ML042730615

License Amendment, Revised Technical Specifications Limiting Conditions for Operation 3.8.4, DC Sources - Operating, for the Remainder of Operating Cycle 19.

ML042730615
Person / Time
Site:	Farley
Issue date:	09/30/2004
From:	Sean Peters NRC/NRR/DLPM/LPD2
To:	Stinson L Southern Nuclear Operating Co
Peters S, NRR/DLPM, 415-1842
Shared Package
ML042730617	List: ML042730615
References
TAC MC1007
Download: ML042730615 (20)

Text

September 30, 2004 Mr. L. M. Stinson Vice President - Farley Project Southern Nuclear Operating Company, Inc.

Post Office Box 1295 Birmingham, Alabama 35201-1295

SUBJECT:

JOSEPH M. FARLEY NUCLEAR PLANT, UNIT 1 RE: ISSUANCE OF AMENDMENT - TECHNICAL SPECIFICATION CHANGES DC SOURCES -

OPERATING (TAC NO. MC1007)

Dear Mr. Stinson:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 164 to Facility Operating License No. NPF-2 for the Joseph M. Farley Nuclear Plant, Unit 1. The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated September 19, 2003, as supplemented by letters dated March 31, June 18, and August 6, 2004.

The amendment revises TS Limiting Conditions for Operation 3.8.4, "DC Sources - Operating,"

for the remainder of operating cycle 19. Specifically, the proposed TS change would increase the completion time for the 1B Auxiliary Building DC electrical power system inoperability due to an inoperable battery to allow for on-line replacement of individual cells.

A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commissions biweekly Federal Register notice.

Sincerely,

/RA/

Sean E. Peters, Project Manager, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-348

Enclosures:

1. Amendment No. 164 to NPF-2

2. Safety Evaluation cc w/encl: See next page

September 30, 2004 Mr. L. M. Stinson Vice President - Farley Project Southern Nuclear Operating Company, Inc.

Post Office Box 1295 Birmingham, Alabama 35201-1295

SUBJECT:

JOSEPH M. FARLEY NUCLEAR PLANT, UNIT 1 RE: ISSUANCE OF AMENDMENT - TECHNICAL SPECIFICATION CHANGES DC SOURCES -

OPERATING (TAC NO. MC1007)

Dear Mr. Stinson:

The U.S. Nuclear Regulatory Commission has issued the enclosed Amendment No. 164 to Facility Operating License No. NPF-2 for the Joseph M. Farley Nuclear Plant, Unit 1. The amendment consists of changes to the Technical Specifications (TSs) in response to your application dated September 19, 2003, as supplemented by letters dated March 31, June 18, and August 6, 2004.

The amendment revises TS Limiting Conditions for Operation 3.8.4, "DC Sources - Operating,"

for the remainder of operating cycle 19. Specifically, the proposed TS change would increase the completion time for the 1B Auxiliary Building DC electrical power system inoperability due to an inoperable battery to allow for on-line replacement of individual cells.

A copy of the related Safety Evaluation is also enclosed. A Notice of Issuance will be included in the Commissions biweekly Federal Register notice.

Sincerely,

/RA/

Sean E. Peters, Project Manager, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-348

Enclosures:

DISTRIBUTION:

1. Amendment No. 164 to NPF-2 PUBLIC PDII-1 R/F G.Hill (2) SSaba

2. Safety Evaluation WBeckner BBonser,RII MStutzke ACRS SPeters MRoss-Lee DClarke OGC cc w/encl: See next page DLPM DPR EHackett TBoyce DOCUMENT NAME: C:\ORPCheckout\FileNET\ML042730615.wpd Package Accession Number: ML042730617 Amendment Accession Number: ML042730615 Tech Spec Accession Number: ML OFFICE PDII-1/PM PDII-1/LA(A) EEIB:SC IROB:SC SPSB:SC OGC:NLO PDII-1/SC (A)

NAME SPeters DClarke RJenkins TBoyce MRubin HMcGurren MRoss-Lee DATE 09/27/04 09/23/04 09/20/04 09/22/04 09/22/04 09/22/04 09/29/04 OFFICIAL RECORD COPY

Joseph M. Farley Nuclear Plant, Units 1 & 2 cc:

Mr. Don E. Grissette William D. Oldfield General Manager SAER Supervisor Southern Nuclear Operating Company Southern Nuclear Operating Company P.O. Box 470 P.O. Box 470 Ashford, Alabama 36312 Ashford, Alabama 36312 Mr. B. D. McKinney, Licensing Manager Southern Nuclear Operating Company P.O. Box 1295 Birmingham, Alabama 35201-1295 Mr. M. Stanford Blanton Balch and Bingham Law Firm P.O. Box 306 1710 Sixth Avenue North Birmingham, Alabama 35201 Mr. J. Gasser Executive Vice President Southern Nuclear Operating Company P.O. Box 1295 Birmingham, Alabama 35201 State Health Officer Alabama Department of Public Health 434 Monroe Street Montgomery, Alabama 36130-1701 Chairman Houston County Commission P.O. Box 6406 Dothan, Alabama 36302 Resident Inspector U.S. Nuclear Regulatory Commission 7388 N. State Highway 95 Columbia, Alabama 36319

SOUTHERN NUCLEAR OPERATING COMPANY, INC.

