ML20198B411
| ML20198B411 | |
| Person / Time | |
|---|---|
| Site: | South Texas  |
| Issue date: | 12/15/1998 |
| From: | NRC (Affiliation Not Assigned) |
| To: | |
| Shared Package | |
| ML20198B394 | List: |
| References | |
| REF-GTECI-*****, REF-GTECI-057, REF-GTECI-103, REF-GTECI-131, REF-GTECI-147, REF-GTECI-148, REF-GTECI-156, REF-GTECI-A-45, REF-GTECI-DC, REF-GTECI-NI, TASK-*****, TASK-057, TASK-103, TASK-131, TASK-147, TASK-148, TASK-156, TASK-57, TASK-A-45, TASK-OR GL-88-20, NUDOCS 9812180161 | |
| Download: ML20198B411 (10) | |
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STAFF EVALUATION REPORT OF l
INDIVIDUAL PLANT EXAMINATION OF EXTERNAL EVENTS (IPEEE) SUBMITTAL ON SOUTH TEXAS PROJECT (STP), UNITS 1 AND 2 l
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ENCLOSURE 9812180161 981215 PDR ADOCK 05000498 P
PDR 4
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STAFF EVALUATION REPORT l
OF INDIVIDUAL PLANT EXAMINATION OF EXTERNAL EVENTS (IPEEE) SUBMITTAL l
ON l
SOUTH TEXAS PROJECT (STP), UNITS 1 AND 2 Table of Contents 1.0 I NTR O D U CTI O N............................................. 1 l
2.0 EVALUATI O N............................................... 2 2.1 Probabilistic Analysis Results................................ 2 2.2 Dominant Contributors........................................... 2 2.3 Containment Performance.................................. 3 2.4 Generic Safety lssues.......................................... 3 2.4.1 USl A-45 2.4.2 GSI-131 2.4.3 GSI-103 l
2.4.4 GSI-57 2.4.5 Fire Risk' Scoping Study issues 2.5 Other Generic Safety issues................................. 4 2.5.1 GSI-147 2.5.2 GSI-148 2.5.3 GSI-156 i
2.5.4 GSI-172 2.6 Unique Plant Features, Potential Vulnerabilities, and Improvements........ 6 3.0 C O N C LU S I O N S.............................................. 6
4.0 REFERENCES
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Appendix A: Staff Evaluation of the South Texas Project PSA (Internal Events and internal Fire Analysis)
Appendix B: Staff Evaluation Report on STP IPEEE Seismic and HFO Analyses r
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..e STAFF EVALUATION REPORT OF lNDIVIDUAL PLANT EXAMINATION OF EXTERNAL EVENTS (IPEEE) SUBMITTAL ON SOUTH TEXAS PROJECT UNITS 1 AND 2
1.0 INTRODUCTION
l On June 28,1991, the NRC issued Generic Letter (GL) 88-20, Supplement 4 (Reference 1) along with NUREG-1407, " Procedural and Submittal Guidance, requesting all licensees to perform individual plant examinations of external events (IPEEE) for Severe Accident Vulnerabilities," to l
identify plant-specific vulnerabilities to severe accidents and to report the results to the NRC l
together with any licensee-determined improvements and corrective actions. In letters dated l
December 23,1991, and August 28,1992, the licensee of South Texas Project Electric Generating l
Station (STP), Houston Lighting & Power (HL&P), submitted its responses to the NRC (Reference 2 l
and 3). As part of these responses, the licensee stated that it made use of a previously performed probabilistic safety assessment (PSA) of internal events and external events for the STP, and the l
staff's review of that PSA.
1 HL&P conducted a Level 2 probabilistic safety assessment over a period of about eight years (1987 thru 1995) with the help of a risk consulting group (PLG, Inc.). The licensee conducted the PSA for risk management purposes. In the Spring of 1989, the licensee requested the staff to review and evaluate its draft PSA for reasonableness of core damage frequency (CDF) results and validity of probabilistic modeling assumptions. This draft PSA included analyses of both internal and external events (seismic events, fires, and high winds, floods and other external events (HFO)). The Research (RES) staff conducted a review of the STP PSA with the assistance of Sandia National l
Laboratories (SNL). SNL's technical findings were published as NUREG/CR-5606 in August 1991.
i The staff issued a staff evaluation report (SER) with its technical findings on internal events and fires. This SER is attached as Appendix A of this SER.
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As part of the STP PSA review, the RES staff also reviewed the seismic and HFO analyses. The l
staff also issued requests for additional information (RAls) on the seismic and HFO analyses, to the l
licensee. The licensee provided its responses to these RAls in four separate letters (Reference 4,5, l
6 and 7). These staff reviews were used by the licensee to develop a final version of the STP PSA which then became the major part of the licensee's IPEEE submittal (Reference 2,3 and 9) in response to Generic Letter (GL) 88-20, Supplement 4. The staff documented its technical l
evaluation findings with respect to these external events in an SER which is attached as Appendix B l
of this SER.
l In accordance with Supplement 4 to GL 88-20, the licensee also proposed to resolve as part of its IPEEE submittal (Reference 2) Unresolved Safety issue (USI) A-45," Shutdown Decay Heat l
Removal Requirements," Generic Safety issue (GSI) 131, " Potential Seismic Interaction involving l
the Movable In Core Flux Mapping System Used in Westinghouse Plants," GSI-57," Effects of Fire l
Protection System Activation on Safety Related Equipment," and the Fire Risk Scoping Study I
(FRSS) issues. The licensee did not propose to resolve any additional USIs or GSis as part of the STPIPEEE.
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2.0 EVALUATION The STP is a two-unit, Westinghouse four loop pressurized-water reactor (PWR), located about 90 miles southwest of Houston, Texas. STP has been designed as a "N+2" train concept (a total of three trains). STP has a separate main control room (MCR) and an auxiliary shutdown panel (ASP)
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- for each unit. The plant is designed to withstand a tornado wind speed of 360 miles per hour (mph) and a straight wind speed of 125 mph. The design basis flood protection for the STP site and the plant was found to be 50.8 feet above mean sea level. STP has a large dry containment (steel-lined, post tensioned and reinforced concrete). The plant was designed to a seismic acceleration level of 0.05g operating basis earthquake (OBE) and 0.10g safe shutdown earthquake (SSE) using the Regulatory Guide 1.60," Design Response Spectra for Seismic Design of Nuclear Power Plants,"
spectral shape. For seismic and fire events, the licensee performed a detailed Level 2 PSA which included an assessment of containment performance. For the analyses of other external events, the licensee used the progressive screening procedure described in NUREG 1407.
2.1 Probabilistic Analysis Results As part of the Individual Plant Examinations submittal process, the licensee estimated a total CDF of about 4.4E-5 per year for Unit 1 of the STP facility. The licensee also compared design and operational differences between Unit 1 and Unit 2 and concluded that the Unit 1 CDF estimate was also applicable to Unit 2. The licensee estimated a seismic CDF of about 1.7E-5 per year using a site-specific hazard curve from the Lawrence Livermore National Laboratory (LLNL) seismic hazard database. The fire-induced CDF due to unscreened fire areas (a description of which is provided below) was estimated to be about SE-7 per year.
Since the IPEEE found the hazard frequency of applicable external floods to be about 6E-6 per year (higher than the NUREG 1407 screening criterion of 1E-6 per year), the licensee estimated a CDF due to external floods. The CDF due to external floods was found to be insignificant. For high winds, tornados, aircraft crashes, and chemical releases, the hazard frequency was estimated and evaluated for screening purposes. The estimated frequency of exceeding a design basis tornado (360 miles per hour) was found to be about 8E-9 per year.
