ML12310A305
| ML12310A305 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 11/21/2012 |
| From: | Farideh Saba Plant Licensing Branch II |
| To: | Annacone M Carolina Power & Light Co |
| Billoch, Araceli | |
| References | |
| TAC ME8893, TAC ME8894 | |
| Download: ML12310A305 (9) | |
Text
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 November 21,2012 Mr. Michael J. Annacone, Vice President Brunswick Steam Electric Plant Carolina Power & Light Company Post Office Box 10429 Southport, North Carolina 28461 SUB~IECT:
BRUNSWICK STEAM ELECTRIC PLANT, UNITS 1 AND 2 - REQUEST FOR ADDITIONAL INFORMATION CONCERNING THE RISK EVALUATION FOR THE EMERGENCY DIESEL GENERATOR COMPLETION TIME EXTENSION FOR TECHNICAL SPECIFICATIONS 3.8.1 "AC SOURCES-OPERATING" (TAC NO. ME8893 AND ME8894)
Dear Mr. Annacone:
By letter to the U.S. Nuclear Regulatory Commission (NRC) dated June 19, 2012 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML12173A112),
Carolina Power & Light Company (the licensee) submitted a license amendment request (LAR) to Renewed Facility Operating License Nos. DPR-71 and DPR-62, for Brunswick Steam Electric Plant, Unit Nos. 1 and 2. The LAR proposed changes to Technical Specification (TS) 3.8.1 !lAC Sources-Operating," which would extend the TS Completion Time (CT) for an inoperable Emergency Diesel Generator from 7 days to 14 days, provided a supplemental power source is available during the CT extension period.
The NRC staff is reviewing the submittal and has determined that additional information is required to complete its evaluation. This request was discussed with Mr. William Murray of your staff on November 5, 2012; and it was agreed that a response to the enclosed request for additional information should be provided within 60 days from the date of this letter.
If you have any questions regarding this matter, I can be reached at 301-415-1447.
Sincerely, Farideh E. Saba, Senior Project Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-325 and 50-324
Enclosure:
Request for Additional Information cc w/encl: Distribution via Listserv
CAROLINA POWER & LIGHT COMPANY BRUNSWICK STEAM ELECTRIC PLANT UNIT NOS. 1 AND 2 REQUEST FOR ADDITIONAL INFORMATION REGARDING CHANGES TO TECHNICAL SPECIFICATIONS FOR EXTENSION OF COMPLETION TIME FOR EMERGENCY DIESEL GENERATORS DOCKET NOS. 50-325 AND 50-324 By letter to the U.S. Nuclear Regulatory Commission (NRC) dated June 19, 2012 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML12173A112),
Carolina Power & Light Company (the licensee) submitted a license amendment request (LAR) to Renewed Facility Operating License Nos. DPR-71 and DPR-62, for Brunswick Steam Electric Plant, Units 1 and 2. The LAR proposed changes to Technical Specification (TS) 3.8.1 "AC
[Alternate Current] Sources-Operating," which would extend the TS Completion Time (CT) for an inoperable Emergency Diesel Generator (EDG) from 7 days to 14 days, provided a supplemental power source is available during the CT extension period. The NRC staff finds that additional information is needed to complete its review.
Request for Additional Information (RAls):
- 1.
Provide a legible copy of the Brunswick Key One Line Diagram showing 230 kV, 24 kV and 4160 V Systems (the copy of the diagram currently available with the NRC staff is not legible).
- 2.
The licensee stated in the LAR, Enclosure 1, page 12, that two 200 kilo Watts (kW), 480 volts M alternating currents 60 hertz diesel generators, referenced as severe accident management alternative (SAMA) diesel generators, are available to supply the blackout unit battery chargers if AC power cannot be restored to any emergency bus of the blackout unit (i.e., if the crosstie is not possible).
Provide one-line drawing(s) showing the SAMA diesel generators' connection to the electrical distribution buses.
- 3.