ALABAMA POWER COMPANY DOCKET NO. 50-348 JOSEPH M. FARLEY NUCLEAR PLANT, UNIT 1 AMENDMENT TO FACILITY OPERATING LICENSE Amendment No. 164 License No. NPF-2

1. The Nuclear Regulatory Commission (the Commission) has found that:

A. The application for amendment by Southern Nuclear Operating Company, Inc.

(SNC), dated September 19, 2003, as supplemented by letters dated March 31, June 18, and August 6, 2004, complies with the standards and requirements of the Atomic Energy Act of 1954, as amended (the Act), and the Commissions rules and regulations set forth in 10 CFR Chapter I; B. The facility will operate in conformity with the application, the provisions of the Act, and the rules and regulations of the Commission; C. There is reasonable assurance (i) that the activities authorized by this amendment can be conducted without endangering the health and safety of the public, and (ii) that such activities will be conducted in compliance with the Commissions regulations; D. The issuance of this license amendment will not be inimical to the common defense and security or to the health and safety of the public; and E. The issuance of this amendment is in accordance with 10 CFR Part 51 of the Commissions regulations and all applicable requirements have been satisfied.

2. Accordingly, the license is amended by changes to the Technical Specifications, as indicated in the attachment to this license amendment; and paragraph 2.C.(2) of Facility Operating License No. NPF-2 is hereby amended to read as follows:

(2) Technical Specifications The Technical Specifications contained in Appendices A and B, as revised through Amendment No. 164, are hereby incorporated in the license. SNC shall operate the facility in accordance with the Technical Specifications.

3. This license amendment is effective as of its date of issuance and shall be implemented within 30 days of issuance.

FOR THE NUCLEAR REGULATORY COMMISSION

/RA/

Mary Jane Ross-Lee, Acting Chief, Section 1 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation

Attachment:

Changes to the Technical Specifications Date of Issuance: September 30, 2004

ATTACHMENT TO LICENSE AMENDMENT NO. 164 TO FACILITY OPERATING LICENSE NO. NPF-2 DOCKET NO. 50-348 Replace the following pages of the Appendix A Technical Specifications with the attached revised pages. The revised pages are identified by amendment number and contain marginal lines indicating the areas of change.

Remove Insert 3.8.4-1 3.8.4-1 B 3.8.4-5 B 3.8.4-5 B 3.8.4-6 B 3.8.4-6 B 3.8.4-7 B 3.8.4-7 B 3.8.4-8 B 3.8.4-8 B 3.8.4-9 B 3.8.4-9 B 3.8.4-10 B 3.8.4-10 B 3.8.4-11 B 3.8.4-11

SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO AMENDMENT NO. 164 TO FACILITY OPERATING LICENSE NO. NPF-2 SOUTHERN NUCLEAR OPERATING COMPANY, INC., ET AL.

JOSEPH M. FARLEY NUCLEAR PLANT, UNIT 1 DOCKET NO. 50-348

1.0 INTRODUCTION

By letter to the U.S. Nuclear Regulatory Commission (NRC, Commission) dated September 19, 2003 (Ref. 1), as supplemented by letters dated March 31, June 18, and August 6, 2004 (Refs. 2, 3, and 4), Southern Nuclear Operating Company Inc. (SNC) et al., submitted a request for changes to the Joseph M. Farley Nuclear Plant (FNP), Unit 1, Technical Specifications (TSs). The 1B auxiliary building battery is reaching the end of its useful life and there are plans to replace it during the next FNP, Unit 1, refueling outage. FNP has experienced a failure of a battery cell and the initial evaluation of the failure indicates that it is due to aging. Other cells within the battery bank have similar indications of aging. Presently, if the battery is inoperable, or if maintenance such as cell replacement is required, the 2-hour completion time (CT) is severely restrictive.

The requested change would revise the TS Limiting Conditions for Operation (LCO) 3.8.4, "DC Sources - Operating," for FNP, Unit 1, for the remainder of operating cycle 19. Specifically, the proposed change would increase the CT for the 1B auxiliary building DC electrical power system inoperability due to an inoperable battery to allow for on-line replacement of individual cells. Operating cycle 19 is presently scheduled to end on October 2, 2004, and the proposed change would revise the CT from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. Allowing 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> for maintenance on the battery would facilitate a more orderly and effective maintenance process. It would also reduce the potential for an additional shutdown/restart transient with the TS in order to accomplish the required maintenance.

The March 31, June 18, and August 6, 2004, letters provided clarifying information that did not change the September 19, 2003, application and the initial proposed no significant hazards consideration determination.

2.0 REGULATORY EVALUATION

The regulatory requirements that the NRC staff applied in its review of the amendment included General Design Criterion (GDC) 17, Electric Power System, of Appendix A, General Design Criteria for Nuclear Power Plants, to Title 10 of Code of Federal Regulations (10 CFR) Part 50, Domestic Licensing of Production and Utilization Facilities, which requires that an onsite electric power system and an offsite electric power system be provided to permit functioning of structures, systems and components important to safety. The onsite system is required to have

sufficient independence, redundancy, and testability, to perform its safety function, assuming a single failure.