The updated estimate of the aircraft crash frequency in the vicinity of the STP site was estimated to be about 2E-7 per year. The overall release frequency and associated impact of onsite stored chemicals, nearby chemicals facilities, and trains and trucks carrying chemicals was also evaluated. The frequency of a release from onsite shared chemicals affecting control room personnel was ostimated to be about 3E-8 per year. The CDF due to a rel ease from nearby chemical facilities was estimated to be about 8E 6 per year. The licensee also evaluated potential explosions of buried pipes carrying combustible gas and/or flammable liquids, and other accidents from offshore facilities, and found them to pose an insignificant impact on the STP safety related structures.
2.2 Dominant Contributors Seismically induced CDF is found to be a dominant contributor (just under 40%) to the overall total CDF, including internal and external events, of 4.4E-5 per year.
Since the fire risk analysis was performed using a progressive screening approach, the licensee quantified the frequency of fire-induced sequences for only a few fire areas (referred to as unscreened compartments). These fire areas include the main control room,
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cable spreading room, switchgear room, and critical areas in the turbine building (Appendix A discusses this in more detail). The fire-induced CDF was found to be about SE-7 per year and is not a dominant contributor (about one percent) to overall CDF. Also, no fires in any of l
the individual fire areas were found to contribute significantly to the overall CDF.
The licensee's IPEEE essessment appears to have examined the significant initiating events 3
and dominant accident sequences for STP.
2.3 Containment Performance The licensee has assessed containment performance under seismic conditions at STP by i.
reviewing the seismically induced system failures that contribute to core damage sequences and plant damage states. Because the plant damapa states specify the entry conditions to a l
Level 2 (containment performance) analysis, a qualtivtive understanding of containment performance was obtained. The licensee has also ponormed a seismic containment performance walkdown for STP. The licensee identified one containment performance
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problem related to certain containment isolation valves of the containment isolation system i
and the letdown portion of the chemical volume and control system. These isolation valves i
are normally open valves and would remain in an open position without the ability to isolate j
them during a seismically induced loss of offsite power. The licensee made improvements to correct this containment performance problem.
The licensee's conta!nment performance analyses for seismic events included modeling of j
support systems such as AC power, DC power, air supply, and essential cooling water (service water). The licensee also conducted containment walkdowns and evaluated j
appl; cable critical containmert failure modes such as containment bypass, containment j
isolation, and availability and seismic performance of the containment barriers. Thus, these j
evaluations appeared to have considered unusual containment performance problems and are consistent with the intent of Supplement 4 to Generic Letter 88-20.
The licensee has also assessed the containment failure modes caused by fires and concluded that tho Level 2 internal events containment performance analysis applies to the i-STP fire PSA. Since the fire-induced system failures did not affect the critical containment j
failure modes, the licensee did not identify any unusual containment performance problems due to postulated fires at STP.
l 2.4 Generic Safety Isman i
As a part of the IPEEE, one specific USl (i.e., USl A-45), three GSis (GSI 131, GSI 103, GSI-57), and the FRSS issues were specifically identified during the initial planning of the IPEEE prograrr. These issues were explicitly discussed in Supplement 4 to GL 88-20 and its associated guidance in NUREG-1407 as needing to be addressed in the licensee's IPEEE submittal. A discussion of these GSis by the licensee is provided in Section 3.5 of Reference
- 3. The staff's eva!uations of these issues are provided below.
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~2.4.1 USl A-45. " Shutdown Decav Heat Removal Reauirements" The licensee's process of addressing USl A-45 external events was very similar to that used for internal events quantification. The seismic and fire PRA event trees and plant system failure models were based on the internal event / failure models. The staff finds that the licensee's USl A-45 evaluations of seismic events (Section 2.4 of Reference 3) and fires are consistent with the guidance provided in Sections 6.3.3.1 of NUREG-1407.
2.4.2 GSI-131. " Potential Seismic Interaction involvina the Movable In-Core Flux Manoina System
.Qged in Westinahouse Plants" The licensee addressed GSI 131, which involves an evaluation of the seismic capacity of the flux mapping system and potential seismic interactions, in Section 2.4 of Reference 3. As a result of that evaluation, the licensee has not identified any significant or unique seismic vulnerabilities. The staff finds that the licensee's GSI 131 evaluation is cor sistent with the guidance provided in Section 6.3.3.1 of NUREG-1407.
2.4.3 GSI-103. "Deslan for Probable Maximum Precioitation (PMP)"
A new PMP evaluation for STP was not required because the impact of the new PMP criteria had been evaluated previously as part of the operating license (OL) process in 1989 (Generic Letter 89 22). Therefore, the staff finds that the licensee's GSI-103 evaluation is consistent with the guidance provided in Section 6.2.2.3 of NUREG-1407.
2.4.4 GSI-57. " Effects of Fire Protection System Actuation on Safetv-Related Eauioment" The licensee addressed applicable FRSS issues in Section 1.1 and 3.4.1 of Reference 3.
(See also Reference 9.) One of the FRSS issues addresses safety problems (e.g.,
inadvertent actuation of fire protection systems on safety systems) documented in GSI-57.
The safety concern of this GSI also includes seismically induced fires, seismically induced suppressant diversion, and seismically induced actuation of fire protection systems. The staff finds that the licensee's overall GSI-57 evaluation is consistent with the guidance provided in Section 6.2 of NUREG-1407.
2.4.5 Fire Risk Scooina Study issues The licensee has addressed applicable FRSS issues in Section 1.1 and 3.4 of Reference 3.
(See also Reference 9.) These FRSS issues include: (1) seismic / fire interactions, (2) adequacy of fire barriers, (3) smoke control and manual fire-fighting effectiveness, (4) equipment survival in a fire-induced environment, and (5) fire-induced alternate shutdown / control room panelinteraction. The staff finds that the licensee's evaluation is consistent with the guidance provided in NUREG-1407.
2.5 Other Generic Safety Issues in addition to those USI and GSIs discussed above that were explicitly reque' ted in s
Supplement 4 to GL 88-20, four GS!s were not specifically identified as issues to be reserved under the IPEEE program; thus, they were not explicitly discussed in Supplement 4 to GL 88 20 and NUREG-1407. However, subsequent to the issuance of the GL, the sinf evaluated the scope and the specific information requested in the GL and the associnted IPEEE guidance, and concluded that the plant-specific analyses being requested in the
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IPEEE program could also be used, through a satisfactory IPEEE submittal review, to resolve the external event aspects of these four GSis. The following discussions summarize the staff's evaluations and resolutions of these four GSis at STP.
2.5.1 GSI-147. " Fire-Induced Alternate Shutdown / Control Room Pane! Interactions" The licensee addressed applicable FRSS issues in Section 3.4.2 of Reference 3. One of the FRSS issues addresses safety problems documented in GSI-147. The licensee's FRSS evaluation addresses applicable issues of GSI-147 through the fire scenario analysis of
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l control room fires (Section L.4 and 9.5 of Reference 10). As part of this evaluation, the licensee did not find any plant vulnerability. The evaluation of control room fires at STP is l
documented in Appendix A of this SER. Based on the results of the IPEEE submittal review, i
the staff considers that the licensee's process is capable of identifying potential l-vulnerabilities associated with this issue. On the basis that no potential vulnerability I
associated with this issue was identified in the STP IPEEE submittal, the staff considers this issue resolved for STP, 2.5.2 GSI-148. " Smoke Control and Manual Fire-Fichtina Effectiveness" l
The licensee addressed applicable FRSS issues in Section 1.1,1.4, and 3.4.2.4 of Referer,ce 3. (See also Reference 9.) One of the FRSS issues addresses safety problems documented in GSI-148. The licensee's FRSS evaluation addresses the applicable issues of GSI-148 through three stages of a fire risk screening analysis and a detailed fire sequence j
analysis of applicable area fires (Section 9.4 and 9.5 of Reference 10). As part of this evaluation, the licensee did not find any plant vulnerability. SNL's findings and the staff's evaluations of applicable fire areas at STP are documented in Appendix A of this SER.
