CRPF) system, and penetration room ventilation (PRV) system. Are there safety-related HVAC systems other than these three systems located in other buildings (such as reactor building) that need to be considered in the aging management review? If yes, provide a basis not to include them in the aging management review.

3.5.8-2 For the ABV, CRPF and PRV systems, Subsections 3.5.8.1.1, 3.5.8.2.1 and 3.5.8.3.1 11/20/98B state that these system components are exposed externally to the ambient conditions within the auxiliary building. Internally, these system components are exposed to a ventilation air environment. In Subsections 3.5.8.1.2, 3.5.8.2.2, and 3.5.8.3.2, the OLRP states that these three systems contain ductwork and other components constructed of aluminum, galvanized steel and stainless steel. No applicable aging.

effects have been identified for the components constructed from these materials in a ventilation air environment. Based on the bases stated above, Duke concludes in Subsections 3.5.8.1.3, 3.5.8.2.3 and 3.5.8..3.3 that because no applicable aging effects have been identified for the components of the ABV, CRPF and PRV systems within the scope of license renewal, no aging management program is required for these three systems during the period of extended operation. Provide a basis and justification to demonstrate that the conclusion that no aging management program is required for these three systems during the period of extended operation is also applicable for the portion of these systems exposed to the ambient conditions.

3.5.8-3 According to the staff's past review experience of other nuclear power plants, cracking 11/20/98B of ductworks due to vibration-induced fatigue and loosening fasteners due to dynamic loading are very common types of aging effects identified in HVAC systems, especially in the vicinity of attached device types exposed to dynamic loads such as fans. Provide ajustification of why these types of aging effects are not applicable for the HVAC systems at Oconee.

3.5.8-4 Provide a basis of why the attached devices (or device types) such as filters, hand 11/20/98B valves (bodies), temperature transmitter (if performing a function subject to license renewal requirements), and heat exchangers, etc. are not considered in the aging management review.

3.5.8-5 Provide a justification of why loss of material due to mechanical wear of the ductwork 11/20/98B systems is not considered a potential aging effect at Oconee.

3.5.8-6 It is the staff's understanding that the intended function for HVAC duct systems and 11/20/98B attached devices (such as fan casings, filters, valves (bodies), and heat exchangers, etc.) is "pressure retaining" (passive intended function). However, no description of how to maintain this passive intended function is discussed in the application. Provide an explanation, of how this passive intended function will be maintained.

3.5.8-7 Are there any parts of the systems and attached devices within the HVAC systems that 1120/98B are inaccessible for inspection? If yes, provide a description in the application of how the potential aging effects will be identified and what aging management program (or programs) will be relied on to maintain the integrity of the inaccessible parts of the HVAC systems. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (1) Preventive actions that will mitigate or prevent aging degradation. (2) Parameters monitored or inspected relative to degradation of specific structure and component intended functions. (3) Detection of aging effects before loss of structure and component intended functions. (4)

Monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions. (5) Acceptance criteria to ensure structure and component intended functions. (6) Operating experience that provides I objective evidence to demonstrate that the effects of aging will be adequately 12-16 RAI Status.doc Page 27 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 managed.

3.5.8-8 The application states that there are carbon steel components in the HVAC systems.

12/3/98A Industry experience has shown that uncoated carbon steel piping may experience loss of material due to corrosion. In light of this experience discuss if the piping at Oconee is coated? If they are coated, are the coatings credited as a means for ensuring that degradation of the underlying carbon steel does not occur? Also, discuss the elements of the aging management program that would address preservation and maintenance of the coatings to ensure that degradation of the carbon steel does not occur.

3.5.9-1 The steam and power conversion system comprises four systems with components 10/29/98 12/14/98 made of materials which may undergo degradation by different types of corrosion mechanisms when exposed during plant operation to the environments of raw or treated water. Your aging management program is designed to control this degradation by (a) controlling the relevant conditions that would lead to the onset and propagation of these aging effects and (b) by performing inspections and analyses verifying the integrity of the piping systems. Describe these inspections and analyses and show how they will permit you to evaluate integrity of the piping and other components in the steam and power conversion system.

3.5.9-2 For the condensate cooler tubing and main condenser tubing examinations, provide the 10/29/98 12/14/98 scope of the examination, the examination method, the acceptance criteria, the frequency of such examinations and relevant Oconee-specific operating experience related to the performance of the condensate coolers and main condensers to date.

Provide the bases to show how these examinations are appropriate for timely detection of aging effects.

3.5.9-3 Portions of the main steam system and the feedwater system are located in the 10/29/98 12/14/98 Auxiliary Building. As described in Section 3.5.2.7.2, the Boric Acid Wastage Surveillance Program is cited to manage loss of material due to exposure to borated water/boric acid for components located in the Auxiliary Building. However, the LRA indicates that the scope of the Boric Acid Wastage Surveillance Program is limited to the Reactor Building. Identify where in the LRA that the Boric Acid Wastage Surveillance Program includes all applicable portions of the main steam and feedwater systems or discuss how loss of material due to boric acid wastage is managed for components of the main steam and feedwater systems located in the Auxiliary Building.

3.5.9-4 Section 3.5.9 of the license renewal application states the applicable aging effects for 10/29/98 12/14/98 the following systems:

- Main Steam System components, including piping and valves;

- Condensate System components, including the main condenser, the condensate coolers and the generator water coolers;

- Emergency Feedwater System, including piping and valves; and

- Feedwater System, including piping and valves.

The LRA also states that the related aging effects will be managed by monitoring and controlling the effects directly. In addition, inspections and analyses are performed to investigate and verify the integrity of the piping systems. In Section 3.5.9.4.3, the licensee identifies the Chemistry Control Program and the Piping Erosion/Corrosion Program as the appropriate means to manage the applicable aging effects. However, the LRA, Section 3.5.2, identified cracking due to vibration as a potential aging effect.

For each of these systems, provide the following information:

1. A description of the methods and equipment that will be used for monitoring and controlling the aging effects combined with mechanical vibrations.

2.

A description of the inspection and analysis performed to investigate and verify the integrity of the piping systems, including piping and component supports, for combined aging effects and mechanical vibrations.

3.5.12-1 Section 3.5.12 states that the applicable aging effects for this system are summarized 12/3/98A in Table 3.5.1. It appears that Table 3.5-10 is meant. Please confirm.

3.5.12-2 The chemistry control program for aging management, the only program for this 12/3/98A system, will not ensure that aging effects in the reactor coolant vents, drains, and instrument lines are detected before there is a loss of the component intended 12-16 RAI Status.doc Page 28 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 functions. What is the assessment regarding the need for an inspection program to address this issue?

3.5.13-1 Based on the staff s experience, degradation of piping systems (e.g., cracking of weld) 11/18/98C may potentially be caused by vibration (mechanical or hydrodynamic) loading. Clarify whether this loading effect has been considered in the aging review for the Keowee Hydroelectric Station discussed in Section 3.5.13, and, if this effect is excluded, provide the basis for its exclusion.

3.5.13-2 Section 2.5.13 indicates that some portions of the Keowee Hydroelectric Station 11/18/98C piping systems within the scope of license renewal are not designed to withstand the effects of a design basis earthquake. Clarify which components and piping segments within the category of "Seismic II over I" (a nonseismic Category I system, structure, or component whose failure could cause loss of safety function of a seismic Category I system, structure, or component) would be subject to aging management review.

Additionally, clarify which aging management program will address these components and piping segments and specifically discuss implementation of the program to manage the applicable aging effects during the period of extended operation.

3.5.14-1 It is stated in Section 3.5.14.1.1 of the license renewal application that no aging effects 11/18/98B have been identified for this system. The diesel exhaust system is exposed to an exhaust gas environment. At some facilities, the structures at the exit of the diesel exhaust system have degraded over a period of time due to impingement of the hot corrosive exhaust gases. The debris from these degraded structures has the potential of blocking the exhaust system and rendering the diesel inoperable during an emergency.

Discuss the potential for similar degradation at the Oconee nuclear station during the extended period of operation.

3.5.14-2 It is stated in Section 2.5.14.5 of the license renewal application that the reactor 1118/98B coolant makeup system piping is designated as Oconee Class B and that it is designed to USAS B31.7, Class II requirements. Discuss the engineering analysis for this system including the specific design temperatures, operating conditions, and thermal cycles, which were used in the analysis to make the determination that assumptions of less than 7000 cycles are valid for all locations during the extended period of operation.

3.5.14-3 It is stated in Section 2.4.14.8 of the license renewal application that no applicable 11/18/98B aging effects have been identified for the components of the starting air system. The diesel generator starting air system at several other facilities has experienced degradation due to excessive vibration in the piping and starting air valves which in some cases rendered the air receivers incapable of delivering starting air to the diesel engines at the design pressures. Discuss the upgrades, if any, and/or surveillance requirements for the starting air system at Oconee to assure operability of this system during the extended period of operation beyond 40 years.

3.5.14-4 Section 2.5.14 of the license renewal application indicates that some portions of the 1118/98B Standby Shutdown Facility piping within the scope of license renewal are not designed to withstand the effects of a design basis earthquake. Clarify the piping segments within the category of "Seismic II over " (a non-seismic Category I system, structure or component whose failure could cause loss of safety function of a seismic Category I system, structure, or component) that are included within Oconee's current licensing basis and would be subject to aging management review. Additionally, clarify which aging management program will address these structures and components and specifically discuss implementation of the program for these segments of piping systems to manage the applicable aging effects during the period of extended operation.

3.5.14-5 Industry experience has shown that uncoated carbon steel piping may experience loss 12/3/98A of material due to corrosion. Are the underground piping and main fuel oil storage tank carbon steel? If so, are they protected by a combination of coatings and cathodic protection and are these credited as a means of aging management? If so, discuss the elements of the aging management program that would address preservation and maintenance of the coatings and cathodic protection to ensure that degradation of the carbon steel structures and components does not occur?

3.5.14-6 Fouling in the auxiliary service water system is mentioned. What plans, if any, are 12/3/98A

-,-_there to use biocides to manage the effects of/control fouling and if so what kinds of 12-16 RAI Status.doc Page 29 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 biocide will be used?

3.6-1 Section 3.6.2 of the application discusses stressors such as connection surface 11/25/98A oxidation, temperature, radiation, and precipitation and their applicable aging effects on the isolated-phase, nonsegregated-phase, segregated-phase, and switchyard buses.

Discuss whether vibration was considered as a stressor and list any applicable aging effects due to vibration for each of the above electrical buses.

3.6-2 Section 3.6.3 of the application identifies temperature, radiation, and moisture as the 11/25/98A principal environmental stressors that insulated cables and connections are exposed to.

Discuss the aging impact of the following operational and environmental stressors as identified in Reference 3.6-1 on the Oconee insulated cables and connectors:

a.

Electrical stressors Energization at normal voltage levels Transient conditions Partial discharge Effects of contaminants Water treeing Indications of electrical degradation Effects of high-potential testing on XLPE-insulated cables

b. Mechanical stressors Vibration Gravity-induced cable "creep" and tensile stress Compression Installation related-degradation Maintenanceloperation-related degradation

c.

Chemical/Electrochemical stressors Chemical attack of organics and cable decomposition Electro-mechanical attack of metal Loss of fire retardants Effects of oxygen and ozone 3.6-3 Section 3.6.4 of the application discusses cracking, loss of material due to wear, and 11/25/98A surface contamination as potential aging effects for insulators. Discuss the aging significance of rust formation where galvanizing is burnt off the insulator due to flash over from lightning strikes and, the inspection process that will detect loss of material due to rust.

