ML052200553

Request for Additional Information Regarding Extended Allowable Outage Time for Inoperable Diesel Generator

ML052200553
Person / Time
Site:	Browns Ferry
Issue date:	08/30/2005
From:	Chernoff M NRC/NRR/DLPM/LPD2
To:	Singer K Tennessee Valley Authority
Chernoff, M H, NRR/DLPM, 301-415-4041
References
TAC MC5254
Download: ML052200553 (10)

Text

August 30, 2005 Mr. Karl E. Singer Chief Nuclear Officer and Executive Vice President Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801

SUBJECT:

BROWNS FERRY NUCLEAR PLANT, UNIT 1 - REQUEST FOR ADDITIONAL INFORMATION REGARDING EXTENDED ALLOWABLE OUTAGE TIME FOR INOPERABLE DIESEL GENERATOR (TAC NO. MC5254) (TS-426)

Dear Mr. Singer:

By letter dated December 6, 2004, Tennessee Valley Authority submitted a request for a Technical Specification change to extend the allowable outage time from 7 to 14 days for an inoperable diesel generator.

Based on our review of your submittal, the U. S. Nuclear Regulatory Commission (NRC) staff finds that a response to the enclosed request for additional information is needed before we can complete the review. As discussed with Mr. Joe McCarthy of your staff on August 8, 2005, the NRC staff requests a response within 60 days from the date of issuance of this letter.

If you have any questions, please contact me at (301) 415-4041.

Sincerely,

/RA/

Margaret H. Chernoff, Project Manager, Section 2 Project Directorate II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-259

Enclosure:

Request for Additional Information cc w/encl: See next page

ML052200553 NRR-088 OFFICE PDII-2/PM PDII-2/PM PDII-2/LA EEIBB/SC PDII-2/SC NAME EBrown MChernoff BClayton RJenkins by memo dated MMarshall DATE 8/11/05 8/12/05 8/10/05 5/03/05 8/30/05

Enclosure REQUEST FOR ADDITIONAL INFORMATION DIESEL GENERATORS ALLOWED OUTAGE TIME TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT, UNIT 1 DOCKET NO. 50-259

1. This submittal states, on page E1-1, that the proposed change to the emergency diesel generator (EDG) allowed outage time (AOT) for Browns Ferry Nuclear Plant (BFN) Unit 1 is based on the prior request and RAI [Request for Additional Information] responses for EDG AOT extension for Units 2 and 3. This submittal also states, on page E1-13, that the impact of returning Unit 1 to operational status would be discussed; however, no such discussion was provided. The Units 2 and 3 EDG AOT extension was based, in part, on the nonoperational status of Unit 1, and the availability of its EDGs to support Units 2 and 3.

Please provide the necessary information and additional analyses which demonstrate that the conclusions of the prior risk analyses for extending the EDG AOT from 7 days to 14 days for Units 2 and 3 remain valid given the return of Unit 1 to operation.

2. This submittal identifies, on page E1-16, a loss of offsite power (LOOP) frequency of 6.43E-3 per year for BFN, Unit 1, and that the value is based on generic industry data with a plant-specific Bayesian update. Given that Unit 1 has been nonoperational for a significant period, it is not clear how plant-specific data could be applicable. Please provide the following information:

a. Provide the details of the calculations of LOOP power frequencies applicable to the BFN probabilistic risk assessment (PRA) models, and for calculation of nonrecovery of offsite power, including the generic data source(s) and the plant-specific data, screening criteria applied to generic industry events, the time periods covered by the data, unit-specific differences or assumptions (if any), and how the non-operational status of Unit 1 was accounted in these calculations.

b. Typically, the PRA for multi-unit sites will distinguish between a site LOOP and a single unit LOOP, which impacts the required number of diesel generators (DGs) that must function, and provides different options to recover offsite power using operating units. Provide details regarding how the BFN PRA models address this issue, including the frequency of these initiating events, differences (if any) between the units with regards to unit LOOP frequency, differences in offsite power nonrecovery probabilities used for unit and site LOOP, and differences in success criteria for DGs.

c.