The regulatory criteria/guidelines on which the NRC staff based its acceptance are:

• Regulatory Guide (RG) 1.174, An Approach for Using Probabilistic Risk Assessments

[PRA] in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, describes a risk-informed approach, acceptable to the NRC, for assessing the nature and impact of proposed licensing-basis changes by considering engineering issues and applying risk insights. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.

• RG 1.177, An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications, describes an acceptable risk-informed approach specifically for assessing proposed TS changes in allowed outage times (AOTs). Note that the phrase completion time used in the licensees TS is equivalent to the phrase allowed outage time used in RG 1.177. This RG also provides risk acceptance guidelines for evaluating the results of such evaluations.

One acceptable approach to making risk-informed (RI) decisions about proposed TS changes, including both permanent and temporary TS changes, is to show that the proposed changes meet five key principles stated in RG 1.174, Section 2 and RG 1.177, Section B:

1. The proposed change meets the current regulations unless it is explicitly related to a requested exemption or rule change.

2. The proposed change is consistent with the defense-in-depth (DID) philosophy.

3. The proposed change maintains sufficient safety margins.

4. When proposed changes result in an increase in core-damage frequency (CDF) or risk, the increases should be small and consistent with the intent of the Commissions Safety Goal Policy Statement.

5. The impact of the proposed change should be monitored using performance measurement strategies.

For permanent TS changes, RG 1.174 and RG 1.177 provide numerical risk acceptance guidelines that are helpful in determining whether or not the fourth key principle has been satisfied. These guidelines are not to be applied in an overly prescriptive manner; rather, they provide an indication, in numerical terms, of what is considered to be acceptable. The intent in comparing risk results with the risk acceptance guidelines is to demonstrate with reasonable assurance that the fourth key principle has been satisfied.

For temporary TS changes, examination of the risk metrics identified in RG 1.174 and RG 1.177 provides insight about the potential risk impacts, even though neither of these regulatory guides provides numerical risk acceptance guidelines for evaluating temporary TS changes against the fourth key principle. The Staff Requirements Memorandum (SRM) issued

March 19, 1998, in response to SECY-97-287, provides some additional guidance concerning the use of risk acceptance guidelines to evaluate temporary changes to plant configurations:

At present, except for the special case of Technical Specification changes, only time-averaged guidelines will be used. In assessing these acceptance guidelines for temporary plant configurations staff should weigh the merits of temporary changes that may lead to improved safety, and should ensure that appropriate compensatory measures are taken into account that could mitigate the conditional CDF and LERF [large early release frequency].

Based on this SRM, coupled with RG 1.174 and RG 1.177, the NRC staff concludes that a proposed temporary TS change meets the fourth key principle of RI decision making, if its associated risk metrics:

• Satisfy the risk acceptance guidelines in RG 1.174 and RG 1.177, or

• Are not substantially above the risk acceptance guidelines in RG 1.174 and RG 1.177 and effective compensatory measures to lower risk are implemented while the temporary TS change is in effect.

3.0 TECHNICAL EVALUATION

3.1 System Description

The 125 VDC electrical power system at FNP, Unit 1 consists of two main systems, the auxiliary building system and the service water intake structure system with two trains in each main system.

The auxiliary building 125 VDC system consists of two independent and redundant subsystems (A-Train and B-Train) that supply DC power to various engineered safety features (ESF) systems throughout the plant. Each auxiliary building subsystem consists of a 125 VDC battery, an associated full capacity battery charger, and all associated control equipment and interconnecting cabling. Each auxiliary building 125 VDC train is normally supplied by the associated battery charger (A or B). In the event of an A or B battery charger failure, battery charger C, the full capacity swing battery charger, may supply power to either train. Either train may be considered OPERABLE when supplied from battery charger C.

Battery charger C input and output breakers are interlocked to prevent paralleling the redundant DC buses or the AC buses through the battery charger and to prevent cross-connecting trains.

During normal operation, the 125 VDC load is powered from the battery chargers with the batteries floating on the system. In case of loss of normal power to the battery charger, the DC load is automatically powered from the station batteries. In the unlikely event that a battery charger fails, the swing battery charger is manually placed in service.

The A-Train and B-Train DC electrical power subsystems provide the control power to its associated Class 1E power load group, 4.16 kV switchgear, 600 V load centers, ESF controls, emergency lights, emergency diesel generator (EDG) field flashing and control, DC solenoids

for air-operated valves, miscellaneous controls and alarms, and reactor trip switchgear. The DC electrical power subsystems also provide DC electrical power to the inverters, which in turn power the AC vital buses. DC bus 1A supplies primary power to the 1A and 1B inverter static transfer switches, while DC bus 1B supplies primary power to the 1C and 1D inverter static transfer switches.

The A-Train EDGs for FNP (1C and 1-2A) support both units and, as such, the control panel for each EDG receives DC power from Unit 1 A-Train DC and Unit 2 A-Train DC through power-seeking automatic transfer switches (ATSs). This arrangement ensures that an operable DC power supply is available for the A-Train EDGs.

The B-Train EDGs for FNP are unit-specific (Unit 1 - 1B, and Unit 2 - 2B). The control panel for each EDG receives DC power from its respective Units B-Train DC subsystem.

The station blackout (SBO) diesel generator for FNP (2C) is B-Train and supports both units.