1 Based on the results of the IPEEE submittal review, the staff considers that the licensee's process is capable of identifying potential vulnerabilities associated with this issue. On the basis taat no potential vulnerability associated with this issue ws.s identified in the STP j
IPEEE submittal, the staff considers this issue resolved for STP.
2.5.3 GSI-156. " Systematic Evaluation Proaram fSEP)"
l 2.5.4 GSI-172. "Multiole System Resoonses Proaram (MSRP)"
l The licensee's IPEEE submittal and associated final STP PSA contain information addressing the following external events-related MSRP issues: effects of fire protection system actuation on safety-related equipment (Section 8 of Reference 10), smoke control and manual fire-fighting effectiveness (Section 9.4 and 9.5 of Reference 10), effects of hydrogen line rupture (Section 8 of Reference 10), seismically induced spatial interactions (Section 8 of Reference 10), seismic-fire interactions (Section 11 and Section 8 of Reference 10), seismically induced fire suppression system actuations (Section 8 of Reference 10),
seismically induced flooding (Section 11 and Section 13 of Reference 10), seismically induced relay chatter (Section 11 of Reference 10), evaluation of earthquake magnitude greater than safe shutdown earthquake (Section 11 of Reference 10), the IPEEE-related l
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6 aspects of common cause failures related to human errors (Section 11.3 of Reference 10),
non safety-related control system / safety related system dependencies (Section 5.3 of Reference 3 and Section 12.4 of Reference 10), and effects of flooding and/or moisture i
intrusion on non-safety related and safety-related equipment (Section 13 of Reference 10).
Based on the resrlts of the IPEEE submittal review and previous PSA reviews (Appendices A and B of this SER), the staff considers that the licensee's process is capable of identifying potential external events-related vulnerabilities associated with this issue. On the basis that no potential vulnerability associated with this issue was identified in the STP IPEEE submittal, the staff considers the IPEEE-related aspects of this issue resolved for STP.
2.6 Unioue Plant Features. Potential Vulnerabilities. and imorovements The STP facility is located in a relatively low seismicity region in the southwestem United States. The staff notes that the STP facility is a three train plant. This plant feature is found to reduce the number of fire-induced vulnerabilities to postulated plant fires.
The licensee did not define a potential severe accident vulnerability for STP and did not identify any potential vulnerabilities associated with external events. However, as a result of the seismic analysis, the licensee made containment performance improvements which involved the containment isolation system and the letdown portion of the chemical volume and control system. These plant improvements include: changing the motor-operated valves (MOVs) of the online containment isolation system to air-operated valves (AOVs), and changing the MOVs of the letdown portion of the chemical volume and control system (CVCS) to AOVs.
3.0
_Q.ONCLUSIONS On the basis of the above findings, the staff notes that (1) the licensee's IPEEE is complete with regard to the information requested by Supplement 4 to Generic Letter 88-20 (and associated guidance in NUREG 1407), and (2) the IPEEE results are reasonable given the STP design, operation, and history. Therefore, the staff concludes that the licensee's IPEEE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities, and therefore, that the STP IPEEE has met the intent of Supplement 4 to GL 88-20 and the resolution of specific generic safety issues discussed in this SER.
It should be noted that the staff focused its review primarily on the licensee's ability to examine STP for severe accident vulnerabilities. Although certain aspects of the IPEEE were explored in more detail than others, the review was not intended to validate the accuracy of the licensee's detailed findings (or quantitative estimates) that underlie or stemmed from the examination. Therefore, this SER does not constitute NRC approval or endorsement of any IPEEE material for purposes other than those associated with meeting the intent of Supplement 4 to GL 88-20 and the resolution of specific generic safety issues discussed in this SER.
Attachments: 1. Appendix A, Staff Evaluation of South Texas Project PSA (Intemal Events and Internal Fire Analysis)
- 2. Appendix B, Staff Evaluation Report on STP :PEEE Seismic and HFO Analyses Principal Contributor: E. Chelliah Date: December 15, 1998
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4.0 REFERENCES
1.
USNRC Generic Letter 88-20, Supplement 4," Individual Plant Examination of Extemal Events (IPEEE) for Severe Accident Vulnerabilities - Title 10 CFR 50.54(f)," June 28,1991.
2.
Letter dated December 23,1991, Steven L. Rosen of HL&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Completion of the Individual Plant Examination of External Events for Severe Accident Vulnerabilities.
3.
Letter dated August 28,1992, from Steven L. Rosen of HL&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Level 2 Probabilistic Safety Assessment and Individual Plant Examination.
4.
Letter dated October 11,1990, from M. A. McBumett of HL&P to USNRC, subject: South l
l Texas Project Electric Generating Station Units 1 & 2, Responses to NRC Request for Additional Information on Fire Risk Analysis in the Probabilistic Safety Assessment (PSA).
5.
Letter dated November 20,1990, from M. A. McBumett of ML&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Responses to NRC Request for l
Additionalinformation on the External Events Analysis in the PSA.
6.
Letter dated March 15,1991, from A. W. Harrison, of HL&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Additional information on the Extemal l
Events Analysis in the PSA.
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7.
Letter dated October 21,1992, from William J. Jump of HL&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Additional Information on the External Events Analysis in the PSA.
8.
Letter dated January 14,1993, from Steven L. Rosen of HL&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Additional Information on the External l
Events Analysis in the PSA.
9.
Letter dated July 7,1998, from Steven L. Rosen of HL&P to USNRC, subject: Information Relating to Fire Risk Scoping Study issues Cross Reference Table.
10.
Letter dated June 15,1989, from M. A. McBumett of HL&P to USNRC, subject: South Texas Project Electric Generating Station Units 1 & 2, Probabilistic Safety Assessment.
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Appendix A l
STAFF EVALUATION OF THE SOUTH TEXAS PROJECT PSA i
(INTERNAL EVENTS AND INTERNAL FIRE ANALYSIS)
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.1-s...,'o UNITED STATES g
g, NUCLEAR REGULATORY COMMISSION g
WASHINGTON, D. C. 20566
%p+.CT4 January 21, 1992
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Docket Nos. 50-498
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and 50-499 Mr. Donald P. Hall Group Vice-President, Nuclear Houston Lighting & Power Company P. O. Box 1700 j
Houston, Texas 77251
Dear Mr. Hall:
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SUBJECT:
PROBABILISTIC SAFETY ASSESSMENT, SOUTH TEXAS PROJECT, UNITS 1 AND 2 (TAC NOS M73009 AND M73010)
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By letter dated April 14, 1989, (ST-HL-AE-3059), Houston Lighting & Power Company (HL&P) submitted the South Texas Project Probabilistic Safety Assessment Summary Report.
In that letter, HL&P informed the NRC ttaff that the Probabilistic Safety Assessment (PSA) would be used as a basis for proposing certain changes to the plants' Technical Specifications.
Consequently the staff requested a copy of the PSA which was submf tted by j
letter dated June 15, 1989 (ST-HL-AE-3137).
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We, along with technical assistance from our contractor, Sandia National Laboratories, have evaluated the models and results for the internal events 1
and internal fire analysis portions of the PSA. We have concluded that the PSA is a state-of-the-art Level I risk assessment. While the staff review identified both modeling optimism and pessimism in the PSA, they had a negligible impact on the overall estimate of core damage frequency of 1.7E-4 per reactor-year.
