ML102010501

Draft Request for Additional Information

ML102010501
Person / Time
Site:	Hope Creek
Issue date:	07/20/2010
From:	Richard Ennis Plant Licensing Branch 1
To:	Chernoff H Plant Licensing Branch 1
Ennis R, NRR/DORL, 415-1420
References
TAC ME3597
Download: ML102010501 (8)

Text

July 20, 2010 MEMORANDUM TO:

Harold K. Chernoff, Chief Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation FROM:

Richard B. Ennis, Senior Project Manager /ra/

Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

SUBJECT:

HOPE CREEK GENERATING STATION, DRAFT REQUEST FOR ADDITIONAL INFORMATION (TAC NO. ME3597)

The attached draft request for additional information (RAI) was transmitted on July 20, 2010, to Mr. Jeff Keenan of PSEG Nuclear LLC (the licensee). This information was transmitted to facilitate an upcoming conference call in order to clarify the licensee=s amendment request for Hope Creek Generating Station dated March 29, 2010, as supplemented by letter dated May 28, 2010. The proposed amendment would revise the Technical Specifications to extend the allowed outage time for the A and B emergency diesel generators from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days.

This memorandum and the attachment do not convey or represent an NRC staff position regarding the licensees request.

Docket No. 50-354

Attachment:

Draft RAI

July 20, 2010 MEMORANDUM TO:

Harold K. Chernoff, Chief Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation FROM:

Richard B. Ennis, Senior Project Manager /ra/

Plant Licensing Branch I-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation

SUBJECT:

HOPE CREEK GENERATING STATION, DRAFT REQUEST FOR ADDITIONAL INFORMATION (TAC NO. ME3597)

The attached draft request for additional information (RAI) was transmitted on July 2019, 2010, to Mr. Jeff Keenan of PSEG Nuclear LLC (the licensee). This information was transmitted to facilitate an upcoming conference call in order to clarify the licensee=s amendment request for Hope Creek Generating Station dated March 29, 2010, as supplemented by letter dated May 28, 2010. The proposed amendment would revise the Technical Specifications to extend the allowed outage time for the A and B emergency diesel generators from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days.

This memorandum and the attachment do not convey or represent an NRC staff position regarding the licensee's request.

Docket No. 50-354

Attachment:

Draft RAI DISTRIBUTION PUBLIC AHowe, NRR/DRA/APLA LPL1-2 R/F GWaig, NRR/DIRS/ITSB RidsNrrDorlLpl1-2 Resource VGoel, NRR/DE/EEEB RidsNrrDorlDpr Resource RidsNrrPMREnnis Resource ACCESSION NO.: MLml102010501 OFFICE LPL1-2/PM NAME REnnis DATE 7/20/10 OFFICIAL RECORD COPY

DRAFT REQUEST FOR ADDITIONAL INFORMATION REGARDING PROPOSED LICENSE AMENDMENT EMERGENCY DIESEL GENERATORS A AND B ALLOWED OUTAGE TIME EXTENSION HOPE CREEK GENERATING STATION DOCKET NO. 50-354 By application dated March 29, 2010, as supplemented by letter dated May 28, 2010 (Agencywide Documents Access and Management System (ADAMS) Accession Nos.

ML100900458 and ML101590514, respectively), PSEG Nuclear LLC (the licensee) submitted a license amendment request for the Hope Creek Generating Station (HCGS). The proposed amendment would revise the Technical Specifications (TSs) to extend the allowed outage time (AOT) for the A and B emergency diesel generators (EDGs) from 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 14 days.

The Nuclear Regulatory Commission (NRC) staff has reviewed the information the licensee provided that supports the proposed amendment and would like to discuss the following issues to clarify the submittal.

1.