3.6-4 Section 3.6.5 of the application lists loss of conductor strength as the only aging effect 11/25/98A for transmission line conductors due to corrosion of the steel core and aluminum strand pitting. Since corrosion can lead to loss of material, and ultimate conductor failure, what percent of composite conductor strength would require transmission conductor replacement and how would that parameter be measured?

3.7.1-1 In view of the fact that expansion joints, caulking, and sealants (other than those for 11/18/98A fire barrier) are not subjected to replacement based on qualified life or specified time period, explain why they should not be considered for aging management review [see 10 CFR 54.21(a)(1)(ii)] and addressed in Sections 2.7 and 3.7.

3.7.1-2 Section 3.2, referred to in Sections 3.7.1 and 3.7.2, provides tables for structures and 11/18/98A components subjected to thermal and radiation environment. The section does not provide a systematic discussion of structures and components subjected to high humidity/moisture/water. High humidity/moisture presents challenging environment for concrete and steel structures and components, as well as for the caulking and sealants. Explain why the process to identify applicable aging effects in Sections 3.2 and 3.7 should not consider high humidity/moisture as one of the dominant challenging environments.

3.7.2-1 Section 3.7.2.1.6, "Oconee Operating Experience." cites one example of cracking (in 11/18/98A the Auxiliary Building), justifies its existence, and makes a conclusion: "No additional aging effects were identified from this review beyond those identified in this section."

In Table B9 of NUREG-1557, "Summary of Technical Information and Agreements from NUMARC Industry Reports Addressing License Renewal, October 1996, in discussion of NUMARC/NRC agreement, NRC proposes a one time focussed plant 12-16 RAI Status.doc Page 30 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 specific inspection of (in-scope) structures and components for identificatioan resolution of potential age related degradation mechanisms (ARDMs). In 19419 time frame, all safety-related structures and components within the scope of the maintenance rule (10 CFR 50.65) would have gone through baseline inspections.

Explain why the results of these inspections including the identification of ARDMs, and their resolution (corrective actions) are not cited as Oconee Operating experience in identifying the aging effects.

3.7.2-1 Microbiologically induced corrosion (MIC), fouling, and pitting are discussed as a 11/18/98D potential aging effect. However, there does not appear to be information on an applicable aging management program. Please provide information on how MIC, Retracted fouling, and pitting will be managed.

12/3/98A 3.7.2-2 Note:

Question 3.7.2-2 was previously issued in a letter to Duke dated November 12/3/98A 18, 1998, that contained questions from the Materials and Chemical Engineering Branch. In the November 18, 1998, letter the question was assigned RAI number 3.7.2-1. However, this number was previously used. Therefore, the question is reissued below with a different number to avoid duplication of RAI numbers.

Because the question has been reissued, question 3.7.2-1 contained in the November 18, 1998, letter from the Materials and Chemical Engineering Branch is therefore retracted.

Microbiologically induced corrosion (MIC), fouling, and pitting are discussed as a potential aging effect. However, there does not appear to be information on an applicable aging management program. Please provide information on how MIC, fouling, and pitting will be managed.

3.7.2-3 Paragraph 3.7.2.2.3 of the submittal states that A490 bolting material may be 12/3/98A susceptible to stress corrosion cracking (SCC). It is not clear in the application how stress corrosion cracking of bolting made from A490 material will be managed. Please discuss. Additionally, analysis of SCC of bolting made from A490 materials may include hardness tests to determine the bolting's susceptibility to SCC. Discuss if hardness tests have been performed and provide details of the results or discuss if there are plans for conducting hardness tests on the bolts? The submittal also states that borated water contributes to stress corrosion cracking of A490 bolting. Please explain the basis for this statement as it is the staff's understanding that borated water may contribute to loss of material of A490 bolting due to wastage.

3.7.3-1 With respect to Section 3.7.3.1, discuss how the aging effects due to settlement 11/30/98A (including differential settlement) of Auxiliary Building concrete components will be managed. Did the concrete foundation of Oconee Auxiliary Building experience any cracking degradation which might affect its ability to perform the intended safety function? If yes, describe the incident(s) and indicate how the observed degradation was resolved.

3.7.3-2 Degradation or corrosion of embedded steel and rebars in concrete is not listed as an 11/30/98A applicable aging effect for Auxiliary Building in Table 3.7-1. Since concrete cracking was observed in Oconee plants and ingress of water through these concrete cracks (e.g., foundation slabs) may lead to corrosion of the embedded steel and rebars, discuss how corrosion of embedded steel and rebar in concrete due to ingress of water through concrete cracks will be managed.

3.7.3-3 Is there any concrete grout used for the Auxiliary Building that is exposed to outside 11/30/98A environment? If yes, discuss the potential of these grouts being eroded or degraded due to sustained "freeze-thaw" as well as other weathering effects. As applicable, discuss Oconee's approach for managing the effects of aging, including degradation due to "freeze-thaw," in concrete grout.

3.7.3-4 The caulking and sealants used for fire doors and fire walls as well as seals for 11/30/98A penetrations are subject to aging related degradation. Discuss the aging effects on these items and how any aging effects on items in the Auxiliary Building will be managed to ensure performance of their intended safety functions during the period of extended operation.

3.7.3-5 Clarify if the Oconee Auxiliary Building uses any type of waterproofing membrane on 1 1/30/98A parts of its exterior walls and base slab to protect the concrete foundation or inhibit infiltration/in-seepage of ground water. If yes, provide the basis for not including this 12-16 RAI Status.doc Page 31 of 53

9 Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 item in Table 3.7-1 of the Oconee license renewal application (LRA). Additionally, as applicable, discuss Oconee's approach for managing the effects of aging on the waterproofing membrane.

3.7.3-6 Are there any jet impingement or missile protection barriers within the Auxiliary 11/30/98A Building? If yes, these items should be included in table 3.7-1 of the Oconee LRA.

As applicable, discuss Oconee's approach for managing the effects of aging on the barriers.

3.7.3-7 Regarding the Inspection Program for Civil Engineering Structures and Components 11/30/98A mentioned in Sections 3.7.3.1 and 3.7.3.2, provide the following information:

(a) Are there any parts of the Auxiliary Building structures and components that are inaccessible for inspection? If so, describe, how the Inspection Program for Civil Engineering Structures and Components will be relied upon to maintain the integrity of the inaccessible areas. Include an example of how the program specifically addressed an inaccessible area. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (1) preventive actions that will mitigate or prevent aging degradation, (2) parameters monitored or inspected relative to degradation of specific structure and component intended functions, (3) detection of aging effects before loss of structure and component intended functions, (4) monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions, (5) acceptance criteria to ensure structure and component intended functions, and (6) operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

(b) The program stated that the nominal frequency of inspection was once every five years with an option of decreasing the frequency to a once every ten-year inspection with appropriate justification. Discuss some examples of justifications which will be appropriate for extending the five-year inspection interval to 10 years. Industry standards generally call for a six-year inspection frequency.

3.7.3-8 Were sealants and caulking used for some of the flood, pressure and specialty doors 11/30/98A (non fire-barrier items) of Auxiliary Building? If yes, discuss the basis for not listing degradation of these caulking and sealant materials as one of the aging effects in Table 3.7-1 of Oconee LRA, and indicate Oconee's plan to manage the degradation of these items.

3.7.3-9 Referring to the structural steel and plates in fluid environment listed on Table 3.7-1, 11/30/98A discuss the loss of material/wastage of the above items experienced for Auxiliary Building and indicate why the chemistry control program being proposed for Oconee is adequate to maintain the functionality and integrity of the items. Material wastage is a concern where the integrity of the protective coating is lost. Discuss Oconee's method(s) that would verify the effectiveness of the chemistry control program for managing loss of material/wastage of the above items during the license renewal period.

3.7.3-10 Did Oconee plants ever experience cracking of the liner and leakage of spent fuel pool 1l/30/98A water? If yes, discuss your past experience and indicate how you intend to manage these aging effects for the extended period of operation.

3.7.3-11 Oconee's spent fuel racks use neutron-absorbing materials (i.e., boraflex sheets). Did 11/30/98A these racks experience some spalling and surface abrasion of the neutron absorbing sheets? As applicable, discuss the extent of actual spalling you have experienced to date. Also, discuss the potential for the debris from spalling of the Boraflex sheets to accumulate in an asymmetrical fashion to the extent to partially clog some gaps between the spent fuel rack cells and fuel assemblies resulting in loss of partial fuel cooling function. As applicable, indicate how you plan to manage the potential accumulation of the debris resulting from this aging effect.

12-16 RAI Status.doc Page 32 of 53

9 Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.7.3-12 Discuss the aging management program that addresses control of infestation of zebra 1//8 mussels in the cooling water intakes or raw water systems for the license renewal.

period. Additionally, pitting corrosion is discussed in the submittal. It appears to the staff, however, that loss of material due to crevice corrosion may be more likely.

Discuss what consideration has been given to this aging effect and how this aging effect will be managed for the period of extended operation.

3.7.4-1 Section 3.7.4.1 lists the following applicable aging effects (1) loss of material due to 11/18/98E erosion, (2) cracking due to settlement or frost heave, and (3) change in material properties due to desiccation. Aging effects (1) and (2) are discussed in sections 3.7.4.1.1 and 3.7.4.1.2, respectively, however, effect (3) is not mentioned further within Section 3.7.4. Provide a discussion of the applicability this aging effect.

3.7.5-1 The intake structure concrete and components are exposed to water from Lake 11/18/98A Keowee, and to backfill and groundwater. Section 3.2.2.3 provides a partial list of the chemicals in these waters. Provide a complete list of chemical properties of these waters, including pH value range, and range of ions such as chlorides, nitrates, and sulfates which could potentially cause corrosion of reinforcing bars in concrete structures and steel structures.

3.7.5-2 Provide a summary of results (observations, identified degradations, corrective actions 11/18/98A taken) of the Intake Structure baseline inspection (see also RAI 3.8.3.3) performed in accordance with Section 4.19. Also provide the results of the inspection related to the condition of caulking, seals, and expansion joints in the Intake Structure.

3.7.5-3 Are there any parts of the intake structure that are inaccessible for inspection? If so, 11/18/98A describe what aging management program will be relied upon to maintain the integrity of the inaccessible areas. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (1) Preventive actions that will mitigate or prevent aging degradation. (2) Parameters monitored or inspected relative to degradation of specific structure and component intended functions. (3) Detection of aging effects before loss of structure and component intended functions. (4)

Monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions. (5) Acceptance criteria to ensure structure and component intended functions. (6) Operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

3.7.6-1 With respect to Section 3.7.6, discuss why the aging effects due to settlement 1 1/30/98A (including differential settlement) of Keowee structure need not be included as an applicable aging effect, and as applicable, address how this effect will be managed.

3.7.6-2 Degradation or corrosion of embedded steel and rebars in concrete is not listed as an 11/30/98A applicable aging effect for Section 3.7.6. Referring to Penstock, intake and spillway components of Keowee Structure, discuss the basis for excluding this potential aging effect (i.e., loss of material effect) of steel and rebars embedded in the concrete which may result from some localized surface cracking of concrete and ingress of water through these concrete cracks.

3.7.6-3 Based on your past operating experience, indicate if the roof slabs of the Keowee 11/30/98A Structure experienced any concrete cracking. If yes, discuss your plan for managing the aging effects resulting from structural steel and rebar corrosion that are embedded in the concrete slab due to accumulation and ingress of water through concrete cracks.

Additionally, is there any concrete grout used for the Keowee Structure that is exposed to outside environment? If yes, discuss the potential of the grout being eroded or degraded due to sustained "freeze-thaw" as well as other weathering effects, and as applicable, discuss Oconee's approach for managing the effects of aging on concrete grout.