Further, our review indicates that there is no unique outlier that contributes significantly (a single sequence exceeding well above IE-4 per reactor-year) to the overall mean core damage frequency at the South Texas Project (STP).
With regard to our review of the fire analysis, we conclude that fires in areas outside the control room contribute less than one percent to the overall core damage frequency. The fire risk for the STP control rooms is an order of magnitude less than that found in the analysis for other plants. While a sensitivity study showed that the severity factor assignments are a function of postulated fire size, the fire risk in the STP control room is not significantly increased by assuming a more conservative fire size.
The results of our review of the internal events and fire analysis are contaireed in the enclosed Safety Evaluation with the attached supporting Technical Evaluation Report, "A Review of the South Texas Project
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Mr. Donald P. Hall January 21, 1992 i
Probabilistic Safety Analysis for Accident Frequency Estimates and Containment Binning," (NUREG/CR-5606) prepared by our contractor, Sandia National l
Laboratories. The external events portion of the PSA cor.tinues under staff review. Upon completion, the results will be provided to you by a separate l
Safety Evaluation.
Sincerely, l
Original Signed By George F. Dick, Jr., Senior Project Manager Project Directorate IV-2 Division of Reactor Projects - III/IV/V Office of Nuclear Reactor Regulation
Enclosure:
Safety Evaluation cc w/ enclosure:
See next page DISTRIBUTION (without Attachment 1 to SER)
Docket File Asingh, Rgn-IV NRC PDR HWohl Local PDR REmch PDIV-2 RF CGrimes PDIV-2 PF Echelliah BBoger HVandermolen MVirgilio MCunningham EPeyton GDick ACRS (10)
OGC WBeckner EJordan GKelly AHowell, RGN-IV (with all enclosures)
Stong
- SEE PREVIOUS CONCURRENCE 4
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- PDIV-2/PM*
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DATE : 12/30/91
- 12/30/91
- 1/jp/92
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OFFICIAL RECORD COPr /
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Document Name: M73009.STP 01/02/92 c
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M. Donald P. Hall January 21, 1992 cc w/ enclosures:
Mr. J. Tapia Jack R. Newman, Esq.
Senior Resident Inspector Newman & Holtzinger, P.C.
U.S. Nuclear Regulatory Commission 1615 L Street, N.W.
P.O. Box 910 Washington, D.C.
20036 Bay City, Texas 77414 Licensing Representative Mr. J. C. Lanier/M. B. Lee Houston Lighting and Power Company City of Austin Suite 610 Electric Utility Department Three Metro Center P. O. Box 1088 Bethesda, Maryland 20814 Austin, Texas 78767 Bureau of Radiation Control Mr. K. J. Fiedler State of Texas Mr. M. T. Hardt 1101 West 49th Street City Public Service Board Austin, Texas 78756 P. O. Box 1771 San Antonio, Texas 78296 Rufus S. Scott Associate General Counsel Mr. D. E. Ward Houston Lighting & Power Company Mr. T. M. Puckett P. O. Box 61867 Central Power and Light Company Houston, Texas 77208 P. O. Box 2121 Corpus Christi, Texas 78403 INP0 Records Center 1100 Circle 75 Parkway Atlanta, Georgia 30339-3064 Regional Administrator, Region IV U.S. Nuclear Regulatory Commission 611 Ryan Plaza Drive, Suite 1000 Arlington, Texas 76011 Mr. Joseph M. Hendrie 50 Bellport Lane Bellport, New York 11713 Judge, Matagorda County Matagorda County Courthouse 1700 Seventh Street Bay-City, Texas 77414 Mr. William J. Jump Manager, Nuclear Licensing Houston Lighting & Power Company P. O. Box 289 Wadsworth, Texas 77483
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UNITED STATES
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8 NUCLEAR REGULATORY COMMISSION WASHINCTON, D. C. 20555
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CM SAFETY EVALUATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION RELATED TO THE PROBABILISTIC SAFETY ANALYSIS EVALUATION HOUSTON LIGHTING & POWER COMPANY CITY PUBLIC SERVICE BOARD OF SAN ANTONIO CENTRAL POWER AND LIGHT COMPANY CITY OF AUSTIN. TEXAS SOUTH TEXAS PROJECT. UNITS 1 AND 2 DOCKET NOS. 50-498 AND 50-499
1.0 INTRODUCTION
By letter dated April 14, 1989 (ST-HL-AE-3059), Houston Lighting & Power Company (HL&P, the licensee) submitted the South Texas Project (STP)
Probabilistic Safety Assessment (PSA) Summary Report which included the results of the Level 1 Probabilistic Risk Analysis (PRA).
In that letter, the licensee also informed the staff that it planned to provide a risk based analysis of the STP technical specifications (TS) based on the STP PRA model.
The intent of the risk based analysis would be to propose changes in the areas of allowed outage times and surveillance intervals of the TSs based on the features of the STP three train design.
The staff requested a complete copy of the PSA in order to evaluate it as an adequate basis for reviewing the expected TS changes.
The PSA was submitted by letter dated June 15, 1989 (ST-HL-AE-3137). The PSA was done by Pickard, Lowe and Garrick, Inc. (PLG), under contract to the licensee. After completion, the licensee took possession of the PSA and responsibility for its maintenance.
2.0 REVIEW PROCESS Staff review of the PSA was supported through a contract to Sandia National Laboratories (SNL), and SEA Corporation to perform a preliminary review of the portions of the PSA internal events analyses and fire sequence analyses. As part of the staff's review, the staff, SNL, and SEA performed three separate site walk-downs and conducted four separate meetings on August 8,1989, November 28, 1989, May 30, 1990, and October 15, 1990, with the plant staff to obtain additional information and responses to questions. The staff also issued a request for additional information (RAI) to HL&P on January 3,1990.
The licensee's responses to the RAI were received by letters dated January 25, 1990 (ST-HL-AE-3352), March 1, 1990 (ST-HL-AE-3350), and April 11, 1990
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(ST-HL-AE-3414) and incorporated as appropriate into a Draft Technical Evaluation Report (TER) developed by SNL. This draft report was issued on April 10, 1990. A separate evaluation report on the STP fire sequences and an associated RAI were issued to the licensee on June 18, 1990 and August 30, 1990. On August 7, 1990, a separate RAI on the human reliability analysis (HRA) review was issued to the licensee. The licensee's comments on SNL's draft evaluation report, and responses to the RAls on the HRA review and fire sequences review (HL&P's letters of April 11, 1990 (ST-HL-AE-3414), June 19, i
1990,(ST-HL-AE-3478), August 26,1990,(ST-HL-AE-3551), October 11, 1990, (ST-HL-AE-3590) and November 20, 1990 (ST-HL-AE-3636)) have been reviewed and incorporated into the final TER, "A Review of the South Texas Probabilistic Safety Analysis for Accident Frequency Estimates and Containment Binning" (NUREG/CR-5606). Overall, the review process employed for the STP PSA was an interactive process with the licensee and its contractors. The staff's Safety l
Evaluation (SE) is based on its own review of the applicable portions of the PSA as well as its review of SNL's TER, which is attached to this SE. Reviev of external events (except fire) is still under staff review aad will be 4
reported in a future SE.
5 J
3.0 EVALUATION 1
The results of the internal events review are reported in Section 3.1 of this j
SE.
Section 3.2 is the documentation of the fire analysis review.
i j
3.1 Internal Events i
3.1.1 Initiatino Events The licensee's analysis of initiating events is documented in Section 5.2 of the STP PSA and in Section 3.1 of the TER.