As such, its control panel receives DC power from Unit 1, B-Train DC and Unit 2, B-Train DC through ATSs. This configuration ensures that an operable DC power supply is available at all times to the SBO diesel generator.

The auxiliary building batteries are a stationary type, consisting of 60 individual lead-calcium cells electrically connected in series to establish a nominal 125 VDC power supply. Initially, during a loss of offsite power (LOOP) or LOOP with safety injection (SI), the auxiliary building batteries supply safety-related loads without charger support. The design is such that subsequent to LOOP, the battery chargers are re-energized by the EDGs.

3.2 Detailed Description of the Proposed Change The current CT for TS 3.8.4, Condition A, Required Action A.1 is 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br />.

The proposed amendment adds a note to TS 3.8.4, Condition A, Required Action A.1 that would increase the CT from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br />. The proposed note states the following:

12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> for 1B auxiliary building DC electrical power subsystem due to inoperable battery for cycle 19 only In addition, the following paragraph will be added to the TS Bases for 3.8.4, Action A.1:

[For Unit 1 only for operating cycle 19] The second Completion Time for Condition A represents the 1B Train of Auxiliary Building DC electrical power subsystem due to an inoperable battery. With the 1B Auxiliary Building battery inoperable, the DC bus is being supplied by the OPERABLE battery charger.

Any event that results in a loss of the AC bus supporting the battery charger will also result in the loss of DC to that train. Recovery of the AC bus, especially if it is due to a loss of offsite power, will be hampered by the fact that many of the components necessary for recovery (e.g., diesel generator control and field flash, AC load shed and diesel generator output breakers, etc.) rely upon the battery. The 12-hour limit allows sufficient time to effect restoration of the inoperable battery given that the majority of the conditions that lead to battery

inoperability (e.g., loss of battery charger, battery cell voltage less than 2.02 volts, etc.) are identified in Specifications 3.8.4, 3.8.5, and 3.8.6 together with additional specific completion times.

3.3 NRC Staff Review Methodology In accordance with the Standard Review Plan (SRP), Chapter 16.1, Risk-Informed Decisionmaking: Technical Specifications, the NRC staff reviewed the submittal against the five key principles of the NRC staffs philosophy of RI decision making listed in RG 1.177, Section B.

3.4 Key Information Used in NRC Staff Review The key information used in the NRC staffs review of the risk evaluation is contained in to the licensees submittal (Reference 1), as supplemented by SNC in its response to the NRC staffs request for additional information (Reference 2). In addition, the NRC staff consulted the safety evaluation reports (SERs) on the individual plant examinations (IPEs) and individual plant examinations of external events (IPEEEs) submitted by the licensee.

3.5 Comparison Against Regulatory Criteria/Guidelines The NRC staffs comparison of the licensees proposed license amendment against the five key principles is presented in the following sections.

3.5.1 Traditional Engineering Evaluation The traditional engineering evaluation presented below addresses the first three key principles of the NRC staffs philosophy of RI decision making, which concern compliance with current regulations, evaluation of DID, and evaluation of safety margins.

3.5.1.1 Compliance with Current Regulations As stated in Section 2.0, per GDC 17, the onsite system is required to have sufficient independence, redundancy, and testability, to perform its safety function, assuming a single failure. As described above, the auxiliary building 125 VDC system consists of two independent and redundant subsystems. In its submittal dated September 19, 2003, the licensee states, At FNP, a failure of a single Auxiliary Building 125 VDC system will not result in conditions that will prevent the safe shutdown of the unit. Procedures are in place to respond to a complete loss of a train of DC power and maintain the capability to respond to design basis events, excluding a single failure due to the time-limited condition. The NRC staff finds that this amendment meets the requirements of GDC 17.

3.5.1.2 Evaluation of DID Per the TS Bases, an operable auxiliary building DC electrical power subsystem must include a battery, a battery charger, and the corresponding control equipment and interconnecting cabling supplying power to the associated bus within the train.

The 1B battery bank is reaching the end of its useful life and the licensee plans to replace it during the next FNP, Unit 1, refueling outage. FNP has experienced a failure of a battery cell and the initial evaluation indicates that the failure is caused by aging. Other cells within the battery bank have similar indications of aging.

For this condition, a dual unit LOOP with an SI on FNP, Unit 1 would be the most limiting accident condition. If this event occurred while a Unit 1 Auxiliary building battery was unavailable, the opposite train of emergency power would start and sequence on the SI/LOOP loads. With the battery unavailable, field flashing to the 1B EDG is not assured. In that circumstance, operator action would allow emergency power to be supplied to FNP, Unit 1 from the SBO DG for LOOP loads.

With the 1B auxiliary building battery inoperable, the OPERABLE battery charger would be supplying the DC bus. If the battery charger becomes inoperable due to the loss of the AC bus, especially if due to a LOOP, recovery of the AC bus would be hampered by the 2-hour CT, since many of the components necessary to the recovery (DG control and field flashing, AC loads shed and DG output breakers, etc.) rely upon the battery. The 12-hour limit allows sufficient time to affect restoration of the inoperable battery.