Discuss how the LOOP initiating event frequency and recovery probabilities reflect the Northeast blackout of August 2003.

d. Describe how the potential for LOOP given a non-LOOP initiating event (e.g.,

"consequential LOOP") is addressed in the BFN PRA models.

3. This submittal identifies, on page E1-24, that three of eight DGs are sufficient to achieve safe shutdown for an extended duration of LOOP. It is not clear if any three DGs are sufficient, or if asymmetries in support systems power supplies or other plant features would result in requiring specific combinations of DGs to successfully achieve safe shutdown for a particular unit. Further, the technical specifications only require operability of the four Unit 1 and 2 DGs, while the requirements for the Unit 3 DGs are only relevant to the standby gas treatment and control room emergency ventilation systems. Please provide information regarding the modeling of the DGs in the BFN PRAs (Regulatory Guide (RG) 1.177 - 2.3.3.1):

a. Identify the success criteria with regards to the specific DGs that can be credited for safe shutdown of each unit for a LOOP, and discuss any asymmetries in DG capabilities with regards to the ability to provide adequate power to safely shut down each unit.

b. If Unit 3 is shut down, one or more of its DGs may be removed from service for more than 14 days. Please discuss the administrative controls that assure availability of the Unit 3 DGs to support Units 1 and 2 during the extended AOT, and describe how the risk analyses account for multiple extended outages of the Unit 3 DGs when Unit 3 is out of service.

c.

A B level fact/observation DA-14 is identified in Reference 13 of the submittal, which deals with common cause failure modeling for the DGs. The resolution of this item did not address a technical basis for separating the Unit 3 DGs into a different population. Please discuss common cause failure modeling for the DGs, including the populations used across the eight DGs, probabilities of events modeled, and discuss how the potential for common cause failure modes is accounted in the risk calculations if the DG is removed from service under the proposed extended AOT for corrective maintenance.

d. Provide information regarding credit taken (if any) in the risk calculations for recovery of failed DGs, and how such recovery credit was adjusted for a DG assumed out of service under the extended AOT.

e. A B level fact/observation HR-17 is identified in Reference 13 of the submittal, which deals with a recovery action for aligning a swing residual heat removal service water (RHRSW) pump for cooling water for a distressed DG. The resolution of this item identified a change to the human error probability (HEP) from 5E-4 to 1.6E-2, and identified procedures applicable to this action. Please provide additional details regarding this recovery action:

i.

A qualitative description of this recovery action, including the specific failure modes and sequences for which the recovery is credited, and the operating conditions of the affected DG during the time period between cooling water failure(s) and restoration of cooling using the swing RHRSW pump.

ii.

The cues and time available for recovery, including the analyses which identify the time the DG can operate distressed due to cooling water prior to equipment failure.

iii. Plant-specific training and simulator experience that support the human reliability analysis calculations.

iv. Sensitivity analyses of this operator recovery action on the baseline PRA model and the specific risk analyses supporting this amendment request.

4. With regards to the success criteria used in the PRA for maintaining core cooling under station blackout conditions (i.e., failed DGs), please provide the following information (RG 1.177 2.3.1):

a.

A B level fact/observation TH-8 is identified in Reference 13 of the submittal, which deals with the plant response to station blackout. The resolution of this item is somewhat vague, in that it is not clear that the plant response is based on actual analyses or judgment, or what mission time is applicable (4, 6, and 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> are all identified). Please discuss the plant systems assumed to be capable of maintaining primary inventory and decay heat removal without any ac power available, their success criteria, including required mission times, and availability of monitoring and control instrumentation, their reliance upon site dc power sources, including the time available until battery depletion, and their functioning after battery depletion (if applicable).

b.

A B level fact/observation QU-11 is identified in Reference 13 of the submittal, which deals with the assumed availability of the main condenser for accident sequences that would make the condenser unavailable (i.e., LOOP). The resolution of this item simply states that main condenser availability is accounted for. Please confirm that for LOOP sequences, no credit is taken for the condenser as a heat sink.

c.

Identify operator actions required to respond to station blackout conditions (excluding offsite power recovery or recovery of onsite power), including the procedural basis for those actions, the probability of those actions in the PRA, and dependencies that are evaluated of those actions with power recovery actions.

d.