Based on the review, the staff accepts the PSA findings related to categorizing, grouping, and screening of various events that could lead to a transient and/or a LOCA event. The staff accepts the licensee's responses to the staff's RAI in the areas related to 4
the treatments of the steam-line break of the Auxiliary Feedwater (AFW) system steam driven train and the postulated core blockage event as applicable to the i
STP facility. The staff notes that the licensee has analyzed the failures of 1
the support systems (such as the Instrument Air [IA] system, Main Control Room
[MCR] HVAC, and Electrical Auxiliary Building [EAB] HVAC) as initiating events and categorized them accordingly for core damage frequency quantification purposes (Table 5.2-4 and Table 7.6-1 of the PSA).
The staff accepts the licensee's estimates of various initiating event frequencies. These estimates are provided in Table 3.4.2-2 of the TER. This table also compares their estimates with the published NUREG-1150 (Severe Accident Risk: An Assessment for Five U.S. Nuclear Power Plants) results provided for similar initiating events. The staff finds a close agreement between the STP PSA results and the NUREG-Il50 results except for loss of Main Feedwater (MFW), reactor trip, turbine trip, and steam generator tube rupture (SGTR) events. The staff accepts the licensee's estimates for all transients because the licensee's estimates are based on an extensive search (PSA subsections 5.2.1 thru 5.2.3) of operating experience and screening analyses for the applicability of generic data (Section 7.4) to the STP facility. The
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3-staff notes however that the number of plant trips at STP are'different from the PSA estimates for the plant trip and turbine events. The licensee indicated that as more plant specific information is generated, it will be evaluated for use in future PSA updates. The staff also accepts the licensee's estimate for loss of offsite power events ((0.13 per year) which is based on data for the Central Power & Light grid system. The licensee's estimate for the SGTR event is based on single tube failure events which is common PRA practice.
Overall, the staff accepts the licensee's analyses in the area of initiating events with exceptions as noted above.
l 3.1.2 Accident Seouence Modelina i
i The licensee's discussions related to the development of accident sequences that could occur following a transient and/or a postulated LOCA event are i
provided in Section 5.4 of the PSA. Unlike the NUREG-ll50 methods, the STP PSA has made use of very large event trees to develop accident sequences.
In addition to modeling frontline core cooling systems as part of the event trees, the PSA has also accounted for the impact of failure and success of the support systems such as electrical and mechanical systems. The plant responses that could be expected during both the early and late stages following the initiating event, including operator recovery action: (per the STP emergency operating procedures), have also been modeled explicitly. The PSA has also developed various event sequence diagrams (ESD) to develop a thorough understanding of various methods of achieving core cooling following a transient, LOCA event, ATWS, or SGTR event. This information has been used in developing the longer event trees and documenting critical assumptions needed to scope the sequence modeling process. The PSA has also developed l
logic models (referred to quantitatively as " split fractions") for each top event modeled in the event tree, that reflect the impact of failure and success of prior top events.
Further, a method of event tree linking has been used to characterize a given top event and to quantify it in order to estimate the frequencies of all sequences involving that particular top event. The details related to the event tree linking procedures have been documented in Section 4.3.5 of the PSA.
Section 5.4 of the PSA has provided ESDs and event trees for a general transient, ATWS, SGTR event, small LOCA event, medium LOCA event, and large t
LOCA event and has documented the graphical displays of potential accident sequences along with details on split fractions and critical assumptions.
Based on the initial review findings, the staff accepted the PSA's modeling of accident sequences with the exception of interfacing LOCA sequences.
In l
response to the staff's RAI, the licensee has further developed sequence modeling details for interfacing LOCA events (Appendix 3 of the TER). The staff has reviewed the response and finds it acceptable.
The staff also notes that the STP PSA transient event tree is more systematic than those used for other PRAs, but is too complex to manually trace a single sequence to reproduce results manually, 4
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3.1.3 System Modelina The staff, with the help of SNL, has reviewed the modeling adequacy of frontline systems and support systems as documented in Sections 3.2.2 through 3.2.5 of the STP PSA with respect to the methods used to analyze system failures and their combinations, critical assumptions made in the PRA, i
modeling adequacy of system dependence requirements, test and maintenance unavailabilities, treatment of common cause failures and human errors, and modeling adequacy of operator recovery actions. The frontline systems modeled (1) High Head Safety Injection (HHSI), (2) Low Head Safety Injection are:
l (LHSI), (3) Containment Spray System (CSS), (4) Reactor Containment Fan Cooler (RCFC), (5) Residual Heat Removal (RHR), (6) Containment Isolation System (CIS), (7) Auxiliary Feed water (AFW), (8) Chemical and Volume Control System (CVCS), (9) Reactor Coolant System (RCS), including steam generators, pressurizer and power operated relief valves (PORV), (10) Hotwell Condensate, l
(11) Main Feed water (MFW), and (12) Steam and Power Conversion.
The support line systems modeled are:
(1) Component Cooling Water (CCW), (2) Essential Cooling Water (ECW), (3) Essential Cooling Pond, (4) Vital and non-vital AC Power (4.16 KV, 480 V, and 125 V) buses, including motor control centers, Class IE diesel generators (DG), Technical Support Center (TSC) diesel generator, and inverters, (5) Vital and non-vital DC-power buses (125 V and l
250 V buses), including batteries and chargers, (6) Compressed Air, (7)
Reactor Protection, and (8) Heating, Ventilating and Air Conditioning (HVAC) for various buildings.
Based on SNL's technical review findings on the systems modeling, the staff provides the following statements:
I 1.
The lack of a need for Emergency Core Cooling System (ECCS) pump room cooling during a transient or a LOCA event was evaluated in detail along with the licensee's additional response to the staff's RAI (IE13 of Appendix 3 of the TER).
The staff accepts the licensee's response.
2.
The treatment of instrument air system failures was evaluated along with the licensee's additional response to the staff's RAI (IE14 of Appendix 3 l
of the TER). The staff accepts the licensee's response.
The staff's review also resulted in the following observations:
1 1.
The STP diesel generators do not use dedicated batteries for field flashing.
Instead, they receive DC power from Class IE DC buses.
l However, this unique dependence of the diesel generators has been found to be an insignificant contributor to the overall core damage frequency.
]
2.
The motor-driven AFW pump room requires ventilation during its operation.
However, the turbine-driven AFW pump does not require room cooling. This eliminates the HVAC dependence during the station blackout scenario.
l 3.
Operation of positive displacement charging pump (PDP) is found to be significant because it can be used to provide seal injection during a station blackout event (given that the isolation of letdown is accomplished), and it can receive power from the TSC diesel generator.
It i
is self-cooled. Also, its room cooling is not needed during a station blackout scenario.
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The loss of the instrument air system, its impact as an initiating event, and its impact on other frontline systems have been found to be small contributors to core damage frequency estimates.
5.
Feed and bleed operation as a backup method of decay heat removal for the STP facility has been credited based on generic Westinghouse analyses which requires one train of the HHSI system and two PORVs.
6.
Uniike the LHSI system at some other PWR's, the LHSI system at STP is not required for operation in the piggy-back mode with the HHSI system during high pressure recirculation. The use of the LHSI system following a small LOCA event requires depressurization of the reactor primary system.
7.
STP has a separate LHSI system independent of the RHR system. This is a feature unique to the STP design.
3.1.4 Success Criteria The licensee's discussions related to success criteria are provided in Section.
5.4 of the PSA.
SNL's technical findings are provided in Section 2.1 of the TER. Based on SNL's technical review findings on modeling adequacy of success criteria,.the staff provides the following statements:
1.
