BSEP 13-0099, Response to NRC Request for Additional Information Regarding Diesel Generator (DG) Completion Time (CT) Extension for Technical Specification(Ts) 3.8.1, AC Sources - Operating
| ML13260A252 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 08/29/2013 |
| From: | Hamrick G Duke Energy Carolinas |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| BSEP 13-0099, TAC ME8893, TAC ME8894 | |
| Download: ML13260A252 (9) | |
Text
George T. Hamrick SODUKED K Vice President ENERGY.
Brunswick Nuclear Plant P.O. Box 10429 Southport, NC 28461 o: 910.457.3698 August 29, 2013 Serial: BSEP 13-0099 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001
Subject:
Brunswick Steam Electric Plant, Unit Nos. 1 and 2 Renewed Facility Operating License Nos. DPR-71 and DPR-62 Docket Nos. 50-325 and 50-324 Response to NRC Request for Additional Information Regarding Diesel Generator (DG) Completion Time (CT) Extension for Technical Specification (TS) 3.8.1, "AC Sources - Operating"
References:
- 1. Letter from M. Annacone (Carolina Power & Light Company) to the U.S.
Nuclear Regulatory Commission, Requests for License Amendments - Diesel Generator (DG) Completion Time (CT) Extension for Technical Specification (TS) 3.8.1, "AC Sources - Operating," dated June 19, 2012, ADAMS Accession Number ML12173A112
- 2. Letter from Christopher Gratton (U.S. Nuclear Regulatory Commission), to George T. Hamrick (Carolina Power & Light Company), Request for Additional Information Regarding Request for Diesel Generator Completion Time Extension (TAC Nos. ME8893 and ME8894), dated July 10, 2013, ADAMS Accession Number ML13175A347 Ladies and Gentlemen:
By [[letter::BSEP 12-0050, Request for License Amendments - Diesel Generator (DG) Completion Time (CT) Extension for Technical Specification (TS) 3.8.1, AC Sources - Operating|letter dated June 19, 2012]] (i.e., Reference 1), Duke Energy Progress, Inc., formerly known as Carolina Power & Light Company (CP&L), submitted a license amendment request to revise the Technical Specifications (TS) for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2. The proposed revision extends the Completion Time (CT) of TS 3.8.1 Required Action D.4 for an inoperable diesel generator (DG). A commensurate change is also proposed to extend the maximum Completion Time of TS 3.8.1 Required Actions C.3 and D.4. BSEP proposed the addition of a supplemental AC power source (i.e., a supplemental diesel generator).
On July 10, 2013 (i.e., Reference 2), the NRC provided a request for additional information (RAI) regarding the license amendment request. The response to this RAI in included in the enclosure to this letter.
This document contains no new regulatory commitments.
Please refer any questions regarding this submittal to Mr. Lee Grzeck, Manager - Regulatory Affairs, at (910) 457-2487.
A)9 1
U.S. Nuclear Regulatory Commission Page 2 of 3 I declare, under penalty of perjury, that the foregoing is true and correct. Executed on August 29, 2013.
Sincerely, eorg T.Hmrick
Enclosure:
Response to Request for Additional Information Regarding Request for Diesel Generator Completion Time Extension
U.S. Nuclear Regulatory Commission Page 3 of 3 MAT/mat cc (with enclosure):
U. S. Nuclear Regulatory Commission, Region II ATTN: Mr. Victor M. McCree, Regional Administrator 245 Peachtree Center Ave, NE, Suite 1200 Atlanta, GA 30303-1257 U. S. Nuclear Regulatory Commission ATTN: Mr. Christopher Gratton (Mail Stop OWFN 8G9A) 11555 Rockville Pike Rockville, MD 20852-2738 U. S. Nuclear Regulatory Commission ATTN: Ms. Michelle P. Catts, NRC Senior Resident Inspector 8470 River Road Southport, NC 28461-8869 Chair - North Carolina Utilities Commission P.O. Box 29510 Raleigh, NC 27626-0510 Mr. W. Lee Cox, Ill, Section Chief (Electronic Copy Only)
Radiation Protection Section North Carolina Department of Health and Human Services 1645 Mail Service Center Raleigh, NC 27699-1645 lee.cox@dhhs.nc.gov
Enclosure Page 1 of 6 Response to Request for Additional Information Regarding Request for Diesel Generator Completion Time Extension By [[letter::BSEP 12-0050, Request for License Amendments - Diesel Generator (DG) Completion Time (CT) Extension for Technical Specification (TS) 3.8.1, AC Sources - Operating|letter dated June 19, 2012]], Duke Energy Progress, Inc., formerly known as Carolina Power & Light Company (CP&L), submitted a license amendment request (LAR) to revise the Technical Specifications (TS) for the Brunswick Steam Electric Plant (BSEP), Unit Nos. 1 and 2.