3.7.6-4 Are there waterproofing membranes used for the Keowee Structure at part of its 11/30/98A exterior walls and base slab to protect the concrete foundation or inhibit infiltration/in seepage of ground water? If yes, discuss the basis for not including this item in Table 12-16 RAI Status.doc Page 33 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.7-4 of the Oconee license renewal application (LRA). As applicable, discuss Oconee's approach for managing the effects of aging on the waterproofing membranes.

3.7.6-5 Regarding the Inspection Program for Civil Engineering Structures and Components 11/30/98A mentioned in Sections 3.7.6.1 and 3.7.6.2, provide the following information:

(a) Describe the criteria for judging that an inspected item needs corrective action(s) to ensure that it will perform its intended safety function. Also, provide a brief description of the ranges of potential corrective actions that might be implemented, on an as-needed basis, for the Keowee Structure and component supports.

(b) Are there any parts of the Keowee structures and components that are inaccessible for inspection, perhaps due to the presence of water? If so, describe, how the Inspection Program for Civil Engineering Structures and Components will be relied upon to maintain the integrity of the inaccessible areas. Include an example of how the program specifically addressed an inaccessible area. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (1) preventive actions that will mitigate or prevent aging degradation, (2) parameters monitored or inspected relative to degradation of specific structure and component intended functions, (3) detection of aging effects before loss of structure and component intended functions, (4) monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions, (5) acceptance criteria to ensure structure and component intended functions, and (6) operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

(c) Discuss why the nominal frequency of inspection for the Keowee Structure is not more frequent than that of the Auxiliary Building due to constant exposure to water and chemicals, such as chlorides or sulfides.

3.7.6-6 Were sealants and caulking used for some of the flood, pressure and specialty doors 11/30/98A (non fire-barrier items) of the Keowee Structure? If yes, discuss the basis for not listing degradation of these caulking and sealant materials as one of the aging effects in Table 3.7-4 of Oconee LRA, and indicate Oconee's plan to manage the degradation of these items.

3.7.7-1 Table 3.2-1 (Oconee Thermal Environment) indicates the bounding temperatures in 11/18/98A steam generator cavities range between 46.7 0 C (1 16 0F) and 55.60C (132 0 F). The industry experience data compiled by Ashar, H., Costello, J., Graves, H.; "Prestress Force Losses in Containments of U.S. Nuclear Power Plants, Proceedings of WANO/NEA Workshop on Loss of Prestress in NPP Concrete Containments, Civaux NPP, Poitier, France, August 25-26, 1997, indicate that at temperatures above 30 0 C, the loss due to relaxation of prestressing steel starts increasing at an escalated rate resulting in lower prestressing forces in tendons. Discuss how the aging management program for the secondary shield wall vertical and hoop tendons addresses prestressing forces (including the original prestress levels, design assumptions regarding losses in prestressing forces, and subsequent lift-off testing) in elevated temperatures seen in the steam generator cavities.

3.7.7-2 Degradation or corrosion of embedded steel and rebars in concrete is not listed as an 11/30/98A applicable aging effect for Reactor Building Structural Components in Table 3.7-5.

Since concrete elements within this category are exposed to a more severe atmosphere than that of the Auxiliary Building (e.g., higher temperature, humidity and radioactivity), and with the presence of some accumulated water on cracked slabs and walls of this category, it may lead to corrosion of the embedded steel and rebars.

Discuss your plan for managing the aging effects resulting from structural steel and rebar corrosion that are embedded in concrete due to accumulation and ingress of water through concrete cracks.

12-16 RAI Status.doc Page 34 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 3.73 The caulkmng and sealants used for flood, pressur and specialty doors as well as seals 11/30/98A for penetrations are subject to aging related degradation due to the high temperature, humidity and radiation environment they are exposed to. Discuss the aging effects on these items and how any aging effects of items placed within the Reactor Building will be managed to ensure performance of their intended safety functions during the period of extended operation.

3.7.7-4 Considering the relatively severe atmospheric environment to which the missile shields 11/30/98A and other reinforced concrete elements (including reactor building internal structures) are exposed, discuss why cracking is not treated as an applicable aging effect and is not listed in Table 3.7-5?

3.7.7-5 Regarding the Inspection Program for Civil Engineering Structures and Components I 1/30/98A mentioned in Sections 3.7.7.1 and 3.7.7.2, provide the following information:

(a)

Are there any parts of the Reactor Building structures and components that are inaccessible for walkdown inspection, due to high radioactive doses or temperatures? If so, describe, how the Inspection Program for Civil Engineering Structures and Components will be relied upon to maintain the integrity of the inaccessible areas. Include an example of how the program specifically addressed an inaccessible area. If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of or result in degradation to such inaccessible areas. If different aging effects or aging management techniques are needed for the inaccessible areas, please provide a summary to address the following elements for the inaccessible areas: (1) preventive actions that will mitigate or prevent aging degradation, (2) parameters monitored or inspected relative to degradation of specific structure and component intended functions, (3) detection of aging effects before loss of structure and component intended functions, (4) monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions, (5) acceptance criteria to ensure structure and component intended functions, and (6) operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

(b) The program stated that the nominal frequency of inspection was once every five years with an option of decreasing the frequency to a once every ten-year inspection with appropriate justification. With respect to items placed within the Reactor Building, provide a basis why doubling the duration between inspections can be justified.

3.7.7-6 Discuss why and how the Inspection Program for Civil Engineering Structures and 11/30/98A Components listed in Table 3.7-5 provides sufficient guidance for inspecting unique structural items, such as, sump screens and the Unit Vent Stack(s), and provides reasonable assurance that aging effects, including loss of material, would be identified and necessary corrective action(s) taken?

3.7.7-7 With respect to the fuel transfer Canal Liner plate, Oconee's Chemistry Control 11/30/98A Program was identified as the method for managing the liner cracking in Table 3.7-5.

Did the fuel transfer canal liner ever experience a leakage problem due to stress corrosion cracking (SCC) of sensitized parts of the liner (e.g., near liner weld)? If liner cracking and leakage were to occur due to stress corrosion cracking without a leakage monitoring system in place, how can you detect the liner leakage and take needed corrective action? Discuss the bases for concluding that monitoring and controlling of spent fuel pool chloride together with monitoring of sulfate in the pool as a diagnostic parameter (per Oconee Chemistry Control Program) without concurrent monitoring of spent fuel pool leakage or a means for determining if cracking is present before leakage occurs will adequately manage cracking due to SCC of the fuel transfer canal liner.

3.7.9-1 Has settlement been observed in the Turbine Building over the long-term (time 11/13/98 dependent). Describe the extent to which settlement is monitored and what, if any, aging management program would be relied upon to manage settlement.

3.7.9-2 Caulking and sealants that are not fire barriers and are exposed to ambient conditions 11/13/98 are susceptible to degradation due to weathering. Your submittal did not address 12-16 RAI Status.doc Page 35 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 degradation of caulking and sealant. Provide a discussion of aging degradation of caulking and sealants (that are not fire barriers) and an aging management program that will address any degradation.

3.7.9-3 Provide a discussion of the intended function(s) of the siding of the Turbine Building.

11/13/98 Include in your discussion whether or not the siding is designed to be blown away during a tornado such that the steel frame will not be subject to the full extent of tornado loadings. Additionally, provide a description of the attachments, e.g., type and material of construction, between the siding and the steel frame and details of your aging management program for addressing degradation of these attachments, i.e., steel in an air environment, such that the intended function for the siding is maintained.

4.3.1-1 Note:

Question 4.3.1-1 and 4.10-1 were originally grouped together.

11/20/98G In regard the content of Section 4.3.1, "Alloy 600 Aging Management Program" (henceforth the Alloy 600 AMP) to the License Renewal Application:

a.

The section states that the Alloy 600 AMP will be used to identify and inspect the four most susceptible locations within the Oconee reactor coolant systems (RCS).

Clarify whether the scope of the proposed inspections of the four most susceptible locations will be on different components within the RCS or on redundant

("sister") components in the RCS.

b.

Clarify whether the aging management program (Section 4.10 of the License Renewal Application) for the Oconee Alloy 600 vessel head penetration (VHP) nozzles and associated Alloy 82/182 partial penetration welds is a separate program from the Alloy 600 AMP and if it will be implemented in addition to the Alloy 600 AMP.

4.3.1-2 Provide Oconee-specific operating experience related to primary-water stress corrosion 12/3/98A cracking of Alloy 600 pressure boundary components or its associated weld metal not related to steam generator tubes, plugs or sleeves. Include a description of specific instances of cracking, the safety significance, and corrective action taken.

4.3.1-3 Are there RCS components fabricated from other Inconel alloys (e.g., Alloy 690 or 12/3/98A Alloy 800)? What is the basis for concluding that SCC of these components is not applicable?

4.3.1-4 The Alloy 600 Aging Management Program will be completed by February 6, 2013 12/3/98A (the end of the initial license of Oconee Unit 1). Discuss how this schedule will provide sufficient information in a timely enough manner such that the possible need for corrective actions before the start of the renewed operating period. Provide a demonstration that implementation of this program will provide adequate assurance that the effects of aging will be detected and managed before there is a loss of the component intended function.

4.3.1-5 Provide the elements/characteristics that are considered in the susceptibility study of 12/3/98A alloy 600 components and alloy 82/182 weld locations in the reactor coolant system.

When will this study be completed and how will it be validated?

4.3.1-6 How are the aging effects on the Inconel components of the Core Flood System 12/3/98A (section 3.5.5.1) managed? The Aging Management Program for Alloy 600 is not credited.

4.3.2-1 If the Brinell Hardness check indicates that selective leaching has occurred in an 10/29/98 12/14/98 inspected cast iron component, what methods will be used to determine the amount of material lost and ensure that it did not exceed the limit required for qualifying the component for further service?

4.3.7-1 Section 4.3.7 of the license renewal application (LRA) indicates the pressurizer 11/20/98D cladding, internal spray line, and spray head examinations will be performed once using visual examination (VT-3). Identify the resolution capability of the VT-3 visual examination techniques that will be used, and the crack size that the examination will be able to detect. Will the proposed examination be able to detect flaws before they reach a critical size? Justify why a one-time examination will ensure that the minimum detectable flaw does not grow to a size that will result in a fracture of the pressurizer. Are VT-1, augmented resolution capability, or any other examination I methods necessary for detection of cracks resulting from operation during the license 12-16 RAI Status.doc Page 36 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 renewal term? Provide any analyses that have been performed which support your conclusions.

4.3.7-2 On page 2.4-27 of the application there appears to be an incorrect reference to the 12/3/98A response to Renewal Applicant Action Item #4, of table 2.4-3. Report BAW-2243A is referred to instead of BAW-2244A. Please clarify.

4.3.8-1 It is the staffs understanding that Section 4.3.8, "Preventive Maintenance Activity 10/29/98 12/14/98 Assessment" is the aging management program to which the licensee refers in the Chapter 3 descriptions as "Preventive Maintenance Activities." With that assumption, the staff expected to find in Section 4.3.8 a description of various aging management programs (including inspection activities, schedules, acceptance criteria, etc.).

Instead, Section 4.3.8 contains a description of a program that will assess the effectiveness of various preventive maintenance activities by the end of the licensee's current operating license. Clarify the intent of the subject "program" and discuss how it differs from Oconee's current self-assessment program. Provide a description of the preventive maintenance program(s) that will be used to manage the applicable aging effects in the LRA. Discuss whether the specific inspections listed in Table 4.3-1 are considered aging management programs unto themselves.