3.5.1.3 Evaluation of Safety Margins In its submittal dated September 19, 2003, the licensee states, The physical plant is unaffected by these changes. These proposed changes do not impact accident offsite dose, containment pressure or temperature, emergency core cooling system (ECCS) or reactor protection system (RPS) settings or any other parameter that could affect a margin of safety. Under the proposed amendment, the unit will continue to be operated in a condition that will ensure that emergency power will be available as needed. The NRC staff concurs with the licensee on this statement that this change does not result in any reduction in safety margin.

Summary The proposed extended time of 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> for an inoperable 1B battery is acceptable based on available redundancy, DID provided by the SBO DG, which support both units. Furthermore, field flashing for the SBO DG may be supplied by either unit. The proposed TS change modifies the CT for Condition A of LCO 3.8.4 such that FNP, Unit 1, 1B auxiliary building DC electrical power subsystem may be inoperable for up to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> before beginning an orderly shutdown of the unit. This change is applicable to FNP, Unit 1 only for the remainder of operating cycle 19 and is acceptable.

3.6 Probabilistic Safety Assessment 3.6.1 Risk Evaluation The risk evaluation presented below addresses the last two key principles of the NRC staffs philosophy of RI decision making, which concern changes in risk and performance measurement strategies. The NRC staff evaluated these key principles by using the three-tiered approach described in Chapter 16.1 of the SRP and in RG 1.177.

• Tier 1 - The first tier evaluates the licensee's probabilistic risk/safety assessment and the impact of the change on plant operational risk, as expressed by the change in CDF and the change in LERF. The change in risk is compared against the acceptance guidelines presented in RG 1.174. The first tier also aims to ensure that plant risk does not increase unacceptably during the period when equipment is taken out-of-service per the license amendment, as expressed by the incremental conditional core damage probability (ICCDP) and incremental conditional large early release probability (ICLERP). The incremental risk is compared against the acceptance guidelines presented in RG 1.177.

• Tier 2 - The second tier addresses the need to preclude potentially high-risk plant configurations that could result if equipment, in addition to that associated with the proposed license amendment, are taken out-of-service simultaneously, or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved. The objective of this part of the review is to ensure that appropriate restrictions on dominant risk-significant plant configurations associated with the AOT extension are in place.

• Tier 3 - The third tier addresses the licensee's overall configuration risk management program (CRMP) to ensure that adequate programs and procedures are in place for identifying risk-significant plant configurations resulting from maintenance or other operational activities and taking appropriate compensatory measures to avoid such configurations. The CRMP ensures that equipment removed from service prior to or during the proposed extended AOT period will be appropriately assessed from a risk perspective.

3.6.2 Tier 1: PRA Capability and Insights The Tier 1 NRC staff review involved two aspects: (1) evaluation of the adequacy of the PRA and its application to the proposed CT extension and (2) evaluation of the PRA results and insights stemming from its application.

3.6.2.1 Evaluation of PRA Adequacy To determine whether the PRA used in support of the proposed CT extension is of sufficient quality, scope, and level of detail, the NRC staff evaluated the relevant information provided by SNC in its submittal, as supplemented, and considered the findings of recent PRA reviews.

The NRC staff's review of the submittal focused on the adequacy of the licensee's PRA model to analyze the risks stemming from the proposed CT extension and did not involve an in-depth review of SNC's PRA.

In order to assess the scope, level of detail, and technical adequacy of the FNP PRA to support the proposed license amendment, the NRC staff considered the following information:

• The licensee used Revision 5 of the FNP PRA model to evaluate the impacts of the proposed CT extension on plant risk. Revision 5 is based on the licensees response to Generic Letter (GL) 88-20, which requested the development of an IPE of FNP. The licensee submitted an IPE in June 1993; the NRC staff concluded in December 1995

that the FNP IPE met the intent of GL 88-20. Supplement 4 to GL 88-20 requested that the licensee expand the IPE to include IPEEE. SNC submitted the IPEEE in June 1995; the NRC staff concluded in October 1998 that the FNP IPEEE met the intent of Supplement 4 to GL 88-20.

• In August 2001, an experienced five-name Peer Review Team coordinated by the Westinghouse Owners Group in a manner described in the Nuclear Energy Institute (NEI) document NEI 00-02, Industry Peer Review Process, extensively reviewed Revision 4 of the FNP PRA. As discussed by the licensee in Reference 2, the peer review generated no Category A facts and observations (F&Os) and 25 Category B F&Os. The licensee modified the PRA in response to nine of the F&Os, and explained why several additional F&Os are based on differences between equally valid assumptions and methods and do not require modifications to the PRA. The licensee also explained that the possible PRA modifications to resolve the remaining F&Os would have an insignificant impact on the risk metrics used to support the proposed license amendment. After review of the Category A and B F&Os and consideration of the licensees response, the NRC staff concludes that revising the current FNP PRA to address all outstanding F&Os would only result in very small changes to the risk metrics used to support the proposed license amendment.

• The NRC staff has recently reviewed the quality of the FNP PRA (Reference 4) in the context of RI inservice inspection, and found that the quality of Revision 5 of the FNP PRA was sufficient to support that RI application.

Based on consideration of the above information, the NRC staff finds that the licensee has satisfied the intent of RG 1.177 (Sections 2.3.1, 2.3.2, and 2.3.3), RG 1.174 (Sections 2.2.3 and 2.5), and SRP Chapter 19.1, and that the quality of the FNP PRA is sufficient to support the risk evaluation provided by the licensee in the proposed license amendment.