The proposed revision extends the Completion Time (CT) of TS 3.8.1 Required Action D.4 for an inoperable diesel generator (DG). A commensurate change is also proposed to extend the maximum Completion Time of TS 3.8.1 Required Actions C.3 and D.4. BSEP proposed the addition of a supplemental AC power source (i.e., a supplemental diesel generator).
On July 10, 2013, the NRC provided a request for additional information (RAI) regarding the license amendment request. Duke Energy's response to this RAI is provided below.
RAI 1
Regulatory Guide (RG) 1.200, Rev 2, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," states that results used to support a risk-informed application should be derived from a probabilistic risk assessment (PRA) model that represents the as-designed, as-built, as-operated plant to the extent needed to support the application. Clarify whether the PRA model of record accurately reflects plant changes associated with the BSEP extended power uprate, including but not limited to modifications to the standby liquid control system, updates to sequence timing, and human error probabilities.
Response
The PRA model of record accurately reflects changes made to the plant due to the extended power uprate of 2003. Brunswick's success criteria calculation (i.e., BNP-PSA-033, Revision 5) and Accident Sequence Calculation (i.e., BNP-PSA-029, Revisions 7) discuss the success criteria and accident sequence changes to the model due to the extended power uprate including the required number of Standby Liquid Control trains. The sequence timing contained in those calculations are supported by Modular Accident Analysis Program (MAAP) results (i.e., BNP-PSA-068, Revision 2), which incorporated the extended power uprate. Timing for human error probability was derived by conducting operator interviews and Anticipated Transient Without Scram sequence simulations as documented in the human reliability calculation (i.e., BNP-PSA-034, Revision 12).
RAI 2
A heat release rate (HRR) associated with motor fires (69 kilowatt (kW)) was used for pump electrical fires rather than the pump electrical HRR of 211 kW that is specified by Table G-1 in NUREG/CR-6850, "Fire PRA Methodology for Nuclear Power Facilities." Given that a 211 kW fire would have a larger zone of influence (and thus, potentially new targets), provide a justification as to why the choice of HRR would not be expected to impact the change in risk associated with the proposed diesel generator (DG) completion time extension. Alternatively, provide a sensitivity study that shows the impact on change in core damage frequency (ACDF),
change in large early release frequency (ALERF), incremental conditional core damage probability (ICCDP), and incremental conditional large early release probability (ICLERP) of using the NUREG/CR-6850-recommended HRR of 211 kW.
Enclosure Page 2 of 6
Response
The choice of HRR does not impact the change in risk associated with the proposed DG completion time extension based on an evaluation performed in support of BSEP's National Fire Protection Association (NFPA) 805 license amendment request (LAR) (i.e., submitted on September 25, 2012, ADAMS Accession Number ML12285A428, and supplemented on December 17, 2012, ADAMS Accession Number ML12362A284) and showed no measurable change in CDF or LERF.