4.3.8-2 An aging effect for the Auxiliary Service Water Piping (Table 4.3-1) is described as 10/29/98 12/14/98

"[flouling due to macro-organisms and silting has been identified as an applicable aging effect for specific portions of the Auxiliary Service Water System piping...."

This aging effect is not consistent with the aging effect described in Section 3.5.6.2, "Auxiliary Service Water System" that describes the applicable aging as the "loss of material for the subject components exposed to an air environment will be...." Provide a clarification of the aging effects and the applicable aging management program such that the staff can evaluate that the effects of aging are being managed consistent with the current licensing basis.

4.3.8-3 Table 4.3-1, "Preventive Maintenance Activities," describes aging effects for the 10/29/98 12/14/98 Component Cooling System and identifies a component cooler tubing examination.

However, Section 3.5.4.2, "Component Cooling System" contains no reference to Preventive Maintenance Activities. Clarify the discrepancy.

4.3.8-4 Table 4.3-1, "Preventive Maintenance Activities," contains the following description 10/29/98 12/14/98 for the aging effects of the Reactor Building Cooling Unit Tubing: "Loss of material due to general and localized corrosion of the tube side exposed to raw water and localized corrosion due to galvanic corrosion and boric acid wastage...." This description is not consistent with the description given in Section 3.5.3.1, "Reactor Building Cooling System," that cites preventive maintenance activities to prevent "loss of material...exposed to a ventilation air environment..." The loss of material due to a ventilation air environment is not discussed in Table 4.3-1. In addition, the loss of material due to galvanic corrosion and boric acid wastage corrosion is not discussed in Section 3.5.3.1. Clarify these discrepancies.

4.3.8-5 Table 4.3-1, "Preventive Maintenance Activities," contains the following description 10/29/98 12/14/98 for the aging effects associated with the carbon steel strainers in the Turbine Generator Cooling Water System: "Loss of material due to general and localized corrosion...."

Confirm that the "filters" listed in Table 3.5-11, "Applicable Aging Effects for Components of Keowee Hydroelectric Station Systems" are the same components called "strainers" in Section 4.3.8, "Preventive Maintenance Activities Assessment."

In addition, Section 3.5.13.7, "Turbine Generator Cooling Water System" discusses fouling as an applicable aging effect. Stainless steel strainers are included in Table 3.5-11. Fouling is not considered as an aging effect in Table 4.3-1. Discuss why fouling of stainless steel strainers are not identified as an applicable aging effect in Table 4.3-1.

4.3.8-6 In Table 4.3-1, "Preventive Maintenance Activities," the aging effect for the 10/29/98 12/14/98 Condensate Cooler Tubing examination differs from that for the Main Condenser Tubing examination. Explain why micro biologically influenced corrosion is considered for one and not the other although the materials and environment appear to be similar. Discuss why fouling is not considered an applicable aging effect for the portions of the condensate system exposed to a raw water environment.

12-16 RAI Status.doc Page 37 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 4391 In Section 3.5.3.2, "Reactor Building Spray System," the LRA states that "the loss of 102/82149 material and cracking for the stainless steel components exposed to an air environment have not been fully characterized and their applicability will need to be verified by a one-time inspection [the Reactor Building Spray System Inspection]." The Reactor Building Spray System is not included in Section 3.5.2.6 "Applicable Aging Effects for a Ventilation Air Environment." In Section 3.5.2.6, the LRA also states that "stainless steel materials in the plant air environments are resistant to general corrosion."

Clarify these discrepancies.

In addition, Section 4.3.9 identified "the loss of material due to pitting corrosion and cracking due to stress corrosion of stainless steel components.. exposed to a borated water environment..." These aging effects are not identified in Section 3.5.3.2.

Clarify this discrepancy.

4.3.9-2 The Reactor Building Spray System Inspection will be completed by February 6, 2013 10/29/98 12/14/98 (the end of the initial license of Oconee Unit 1). The staff finds this date to be unacceptable without additional information. Provide a justification for not completing the inspection activities at the time of application. Along with your justification, describe the methodology, identify any applicable acceptance criteria, identify planned corrective actions, and provide a schedule for implementation.

4.3.9-3 Explain whether the Reactor Building Spray System Inspections provide for sample 10/29/98 12/14/98 expansion or follow up inspections if unacceptable indications are. If not, please justify.

4.3.9-4 Please discuss the confirmation process for the Reactor Building Spray System 10/29/98 12/14/98 Inspections, i.e., when corrective actions are completed, what are the follow up activities that are done to confirm that the corrective actions are completed, a root cause determination is performed, and recurrence is prevented. (The discussion of this element in your quality assurance program was not clear, stating that it applied to "more significant events.")

4.3.9-5 For Reactor Building Spray System Inspections, discuss Oconee or applicable industry 10/29/98 12/14/98 operating experience from similar programs or inspection techniques used to develop this inspection program.

4.3.13-1 How does the proposed one time inspection's scope, and methodology detect aging 12/3/98A effects before there is a loss of the component intended functions?

4.3.13-2 It is not clear in the application whether the inspections provide for sample expansion 12/3/98A or follow-up inspections if unacceptable indications are found. For the stainless steel items within the scope of this program provide additional details regarding follow-up actions where unacceptable indications are found. If sample expansion or follow-up inspections are not included, please justify.

4.3.13-3 Please discuss the confinnation process for these inspections, i.e., when corrective 12/3/98A actions are completed, the follow up activities performed to confirm that the corrective actions are completed, the root cause determination is performed, and recurrence is prevented. (The discussion of this element in the QA program was not clear, stating that it applied to "more significant events.")

4.3.13-4 For these inspections discuss Oconee or applicable industry operating experience from 12/3/98A similar programs or inspection techniques used to develop this inspection program.

4.5-1 In Section 4.5.1, the submittal states that the subject program addresses equipment 12/3/98A both inside and outside the Reactor Building. However, section 4.5.1, "Frequency,"

mentions only inspections performed "each time the reactor building is entered."

Clarify and confirm that inspections conducted under the Boric Acid Wastage Surveillance Program are not just for the systems, structures, and components inside the reactor building but those systems, structures, and components in other buildings outside of the reactor building, including the auxiliary building. If not, discuss how loss of material due to boric acid corrosion is managed for components located outside the Reactor Building.

4.5-2 Provide more details regarding the scope of the inspections. For example, is the scope 12/3/98A of the Boric Acid Wastage Surveillance Program equivalent to the scope of the Inservice Inspection (ISI) Plan? If so, how are the "carbon steel and low-alloy items" and the "OTSG Upper Lateral Support Structure" listed in Table 3.4-1 (which do not 12-16 RAI Status.doc Page 38 of 53

0 Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 appear to be part of the ISI program) included in the scope of the Boric Acid Wastage Surveillance Program?

4.6.2-1 Were there any instances during operation of the plant when the control parameters for 10/29/98 12/14/98 primary water chemistry exceeded EPRI's Corrective Action Level 3, which, according to EPRI guidelines required immediate plant shutdown? If such incidents have occurred, specify the parameters that exceeded the Action Level 3 limits. Identify any noted effects on the plant from these incidents, and identify any programmatic or corrective actions taken.

4.6.2-2 Describe which of the following chemistry regimes were used in controlling pH in the 10/29/98 12/14/98 reactor coolant system:

Coordinated Chemistry Modified Chemistry Elevated Lithium Chemistry 4.6.2-3 Describe the frequency of sampling for chloride and sulfate in the spent fuel pool and 10/29/98 12/14/98 provide maximum acceptable concentrations for these impurities.

4.6.2-4 Were there any significant corrosion incidents (i.e., causing replacement or major 10/29/98 12/14/98 repair of a component) in the past affecting carbon steel components exposed to the borated water in the spent fuel pool and its supporting systems? If such incidents have occurred, describe them.

4.6.3-1 What are the maximum allowable concentrations of silica and iron required by your 10/29/98 12/14/98 secondary water chemistry specifications?

4.6.3-2 Were there any significant secondary water chemistry excursions (i.e., greater than 10/29/98 12/14/98 level 3 excursions according to EPRI guidelines) in the past? If such excursions have occurred, describe any significant impact on the condition of the plant, such as increased potential for corrosion damage of the components in the secondary water system.

4.6.4-1 Provide the limits, target values, and inspection frequencies for water chemistry 10/29/98 12/14/98 parameters monitored for the component cooling system. Also, generally describe the procedures that are used to maintain the chemistry parameters within these values.

4.8-1 In Section 4.8, Duke states three options for implementing the containment inservice 11/19/98 inspection plan. Any one of the options is acceptable for inspection during a specific interval. However, for options 2 and 3, prior NRC approval is required. Describe your implementation plans for the following:

a.

The interval starting with the first inspection period as per 10 CFR 50.55a(g)(vi)(B),

b.

the subsequent inspection intervals in the current license, and

c.

the inspection intervals in the renewed license period.

4.8-2 In Section 4.8, Duke Power describes the extent of application of ASME Section XI, 11/19/98 Subsection IWE for the examination of containment liner and penetrations. Subarticle IWE 1240 of the ASME subsection requires augmented examinations of suspect areas.

In light of the operating experience of the Oconee containments (e.g., Section 3.3.3.6),

describe what areas are identified for augmented examinations for the current and extended license periods.

4.8-3 In Section 4.8.2 (Subsection IWL Examinations), you state that sample size is not 11/19/98 applicable for an existing program. For examination Category L-B (unbonded post tensioning tendons), sample size plays a significant role. In 1996, you performed the first inspection of the Oconee containment post-tensioning tendons with randomly selected tendons. Oconee has a limited database for performing a trending analysis.

Under the current license, with the normal sample size (i.e., 2% of the population),

you would have no more than 6% of the tendon prestress forces available for each containment for trending analysis.

With this limited database, in 1997, you performed trend analyses of the tendon prestressing forces in the three units, and discovered that vertical tendon forces in Unit 1 and Unit 2 would go below the required minimum value at 30 years and 10 years after the Units' structural integrity testing. In light of the operating experience, 12-16 RAI Status.doc Page 39 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 poiejsiication why the sample size should not be increased to systemnatial assess the need for retensioning of tendons prior to the license renewal period so that the tendon prestressing forces could be later managed as a limited aging analysis (TLAA).

4.8-4 In Section 4.8.2 (Subsection IWL examinations), you state that acceptance criteria are 11/19/98 specified in IWL-3000. For concrete and areas around tendon anchorages, IWL-3211 leaves the acceptance criteria to the judgement of the Responsible Engineer. In light of the operating experience about concrete cracking and degradations around tendon anchorages (Refs. 2, 3, 4), describe the acceptance criteria established by the responsible engineer that would be used during the current license period, as well as, the renewed license period.

4.9-1 Provide a basis for the adequacy of Type A and B containment leak rate tests for 12/1/98A verifying the integrity of the pressure boundary established by the outboard containment isolation valve. In this discussion address the ability of Type A and B tests to verify the pressure boundary or existence of any aging effects due to degradation of the outboard containment isolation valve.

4.9-2 Table 2.5-5, "Components of Containment Isolation Systems and their Intended 12/1/98A Functions," of OLRP-1001 lists three intended functions; pressure boundary, throttling, and filtration. Discuss how the Type A and B containment leak rate tests described in Section 4.9, "Containment Leak Rate Testing Program," of OLRP-1001, are capable of detecting the affects of aging on filter efficiency or the ability of the orifice to throttle.

4.9-3 Containment leakage testing identifies degradation that is exhibited by failure of 12/4/98B component/structure to perform it's intended function, i.e., that it maintain a leak tight barrier. The purpose of the aging management program is to demonstrate effective management of aging effects prior to the discovery of a failure. Discuss how containment leakage testing is credited at Oconee for management of aging effects.