3.6.2.1.1 Evaluation of PRA Results and Insights Based on information provided by the licensee, the NRC staff determined the following risk metrics in support of the proposed license amendment:

Baseline (current) core-damage frequency (CDF): 3.9 x 10-5/y CDF associated with the proposed license amendment: 3.9 x 10-5/y Change in CDF: 1.4 x 10-7/y Risk achievement worth (RAW) of the 1B battery: 9.65 Fussell-Vesely importance measure of the 1B battery: 2.7 x 10-4 Incremental conditional core-damage probability (ICCDP): 3.4 x 10-7 Baseline (current) large early release frequency (LERF): 4.2 x 10-7/y LERF associated with the proposed license amendment: 4.2 x 10-7/y Change in LERF: 2 x 10-11/y Incremental conditional large early release probability (ICLERP): 6.6 x 10-11 The quantitative risk metrics provided above are based on the contributions from internal events, including internal floods. A large majority of the risk increase associated with the proposed license amendment is due to accidents initiated by LOOP. Should a LOOP occur when the 1B auxiliary building battery is out-of-service, EDG 1B would not function since the 1B auxiliary building battery provides its sole source of field flashing. However, the Train B buses could be re-energized by manually starting and aligning EDG 2C (the SBO EDG). The proposed license amendment does not affect the EDGs that supply emergency power to the Train A buses. Turbine-driven auxiliary feedwater pump is supported by separate batteries (i.e., does not depend on the auxiliary building batteries) and is, therefore, not affected by the proposed license amendment.

A review of the licensees IPEEE results indicates that the FNP seismic risk has been evaluated using the Electric Power Research Institute's (EPRI) seismic margins assessment (SMA) methodology as described in EPRI NP-6041. Since FNP was categorized as a reduced-scope plant, the safe shutdown earthquake ground response spectra with a peak ground acceleration (PGA) of 0.1g were used as the IPEEE review level earthquake. For the component screening and evaluation, the Seismic Qualification Utility Group (SQUG) Generic Implementation Procedure (GIP) was used for both units. For items not covered by the SQUG GIP, the guidance from EPRI NP-6041 were used. Since the SMA approach was used, no quantitative estimate was made for the seismic contribution to plant risk. The licensee has indicated (Reference 5) that all seismic outliers identified in NUREG-1742 have been addressed.

The NRC staff performed a qualitative assessment to determine the seismic risk implications of the proposed licensee amendment by considering how the licensees SMA would be affected when the 1B auxiliary building battery is out-of-service due to cell replacement. The proposed license amendment involves a change to the 1B auxiliary building battery CT; it does not change the physical characteristics (e.g., design, mounting, anchorage, etc.) of any plant equipment and, hence, does not change the seismic margin of any plant equipment. In accordance with the EPRI SMA methodology, the licensee defined a primary and alternative success path, either of which is capable of providing adequate core cooling following an

earthquake. Both success paths presumed a simultaneous LOOP and small break loss-of-coolant accident. In general, the success paths are identical in equipment configuration; the primary success path is based on Train A equipment and the alternative success path is based on Train B equipment. Each success path considers secondary cooling from the steam generators using auxiliary feedwater, reactor coolant system makeup by charging pumps, and long-term cooling by the residual heat removal system. In addition, each success path credits primary feed-and-bleed cooling as a backup to the secondary cooling. If the 1B auxiliary building battery is out-of-service when an earthquake occurs, the alternative success path would not be available since the 1B auxiliary building battery provides control power to most of the plant equipment that comprise the alternative success path; the primary success path would not be affected. Since the plants seismic margin is higher than the primary and alternative success path seismic margins, the proposed license amendment does not change the plant-level seismic margin.

In its IPEEE, the licensee assessed the risks to FNP arising from internal fires using the EPRI Fire Induced Vulnerability Evaluation (FIVE) methodology. SNC recently updated the IPEEE analysis using the Revision 5 PRA model (Reference 5). The total fire-induced CDF was estimated to be about 5 x 10-5/y; the total fire-induced LERF was estimated to be about 1 x 10-8/y. There are six compartments with estimated fire-induced CDFs above the 10-6/y screening value used in the EPRI FIVE methodology:

Fire Description CDF (/y) LERF (/y)

Compartment 1-41A Auxiliary building switchgear room train A 1.57 x 10-5 3.33 x 10-9 44A Control room 1.16 x 10-5 3.10 x 10-9 1-21A Auxiliary building switchgear room train B 1.04 x 10-5 2.20 x 10-9 72A Service water intake structure 3.77 x 10-6 8.01 x 10-10 1-35A Train A electrical penetration room 2.18 x 10-6 4.63 x 10-10 1-35B Train B electrical penetration room 1.54 x 10-6 3.26 x 10-10 The IPEEE concluded that multi-compartment fire scenarios could be screened out as insignificant risk contributors. The licensee has indicated (Reference 5) that all fire-related plant improvements identified in Table 3.5 of NUREG-1742 have been implemented.

SNC has also indicated (Reference 6) that the proposed licensee amendment causes a change in CDF associated with fires in Fire Compartment 1-41A of approximately 2 x 10-7/year; the ICCDP is approximately 6 x 10-7. The CDFs of other fire scenarios are not notably impacted by the proposed license amendment. The licensee noted that the fire risk assessment does not take credit for manually starting and aligning the 2C EDG (the SBO EDG), and that the preceding results are conservative.