The licensee stated in the LAR, Enclosure 1, page 14, that the supplemental diesel generator (SUPP-DG) electrical system will be provided with metering and protective relaying at the SUPP-DG output breaker and the new BOP
[Balance-of-Plant] Bus switchgears.
Describe and provide a copy of the metering and protective relaying design for the SUPP-DG and the new BOP Bus switchgears. Also, describe measures, which will be taken to maintain electrical separation between the two trains of BOP buses to which the SUPP-DG can be connected.
- 2
- 4.
The licensee stated in the LAR, Enclosure 1, page 13, that the SUPP-DG will be of commercial-grade type, non Class 1 E, permanently-installed inside the plant protected area, and outside the existing power block building; east of the switchyard and north of the transformer yard.
Provide a plant physical drawing showing the proposed physical location of major components of the SUPP-DG, such as the diesel enclosure, electrical enclosure, mechanical enclosure, radiator, fuel storage tank, and refill station for the tank.
- 5.
The licensee stated in the LAR, Enclosure 1, page 15, that the electrical enclosure will house the SUPP-DG output breaker switchgear, engine/generator control panel, 125 V direct current (DC) battery system with battery charger, 4160:480 V auxiliary power transformer, 480 V automatic transfer switch, and 480 V motor control center.
Provide one line diagram of the above AC and DC electrical equipment to be located in the Electrical Enclosure.
- 6.
The licensee stated in the LAR, Enclosure 1, page 15, that the fuel storage tank can be replenished via a refill station for the tank.
Provide details of refill station such as the source of fuel for the refill station, and the source of any power supply needed at the refill station including a brief description of procedures used to replenish the tank.
- 7.
Justify why the regulatory commitments for the following additional compensatory actions as recommended in the NRC Branch Technical Position (BTP) 8-8 have not been provided:
- a.
The system load dispatcher will be contacted once per day to ensure no significant grid perturbations (high grid loading unable to withstand a single contingency of line or generation outage) are expected during the extended CT, and
- b.
TS required systems, subsystems, trains, components, and devices that depend on the remaining power sources will be verified to be operable and positive measures will be provided to preclude subsequent testing or maintenance activities on these systems, subsystems, trains,components, and devices.
- 8.
The licensee stated in the LAR, Enclosure 1, pqge 14, that the time required to enable the SUPP-DG to supply power to any Electrical-Bus is within one hour from the station blackout (SBO) event.
Confirm that a coping analysis has been performed which shows that the SBO unit can remain in a safe shutdown condition without any AC power for the first hour of the SBO event.
- 3
- 9.
According to BTP Page 8-8-6, although the extended CT is allowed for pre-planned maintenance activities, it could be used for corrective maintenance on a limited bases. Confirm that the licensee will continue to meet the maintenance rule availability/reliability requirements, the reactor oversight process performance indicator criteria for availability/reliability, and the EDG target reliability criterion of 0.975.
- 10.
The submittal indicates that a full-scope peer review was performed in 2010 for the internal probabilistic risk assessment (PRA) events. The LAR also indicates that the PRA model has been revised periodically and some of these revisions included changes to address findings from the past peer reviews.
- a.
Identify any changes made to the internal events PRA since the last full-scope peer review of the internal events PRA that are consistent with the definition of a "PRA upgrade" in ASME/ANS-RA-Sa-2009, as endorsed by Regulatory Guide 1.200.
- b.
Provide all findings and observations from the last independent peer review. Also, please describe how each finding was dispositioned for this application.
- c.
If any changes, since the independent peer review, are characterized as a PRA upgrade, please identify if a focused-scope peer review was performed for these changes consistent with the guidance in ASME/ANS-RA-Sa-2009, as endorsed by Regulatory Guide 1.200, and describe any findings from that focused-scope peer review and the resolution of these findings for this application.
- d.
If a focused-scope peer review has not been performed for changes characterized as a PRA upgrade, please describe what actions will be implemented to address this review deficiency and when the application will be supplemented to describe any findings from that focused-scope peer review and the resolution of these findings for this application.