4.10-1 Regarding the content of Section 4.10, "Control Rod Drive Mechanism Nozzle and 11/20/98G Other Vessel Closure Penetrations Inspection Program:"

In Section 4.10 to the License Renewal Application Duke indicated, in part, that the existing regulatory basis for the aging management program for Alloy 600 VHP nozzles is provided in the Duke response to Generic Letter 97-01, "Degradation of Control Rod Drive Mechanism Nozzle and Other Vessel Closure Head Penetrations."

In its response to GL 97-01, Duke indicated that it was a participant in the joint Babcock and Wilcox Owners Group (BWOG)/Nuclear Energy Institute (NED integrated program for assessing primary water stress corrosion cracking (PWSCC) in VHP nozzles to B&W designed VHP nozzles, and that this program was contained in BWOG Topical Report BAW-2301. On May 14, 1998, the NEI submitted an integrated "industry Histogram for Reactor Vessel Head Penetration" on behalf of PWR licensees participating in NEI's integrated assessment program for control rod drive mechanism (CRDM) penetration nozzles and other VHP nozzles in domestic PWR designs. The histogram ranked the CRDM penetration nozzles in "less than 5 year," "5 to 15 year," and "beyond 15 year" probabilities of failure categories. The CRDM penetration nozzles of Oconee have been designated as falling into the "less than 5 year" category and inspections of the Oconee Unit 2 CRDM penetration nozzles have been scheduled to be reinspected for a second time in the year 1999. However, the current integrated program and susceptibility assessment for the PWR industry is based on a 40-year (normal life) time frame. Provide the following information with respect to how the license renewal term for the Oconee units relates to the industry's integrated program for assessing domestic PWR VHPs:

a.

Indicate whether Duke is committed to extending its participation in the BWOG integrated aging management program for VHP nozzles during the license renewal term for the Oconee units.

i.

If Duke is committed to extending its participation in the integrated program to the license renewal term, indicate how the integrated program will be used as the basis for proposing any further inspections of the VHP nozzles at Oconee Units 1, 2, and 3 during the extended license terms for the facilities.

ii.

If Duke is not committed to extending its participation in the integrated 12-16 RAI Status.doc Page 40 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 program to the license renewal term, describe what the basis (in addition to the inspections of the Oconee Unit 2 VHP nozzles in 1999) will be for assessing the potential for primary water stress corrosion cracking to exist in the Oconee VHP nozzles and for proposing any further inspections of the Oconee VHP nozzles during the extended license terms for the facilities.

4.11-1 Industry experience has shown that flame-cut holes can lead to cracking of the crane 12/3/98C rails. Clarify if there are flame-cut holes in the crane rails at the Oconee units. If yes, discuss low cycle fatigue for the rails and include in your discussion the propensity for the occurrence of unstable crack growth under design loads at the flame-cut hole locations if low cycle fatigue in these locations is not managed. Additionally, provide a discussion of your plans for mitigating the potential failure at the flame-cut holes and the potential for fatigue damage to the rails. Indicate whether your aging management methods would include nondestructive examination for the crane rails.

4.12-1 Referring to Section 4.12.1, indicate if the once every five-year visual examination of 11/30/98A external surfaces covers 100% of Keowee Intake, Spillway and Powerhouse's concrete surfaces exposed to water. If not, indicate the approximate percentage of the exposed surfaces that will be examined and how the surfaces to be examined are selected.

4.12-2 Based on the results of past examinations, discuss your rationale for concluding that 1 1/30/98A the once every five-year inspection frequency is reasonable and acceptable to manage the aging effects on the underwater portions of the concrete and steel components of Oconee hydroelectric dams and appurtenances.

4.12-3 Discuss how Oconee underwater inspectors handle areas that are either inaccessible or 11/30/98A hard to reach? Do Oconee inspectors use remote viewing devices to help examine areas with limited access? As applicable, provide an example of such an application.

4.13-1 In OLRP-1001, Subsection 4.13, "Duke Quality Assurance Program," Duke states, in 1211198B part, that it has "established and implemented a Quality Assurance Program which conforms to the criteria established in 10 CFR Part 50, Appendix B, 'Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants."' This subsection further states that "[t]he Quality Assurance Program is presented in the Duke Power Topical Report "Quality Assurance Program," DUKE-lA, which is incorporated by reference into Chapter 17 of the Oconee UFSAR. The Quality Assurance Program addresses all aspects of quality assurance at Duke's nuclear power stations." Subsection 4.13, also asserts that, "[t]wo of these aspects that are pertinent to the aging management programs identified for license renewal are "Corrective Actions" and "Document Control" which are briefly described below." Subsections 4.13.1 and 4.13.2 provide a limited description of the implementation aspects of Duke's corrective action and document control programs as they relate to safety related structures, systems and components subject to an aging management program.

However, the aging management program for Oconee includes both safety-related and nonsafety-related SSCs.

Please describe the methodology and processes that will be used by Duke to address corrective actions, confirmation processes and administrative controls for nonsafety related SSCs subject to an aging management program at Oconee in a manner consistent with the guidance in draft "Standard Review Plan for the Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR).

If Duke has elected not to use the guidance in the draft SRP-LR, please provide justification.

4.14-1 Referring to Section 4.14.1, indicate if the once every five-year visual examination of 11/30/98A the Elevated Water Storage Tank covers 100% of both the interior and the exterior tank surfaces. If not, indicate the approximate percentage of the total tank surfaces which will be examined and how the surfaces to be examined are selected.

4.14-2 With respect to the experience described in Section 4.14.2, identify when water tank 1 1/30/98A degradation was first observed at Oconee and provide a summary of the tank inspections including the types of degradation found and the corrective actions taken.

Based on the results of past examinations, discuss your rationale for concluding that the once every five-year inspection frequency for the elevated water tank is reasonable and acceptable to effectively manage the aging effects on the tank.

4.14-3 Describe the anchor connection provided between the conical bell of the tank and the 11/30/98A foundation and indicate if the anchors including the anchor chairs are included within 12-16 RAI Status.doc Page 41 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 the scope of the elevated water tank aging management program. Discuss any past anchor/anchor-chair degradation which was experienced to date and, as applicable, discuss the disposition of anchorlanchor-chair degradation found through implementation of the Elevated Water Tank Civil Inspection.

4.15-1 The method used to detect possible aging effects, such as loss of material due to 11/18/98E erosion and seepage, leakage, internal stress and hydrostatic pressure, is described as "visual examination of external surfaces." Is the method used to detect these potential aging effects entirely visual or are there parameters such as hydraulic head and uplift pressure that are monitored?

4.15-2 The acceptance criteria for the FERC Inspection Program is based on "the knowledge 11/18/98E of the qualified independent consultant." Elaborate on the criteria used by the inspector to determine if aging effects, such as loss of material, internal stress, and hydrostatic pressure, are within acceptable limits. Are there quantitative values for some of these aging effects that are monitored more frequently than once every 5 years?

4.15-3 For each of the identified aging effects, describe the actions that would be taken if the 11/18/98E acceptance criteria were not met.

4.15-4 Past 5-year inspections of the earthen embankments have detected only minor seepage, 11/18/98E saturation, and erosion with the conclusion that, "The general appearance and condition of the earthen structures remains acceptable though (sic) all inspections."

Provide more information regarding the evidence that lead inspectors to the above conclusion. Is this conclusion entirely qualitative?

4.15-5 Referring to page 4.15-1 of Oconee's LRA, indicate if FERC's five-year inspection 11/30/98A program requires 100% visual examination of external surfaces of a covered structure including underwater or submerged surfaces, and if not explain what percentage of all exposed surfaces are inspected every five years and the basis for selecting areas to be inspected during an inspection. Also discuss how the aging effects of structural elements and surfaces located at hard to reach or inaccessible areas are managed under the FERC program.

4.15-6 Referring to the past five inspection reports submitted since 1976, discuss key 11/30/98A examples of corrective actions recommended by independent inspectors to correct detected deficiencies and explain how the corrective actions were implemented to maintain the safety functions of the inspected structures or components.

4.16-1 Section 3.7.2.4 defined aging effects for fire walls, fire doors, and fire barrier 12/4/98A penetration seals. Describe the scope of the fire barrier inspections included in Section 4.16.1 and explain how they will be used to manage the aging effects of the fire barriers (e.g., cracking and separation of penetration seals located beneath damming boards). Describe which material properties of fire barrier and penetration seal materials will be reviewed and assessed during these inspections. Describe the methods that will be used to detect aging effects prior to an observed failure.

4.16-2 For materials such as silicone elastomer and silicone foam, provide an analysis or 12/4/98A industry data that addresses whether or not these materials are subject to age-related degradation in their installed configurations and locations or exhibit appreciable degradation over time.

4.16-3 Provide a list of surveillance, maintenance, and inspection procedures that are credited 12/4/98A with managing the effects of aging for the fire protection systems listed in Section 4.16. Provide a demonstration of how the procedures manage aging effects for fire protection piping and fire barriers.

4.16-4 Provide a list of all materials used for fire protection including those used for fire 12/4/98A protection barriers and describe the aging effects specifically associated with each of the material types.

4.16-5 The application states that raw water is used in the fire protection system. Please 12/4/98A clarify the source for the raw water (i.e., well water vs. river water). Also, discuss the general chemistry of the raw water and the potential aging degradation and associated effects that could occur based on the chemistry of the water.

4.16-6 Discuss how fouling is managed/controlled in the fire water system. The submittal 12/3/98A 12-16 RAI Status.doc Page 42 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 states that part of the fire water system is buried. Discuss the materials used in the buried part of the system, i.e., is it coated, and is it cathodically protected.

4.16-7 Note: Question 4.16-6 was issued to Duke in a December 3, 1998 letter.

12/4/98A Describe any special treatment used to control corrosion of the fire protection piping.

Include in your discussion, the use of inhibitors, biocides, or other chemical additions, and describe when and how they are used. For instance, what actions are taken for layed-up lines or low flow lines? Summarize the procedures for testing these lines, and the actions taken after testing these lines.

4.16-8 With regard to the "sample size" and "frequency" of the fire barrier inspection 12/3/98E program, the application (Page 4.16-2) states that the sample size is not applicable for an existing program (fire barrier inspection program). The application also states that, at an inspection frequency of at least once every 18 months, exposed surfaces of fire walls are visually inspected and at least 10 percent of each type of fire barrier penetration seal is inspected. Clarify the inconsistency between the statement, "sample size is not applicable for an existing program" and the statement, "at least 10 percent of each type of fire barrier penetration seal is inspected."

4.16-9 Clarify that the acceptance criteria of the fire barrier inspection program contains 12/3/98E attributes necessary to manage all aging effects for those structures and components within the scope of the program. Discuss whether the aging effects "managed" by the acceptance criteria should be at least the same as those specified under the "Aging Effects" as shown in Page 4.16-2. Expand the coverage of aging effects listed in the "Acceptance Criteria" to include all aging effects listed in the "Aging Effects." (e.g.,

for fire doors, the acceptance criteria (no indication of loss of material) cannot cover the aging effects listed under the "Aging Effects.")

4.16-10 The following regard the fire water system test program:

12/3/98E

a.