Three B level fact/observations HR-9, HR-9.1, and HR-12 are identified in Reference 13 of the submittal, which deal with a recovery action for venting containment during loss of all ac power scenarios. The resolution of these items identify (1) that 6.1E-3 is a screening value for the local actions needed to vent containment during blackout, and/or (2) that a new HEP of 1.43E-1 has been assigned. Please identify credit taken (if any) and the performance shaping factors considered for local actions for containment venting to maintain a reactor heat sink for long term station blackout sequences. Please also provide the results of any sensitivity analyses conducted on this operator recovery action.

5. Provide the results of any uncertainty and sensitivity studies on the DG assumed unavailability, LOOP frequency, offsite power recovery probabilities, station blackout mitigation success criteria, and any other key assumptions or sources of uncertainty relevant to the risk results supporting this amendment request. (RG 1.177 - 2.3.5)

6. The submittal does not identify the relationship between the configuration of BFN Unit 1 used as the basis for the risk calculations and the configuration of BFN Unit 1 that will exist when the plant is placed into service. Please provide identification and disposition of any plant changes (i.e., modifications or procedure changes) that are planned to be in place at startup, but which are not reflected in the PRA model used to support this amendment request. (RG 1.177-2.3.1)

7. Provide information regarding the scope and quality of the PRA used for the risk calculations with regards to internal fires and external events, since these items were not reviewed as part of the industry peer review. If internal flooding was not within the scope of the peer review conducted for BFN PRA models, please also discuss the scope and quality of that portion of the PRA as well. Please also discuss the integration of the internal and external events risk models. (RG 1.177 - 2.3.2)

8. A B level fact/observation QU-7 is identified in Reference 13 of the submittal which deals with the use of the saved sequence model for applications and its impact on risk importance measures, with symptoms of truncation effects identified. The resolution of this item identifies that an analysis of truncation effects was completed and documented.

However, the specific concerns identified on the truncation effects impact on importance measures in the base model were not dispositioned. The risk analyses supporting this amendment request appear to be based on the importance measures of the saved sequence model. Please provide additional information regarding how this item was corrected to eliminate truncation effects on the base model importance measures. Discuss the adequacy of the truncation level used to quantify the PRA model for this amendment request, specifically to address the use of the DG risk achievement worth for calculating the incremental conditional core damage probability instead of providing a quantification of the model with the DG out of service. Item QU-7 also identified model asymmetry as a limitation; please discuss model asymmetry as it impacts this amendment request.

(RG 1.177 - 2.3.4, A.1.3.1.1)

9. An A level fact/observation HR-26, and a similar B level fact/observation HR-27, are identified in Reference 13 of the submittal which deal with dependencies of multiple HEPs.

The resolution of this item identifies (1) that the dependencies were evaluated using a systematic approach, (2) revised HEPs were developed, and (3) the results were documented. Please provide additional information regarding the disposition of these items (RG 1.177-2.3.1):

a.

Discuss the systematic process used to identify dependent combinations.

b.

Identify the criteria applied to identify multiple actions as independent.

c.

Identify the lower limit (if any) to the overall HEP applied for a given sequence.

d.

Provide the disposition of the specific example cited in HR-26.

e.

Provide dependencies evaluated relevant to station blackout sequences, including the individual basic event probabilities and the final combined HEPs.

10. Section 4.2.1.3 of the submittal describes administrative controls applicable for scheduling maintenance, which is referenced as satisfying tier 3 requirements of RG 1.177. Please clarify the following aspects of these administrative controls as they apply to on-line maintenance (RG 1.177 - 2.3.1):

a. No limits are identified for configuration-specific instantaneous risk, only limits based on incremental core damage probability.

b. No evaluation of maintenance risk in terms of large early release frequency is identified.

c.

No criteria are identified for the risk threshold at which the various risk management actions would be taken.

d. No management involvement, except for senior management approval of risk management plans, is identified.