As described in Change Package BNP-0267, 199 pumps were subjected to a combination of plant walkdowns and drawing reviews, where access was not possible, using the expanded Zone of Influence (ZOI) for a 211 kW HRR rather than the ZOI for 69 kW HRR. For thermoset cables, the difference in the ZOI is less than 2 feet horizontally and 4 feet vertically. New targets (i.e., raceways) were identified for 113 pumps; however, these new targets translated to new failed basic events in the Fire PRA for only the following 13 pumps:
FC266_6503 2-FP-P1 - DIESEL FIRE PUMP P1 FC269 1011, 1-E11-CO02A-RHR PUMP 1A FC269_1012, 1-E11-CO02C - RHR PUMP 1C FC280_1101, 1-E11-CO01B - NODE NCl: RHR SW BOOSTER PUMP 1B FC280 1103, 1-Eli-Co01 D - NODE NC3: RHR SW BOOSTER PUMP 1 D FC289 1107, 1-C41-CO01A - NODE PW5: STANDBY LIQUID CONTROL PUMP 1A FC294 1008 1-E41-C002-AUX-OIL-PMP - NODE PM2: HPCI TURB AUX OIL PUMP FC318_2014, 2-E 11-CO02A - NODE NC6: RHR PUMP 2A FC318 2016, 2-El l-CO02C - NODE NC8: RHR PUMP 2C FC329 2123, 2-El 1-CO01C - NODE NC2: RHR SERVICE WATER BOOSTER PUMP 2C FC329 2124, 2-El 1-C001D - NODE NC3: RHR SERVICE WATER BOOSTER PUMP 2D FC344_2013, 2-E41-C002-AUX-OIL-PMP - NODE PM2: HPCI TURBINE AUX OIL PUMP FC367_7620, l-G16-C022 - 1A CONDENSATE BACKWASH TRANSFER PUMP For only two pumps were there more than four new failed basic events, counting all impacted failure modes for every affected piece of equipment. Consequently, the sensitivity study indicated no measureable change in CDF or LERF. An inspection of those results identified no unique vulnerability that would suggest any different conclusion for the DG completion time extension.
From a physical perspective, the results are reasonable since: (1) some minimum unobstructed space is necessary for normal pump maintenance and (2) raceways in the immediate vicinity are most likely those necessary to support the pump itself.
RAI3 Section 2.3 of RG 1.177, Rev 1, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications," provides guidance on calculating ICCDP and ICLERP. Please clarify whether the method described by the RG was applied consistently to all hazard groups. For example, Enclosure 4, Section 4.6.2 of the License Amendment Request (LAR) quantifies the risk due to seismic hazards as follows:
Enclosure Page 3 of 6 ICCDP = ACDF x d Where:
ACDF = [Seismic core damage frequency with completion time extension] - [Seismic core damage frequency without completion time extension]
d = Duration of exposure time = completion extension time = 14 days Bounding values are provided in Enclosure 4, Table A4-6 of the LAR:
ACDF (yr')
Duration ICCDP (yr"1)
Seismic 3.4E-07 2.4E-06 2.1E-06 14 days =
8E-08 (Unit 1,
.038 years
This does not appear to be consistent with the approach used for internal events, internal flood, high winds, external flood, and internal fires as shown in Enclosure 4, Table A4-3 of the license amendment request (LAR):
ACDF (yr')
Duration ICCDP (yr"1)
Internal 1.4E-05 (not 5.7E-07 (not 1.5E-07 Events provided) provided)
Calculating ICCDP in the same manner as for seismic would yield:
5.7 E-07 yr-1 x.038 yrs = 2.2 E-8 This does not equal the ICCDP value shown in Table A4-3 of the LAR.
Calculating ICCDP in the same manner as for seismic would yield:
2.8 E-07 yr-1 x.038 yrs = 1.1 E-8 This does not equal the ICCDP value shown in Table A4-16 of the LAR.
If ACDF, ALERF, ICCDP, and ICLERP were calculated in different ways for different hazard groups, please clarify whether this was done in accordance with the aforementioned RG 1.177 guidance. If not, provide a justification for why comparison with the acceptance guidelines in
Enclosure Page 4 of 6 RG 1.177 and RG 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," would not be impacted for this application.