Are there any buried sections of the high pressure service water system, low pressure service water system and service water system (Keowee)? If yes, how will the corrosion and settlements of supports of the buried piping sections be detected and managed and which aging management programs are you relying on for license renewal? For the above ground portions of the fire water piping system, discuss how the cumulative aging effects on their supports will be managed?

b. With regard to the "Method" of this program, the application only mentions periodic performance or flow tests for piping, pumps, fire hydrants and deluge valves, and visual inspections for hose racks and some sprinkler heads. Provide a description of the methods that are to be used for detecting and managing corrosion (loss of material) of these piping systems and components. The description of these methods should address the detection of cumulative aging effects prior to an observed failure.

c. With regard to the "sample size," the application states that "the components that serve a fire protection function within the high pressure service water system, low pressure service water system and Keowee service water system are tested or inspected and maintained on a periodic basis." Are all piping and components of these three systems associated with the fire protection function to be periodically "tested or inspected and maintained" at the same time? If not, what is the sample size for each test and/or inspection and provide the basis for this criteria.

d. On Page 4.16-4, the application states that the inspection and test frequencies are established based on the type of component and managed by plant procedures. It also states that acceptance criteria are specifically stated in the plant procedures that govern each inspection or test. Provide the demonstration that the inspection and test frequencies, and acceptance criteria associated with the current programs are adequate and will address the aging management of cumulative degradation due to aging during the extended period of operation.

4.16-11 Clarify if the fire barrier inspection program and fire water system test program are to 12/3/98E be used to detect and manage loss of material, e.g., from corrosion, for the high pressure service water system, low pressure service water system and service water system (Keowee). If not, explain how the loss of material will be detected and managed for these systems, and which program will be credited as an aging 12-16 RAI Status.doc Page 43 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 management program for the management of this aging effect.

4.17-1 Provide Oconee-specific operating experience that demonstrates the effectiveness of 12/3/98A Heat Exchanger Performance Testing Activities.

4.17-2 Describe how the test frequencies and the sampling basis are determined for each heat 12/3/98A exchanger type.

4.17-3 In Section 4.17 of the license renewal application, Duke identified the heat 12/3/98D exchangers in the following three systems that are subject to aging management review:

(a) the decay heat removal cooler in the low pressure injection system, (b) the reactor building cooling units in the reactor building cooling system, and (c) the standby shutdown facility heat exchangers in the standby shutdown facility auxiliary service water and heating ventilation and air conditioning systems.

Discuss the criteria used to determine which heat exchangers are selected for aging management review (AMR). The heat exchangers associated with the diesel generators and with the circulating water system are excluded from those identified as being subject to AMR. Discuss the basis for excluding these heat exchangers and note whether they perform passive or active functions. Discuss if and how the aging management program will determine if replacement of the heat exchangers is necessary when they fail to perform adequately.

4.18-1 Table 4-1 of BAW-2248 indicates that the vent valve retaining ring, vent valve bodies 11/20/98C and the locking devices on the modified vent valve assembly do not require supplemental aging management program(s). Aging will be managed during the renewal term using ASME Code inspection methods. Since function of these components are affected by either a reduction of fracture toughness or stress corrosion cracking, what examination methodology will be utilized and are the surfaces of the components accessible for detecting cracks that could lead to failure of the components during the license renewal term? In addition, BAW-2251 states that the aging management elements of the reactor internals vent valves are contained in plant specific technical specifications for ANO-1 and TMI-1 (see page 4-3 of report). In accordance with 10 CFR 54.22, provide the justification for whether changes or additions to the technical specifications are necessary to manage aging effects of the vent valve assembly during the license renewal term for Oconee.

4.18-2 Section 4.18 "Inservice Inspection Plan" as titled, is a subset of an overall inservice 12/2/98D inspection plan applicable for management of aging in certain Class 1 components.

Since the examinations under ASME Code,Section XI, are being credited towards detection of aging effects to maintain the intended function of the components during the period of extended operation, please provide the following information:

Are there components or structures within the inservice inspection boundary that are either inaccessible or cannot be examined in accordance with the applicable Code due to geometry and/or physical constraints? The section 4.18.1 "Scope" states that in instances of inaccessiblity of components for examination, an indirect assurance of component integrity shall be made. How will this indirect assurance address aging effects in the component? If the aging management program for the inaccessible areas is an evaluation of the acceptability of inaccessible areas based on conditions found in surrounding accessible areas, please provide information to show that conditions would exist in accessible areas that would indicate the presence of, or result in degradation to, such inaccessible areas. Please provide a summary to address the following elements for the inaccessible areas:

(a) Preventive actions that will mitigate or prevent aging degradation; (b) Parameters monitored or inspected relative to degradation of specific structures and component intended functions; (c) Detection of aging effects before loss of structure and component intended functions; (d) Monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection of aging effects and corrective actions; 12-16 RAI Status.doc Page 44 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 (e) Acceptance Ocriteria to ensure Estructure and Ecomponent intended functions; and (f) Operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

4.18-3 Section 4.18 "Inservice Inspection Plan" states that the period of extended operation 12/2/98D will contain the fifth and the sixth inspection intervals. However, the ASME Code,Section XI, addresses up to the fourth inspection interval. Therefore, how will the inspection period, percentage of examination during each period, the extent and frequency of examination be tailored to benefit timely detection of aging effects during the fifth and the sixth inspection intervals to maintain intended function of the components during the extended term of operation? Also, provide your criteria for selection of weld inspection locations for Examination Category B-J "Pressure Retaining Welds in Piping" during the extended term of operation.

4.18-4 What is the aging management program for the flow stabilizers inside the reactor 12/2/98D pressure vessel (Refer open item 4.2(2) in the topical report BAW-2251)?

4.21-1 Describe your erosion/corrosion program by providing the following information:

10/29/98 12/14/98

a.

Provide a description of the methodology for predicting degradation of the components in the Main Steam and Feedwater Systems,

b.

Identify any predictive codes, such as CHECWORKS or other similar codes, used in the program,

c.

Describe the methods used for trending material loss in the components susceptible to erosion/corrosion,

d.

Describe any other predictive methods, besides computer codes, which may be used in the program, and

e.

Describe the inspection methods used in determining the degree of degradation for the components determined to be affected by erosion/corrosion.

4.21-2 Were there any other types of components within the scope of components requiring 10/29/98 12/14/98 aging management review other than straight pipes (e.g., valves/pump bodies, elbows, "T" connections, etc.) included in the erosion/corrosion program? If there were none, provide a justification for excluding them from the program. If they were included, describe any unique inspections in the erosion/corrosion program for these components.

4.21-3 List any significant component failure caused by erosion/corrosion that may have 10/29/98 12/14/98 occurred in the past in the systems included in your license renewal application.

Identify the component, and date of occurrence.

4.21-4 For the components that failed due to erosion/corrosion, describe the corrective actions 10/29/98 12/14/98 including replacement by materials resistant to erosion/corrosion damage (e.g.,

chromemoly).

4.21-5 Describe any special training provided to the personnel responsible for managing the 10/29/98 12/14/98 erosion/corrosion program?

4.21-6 Section 4.21 of the application describes the piping erosion/corrosion program and 11/18/98D indicates that corrective actions are taken prior to the piping reaching the "allowable minimum wall thickness." Please discuss whether piping with a pipe wall thinned locally to this minimum thickness could withstand all licensing basis loads, including bending. Also discuss the evaluation for fittings, such as elbows, tees, reducers, and fabricated branch connections.

4.22-1 Section 4.22 of the LRA indicates that aging effects of the HPI nozzles, thermal 11/20/98D sleeves, and attached RCS piping will be managed by the "Program to Inspect the High Pressure Injection Connections to the Reactor Coolant System." For each component in the program, identify the method of inspection and the frequency of inspection to be used during the license renewal term.

The Corrective Action in Section 4.22 of the LRA indicates "flaws in welds or base metal which cannot be accepted based on either geometry screening or the Fracture Mechanics Analysis methods of the ASME Code Section XI are corrected by repair or replacement." In order to perform a Fracture Mechanics analysis, the stresses that 12-16 RAI Status.doc Page 45 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 cause the crack to grow must be known. Based on the causes of crack growth in HPI nozzles, thermal sleeves, and attached RCS piping, are the stresses that cause the crack to grow known? If they are not known, how does it impact the corrective action section of the LRA?

4.23-1 In Section 4.23 of your license renewal application, you describe the scope of the 12/2/98A reactor coolant system (RCS) operational leakage monitoring for license renewal purposes. You indicate that the scope of the operational leakage monitoring to be credited for aging management includes all RCS and high pressure injection (HPI) system components that contain coolant. You also indicate that when the RCS and HPI system are in operation, the HPI system is contiguous with the RCS. However, since the HPI system is usually not in operation and major portions may be isolated from the RCS, please describe how the RCS operational leakage monitoring system surveillance requirements (i.e., inventory balance described in Oconee Improved Technical Specification 3.4.13) can be credited with contributing to the aging management of the components of the HPI system. For portions of the HPI system that are not pressurized with reactor coolant during the inventory balance, describe how the aging management program addresses components in those portions of the system.

4.25-1 For the planned Keowee inspection for bronze and brass piping, provide the following 12/3/98A information: inspection scope, inspection technique (e.g., visual, eddy current, ultrasonic), inspection personnel qualification, inspection timing and frequency (i.e.,

when is it performed and how often is it performed), acceptance criteria and basis for acceptance criteria, sample size, etc. Discuss the basis for concluding that the above inspection elements will detect degraded conditions for bronze and brass piping before there is a loss of component function.

4.25-2 Section 3.5.9.2 "Condensate System" references the Service Water Piping Corrosion 12/3/98A Program. However, it is not explicitly mentioned in the "Purpose" section of 4.25.

Confirm that the main condensers and condensate coolers are within the scope of this aging management program.

4.26-1 Discuss the differences between the subject aging management program and that 12/3198A provided by Oconee's Improved Technical Specification 5.5.10. For example, comprehensively managing aging effects for steam generators requires more than just an eddy current test procedure. Specifically, there are requirements for determining what type of technique is to be applied in what region of the steam generator, what type of training program is to be given to eddy current test personnel, and what guidance is developed on how to disposition eddy current test results. In addition, industry guidelines are constantly being updated to reflect the state-of-the-art in eddy current testing. Discuss how this type of information, among other things, is addressed in the subject aging management program.

4.28-1 The program description of the surveillance program for SSW tendons in Section 11/18/98A 4.28.1 indicate that the sample size is not applicable for an existing program. Under the description of "frequency," it is indicated that a random sample of tendons are lift off tested every other refueling cycle. Please provide a more detailed description of the current SSW tendon surveillance program with regard to the size of the sample of tendons tested and the basis for the associated frequency that is currently used (this information is not described in the UFSAR), and the basis upon which you concluded that this surveillance program is adequate for the period of extended operation.

4.28-2 What population of the tendons in the SSW is inaccessible for visual examination and 11/18/98A lift-off testing? How are you assessing the integrity of the inaccessible tendons?

Describe what aging management program that will be relied upon to maintain the integrity of the inaccessible tendons. If the aging management program for the inaccessible tendons is an evaluation of the acceptability of inaccessible tendons based on conditions found in neighboring accessible tendons, please provide information to show that conditions would exist around accessible tendons that would indicate the presence of or result in degradation to such inaccessible tendons. If different aging effects or aging management techniques are needed for the inaccessible tendons, please provide a summary to address the following elements for the inaccessible tendons: (1) Preventive actions that will mitigate or prevent aging degradation. (2)

Parameters monitored or inspected relative to degradation of specific structure and I component intended functions. (3) Detection of aging effects before loss of structure 12-16 RAI Status.doc Page 46 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 and component intended functions. (4) Monitoring, trending, inspection, testing frequency, and sample size to ensure timely detection, of aging effects and corrective actions. (5) Acceptance criteria to ensure structure and component intended functions.

(6) Operating experience that provides objective evidence to demonstrate that the effects of aging will be adequately managed.