In Attachment 5 of the application dated March 29, 2010, the licensee has identified six regulatory commitments associated with this license amendment request. The commitments relate to compensatory actions which would be applicable during the extended AOT for the A and B EDGs. These compensatory actions would be incorporated into the TS Bases concurrent with implementation of the proposed amendment. The NRC staff requests the following information:

a. Commitment #1 requires verification of availability and operability of systems, subsystems, trains, components, and devices required to mitigate the consequences of an accident prior to removing an EDG for extended preventive maintenance. This is to be done through TSs, procedures, or detailed analyses.

1. What is the specific scope of plant equipment covered by this commitment?

2. Is this verification required only when it is planned to remove an EDG from service (as opposed to emergent failure of an EDG) for preventive maintenance, and is it only applicable when exceeding 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />? What about corrective maintenance or other inoperable causes?

3. If components in scope are covered by an existing TS limiting condition for operation (LCO), is meeting the LCO and action requirements considered adequate to satisfy the commitment, or does the LCO need to be met without reliance upon the action requirements? Why are these operability requirements not directly referenced in the TS action requirements for TS 3.8.1.1, rather than referring to the TS Bases and then to the LCOs?

Attachment

4. What components in the scope of this commitment (accident mitigation equipment) are not covered by the TSs and therefore may require procedural or detailed analyses to confirm availability?

5. If a component in the scope of this commitment subsequently becomes unavailable or inoperable during the extended outage period, what TS action is required?

6. Why is the term available and operable applied and how is this different than simply requiring a component to be operable?

7. It is not clear how detailed analyses are intended to be used to determine the operability/availability of components to satisfy this commitment. Describe under what conditions such analyses would be needed, and describe such analyses.

8. The commitment says Hope Creek should verify operability and availability; why isnt this more firmly worded since it is a commitment?

b. Commitment #2 requires positive measures to preclude testing or maintenance activities on the components in the scope of commitment #1 (this is assumed to be the meaning of these systems, ). Why isnt the commitment worded more directly, such as do not perform any voluntary testing or maintenance on otherwise operable components, rather than positive measure should be provided to preclude? What constitutes a positive measure? Under what conditions could testing or maintenance activities be initiated but remain within the intent of this commitment?

c. Commitment #3 requires the second EDG in the same mechanical division to be capable, operable and available?

1. How is capable, operable and available different than operable?

2. The existing TS 3.8.1.1 action e already provides a 2-hour completion time (CT) for the condition of two inoperable EDGs. It appears that this commitment would supercede this 2-hour CT and require an immediate shutdown. Is this a correct interpretation of this commitment? If not, please explain the intent of the commitment; if so, why is this not incorporated into required action e?

d. Commitment #4 requires minimizing removal of safety systems and important non-safety systems from service.

1. What is the scope of systems included in this commitment?

2. Explain how this commitment differs from commitments #1 and #2.

3. Offsite power sources are identified in this commitment; doesnt the existing TS 3.8.1.1 actions c and g already address offsite power sources while an EDG is inoperable?

4. What constitutes minimizing with regards to this commitment? Under what conditions, would these systems be permitted to be removed from service but remain within the intent of this commitment?

e. Commitment #5 requires avoiding testing or maintenance which increases the likelihood of a plant transient. What is the scope of this commitment and how is the determination made as to the likelihood of a plant transient? Specifically describe how the decision to initiate testing or maintenance during the extended EDG outage is more restrictive compared to such decisions when the EDG is operable.

f.

Commitment #5 further states that plant operation should be stable. How is this defined?

g. Commitment #6 recommends not voluntarily entering an extended outage when adverse weather is expected. What is the scope of adverse weather? What constitutes an expectation of severe weather (i.e., 10% probability at day 14 of a long range forecast)?

h. On page A-18 of Attachment 4 of the application dated March 29, 2010, four additional compensatory measures are identified related to fire risk results which do not appear in the commitment list. Are these intended to be implemented as commitments?

2.

TS 3.8.1.1 action g requires restoration of all alternating current (AC) sources in 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Describe how this required action is applied consistent with a 14-day CT for the EDGs. For example, if an extended CT is entered on one EDG, and subsequently action g is entered due to emergent failures, does the 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> CT in action g now supercede the 14-day CT?