Response
The method described in Section 2.3 of RG 1.177, Revision 1, for calculating ICCDP and ICLERP was consistently applied to all hazard groups, except for seismic. A bounding seismic risk was evaluated using a combination of quantitative and qualitative risk assessments to show it would not affect the decision consistent with RG 1.174 and RG 1.177. Otherwise, ICCDP (i.e.,
or ICLERP) was calculated as the product of the proposed Completion Time and the difference between the conditional CDF (i.e., or conditional LERF), with the diesel generator out of service, and the baseline CDF (i.e., or baseline LERF). However, the ACDF/ALERF values listed in Table A4-3 and the ICCDP/ICLERP values listed in Table A4-4 were provided for comparison to the acceptance guidance of RG 1.174 and RG 1.177, respectively, but were not intended to permit either to be calculated from the other. The following tables provide clarification of where appropriate information is located in Enclosure 4 to the BSEP DG Completion Time LAR for comparison to the acceptance guidance of RG 1.174 and RG 1.177.
Base CDFILERF (Iyr) for Comparison With Acceptance Guidance in RG 1.174 BSEP DG Completion Time LAR HAZARD Unit 1 Unit 2 Reference CDF LERF CDF LERF Internal Events Table A4-16/17, Unit 1/2 Initial CDF/LERF Internal Flood 1.4E-05 6.2E-07 1.4E-05 6.2E-07 (non-fire, no AOT)
External Flood High Winds Table A4-16/17, Unit 1/2 Initial CDF/LERF I
(fre nAO)Internal Fire1 2.7E-05 3.1E-06 2.6E-05 1.9E-06 (fire, no AOT)
Table A4-6 Base CDF / Table A4-7 Base LERF Seismic (SSE) 6.2E-08 8.7E-10 6.5E-08 8.7E-10 Table A4-8 Base CDF / Table A4-9 Base LERF Seismic (OBE) 3.4E-07 4.9E-09 3.5E-07 4.9E-09 Table A4-16/17, Total Unit 1/2 CDF/LERF Total 4.2E-05 3.7E-06 4.1E-05 2.5E-06 Includes Main Control Room Abandonment ACDF/ALERF (/yr) for Comparison With Acceptance Guidance in RG 1.174 BSEP DG Completion Time LAR HAZARD Unit 1 Unit 2 Reference ACDF ALERF ACDF ALERF Internal Events Table A4-16/17, Unit 1/2 Delta CDF/LERF Internal Flood (non-fire, AOT)
External Flood 5.7E-07 3.8E-09 5.6E-07 3.7E-09 Table A4-3 Etra lo High Winds Table A4-16/17, Unit 1/2 Delta CDF/LERF (fire, AOT)
Internal Fire 2.8E-07 1.OE-09 2.7E-07 2.5E-09 Table A4-3 4.6.3 Seismic
__Neg.
Neg.__e__Ne.
Table A4-16/17, Total Unit 1/2 Delta CDF/LERF Total 8.5E-07 4.8E-09 8.3E-07 6.2E-09 Table A4-3 Negligible
Enclosure Page 5 of 6 ICCDP/ICLERP for Comparison With Acceptance Guidance in RG 1.177 BSEP DG Completion Time LAR HAZARD Unit 1 Unit 2 Reference ICCDP ICLERP ICCDP ICLERP Internal Events Table A4-16/17, Unit 1/2 ICCDP/ICLERP Internal Flood (non-fire)
External Flood 1.5E-07 1.OE-09 1.4E-07 1.OE-09 Table A4-4 Etra lo High Winds Table A4-16/17, Unit 1/2 ICCDP/ICLERP (fire)
Internal Fire 2.8E-07 1.OE-09 2.7E-07 2.5E-09 Table A4-4 Table A4-16/17, Unit 1/2 ICCDP/ICLERP Total 4.3E-07 2.OE-09 4.1 E-07 3.5E-09 Table A4-4
RAI 4
The Tier 2 guidance in RG 1.177, Section 2.3 states that the licensee should provide reasonable assurance that risk-significant plant equipment outage configurations will not occur when specific plant equipment is out of service consistent with the proposed change to the TSs., Table A4-10 of the LAR provides risk achievement worth values for several such configurations but does not include an assessment as to whether "certain enhancements to the TS or procedures are needed to avoid risk-significant plant configurations" as called for by RG 1.177. Furthermore, the configurations that are identified were based only on the internal events model, even though the stated fire CDF values are higher than the internal event CDF values for both units.