- 11., page 8, of the LAR provides a description of the changes made to the base PRA model to account for a SUPP-DG and 14 day completion time.
The submittal indicates that a new test and maintenance (T&M) interval was added for each DG while maintaining the existing T&M event. The submittal states this represents "14 additional days of unavailability." The NRC staff requests further clarification regarding how many days of unavailability are modeled in the base PRA and what time frames are used calculate the delta core damage frequency (CDF).
- 12., page 1, of the LAR indicates that the 2010 peer review found supporting requirement (SR) IE-A5 was not met because a systematic evaluation was not performed for systems other than mitigating systems to assess the possibility of an initiating event occurring. Provide a more comprehensive list of additional systems and support systems evaluated to determine initiating event occurrences.
-4
- 13., page 3, of the LAR indicates SRs HE-E3 and HE-E4 are not Capability Category (CC) II due to lack of evidence of detailed operator interviews. For this application, a new operator action is added to reflect the actions necessary to start and align the SUPP-DG to the applicable emergency bus. Five related critical operator actions are listed in Enclosure 4. page 10.
Provide a brief summary of operator interviews and input gained from site operations to assess these operator actions.
- 14.. page 5, of the LAR indicates SR DA-C8 is not CCII because of the methodology used to characterize system standby times. CCII requires plant-specific operational records to determine time that components are configured in their standby status. The licensee provides a brief statement in the LAR stating that an investigation determined the results gained from the estimates are realistic. Provide the plant-specific basis used to estimate the standby times for DGs.
- 15.. page 7. of the LAR indicates SR QU-D1 is not met because the licensee failed to properly review a sample of Significant cutsets. Calrify how the review was improved and how many CDF and large early release frequency (LERF) cutsets were analyzed.
- 16., page 7, of the LAR indicates SR QU-D4 is not met because the licensee failed to identify causes for significant differences in results to other similar plants. The licensee states that the model is revised to include an enhanced similar plant review. Provide any significant differences found during this review associated with cutsets related to DGs.
- 17., page 9, of the LAR indicates SR LE-E1 is met; however, the finding suggests that offsite power (aSP) recovery values are not consistent with the current asp recovery curve. The licensee states that the asp curves and component failures are now updated. Provide an assessment that shows asp recovery values are consistent between Level 1 and 2 data.
- 18., page 10. of the LAR lists twenty six internal flooding supporting requirements as not met to CCI and each of these findings is dispositioned by the licensee as resolved. Enclosure 5, in response to peer review findings, notes that significant flooding scenarios were examined for realism and some adjustments were made based upon material of piping and design attributes. As highlighted in the previous RAI, the licensee should address if those examination and adjustments made to the internal flooding model constitutes a PRA upgrade. If a PRA upgrade is warranted, provide the NRC staff with the results of a focused-scope peer review for the internal flooding PRA. Otherwise. address each internal flooding finding more specifically than the generic disposition provided in the LAR since the staff cannot make a determination on the adequacy of the internal flooding PRA model based on the information provided.
- 19.. page 15, of the LAR notes an elevated foundation to protect the SUPP-DG system from flood and storm surge. Provide the height of the elevation
- 5 and the determination used to establish this value such as historical flood records or calculated estimates.
- 20., page 83, of the LAR lists examples by the peer review of omitted justifications for several partitioning elements that lack fire resistance rating. If applicable, provide justification or clarification for partitioned elements that lack fire resistance rating for fire areas that involve DGs or the supplemental DG.
- 21., page 48, of the LAR states that the Fire PRA model does not include mapping of initiating events to specific equipment such as loss of DC power and offsite power. The peer review further notes that review of loss of offsite power (LOOP) logic indicates several locations where consequential LOOP was not included. The licensee's assessment found that all initiating events had been adequately addressed except for fire induced LOOP and therefore logic for fire induced LOOP was added to the fault tree where appropriate. Provide the tracing performed to identify the equipment affected due to fire-induced loss of DC power. In addition, further describe the fault tree logic added to the model to address fire induced LOOP and consequential LOOP.