The adequacy of the steam generator boil-dry time estimated for various transients was evaluated since this time affects the operator recovery probabilities. The licensee's response to the staff's RAI on this issue, estimated a minimum time of 34 minutes to steam generator dryout following a loss of offsite power event. This is acceptable.
2.
The assigned conditional probability (0.0001 per demand) of reactor vessel failure at the STP facility, given a pressurized thermal shock (PTS) event, has been evaluated and is found to be acceptable to the staff.
This is based on the significantly lower content of certain elements at STP, such as copper (about 0.05 percent) and nickel (about 0.64 percent),
than at other PWR reactor vessels. An acceptable limit for the contents c' these elements is about 0.4 percent for copper and is about 1 percent for Nickel (" Radiation Embrittlement of Reactor Vessel Materials,"
Regulatory Guide 1.99, Rev. 2).
It should be noted that these elements contribute to a reduction in the toughness of the vessel that could lead to vessel failure during a postulated PTS event.
3.
The staff evaluated the impact on core damage frequency of the lack of accumulator injection for postulated medium and large LOCA events.
Based on the licensee's response (IE3 of Appendix 3 of the TER) to the staff's RAI on this issue, the staff accepts the licensee's core damage frequency estimate of 4 E-7 per reactor-year.for these events assuming that 2 accumulators will inject wat6r to the reactor following a medium and/or s
large LOCA (greater than a 2-inch break) event. The staff also accepts the licensee's conclusion that, for break sizes below two inches, core cooling can be achieved without accumulators.
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4.
The staff evaluated the impact on core ~ damage frequency of the containment isolation system (CIS) failures (a lower containment back pressure resulting in degradation in core cooling) following a medium or a large LOCA event. Based on the licensee's response (IE4 of Appendix 3 of the TER) to the staff's RAI on this issue, the staff accepts the licensee's statement that, with the failure of the CIS the peak clad temperature (PCT) will increase to a temperature of not more than 2510 degrees F.
With the LHS! and CIS functioning successfully, the PCT will be below the regulatory temperature limit of 2200 degrees F.
Because the zirconium phase transition temperature is about 2900 degrees F, beyond which a core damage will be most likely, the staff agrees with the licensee's statement that successful operation of the LHSI system with the failure of the CIS will not result in a severe core damage event.
5.
The staff evaluated the impact on core damage frequency of a modeling omission related to the need for switchover to hot leg recirculation in order to avoid boron precipitation following a large LOCA event. The licensee stated that failure to switchover would not lead to core damage, so it was not included in the PSA. However, the licensing basis for the plants assumes that failure to switchover would lead to core damage.
The licensee's response (IES of Appendix 3 of the TER) to the staff's RAI on this issue, stated that if the event is included, the CDF associated with operator failure to switchover to hot leg recirculation following a large LOCA event is about 2E-8 (0.01 percent of overall CDF). The staff accepts the licensee's calculation of the contribution to the CDF.
6.
The staff evaluated the modeling adequacy in characterizing the small break LOCA event frequency as documented in she PSA. For pipe breaks below 0.5 inch diameter, normal charging makeJp flow will be sufficient to provide coolant makeup to the reactor-The fluid loss through a single instrument tube break could also be compensated by the normal charging makeup capability (IE6 of Appendix 3 of the TER).
Thus the staff judges that a 0.5 inch size will be the lower end of the small LOCA break sizes.
Therefore, the licensee's estimate of the small break LOCA frequency based on a 0.5 inch size break is acceptable to the staff.
7.
The staff evaluated the success criteria employed for depresturization of the reactor primary system following a SGTR event and has found modeling conservatism. The PSA did not take credit for use of the turbine bypass steam dump system as a means of decay heat removal. Also, the PSA has not taken credit for remaining at hot standby with AFW system makeup to the steam generators (SG) in events where the RHR shutdown cooling mode is not available.
The staff accepts the STP findings that the above core cooling criteria are conservative.
8.
The staff evaluated the adequacy of the logical minimum number of system trains needed to provide emergency boration, overpressure protection features, coolant makeup to the primary system, and subsequent decay heat removal following a failure-to-scram event.
The review indicates that the success criteria basically requires one of two boric acid transfer pumps 4'
for emergency boration, two PORVs and two safety valves to open (or all
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three safety valves to open) for primary system overpressure protection,
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one PORV and one safety valve to open (or two safety valver to open) for steam generator overpressure protection, one of three HHSI trains and one of three LHSI trains for primary system coolant makeup, and two of four AFW trains for decay heat removal. The staff accepts the PSA findings in this area.
9.
The staff evaluated the minimum number of trains needed for containment cooling following a postulated LOCA event or a transient-induced LOCA event. One LHSI train or two RCFC trains are required to remove the decay heat from the South Texas containment. The staff accepts the PSA findings in this area.
The staff' review also yielded the following safety insights:
1.
If it is required to keep the reactor in the hot standby mode for an extended period of time following a transient or a SGTR event, makeup water to the AFW storage tank must be provided. The primary' source of makeup water to the AFW storage tank is the hotwell condenser system.
While not considered in the PSA, makeup water to the AFW storage tank could also be accomplished through either the demineralized water system or the fire water system. These systems are designed with industrial grade (not seismic category I) structures and components; but in an area of low seismic activity such as STP they could be considered as non-safety backup systems.
2.
For a small LOCA event or a transient-induced LOCA event, the HHSI system is required to function in the recirculation mode, taking suction from the containment sump.
During this mode of operation, the RHR system, including the RHR heat exchanger, is not needed to remove decay heat.
i Decay heat removal will be accomplished by means of the RCFC, CCW and ECW systems.
If the RCFC system should fail, then the reactor primary system depressurization function, the LHSI system, the RHR heat exchanger, the CCW system, and the ECW system are required to function.
3.
One train of the LHSI system is sufficient for both coolant injection and recirculation following a large LOCA event. When the recirculation mode l
of the LHSI system (with RHR heat exchangers) is not available, two of the l
three RCFC trains (without RHR heat exchangers) are needed to remove decay heat from the containment. Thus, the importance (with respect to reliability requirements) of the LHSI system to remove decay heat i
following a LOCA event is significant.
l 4.
The staff considered the potential failure of the STP vessel following a i
failure-to-scram event.
For a failure-to-scram event, the PSA has employed generic thermal-hydraulic analyses to establish core cooling success criteria.
For example, the PSA assumes that a moderator temperature coefficient of -8 pcm per degree-F could lead to an event that could result in pressurization of the primary system (including the vessel head) to about 2790 psig (following a turbine trip event).
The PSA also assumes that the primary system will fail, resulting in a LOCA event, only if the ASME Level C (a pressure equivalent of about 3200 psig) limit is exceeded.
Therefore, a vessel failure event should not occur.
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3.1.5 Data Analyses The staff evaluated the adequacy of the data (random failures, common cause failures, test and maintenance unavailabilities unreliability estimates and sequence frequency e)stimates.used to quantify the system Overall, the licensee has not developed plant-specific data data) for sequence frequency estimation purposes (in particular, common cause The STP facility was under operating license (0L) review, and the facility was not licensed to operate, at that time the PSA was performed. Therefore, with the exception of a few components, the licensee has made use of the collection of generic data documented by its contractor, Pickard, Lowe and Garrick (PL&G). The staff review found that the generic data employed in the PSA (Section 7.7 of the PSA) is a mixture of both nuclear operating experience (until 1987) and data collected by the industry, the DOE National Laboratories, recognized professional societies (such as ASTM, ANS, IEEE, and ASME) and the USNRC.
During the review process, some of the PL&G database used for the STP PSA were made available for the staff's review. The review primarily involved a comparison of the PSA data (component failures including common cause l
failures) with those documented in the NUREG-1150 supporting analyses. The results of a summary comparison are documented in Section 3.4 of NUREG/CR-l 5606.