In its IPEEE, SNC evaluated high winds, floods, and other (HFO) external events using the

progressive screening approach described in NUREG-1407. The licensee did not quantitatively estimate the contribution to CDF from HFO external events since these events were screened out on the basis of low occurrence frequency using the NUREG-1407 screening approach. The licensees evaluation also confirmed that no plant changes had occurred since the issuance of the original Operating License that would impact the HFO areas of review.

The NRC staff concludes that the proposed license amendment results in an acceptable increase in risk that is very small and consistent with the NRCs Safety Goal Policy Statement because:

• The ICCDP and ICLERP associated with the proposed license amendment are less than the risk acceptance guidelines stated in Section 2.4 of RG 1.177 (ICCDP less than 5.0 x 10-7 and ICLERP is less than 5.0 x 10-8). Specifically, the ICCDP associated with the proposed license amendment is approximately 4 x 10-7, which is the sum of the internal events and internal flood ICCDP and the internal fire ICCDP multiplied by 0.1 in order to credit the use of EDG 2C (the SBO EDG) during specific fire scenarios. The NRC staff believes that the use of a 0.1 failure probability for the SBO EDG is reasonable because the SBO EDG is physically separated from fire locations that could potentially affect other EDGs, the SBO EDG reliability is monitored and controlled by the FNP Maintenance Rule program, use of the SBO EDG is addressed in the plant operating procedures, and the plant operators are trained in use of the SBO EDG. The ICLERP associated with the proposed license amendment is approximately 7 x 10-11.

• The risk metrics associated with the proposed license amendment satisfy the risk acceptance guidelines contained in RG 1.174. Specifically, the CDF risk metrics lie in Region III of the graph contained in Section 2.2.4 ( CDF versus baseline CDF), and the LERF risk metrics lie in Region III of the graph contained in Section 2.2.5 ( LERF versus baseline LERF) of RG 1.174.

• The proposed license amendment does not change the plant-level seismic margin.

• The proposed license amendment does not change the conclusion reached during the IPEEE that HFO external events at FNP have low occurrence frequencies and may be screened from further consideration using the NUREG-1407 screening approach.

Therefore, the NRC staff finds that the licensees first tier risk evaluation, as described in Chapter 16.1 of the SRP and RG 1.177, is acceptable.

3.6.3 Tier 2: Avoidance of Risk-Significant Plant Configurations The second tier evaluates the capability of the licensee to recognize and avoid risk-significant plant configurations that could result if equipment, in addition to that associated with the proposed license amendment, are taken out-of-service simultaneously or if other risk-significant operational factors, such as concurrent system or equipment testing, are also involved.

The licensee conducted a systematic search for risk-significant equipment configurations by examining the RAWs computed from the core damage accident sequence results of the PRA, assuming that the 1B auxiliary building battery was also out-of-service. This search was

performed for both Train A and Train B on-service alignments. The licensee indicated that the results of this search will be provided to FNP work planning and operations personnel.

In addition, the licensee identified several compensatory measures, to be treated as regulatory commitments (see Section 4.0), that will be implemented during the replacement of cells in the 1B auxiliary building battery.

The systematic search and use of PRA results to identify compensatory measures demonstrates the licensees ability to recognize and avoid risk-significant plant configurations.

Therefore, the NRC staff finds that the licensees second tier risk evaluation, as described in Chapter 16.1 of the SRP and RG 1.177, is acceptable.

3.6.4 Tier 3: Risk-Informed Configuration Risk Management The third tier assesses the licensees program to ensure that the risk impact of out-of-service equipment is appropriately evaluated prior to performing any maintenance activity. The need for this third tier stems from the difficulty of identifying all possible risk-significant configurations under the second tier that could ever be encountered.

To ensure that DID capabilities and the assumptions in the PRA are maintained during the replacement of cells in the 1B auxiliary building battery, the licensee will utilize its CRMP, which is governed by site administrative procedures, to help ensure that on-line risk is appropriately evaluated prior to performing any maintenance activity. This program provides guidance for managing plant trip risk, probabilistic risk, and safety function degradation from on-line maintenance, external, or internal conditions, as required by 10 CFR 50.65(a)(4). The NRC staff notes that the FNP Equipment Out-of-Service computer model provides the licensee with real-time risk monitoring capability.

Therefore, the NRC staff finds that the licensees third tier risk evaluation, as described in Chapter 16.1 of the SRP and RG 1.177, is acceptable.

3.7 NRC Staff Findings In summary, the NRC staff finds that the licensee's proposed license amendment to revise, only for FNP, Unit 1 and only for the remainder of operating cycle 19, the CT associated with LCO 3.8.4, DC Sources - Operating, from 2 hours0.0833 days <br />0.0119 weeks <br />0.00274 months <br /> to 12 hours0.5 days <br />0.0714 weeks <br />0.0164 months <br /> is acceptable because the five key principles of RI decision making identified in RG 1.174 and RG 1.177 have been satisfied.