- 22., page 53, of the LAR indicates the licensee performed an evaluation to update realistic transient combustibles heat release rate (HRR) for various locations including the DG building. The results of this evaluation indicate that in some areas the use of the 143 kW HRR (98%) fire for these areas were determined to be realistic and bounding HRR. The submittal further notes that other areas have no impact on the application as either administrative controls limiting transient combustibles, or specific analysis 'will be' performed. Provide confirmation that the indicated analysis for the DG building has been performed and verify if risk significant targets were impacted by the higher HRR transient scenarios.
- 23.
Tier 2 evaluations are used to identify high risk equipment that could exist if they are taken out of service along with the equipment involved in the TS change., page 22, ranks the risk achievement worth of a range of equipment based on having DG 2 in extended maintenance. The remaining DGs are assumed operational during the maintenance period for one DG. Does this application request extended maintenance for concurrent DG failures. Provide a brief summary of procedures for common cause failure of two or more DGs.
- 24.
Describe how your evaluation includes the possible increase in HRR caused by the spread of a fire from the ignition source to other combustibles. Summarize how suppression is included in your evaluation.
- 25.
Transient fires should at a minimum be placed in locations within the plant physical analysis units (PAUs) where conditional core damage probability are highest for that PAU, i.e., at "pinch points." Pinch points include locations of redundant trains or the vicinity of other potentially risk-relevant equipment, including the cabling associated with each. Transient fires should be placed at all appropriate locations in a PAU where they can threaten pinch points. Hot work should be assumed to occur in locations where hot work is a possibility, even if
- 6 improbable (but not impossible), keeping in mind the same philosophy. Describe how transient and hot work fires are distributed within the PAUs at your plant. In particular, identify the criteria for your plant which determine where an ignition source is placed within the PAUs. Also, if you have areas within a PAU where no transient or hot work fires are located since those areas are considered inaccessible, define the criteria used to define "inaccessible." Note that an inaccessible area is not the same as a location where fire is simply unlikely, even if highly improbable.
- 26.
Discuss the calculation of the frequencies of transient and hot work fires.
Characterize your use of the influence factors for maintenance, occupancy, and storage, noting if the rating "3" is the most common, as it is intended to be representative of the "typical" weight for each influence factor. It is expected that the influence factor for each location bin associated with transient or hot work fires will utilize a range of influence factors about the rating "3," including the maximum 10 (or 50 for maintenance) and, if appropriate, even the rating "0."
Note that no PAU may have a combined weight of zero unless it is physically inaccessible, administrative controls notwithstanding. In assigning influence factor ratings, those factors for the Control/Auxiliary/Reactor Building are distinct from the turbine building; thus, the influence factor ratings for each location bin are to be viewed according to the bin itself.
- 27.
If you have used any influence factors outside of the values identified in Table 6-3 of NUREG/CR-6850, identify the values used, identify the PAUs that use these factors, and justify the assigned factor(s).
- 28.
Section 10 of NUREG/CR-6850 Supplement 1 states that a sensitivity analysis should be performed when using the fire ignition frequencies in the Supplement instead of the fire ignition frequencies provided in Table 6-1 of NUREG/CR-6850.
Provide the sensitivity analysis of the impact on using the Supplement 1 frequencies instead of the Table 6-1 frequencies on CDF, large early release frequency (LERF), ~CDF, and ~LERF for all of those bins that are characterized by an alpha that is less than or equal to one. If the sensitivity analysis indicates that the change in risk acceptance guidelines would be exceeded using the values in Table 6-1, please justify not meeting the guidelines.
- 29.
Please describe how CDF and LERF are estimated in main control room (MCR) abandonment scenarios. Do any fires outside of the MCR cause MCR abandonment because of loss of control and/or loss of control room habitability?