3.

The fire probabilistic risk assessment (PRA) portion of the risk analysis is based on the Individual Plant Examination of External Events (IPEEE) fire evaluation, which has been updated to reflect some new data and practices. However, the models have not been assessed against the industry consensus standards, and no formal peer review has apparently been done.

a. Have there been any external reviews of the fire PRA since the IPEEE? If so, describe the scope and findings of the reviews and the resolution of the identified issues for this application.

b. What internal reviews have been done to the fire PRA since the IPEEE? Similarly describe the scope and findings of the reviews and the resolution of the identified issues for this application.

4.

The fire risk evaluation of the configuration of one EDG out of service has not been described in sufficient details in the application.

a. It is stated that only fires which cause a loss of offsite power are relevant to this application. With one EDG out of service, increased risk would result from reliance upon the remaining operable safety train of equipment in the event that offsite power is lost to the electrical bus normally powered by the unavailable EDG (i.e., not necessarily a total loss of offsite power). This can occur from either a total loss of offsite power or a loss of offsite power to the one electrical bus. Are both of these scenarios captured in the fire PRA used for this application?

b. As identified in Table 2-1 of Attachment 2 the supplemental dated May 28, 2010, fire scenarios may be screened below a threshold of 1E-6 per year core damage frequency (CDF). For a specific application like the analysis of risk for an EDG outage, some screened scenarios may become more significant. If screening of scenarios was performed for the baseline PRA, discuss the review of screened fire scenarios to assure that the configuration-specific risk is not underestimated.

c. Multiple spurious operations have been found to be potentially significant to fire risk, yet these are dispositioned for HCGS only by acknowledging that the treatment of this failure mode in the IPEEE was rudimentary, and then stating that hot shorts were considered for specific systems only. For this application, how has the licensee assured that a more comprehensive treatment of multiple spurious operations, given the current state of knowledge, would not significantly impact the risk results for fire?

d. The submittal dated May 28, 2010, states that no credit is taken for any suppression.

This seems to be unlikely, since it would mean that any fire precursor event would progress to a large engulfing fire. Clarify exactly how suppression is addressed in the fire PRA.

e. It is not clear if recovery of offsite power following loss due to fire effects is being credited in the analysis. Clarify how the PRA addresses post-fire repairs and recovery of plant equipment and offsite power supplies.

f.

One critical aspect of fire PRA development involves the physical location of cables.

One approach when the locations are mostly unknown employs an exclusion assumption, that cables are assumed to be located anywhere except where they are known not to be present. Some cable routing information may not be readily available, and assumptions as to the location of such cables may be made to simplify the data collection to support the PRA development. Are such assumptions employed in the HCGS PRA development? If so, describe and justify these assumptions, and characterize their significance to this specific application.

g. Describe any plant-specific features of the HCGS design related to detection, suppression, and mitigation of fires which are credited in the fire PRA. Examples of such items would be credit for water curtains, incipient detection, credit for prompt detection and/or suppression based on administrative controls, or other items that may be relevant to the risk analyses supporting this amendment request.

h. Describe how fire growth and propagation are treated in the HCGS fire PRA.

Specifically identify and justify any assumptions applied, and any fire modeling and codes used.

i.

Fires occurring in the main control room, or other plant areas, which can lead to evacuation of the control room (including evacuation due to loss of functionality, not necessarily habitability, especially for ex-Control Room fires), have sometimes been conservatively modeled in fire PRAs. This can mask the risk importance of out-of-service equipment if such fires are conservatively assumed to be unmitigatable. In addition, some plants only protect a single safety train of equipment for remote shutdown, so if a control room fire occurred during maintenance on that specific train of equipment, mitigation may not be available. It is assumed that a control room fire could cause a loss of power to a bus during the diesel generator outage. Identify and describe the impact of such fires on the configuration-specific risk analyses for the diesel generator outage configurations, addressing any conservatisms in assumptions, and impacts due to plant design of remote shutdown capability.

5.