11. The submittal states (on page E1-29) that for the EDG AOT, no compensatory measures are required to avoid potential risk significant configurations. The submittal further states (on page E1-24) that certain pumps cannot be deliberately disabled for maintenance if certain EDGs are concurrently disabled. It is expected that EDG outages would be carefully planned and carried out to minimize the total outage duration and to take actions to minimize the risk impacts. Please clarify how the administrative controls for on-line maintenance would specifically be implemented for the EDG AOT, including management approvals, risk management plans, specific restrictions on maintenance of other components, and compensatory measures to reduce risk. (RG 1.177 - 2.3.1)

12. Since three out of eight DGs are sufficient to achieve safe shutdown following a LOOP, please clarify how many DGs can be considered as spare that can be substituted for an inoperable DG assuming LOOP in all units and one DG under maintenance in each unit.

13. Are there any restrictions as to how many DGs can be taken out for preplanned maintenance simultaneously at BFN site?

14. On page E1-7 of Enclosure 1 of the submittal, it is stated that the DGs are arranged such that four DGs provide standby power to Units 1 and 2, and four DGs are in standby service for Unit 3. Also, through use of 4-KV Shutdown Buses 1 and 2, and the 4-KV Bus Tie Board, any DG can be cross connected with any 4-KV Shutdown Board. In addition, these alignment actions can be performed from the control room for the Shutdown Buses or from an electrical board room for Bus Tie Board transfers. Please describe how long it takes to accomplish this cross connection (a) from control room for Shutdown Buses, and (b) from an electrical board room for Bus Tie Board transfers?

15. On page E1-12 of Enclosure 1 of the submittal, it is stated that each DG is required to maintain an unavailability factor of less than or equal to 0.0342, as monitored over a 24-month rolling interval. Please provide the basis for the required unavailability factor of 0.0342.

16. What type of formal agreements have been established between the control room operators and the transmission system operator (TSO)? Is the TSO notified in advance that a DG is going to be out for an extended period of time? Does the TSO notify the operator when the conditions of the grid are such that degraded voltage (i.e., below the Technical Specification requirements) could occur following a trip of the reactor unit?

17. With respect to compensatory measures, please describe your policy regarding discretionary maintenance on the switchyard, main and station service transformers.

18. Is any equipment that supports the stations physical security plan powered from the EDGs or otherwise affected by this requested Technical Specification change?

Mr. Karl W. Singer BROWNS FERRY NUCLEAR PLANT Tennessee Valley Authority cc:

Mr. Ashok S. Bhatnagar, Senior Vice President Nuclear Operations Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Mr. Larry S. Bryant, General Manager Nuclear Engineering Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Brian OGrady, Site Vice President Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609 Mr. Robert J. Beecken, Vice President Nuclear Support Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 General Counsel Tennessee Valley Authority ET 11A 400 West Summit Hill Drive Knoxville, TN 37902 Mr. John C. Fornicola, Manager Nuclear Assurance and Licensing Tennessee Valley Authority 6A Lookout Place 1101 Market Street Chattanooga, TN 37402-2801 Mr. Bruce Aukland, Plant Manager Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609 Mr. Jon R. Rupert, Vice President Browns Ferry Unit 1 Restart Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609 Mr. Robert G. Jones Browns Ferry Unit 1 Plant Restart Manager Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609 Mr. Scott M. Shaeffer Browns Ferry Unit 1 Project Engineer Division of Reactor Projects, Branch 6 U.S. Nuclear Regulatory Commission 61 Forsyth Street, SW.

Suite 23T85 Atlanta, GA 30303-8931 Mr. Glenn W. Morris, Manager Corporate Nuclear Licensing and Industry Affairs Tennessee Valley Authority 4X Blue Ridge 1101 Market Street Chattanooga, TN 37402-2801 Mr. William D. Crouch, Manager Licensing and Industry Affairs Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609 Senior Resident Inspector U.S. Nuclear Regulatory Commission Browns Ferry Nuclear Plant 10833 Shaw Road Athens, AL 35611-6970 State Health Officer Alabama Dept. of Public Health RSA Tower - Administration Suite 1552 P.O. Box 303017 Montgomery, AL 36130-3017 Chairman Limestone County Commission 310 West Washington Street Athens, AL 35611