Are "screening" values for post MCR abandonment used (e.g., conditional core damage probability of failure to successfully switch control to the Primary Control Station and achieve safe shutdown of 0.1) or have detailed human error analyses been completed for this activity. Please justify any screening value used.
- 30.
It was recently stated at the industry fire forum that the Phenomena Identification and Ranking Table Panel being conducted for the circuit failure tests from the DESIREE-FIRE and CAROL-FIRE tests may be eliminating the credit for Control Power Transformers (CPTs) (about a factor 2 reduction) currently allowed by Tables 10-1 and 10-3 of NUREG/CR-6850, Vol. 2, as being invalid when
-7 estimating circuit failure probabilities. Provide a sensitivity analysis that removes this CPT credit from the PRA and provide new results that show the impact of this potential change on CDF, LERF, t:.CDF, and t:.LERF. If the sensitivity analysis indicates that the change in risk acceptance guidelines would be exceeded after eliminating CPT credit, please justify not meeting the guidelines.
- 31.
Did the peer reviews for both the internal events and fire PRAs consider the clarifications and qualifications from Regulatory Guide (RG) 1.200, Revision 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," March 2009 (ADAMS Accession No. ML090410014) to the ASME/AMS PRA Standard? If not, provide a self-assessment of the PRA model for the RG 1.200 clarifications and qualifications and indicate how any identified gaps were dispositioned.
- 32.
Sufficient level of information on the fire PRA will be needed for performing the review of the fire PRA for the application. This includes identification and technical justification of any unreviewed analysis methods (UAMs), as well as a description of other method differences from NUREG/CR-6850 (as supplemented) or the National Fire Protection Association Standard 805, "Performance Based Standard for Fire Protection for Light Water Reactor Electric Generating Plants," (NFPA-805) frequently asked question guidance, and their significance for the application. If a position on a previous UAM has been established on a method by the NRC, confirm that the accepted version of the UAM is used per the NRC position and, if not, then provide a revised analysis and results using an accepted approach.
November 21,2012 Mr. Michael J. Annacone, Vice President Brunswick Steam Electric Plant Carolina Power &Light Company Post Office Box 10429 Southport, North Carolina 28461
SUBJECT:
BRUNSWICK STEAM ELECTRIC PLANT, UNITS 1 AND 2 - REQUEST FOR ADDITIONAL INFORMATION CONCERNING THE RISK EVALUATION FOR THE EMERGENCY DIESEL GENERATOR COMPLETION TIME EXTENSION FOR TECHNICAL SPECIFICATIONS 3.8.1 "AC SOURCES-OPERATING" (TAC NO. IVIE8893 AND ME8894)
Dear Mr. Annacone:
By letter to the U.S. Nuclear Regulatory Commission (NRC) dated June 19, 2012 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML12173A112),
Carolina Power & Light Company (the licensee) submitted a license amendment request (LAR) to Renewed Facility Operating License Nos. DPR-71 and DPR-62, for Brunswick Steam Electric Plant, Unit Nos. 1 and 2. The LAR proposed changes to Technical Specification (TS) 3.8.1 "AC Sources-Operating," which would extend the TS Completion Time (CT) for an inoperable Emergency Diesel Generator from 7 days to 14 days, provided a supplemental power source is available during the CT extension period.
The NRC staff is reviewing the submittal and has determined that additional information is required to complete its evaluation. This request was discussed with Mr. William Murray of your staff on November 5,2012; and it was agreed that a response to the enclosed request for additional information should be provided within 60 days from the date of this letter.
If you have any questions regarding this matter, I can be reached at 301-415-1447.
Sincerely, IRA!
Farideh E. Saba, Senior Project Manager Plant Licensing Branch 11-2 Division of Operating Reactor Licensing Office of Nuclear Reactor Regulation Docket Nos. 50-325 and 50-324
Enclosure:
Request for Additional Information cc w/encl: Distribution via Listserv DISTRIBUTION:
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