The following is a summary of the major highlights:
l 1.
The PSA has used a total of about 2.6 trips per calendar-year as opposed to 6.6 trips per reactor-year in the NUREG-ll50 report. The staff notes that in future PSA updates, actual STP trip data will be considered for inclusion.
2.
The frequency of the loss of feedwater events (considering recoveries) is slightly higher than that estimated for the NUREG-IISO report.
3.
The PSA's frequency estimate for the SGTR event (2.8E-2 per reactor-year) is higher than that estimated for the NUREG-1150 report. The PSA estimate is based on single tube failure events.
4.
The mean check valve failure probability per demand for the PSA is three times higher than that estimated for the NUREG-1150 analyses. The staff finds that this difference is within the range of the NUREG-1150 uncertainty estimates.
5.
The fail-to-reclose probability for the STP PORVs is higher than that estimated in the NUREG-1150 analyses.
6.
The fail-to-run probability (per hour basis) for the turbine driven AFW pump of the STP facility is lower (by a factor of five) than that of the NUREG-ll50 plants. However, the staff finds that the mission time adopted in many dominant sequences is about one to two hours, and therefore, the use of a lower estimate for the AFW turbine-driven pump will not significantly change the estimated frequency of the station blackout sequences.
__m
_g-The estimates used for the components noted above reflect PLG's method of generic data applicability analyses, and the STP-specific design features.
When compared to those used in NUREG-1150, the reasons for these variances are acceptable to the staff.
The staff notes that the PSA has made use of the Multiple Greek Letter (MGL) method to quantify the common cause contributions to the three-train system failures (applicable to the STP facility) to the overall system failure. The licensee's discussions related to common cause methods, data classification and screening, and development of the STP-specific MGL parameter distribution's are documented in Section 7 of the PSA. The staff notes that the PL&G generic data for individual components (such as diesel generators, pumps, check valves, motor operated valves, PORVs, Safety Relief Valves (SRVs), fans, circuit breakers, level sensors) have been used as the basis for the common cause parameter quantification. The staff also notes that the data from this generic data base has been screened for its applicability to the STP facility.
Moreover, the staff believes that the PSA's documentation related to the method of quantifying common cause failures is outstanding. The staff accepts the licensee's method of common cause analyses.
The staff has also evaluated the modeling adequacy of test and maintenance contributions to the overall system unavailabilities.
The contributing components which have been modeled are online maintenance, unscheduled maintenance, preventive maintenance, scheduled testing, online testing, unscheduled testing, and testing after maintenance. Again, the PL&G generic data base has been used in screening and categorizing these contributing elements in developing the probability distributions for maintenance frequencies and durations (Section 7.5 of the PSA). The staff notes that the STP specific design features and maintenance policies and procedures have been used in applying the generic data base to estimate maintenance frequencies and durations.
The staff also notes that the STP specific technical specifications with respect to allowed outage time and test intervals have also been considered, as applicable, in estimating frequencies and durations.
A detailed summary of these frequencies and durations along with the distributions is documented in Table 7.5-1 and 7.5-2 of the PSA. The staff finds that these estimates are reasonable and comparable with those estimates documented in the NUREG-ll50 report. The staff accepts the licensee's method of estimating the test and maintenance contributions to the overall system unavailabilities.
3.1.6 Human Reliability Analysis The staff has evaluated the adequacy of certain aspects of the HRA such as methods, assumptions and probability distributions assigned to estimate the human error probabilities documented in the STP PSA. The licensee provided its response to the staff's RAI in the above HRA areas.
Basically, the PSA has used the modified SLIM, SHARP, and THERP methods as part of the overall l
HRA methods. The principles of the SHARP method have been used to identify the critical dynamic human actions, including recovery actions (to be initiated following a transient or a postulated LOCA event), to be modeled as part of the event trees.
The PSA has also performed a transient-specific thermal-hydraulic calculation to estimate the steam generator boil-dry
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1 10 -
time and the RCP seal failure time and factored them into the STP HRA accordingly.
The staff also notes the licensee's room heat-up and thermal fragility calculations were performed as part of the loss of HVAC scenarios.
The modified SLIM method has been used to quantify the performance shaping factors (PSFs) used in characterizing the attributes of a particular human action to be modeled in the event sequence and the associated uncertainty distributions. The tabulated human error probability estimates and dependency correlations from NUREG/CR-1278, " Handbook of Human Reliability Analysis with Emphasis on Nuclear Power Plants Application," have been used to quantify the human actions modeled as part of the system analyses.
The staff accepts these i
enhanced modeling aspects of the HRA analyses. The following is a summary of our technical review f.indings:
1.
The staff evaluated the basis for the probability used for recovery of the offsite power, the initially-lost diesel generators, the turbine-driven AFW pump following a station blackout event, and the initially-lost chillers (prior to the heat-up of the 4.16 KV switchgear) following a loss of HVAC scenario. These probability estimates are comparable to those estimated for the NUREG-1150 analyses. Thus the staff accepts these j
probability estimates.
1 2.
The staff also evaluated the appropriateness of the application of the miscalibration probability estimate for the Seabrook facility to the STP facility.
The licensee's response in this review area included a design comparison analysis of the facility instrumentation hardware, configuration, and calibration procedures for the two facilities. The staff has reviewed this response and has found it to be appropriate for the South Texas facility.
3.1.7 Seouence Ouantification The licensee's discussions related to quantification methods (including the method of crediting scenario-specific operatur recovery actions) of all end states of the developed event trees for transients, LOCAs, ATWS events, and SGTR events are documented in Sections 5.5 and 5.6 of the PSA. During the review process, the staff found several disagreements between the table of 4
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dominant accident sequences (provided separately) and the system description split fraction quantification in the PPA. The differences were in the areas of AFW train combinations and the diesel train combinations.
In response to a staff RAI, the licensee provided clarification on several items, confirmed the staff's assessment on others, and based on further review, identified one additional error. There was no change to the overall core damage frequency (CDF). The licensee committed to include the corrections in the next PSA update. The details of these findings are documented in Item C of Section 3.6 of NUREG/CR-5606. With the exception of a few sequences previously identified, the staff accepts the PL&G's method of quantification of event trees along with their frequency estimates.
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l The following is a summary of the staff's portrayal of potential core damage 1
sequences:
1.
The PSA has developed a large number (millions) of sequences with frequency estimates ranging as low as 1 E-10 per reactor-year. There are l
about 225 sequences having frequency estimates greater than 1 E-7 per reactor-year, and about 21 sequences having frequency estimates greater than 1 E-6 per reactor-year. Although the licensee identified the 225 l
sequences to be " dominant," the staff's review involved a focus on only l
the first 21 of the dominant sequences.
2.
The total mean CDF is about 1.7 E-4 per reactor-year. The staff notes that STP is a three-train plant which has been designed and built based on an "N+2" concept for many accident scenarios. The staff also notes that I
the STP facility has three motor-driven AFW pumps and one turbine-driven l
AFW pump to remove decay heat.
3.
Of the above 21 sequences, 13 sequences are initiated by a loss of offsite i
power event. Of these 13 sequences, 8 sequences involve station blackout i
events (4 events with failure of the turbine-driven AFW train, 3 events with RCP seal failures, and I event with a stuck-open PORV event). The rem Ining five loss of offsite power sequences involve combinations of in/
jndent failures of the diesel generators, the motor-driven AFW t
.s, the turbine-driven AFW train, and the ECW trains.
I i
The relative contribution of the loss of offsite power events to the overall core damage frequency is about 53 percent. The station blackout core damage frequency is about 3 E-5 per reactor-year.