4.0 REGULATORY COMMITMENTS In Reference 3, the licensee made the following regulatory commitments pertaining to the on-line replacement of cells in the 1B auxiliary building battery:

Regulatory Commitment Implementation of the Regulatory Commitment Compensatory measures will be put in Upon implementation of the one-time Unit 1 place to ensure no maintenance activities Technical Specification Change related to LCO are initiated in the high voltage or low 3.8.4, DC Sources - Operating. This voltage switchyards at Farley Nuclear commitment will be applicable until the end of Plant when battery bank 1B is in Operating Cycle 19.

maintenance.

Grid operators will be notified of the Whenever Condition A of LCO 3.8.4 is to be battery maintenance and asked to forego entered due to planned maintenance on voluntary system operations which could auxiliary building battery bank 1B. This increase the likelihood of LOOP affecting commitment will be applicable until the end of the FNP site. operating cycle 19.

Battery bank 1B maintenance will not be Whenever Condition A of LCO 3.8.4 is to be initiated if inclement weather is present or entered due to planned maintenance on forecast for the planned duration of the auxiliary building battery bank 1B. This maintenance. Inclement weather commitment will be applicable until the end of includes, but is not limited to, severe operating cycle 19.

thunderstorms, hail, and tornados. Should inclement weather develop while battery bank 1B is undergoing maintenance, SNC will restore battery bank 1B to operability as soon as practicable.

The grid operator will be contacted prior to Whenever Condition A of LCO 3.8.4 is to be initiating maintenance to ascertain the entered due to planned maintenance on status of the grid. Battery bank 1B auxiliary building battery bank 1B. This maintenance shall not be initiated if commitment will be applicable until the end of electrical grid is degraded. Should operating cycle 19.

electrical grid become degraded while battery bank 1B is undergoing maintenance, SNC will restore battery bank 1B to operability as soon as practicable.

The NRC staff finds that reasonable controls for the implementation and for subsequent evaluation of proposed changes pertaining to the above regulatory commitment(s) are best provided by the licensee's administrative processes, including its commitment management program. The above regulatory commitments do not warrant the creation of regulatory requirements (i.e., items requiring prior NRC approval of subsequent changes).

5.0 STATE CONSULTATION

In accordance with the Commission's regulations, the State of Alabama official was notified of the proposed issuance of the amendments. The State official had no comments.

6.0 ENVIRONMENTAL CONSIDERATION

The amendments change a requirement with respect to installation or use of a facility component located within the restricted area as defined in 10 CFR Part 20. The NRC staff has determined that the amendments involve no significant increase in the amounts and no significant change in the types of any effluents that may be released offsite and that there is no significant increase in individual or cumulative occupational radiation exposure. The Commission has previously issued a proposed finding that the amendments involve no significant hazards consideration, and there has been no public comment on such finding (68 FR 64137). Accordingly, the amendments meet the eligibility criteria for categorical exclusion set forth in 10 CFR 51.22(c)(9). Pursuant to 10 CFR 51.22(b) no environmental impact statement or environmental assessment need be prepared in connection with the issuance of the amendments.

7.0 CONCLUSION

The Commission has concluded, based on the considerations discussed above, that (1) there is reasonable assurance that the health and safety of the public will not be endangered by operation in the proposed manner, (2) such activities will be conducted in compliance with the Commissions regulations, and (3) the issuance of the amendments will not be inimical to the common defense and security or to the health and safety of the public.

8.0 REFERENCES

1. Letter from J. B. Beasley, Jr., Southern Nuclear Operating Company to U.S. Nuclear Regulatory Commission, Joseph M. Farley Nuclear Plant - Unit 1, Request for Technical Specification Changes, DC Sources - Operating, NL-03-1914, September 19, 2003.

2. Letter from L. M. Stinson, Southern Nuclear Operating Company to U.S. Nuclear Regulatory Commission, Joseph M. Farley Nuclear Plant - Unit 1, Response to Request for Additional Information Related to DC Sources - Operable, NL-04-0469, March 31, 2004.

3. Letter from L. M. Stinson, Southern Nuclear Operating Company to U.S. Nuclear Regulatory Commission, Joseph M. Farley Nuclear Plant - Unit 1, Additional Compensatory Actions Related to Request for Technical Specification Changes, DC Sources - Operable, NL-04-1025, June 18, 2004.

4. Letter from U.S. Nuclear Regulatory Commission to L. M. Stinson, Southern Nuclear Operating Company, Joseph A. Farley Nuclear Plant, Units 1 and 2 Re: Risk-Informed Inservice Inspection Program - ASME Code Category B-F, B-J, C-F-1, and C-F-2 Piping, ADAMS Accession No. ML04700258, March 9, 2004.

5. Letter from L. M. Stinson, Southern Nuclear Operating Company to U.S. Nuclear Regulatory Commission, Joseph M. Farley Nuclear Plant - Units 1 and 2, Application for License Renewal, December 12, 2003 Requests for Additional Information, NL-04-0287, February 26, 2004.

6. Letter from L. M. Stinson, Southern Nuclear Operating Company to U.S. Nuclear Regulatory Commission, Joseph M. Farley Nuclear Plant - Unit 1, Additional Information Request Related to Request for Technical Specification Changes, DC Sources - Operating, NL-04-1426, August 6, 2004.

Principal Contributors: M. Stutzke S. Saba Date: September 30, 2004