The submittal identifies that based on a 14-day weather forecast; the frequency of loss of offsite power (LOOP) due to severe weather is reduced by 75%. Given the uncertainty of weather forecasting over extended periods, and since the licensee does not preclude the use of the 14-day extended CT for unplanned repairs, this reduction in frequency could be introducing a non-conservative bias in the risk results.

a. Identify the nominal LOOP frequency applied in the baseline PRA, and the reduced frequency used for this application, and describe how each of these frequencies were calculated. Justify the assumption of a 75% reduction in severe weather LOOP for a 14-day CT.

b. The offsite power recovery probability is directly dependent upon the cause of the loss of offsite power. Provide the baseline and analysis probabilities for offsite power recovery, and describe how the exclusion of 75% of the severe weather event frequency has been accounted for in the offsite power recovery probabilities.

c. Provide a sensitivity analysis for the risk results if the nominal loss of offsite power frequency and recovery probabilities are retained for the configuration-specific risk evaluation.

6.

Given a LOOP and failure of EDGs (station blackout), describe the assumptions for equipment credited in the PRA internal events model for continued core cooling. Include in your response any operator actions necessary, assumptions on environmental conditions given a station blackout, water inventories and makeup sources, and mission times. Does the PRA assume that core damage can be prevented even if AC power is not restored, or is offsite power recovery or diesel generator repair necessary?

7.

Considering that HCGS has four EDGs for a one unit plant, confirm the minimum number of EDGs that are required in each of following scenarios: (1) loss of offsite power (LOOP) concurrent with a loss-of-coolant accident (LOCA); (2) LOOP while operating at full power; and (3) plant in extended hot or cold shutdown condition. Provide details on the maximum loads that will be connected to each EDG in each of the above scenarios, assuming a single failure of an EDG.

8.

Provide the following information relating to the Alternate AC source, proposed as an additional compensatory measure by the licensee in its letter dated May 28, 2010:

a. A diagram which shows the connections between Salem Unit 3 Gas Turbine Generator (GTG) and the HCGS safety-related buses.

b. Confirm the estimated total time that will be required to enable the GTG to supply power to the HCGS safety-related buses from the onset of a LOOP condition, considering the various switching actions required.

c. Details on a previous occasion, if the GTG has been connected to supply HCGS safety-related buses.

d. Details on reliability of the GTG and frequency of maintenance activities performed on the GTG to ensure high reliability.

e. Considering the distance involved from Salem, confirm whether the GTG has been evaluated to ensure its capability to start and run large loads at the HCGS buses expected during a LOOP or station blackout (SBO). Discuss the capability of the GTG to cope with inrush currents associated with energization of large transformers during black start conditions.

f.

Confirm that the GTG is not credited in Salem design basis events including SBO.

9.

An AOT extension for 14 days for EDGs C and D was approved by the NRC on August 1, 1995. In the current license amendment request, the compensatory measures for the proposed AOT extension for EDGs A and B and the previously approved AOT extension for EDGs C and D are separately listed in the TS Bases. These compensatory measures should be combined into a common list. Also, based on some of the previously approved extension of AOTs, explain the licensees plans to implement the following additional compensatory measures:

a. Maintenance will not be performed in the switchyard that would challenge offsite power availability during the 14-day EDG AOT.

b. The system dispatcher will be contacted once per day and informed of the EDG status along with the power needs of the facility during the 14 day EDG AOT.

c. Maintenance will not be performed on the high-pressure core injection and the reactor core isolation cooling systems during the 14 day EDG AOT.

d. Operating crews will be briefed on the EDG work plan and procedural actions regarding LOOP and SBO.

e. Availability of the GTG will be checked before any EDG entering extended AOT (beyond 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />), and every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> thereafter.

10.

Explain the licensees plan to amend TS 3.8.1.1 to require compensatory measures to be in place before entering 14 days AOT, and verified once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, otherwise restore EDG to operable status within next 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />, not to exceed 14 days from discovery of failure to meet LCO.