The statement in Enclosure 1 of the LAR, Section 4.4.2.2 that "out-of-service combinations can be evaluated for their risk significance to determine if additional measures may be required,"
provides no definition of how risk-significant combinations are selected and does not appear to satisfy RG 1.177 guidance to provide reasonable assurance that risk-significant configurations will not occur. Please explain how your proposal complies with all of the Tier 2 guidance in Section 2.3 of RG 1.177. If the guidance is not clearly satisfied, provide justification for why the intent of the RG is met.
Provide a justification if any hazard groups are excluded from this analysis. If only one unit is analyzed, address how known asymmetries in fire PRA results were addressed.
Response
The proposal complies with all of the Tier 2 guidance in Section 2.3 of RG 1.177 and provides reasonable assurance that risk-significant plant equipment outage configurations will not occur when a DG is taken out of service consistent with the proposed change to Technical Specifications.
Tier 2 requires an evaluation of equipment according to its contribution to plant risk while the equipment covered by the proposed Completion Time change is out of service. This evaluation was provided in Enclosure 4, Table A4-1 0, of the BSEP DG Completion Time LAR.
Based on this evaluation, Tier 2 requires an assessment of whether certain enhancements to Technical Specifications or procedures are needed to avoid risk-significant plant configurations.
No such enhancement to the Technical Specifications or procedures was identified because the existing Technical Specifications and procedures are sufficient to avoid risk-significant plant
Enclosure Page 6 of 6 configurations. The site procedure for online risk (i.e., OAP-025, BNP Integrated Scheduling) assesses the risk of equipment being out of service and would include the proposed DG configuration. Also, the fleet procedure for risk assessment (i.e., ADM-NGGC-0006, Online EOOS Models for Risk Assessment) provides additional qualitative guidance for risk management actions. For cases above the green/yellow risk threshold, the procedures require the protection of the opposite train of equipment. These existing procedures ensure that risk significant outage configurations will not occur during the allowed outage time.
Tier 2 requires the identification of compensatory actions that can mitigate any corresponding risk. These compensatory actions are included in the Commitment List (i.e., Enclosure 9 of the LAR):
Component testing or maintenance of safety systems and important nonsafety equipment in the offsite power systems which can increase the likelihood of a plant transient or LOOP will be avoided during the extended DG CT (i.e., Commitment 3).
No discretionary switchyard maintenance will be allowed during the extended DG CT (i.e., Commitment 4).
The High Pressure Coolant Injection (HPCI) pump, the Reactor Core Isolation Cooling (RCIC) pump, and the Residual Heat Removal (RHR) pump associated with the operable DG will not be removed from service for elective maintenance activities during the extended DG CT (i.e., Commitment 8).
The SUPP-DG will be protected, as defense-in-depth, during the DG CT (i.e.,
Commitment 1).
Finally, Tier 2 requires any changes made to the plant design or operating procedures as a result of the risk evaluation to be incorporated into the analyses. No such change was made.
No hazard group was excluded from the analysis. Although risk significant configurations were based on the internal events model, internal fire events are expected to be included in the maintenance rule (a)(4) risk evaluations beginning December 1, 2013, with Revision 4a of Nuclear Utility Management and Resource Council (NUMARC) 93-01, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." The site risk evaluation employs a blended approach, combining the internal events equipment out-of-service (EOOS) model with pre-calculated results from the Fire PRA model and with configuration-specific Risk Management Actions. Per the Commitment List (i.e., Enclosure 9 of the LAR, Commitment 5),
weather conditions will be evaluated prior to intentionally entering the extended DG CT and will not be entered if official weather forecasts are predicting severe weather conditions. High winds are also addressed by the fleet risk assessment procedure with quantitative responses for severe weather events, including tornados and hurricanes. For the site, a storm surge associated with a hurricane is expected to be the most likely external flooding hazard. The site would have advance warning of this event. If the flood magnitude was such that it could overwhelm the protective measures taken by the plant and damage the DGs, it would affect all four DGs the same and having one out for maintenance would be insignificant. Seismic events are not predictable and would not be directly part of the online risk process; however, the site seismic risk increase is negligible when considering a potential seismic event during the use of the extended DG CT.
Both units are analyzed in the Fire PRA; therefore, asymmetries in Fire PRA results are not applicable.