5.1-1 Duke did not identify the following as time-limited aging analyses (TLAAs) for the 12/3/98B Oconee Units:

Metal corrosion allowance Inservice local metal containment corrosion Reactor vessel pressure-temperature limit analysis and low temperature overpressure protection analysis For each of these areas, discuss whether the TLAA is applicable to the Oconee units or provide the basis if it is not applicable. For each of those analyses that are considered applicable, discuss whether the TLAA meets the definition of a TLAA in 10 CFR 54.3(a) or provide the basis if it does not meet this definition. For those TLAAs that are determined to be applicable to the Oconee units and meet the definition of a TLAA in 10 CFR 54.3(a) provide the demonstration required by 10 CFR 54.21(c)(1).

5.3.1-1 Section 5.3.1 of the license renewal application states that the design of the 11/19/98 containment penetrations meets the general requirements of the ASME Boiler and Pressure Vessel Code,Section III, "Nuclear Vessels," 1965, for thermal cycling. The application assumes 500 thermal cycles due to containment heat up and cooling, but is silent regarding specific cumulative usage factors (CUF).

a.

Provide the highest CUF determined for each containment penetration on the basis of 500 thermal cycles combined with relevant mechanical cyclic loading, and loading due to anchor motion.

b.

Provide the basis for the statement "The projected number of cycles for each Oconee unit through 60 years of operation has been determined to be less than the original 360 cycle design limit."

c.

Describe the approach that was used in the fatigue analysis of the containment penetrations to account for environmental effects.

5.3.1-2 State if containment penetrations fall under the Oconee Thermal Fatigue Management 11/19/98 Program, described in Section 5.4.1.3 of the license renewal application. If not, provide justification for the exclusion. If yes, provide the following information for each location monitored by the program:

a.

The location monitored;

b.

The parameters monitored;

c.

The method used to compare the monitored data to the fatigue analysis of record.

5.3.2-1 The prescribed lower limit lines (PLL) in Figures 1, 2, and 3 of Appendix 16.6-2 11/19/98 indicate that you are using the same values for elastic shortening losses and the time dependent losses (i.e., creep and shrinkage of concrete, and relaxation of prestressing steel) for calculating the anchorage forces for each group of tendons. In fact, the elastic shortening loss varies from tendon to tendon, and could vary between 0% to 6%

of the anchoring force, and is not time-dependent (see Regulatory Guide 1.35.1, July 1990). Describe, how you account for this discrepancy in comparing the PLL with the measured lift off force of a randomly selected tendon.

5.3.2-2 Figures 1, 2, and 3 (Appendix 16.6-2 of UFSAR supplement) do not include 11/19/98 information regarding the operating experience or trend lines for the existing tendon prestressing forces for the three containments at Oconee. The TLAA should be based on the most reliable information available. Provide information (including the actions you plan to take) that would ensure that the actual individual tendon forces will exceed corresponding PLL for the extended lives of the three units.

5.4.1-1 Section 5.4 of the license renewal application indicates that B&W Owners Group 11/24/98A Report BAW-2243A, Demonstration of the Management of Aging Effects for the Reactor Coolant System Piping, June 1996, identified leak-before-break and high 12-16 RAI Status.doc Page 47 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 energy line break postulation based on fatigue cumulative usage factor (CUF>0. 1) as generically applicable time-limited aging analyses (TLAAs). However, the application indicates that, "the review conducted of Oconee documentation determined that neither the leak-before-break analyses nor the cumulative usage factor (CUF0.1) analyses are time-limited aging analyses for Oconee." Provide the bases for this conclusion. Describe the documentation that was reviewed. Include a discussion of the applicability of the definition of TLAA in 10 CFR 54.3 to leak-before-break and high energy line break postulation at Oconee.

5.4.1-2 Section 5.4.1.1.2 of the license renewal application identifies locations within the 11/24/98A B&W scope of supply that require further evaluation for thermal fatigue. The locations that require further evaluation include the reactor vessel studs for all three units, the pressurizer spray line for Unit 3, and the Emergency Feedwater System nozzle for Unit 3. Describe the planned evaluation of these components. Provide a schedule for the completion of this evaluation. Discuss your compliance with the requirements in 10 CFR 54.21(c)(1) for these items.

5.4.1-3 Section 5.4.1.1.3 of the license renewal application indicates that the reactor coolant 11/24/98A loop attached piping was originally analyzed to USAS B31.7, Class II standards. The application further indicates that the fatigue evaluation of this piping to Class I standards is currently underway. Provide the schedule for the completion of these analyses. Discuss your compliance with the requirements in 10 CFR 54.21(c)(1) for these items.

5.4.1-4 Section 5.4.1.1.5 of the license renewal application addresses NRC Bulletin 88-08, 11/24/98A "Thermal Stresses in Piping Connected to Reactor Coolant Systems." The application indicates that a supplemental response to the bulletin will be provided by July 1, 2000.

Discuss your compliance with the requirements in 10 CFR 54.21(c)(1) considering the ongoing effort regarding NRC Bulletin 88-08.

5.4.1-5 Section 5.4.1.3 of the license renewal application describes the Thermal Fatigue 11/24/98A Management Program. The application indicates that the program, "tracks actual plant thermal cycles for those components that contain design features that have explicit design basis transient cycle assumptions in order to assure the continued validity of the component design basis." Provide a summary of the Thermal Fatigue Management Program that addresses the elements listed below. The summary should also include a discussion of the bases for each of these elements.

a.

Scope of the program that includes the specific structures and components subject to fatigue monitoring including the location monitored for each structure or component;

b.

Preventive actions that will be used to mitigate or prevent fatigue degradation;

c.

Parameter(s) to be monitored and the monitoring device(s) at each location monitored by the program;

d.

Assurance that detection of fatigue degradation will occur before loss of the structure or component intended functions;

e.

Program monitoring, trending, inspection technique, testing frequency, and sample size to ensure structure and component intended functions;

f.

The method used to compare the monitored data to the fatigue analysis of record;

g.

Acceptance criteria to ensure structures and components can perform intended functions; and

h.

Operating experience from similar programs or inspection techniques used by Duke or the industry.

5.4.2-1 It is stated in the LRA that information in Tables 5.4-1, 5.4-2 and 5.4-3, "Evaluation 11/20/98D of Reactor Vessel Pressurized Thermal Shock Toughness Properties at 48 EFPY,"

supersedes the information presented in Appendix A to Babcock & Wilcox Owners Group (B&WOG) Topical Report BAW-2251. Appendix A to the report, in part, includes the RTprs calculations for the Oconee beltline materials that are calculated using reactor pressure vessel surveillance data. However, no corresponding information was provided in Section 5.4.2 of the LRA nor in corresponding tables Referenced in the section. Since the submittal of the Oconee LRA, the B&WOG has 12-16 RAI Status.doc Page 48 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 submitted additional best-estimate chemistry and surveillance data information for the beltline materials in B&W fabricated vessels (Topical Report BAW-2325). The data in LRA Tables 5.4-1, 5.4-2 and 5.4-3 are different from the data reported for the beltline materials in Topical Report BAW-2325.

a.

Provide revised Pressurized Thermal Shock Tables (Tables 5.4-1, 5.4-2 and 5.4-3) based on the most recent beltline and surveillance data for beltline materials in Oconee Units 1, 2, and 3.

b. Provide the appropriate surveillance data and calculations used in the RTprs assessments of beltline materials which use surveillance data for calculating chemistry factors of the materials. Include application of the ratio procedure in Regulatory Guide (RG) 1.99, Revision 2 where appropriate (e.g., for beltline welds represented in the surveillance programs). Identify the sources of all surveillance data used in the assessments. Provide an assessment of which surveillance data points meet the credibility criteria of RG 1.99, Revision 2.

5.6-1 Sections 5.6.24 (Viking electrical penetration assemblies) and 5.6.26 (Rosemont 11/25/98A RTDs) of the application are based on option (i) of 10 CFR Part 54.21 (c)(1) to demonstrate that the analyses remain valid for the period of extended operation. To illustrate the basis upon which you have concluded that the existing analyses are valid for the period of extended operation, provide calculation OM-360-24 for the Rosemount RTDs and the calculation from OM-337.00-0080-001 for the Viking electrical penetrations. In addition, provide summaries of the thermal and radiation analyses for the Rosemount RTDs.

5.6-2 Sections 5.6.2 (Limitorque actuators), 5.6.10 (Okonite EPRINeoprene cables), 5.6.11 11/25/98A (Samuel Moore EPDM/Hypalon cables), 5.6.12 (Scotchcast 9 and Swagelok quick disconnect assemblies), 5.6.23 (D.G. O'Brien penetrations), 5.6.32 (Barton 764 transmitters) are based on option (ii) of 10 CFR Part 54.21 (c)(1) to demonstrate that the analyses have been projected to the end of the period of extended operation. To illustrate the basis upon which you extended the analyses for the period of extended operation, provide the calculations that document the qualified life for the above items as follows

a.

Limitorque Actuators - Calculation OSC -7167

b.

Okonite EPRINeoprene Cables - Calculation OSC - 6530

c.

Samuel Moore EPDM/Hypalon cables - Calculation OSC -7055

d. Scotchcast 9/Swagelok Assemblies -Calculation OSC 7095

e.

D.G. O'Brien penetrations -Calculation OSC - 7153

f.

Barton 764 transmitters - Calculation OSC - 7096 5.6-3 The following sections in the application are based on option (iii) of 10 CFR Part 11/25/98A 54.21 (c)(1) to demonstrate that the effects of aging on the intended function(s) will be adequately managed for the period of extended operation:

5.6.3.

Rotork Actuators 5.6.16 EGS Grayboots 5.6.17 EGS Connectors 5.6.18 Joy/Reliance Motors 5.6.19 Louis - Allis Motors 5.6.20 Reliance Motors 5.6.21.1 Westinghouse BS pump motors 5.6.25 Conax RTDs 5.6.27 Weed RTDs 5.6.28 Valcor Solenoid valves 5.6.29 Barton/Westinghouse switches 5.6.31 Gems Delaval transmitters 5.6.33 Rosemount transmitters For each of the above items, provide the following information for the option chosen:

Replacement Describe the activities for replacement equipment qualified to 10 CFR 150.49 and any sound reasons to the contrary (Regulatory Guide 1.89, Rev. 1) that will 12-16 RAI Status.doc Page 49 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 be used for replacement equipment.

Refurbishment - Describe the activities that will result in the equipment being retumned to its original (like new) qualified condition.

On going Qualification/Retestine - Describe the ongoing qualification test program in accordance with IEEE Std. 323-1974, that is being used.

Reanalysis - Provide the analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, corrective actions if the acceptance criteria are not met, and the period of time prior to the end of qualified life when reanalysis will be completed.

5.7.1-1 It is stated in Section 5.7.1 of the license renewal application that Oconee installed an 10/29/98 12/14/98 Independent Spent Fuel Storage Installation (ISFSI), which became operational in 1990. The operation of the ISFSI required additional lifts by the spent fuel pool cranes near their rated lifting capacity. This resulted in a reevaluation of the fatigue concerns for the polar cranes through 60 years of operation. Even though the results of this reevaluation indicate that the number of estimated heavy lifts will remain below the specified threshold of 20,000 cycles, the concern remains that similar changes in the operation of the polar cranes may occur in the future that may result in additional lifts and invalidate the current estimates. Describe the tracking mechanisms and/or procedural controls that are in place that may trigger a reevaluation of the estimated heavy lifts, if changes occur in the future operation of the polar cranes.

5.7.2-1 For license renewal, Duke has indicated that the Boraflex Monitoring Program will 12/2/98B continue for the period of extended operation. In response to NRC Generic Letter 96 04 on Boraflex degradation, and in Section 5.7.2 of the license renewal application, Duke indicated that the Oconee spent fuel storage racks are to be reanalyzed taking reduced or no credit for Boraflex. Since future Boraflex verification activities at Oconee will depend upon the extent to which Boraflex is relied upon in this reanalysis, describe the methodology for performing this reanalysis, the acceptance criteria to be applied, the schedule for the reanalysis, and discuss specific actions to be taken if the reanalysis shows that credit must be taken for Boraflex.

BAW-REQUEST FOR ADDITIONAL INFORMATION BWOG NA 2248-1 THE BABCOCK & WILCOX OWNER'S GROUP GENERIC LICENSE RENEWAL 12/2/98 PROGRAM TOPICAL REPORT ENTITLED, " DEMONSTRATION OF THE MANAGEMENT OF AGING EFFECTS FOR THE REACTOR VESSEL INTERNALS," BAW-2248, JULY 1997 Section 1.4 of BAW-2248 identifies the functions of the reactor vessel internals (RVI).

It does not include, "provide shielding for the RPV [reactor pressure vessel]." Do the intended functions of the reactor vessel internals "provide shielding for the reactor pressure vessel"?

BAW-BAW-2248 addresses certain applicable aging effects for specific reactor vessel BWOG NA 2248-2 internals components. Describe, in summary form, the bases for concluding that the 12/2/98 following aging effects were not significant for the specific components: stress corrosion cracking (SCC), and irradiation-assisted stress corrosion cracking (IASCC) of the plenum cover and plenum cylinder; SCC, IASCC, wear, and thermal embrittlement of the rod control assembly (CRA) guide tubes; SCC and IASCC of the CRA guide tube bolts; SCC of the upper grid assembly; SCC and IASCC of the upper grid rib section, upper grid assembly bolts, and the upper internals fuel guide pads; SCC, IASCC, and neutron irradiation embrittlement of the core support shield and the core support shield flange; IASCC and neutron irradiation embrittlement of the vent valve assemblies; SCC of the core barrel assembly; SCC, IASCC, creep, and neutron irradiation embrittlement of the baffle and former plates; SCC, and stress relaxation of the baffle-former bolts; SCC of the lower grid top rib section, the lower grid bottom rib weldment, and the lower grid assembly support posts; SCC, IASCC, and neutron irradiation embrittlement of the lower internals fuel guide pads, the lower grid assembly bolts, and the lower grid assembly guide blocks.

BAW-Section 54.21(a)(3) of 10 CFR states that the integrated plant assessment must BWOG NA 2248-3 "demonstrate that the effects of aging will be adequately managed...for the period of 12/2/98 extended operation." Section 4.6 of BAW-2248 describes a proposed Reactor Vessel Internals Aging Management Program (RVIAMP) that is intended to meet 10 CFR 12-16 RAI Status.doc Page 50 of 53

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 54.21(a)(3), for the affected part and aging effect combinations listed in Table 4-1 of BAW-2248. For those items listed in Table 4-1 susceptible to a reduction of fracture toughness aging mechanism, submit a fracture mechanics analysis to determine the critical flaw size during normal operation and during emergency and faulted conditions. Identify the inspection procedure and the capability of the inspection to detect flaws smaller in size than that of the critical flaw.

The fracture toughness of austenitic stainless steel can become degraded with high levels of neutron irradiation; for example, fluences greater than 1 x 1020 n/cm 2 (E >

IMeV). Fracture toughness data for irradiated stainless steels at such high fluences are not plentiful. Two sources available in the public literature are References I and 2.

The data in Reference I are for the initiation fracture toughness (i.e., at the initiation of crack growth), defined by:

Kic= bJcxE Je is defined as the J-integral value at the initiation of crack growth and E is the Young's modulus for the material. For Type 304 stainless steel plate irradiated to a fluence of -5 x 1020 n/cm2 (E > IMeV) at -280 oC and tested at 288 'C, the lowest reported value in Reference I of Jhe (-75 in.-lb/in.2) corresponds to a Kj of -50 ksiOin.

From Reference 2, J-integral resistance or J-R curve data are reported for two samples fabricated from core shroud material removed from an overseas boiling water reactor (BWR) (see figure attached). The fluence for these samples is reported in Reference 2 as 8 x 1020 n/cm 2.

Reconciliation of the Je from Reference I with the J-R curve trends from Reference 2 (through scaling of the J levels in the J-R curves) can provide one estimate of the fracture toughness of highly irradiated austenitic stainless steel.

Provide any other fracture toughness data used in this evaluation.

BAW-Aging effects of many reactor vessel internal components will be managed by the BWOG NA 2248-4 Reactor Vessel Internals Aging Management Program. The program elements are 12/2/98 discussed in Section 4.6 of BAW-2248. Provide a plan and schedule for completing all the elements of the program.

BAW-Table 4-1 of BAW-2248 indicates that management of reduction of fracture toughness BWOG NA 2248-5 in vent valve bodies and vent valve retaining rings will be accomplished principally by 12/2/98 the American Society of Mechanical Engineers (ASME) Section Inservice Inspection (ISI) Program. This is in contrast to the treatment of other RVI components subject to loss of fracture toughness, for which the RVIAMP is set forth to manage the aging effects. Why are the vent valve components treated differently, and should they be included in the scope of the RVIAMP?

BAW-Table 4-1 of BAW-2248 indicates that the vent valve retaining ring, vent valve bodies, BWOG NA 2248-6 and the locking devices on the modified vent valve assembly do not require a 12/2/98 supplemental aging management program. Aging effects will be managed during the renewal term using ASME Boiling and Pressure Vessel Code (Code) inspection methods. Since functions of these components are affected by either a reduction of fracture toughness or stress corrosion cracking, will ASME Code VT-3 visual examination be adequate for discovering cracks that could lead to failure of the component? What examination methodology is required? Are the surfaces of the components accessible for detecting cracks that could lead to failure of the components?

BAW-Page 3-5 of BAW-2248 states that "the ONS-1 CRGT assembly sectors required BWOG NA 2248-7 straightening after the first hot functional test (FHT)." Provide a summary of the 12/2/98 evaluation indicating that the cracking mechanisms (SCC and IASCC) are not plausible in this case. If these guide tube sectors were to be degraded by a cracking mechanism, could such cracking impede the ability of the reactor vessel internals to perform its function to "provide support, orientation, guidance, and protection of the control rod assemblies"?

BAW-Examination Category B-N-3 of ASME Section XI requires a VT-3 visual examination BWOG NA of "accessible surfaces" of removable core support structures. For assemblies and 12-16 RAI Status.doc Page 51 of 53

0 0

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 2288 parts determined to be susceptible to no aging mechanisms, and hence to require no 12/2/98 additional aging management, the VT-3 examination provides one measure of assurance of the structural integrity of the part. Which components not susceptible to an aging mechanism (and hence, no additional aging management) will receive a VT-3 examination that can serve as a sampling of nonsusceptible components?

BAW-Section 3.3 of BAW-2248 indicates that crevice corrosion is not expected to be a BWOG NA 2248-9 concern, unless the internals are exposed to a series of long outages that have 12/2/98 stagnation and high impurity levels. What impurity levels and how much cumulative outage time are required before crevice corrosion becomes a concern? What components could be affected by crevice corrosion? How could crevice corrosion be prevented if there were a long outage?

BAW-Section 3.3 of BAW-2248 indicates that wear is not a concern for the modified vent BWOG NA 2248-10 valve locking devices. Explain the difference between the original design and the 12/2/98 modified design that eliminated the concern for wear of the vent valve locking device.

To what criteria are the modified vent valve locking devices being inspected to ensure that they are not subject to wear? Summarize the results of these inspections; include the number and frequency of inspection. Will these inspections be continued into the license renewal term?

BAW-Section 3.3 of BAW-2248 indicates that Westinghouse has observed wear of incore BWOG NA 2248-11 guide tubes caused by flow induced vibration in regions directly exposed to reactor 12/2/98 coolant system (RCS) flow. Wear of Babcox & Wilcox (B&W)-designed guide tube and spiders are not a concern; however, because of differences between the Westinghouse and B&W guide tube design and because the B&W-designed detectors are inserted and withdrawn once per fuel cycle. Explain the difference in design and operation of the Westinghouse and B&W incore guide tubes that indicates wear is not a concern for the B&W design. Are there any limits on the number of insertions and withdrawals of the incore monitors that could lead to a concern about wear of the guide tubes?

BAW-During its interaction meetings with the staff (referenced in the Section 4.3.11 of the BWOG NA 2248-12 Oconee Nuclear Station License Renewal - Technical Information New Programs and 12/2/98 Activities Report, June 1998), the B&W Owners Group (B&WOG) described current and ongoing reactor internals baffle bolt activities that included preparation for possible augmented baffle bolt inspection during the next 10-year ISI interval at Oconee 1 (2003 at the earliest). Describe baffle bolt inspections that will be conducted prior to the start of the extended license renewal period and indicate how these actions provide the basis for assuring the baffle bolt monitoring and inspection techniques that are planned during the period of extended operation are appropriate.

BAW-Describe the program that will be implemented as outlined in Section 4.6 of BAW-BWOG NA 2248-13 2248 with regard to the aging management of the reactor internals baffle bolts.

12/2/98 Describe the overall inspection program, including aspects such as, intervals, monitoring, and inspection techniques.

BAW-Describe the replacement bolts and redesigned RVI that are referred to in the fatigue BWOG NA 2248-14 analysis discussed in BAW-2248 Section 4.5.1. Are the replacement bolts and 12/2/98 redesigned RVI identified in the fatigue analysis related to the issue of the A-286 bolt cracking discovered in B&W RVI? Arethe baffle bolts discussed in the BAW-2248 report included in the fatigue analysis? If not, what is the basis for not including the baffle bolts in the fatigue analysis? If the baffle bolts are included in the analysis, describe how baffle bolt cracking is taken into account and identify the analysis report.

REFERENCES

1. Loss, F. J., and Gray, Jr., R. A., "J-Integral Characterization of Irradiated Stainless Steels," NRL Report 7565, Naval Research Laboratory, Washington, D. C., April 25, 1973.

2.

EPRI TR-107079, "BWR Vessel and Internals Project, BWR Core Shroud Inspection and Flaw Evaluation Guideline, Revision 2 (BWRVIP-01)," October 1996, pp. 4-13.

OLRP-1001 SECTIONS WITHOUT RAls 12/4/98 NC NA 1.1 1.2 12-16 RAI Status.doc Page 52 of 53

9*

Oconee License Renewal Application NRC Request For Additional Information Status December 16, 1998 2.10 1.3 1.4 1.5.1 1.5.3 1.5.4 2.1 2.3.1 2.4.1 2.4.2 2.5.1 2.5.2 2.5.11 2.5.12 2.5.14 3.1 3.4.1 3.4.2 3.5.1 3.5.10 3.5.11 3.7.8 3.7.10 4.312 4.3.3 4.3.4 4.3.5 4.3.6 4.3.10 4.3.11 4.3.12 4.4 4.6.1 4.6.5 4.7 4.19 4.20 4.27 4.29 5.4.3 2 5.5.1 Notes I

RAI issued on related Section 5.7.2.

2 OLRP-1001 Sections 4.3, 4.3.11, and 5.4.3 along with 3.4.6 reference BAW

2248A, "Management of Aging Effects for Reactor Vessel Internals." RAIs for BAW-2248A were transmitted to the Babcock and Wilcox Owners Group by NRC letter dated December 2, 1998.

12-16 RAI Status.doc Page 53 of 53