4.
Two sequences are initiated by SGTR events for the STP facility. These sequences involve a failure to depressurize the reactor below the steam generator PORV setpoint, and a failure to isolate the stuck-open PORV on the affected steam generator. The SGTR sequence frequency is 2.5 E-6 per reactor-year.
5.
Two sequences are initiated by a loss of the Electrical Auxiliary Building (EAB) HVAC system.
The failure of the EAB HVAC system is expected to result in a failure of all three trains of the 4.16 KV buses (due to overheating of the 4.16 KV switchgear) which results in a demand for RCP seal cooling by means of the PDP pump and the TSC diesel generator, and a demand for coolant makeup to the steam generator through the turbine-driven AFW train.
The frequency estimate of these sequences is about 9 E-l 6 per reactor-year.
6.
There are two sequences initiated by a reactor trip with a combined sequence frequency estimate of 3.7 E-6 per reactor-year.
These sequences involve a failure of the secondary side decay heat removal system (four-e train AFW system), and a failure to provide primary side decay heat 1
removal by means of feed and bleed operation (through both pressurizer PORVs) in a timely fashion, or a failure to provide long-term stabilization of the plant.
The "long term stabilization of the plant" refers to a stable plant state where core decay heat is being removed 2
i
o through the steam generators, and the steam generator coolant makeup is being accomplished through the AFW storage tank.
It should be noted that makeup to the AFW storage water tank is not required until several hours (when the level in the tank falls below a limit of 138,000 gallons) after the reactor trip.
7.
There is one sequence initiated by a turbine tri) with a sequence frequency estimate of 2 E-6 per reactor-year. T)is sequence also involves a failure to provide long-term stabilization of the plant.
8.
There is one sequence initiated by a partial loss of MFW event with a sequence frequency estimate of 2.2 E-6 per reactor-year. This sequence also involves a failure to provide long-term stabilization of the plant.
3.1.8 Comoarison with Results From NUREG-1150 A summary of relative contributions of various initiating events to the overall CDF is shown in Figure 1.
The staff has compared the results of the STP sequences with those of the NUREG-II5O analyses and has concluded 'the following:
t 1.
Unlike the NUREG-1150 findings, the frequencies of small LOCA sequences (at the STP facility) involving recirculation failures have been estimated to be insignificant and are lower than 1 E-6 per reactor-year. This is primarily due to the fact that, unlike the NUREG-ll50 plants, the ECC pumps of the STP facility are self-cooled, and no forced cooling is needed for the ECC pump rooms, and the switchover from injection to recirculation following a postulated LOCA event is an automatic action at the STP facility.
2.
The frequency estimates of sequences initiated by other events, such as loss of offsite power, SGTR, reactor trip, turbine trip, loss of MFW, and interfacing LOCA, are closely comparable (within a factor of 2 to 5 to the corresponding estimates documented in the NUREG-1150 analyses. )The staff notes that the differences in methods (use of shorter vs longer event trees; Shoreham Contention 7B) of these two probabilistic safety analyses do not play a major role in reaching the above conclusion.
3.
Proper risk application of the PRA will obviously require a thorough understanding of and attention to the first 21 dominant sequences.
However, attention should also be paid to understanding the safety details that could be gained from the remaining sequences (a frequency range of greater than IE-8 per reactor-year). The latter set could be as important as the first in order to characterize a substantial change in core damage frequency, if any, due to future identification of potential defects in component design and installation procedures. The staff also believes that activities for which the STP PSA could be used include: (1) identification of areas for further design and/or operational improvements with respect to substantial reduction in overall core damage frequency (such as IPE and IPEEE activities), (2) review of the licensee's modifications to the current STP technical specifications, and (3) use of
i
}3 l
the STP PSA dominant accident sequences in training the STP operators (e.g., updating STP-specific operator training modules to reflect the required recovery actions in responding to cr' tical multiple failures)
J, regarding the role of certain failures of critical systems and equipment and the required recovery actions for transients. The extensive probabilistic and reliability knowledge from the STP PSA could also be used in updating the training simulator.
a 4
4.
Maintenance of the STP PSA to reflect " current" plant, accommodate future j
plant-specific experience (revised component failure data and new events j
or sequences based on U.S. and foreign experience), update research knowledge (e.g., new sec uences, new accident phenomena, and new 1
consequence methods) anc hardware and procedural modifications will be a valuable tool for the licensee.
3.2 Fire Analysis The staff has reviewed the applicable portions of the fire analyses documented in the STP PSA and SNL's technical findings on these fire analyses. The licensee's analyses of fire zone-specific combustibles, postulated fire 1
scenarios, fire data analysis, method of screening analysis and its results, I
and frequency estimates of the screen scenarios are documented in Sections 8, l
9, and Appendix D of the STP PSA. As part of the review of these selected fire scenarios, SNL performed a technical review of the fire analyses.
In addition to RAls the staff, with the help of the SNL staff and plant fire i
protection engineers, conducted a plant walkdown of critical fire zones to a
l obtain first-hand information on the amount of zone-specific combustibles, fuel sources, location of fire detection and suppression systems, and 4
information on the applicability of generic fire data to the STP-specific fire zones. The additional information gathered during the plant walk-down, along with information provided by the licensee in its response to the RAls, was included in the TER on fire risk review. These fire risk evaluation findings j
are documented in Section 6 and Appendix 6 of NUREG/CR-5606.
i j
3.2.1 Screenino Criteria
}
The staff evaluated the adequacy of the screening criteria used by the PSA to exclude the frequency estimate of a single zone fire scenario if it exceeded e
one tenth of one percent of the overall core damage frequency estimated for transients and LOCAs (2 E-7 per reactor-year).
This approach was considered necessary by the licensee for the management of the enormous number of fire sequences that could be expected from a fire event tree. After review of the process the staff concluded that use of the screening criteria would not have eliminated from further consideration any significant fire induced contributors to overall core damage frequency.
3.2.2 Adeauncy of Overall Fire Analysis Model The staff evaluated the modeling adequacy of the fire detection and suppression systems along with the assignment of geometry and severity factors used for postulated fires in the various fire zones.
Fire zones have been screened based on two levels of screening criteria.
The staff has found that, y,__,__,
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unlike other fire PRAs evaluated, detection and suppression systems located in various fire zones have been implicitly modeled. The PSA has assigned severity factors in order to model the characteristics of the detection and suppression systems for critical fire zones. As part of this evaluation, the staff requested the licensee to perform a sensitivity analysis to remove such severity factors from the fire scenario frequency estimates and to provide results of the sensitivity analysis including the impact on the zone-specific fire sequence frequency estimate for selected fire zones. These sensitivity results by the licensee which are documented in Appendix 6 of NUREG/CR-5606 indicate that the total fire frequency for these critical zones is about 1.5 E-5 per reactor-year. The staff has reviewed these results and found them acceptable.
The total main control room (MCR) fire frequency estimated by the licensee is about 5 E-3 per reactor-year and is based on a systematic documentation of all reported fire data since 1987. The staff accepts this estimate for fire scenario frequency estimation purposes.
The staff evaluated the modeling adequacy of postulated main control room fires at the STP facility.
In particular, the staff and its contractor evaluated the modeling adequacy of the propagation characteristics of postulated panel fires, the completeness of the PLG panel fire, data, and the appropriateness of the severity factor assigned for panel fires in the control room. The licensee provided its response to the staff's RAI in these review topics.
Review of this response indicates that these severity reduction factors range from 0.0023 to 0.028 depending upon the size of the postulated fire and the location of the postulated fire (such as the fire at a panel interface). These reduction factors have been assigned based on a licensee review of the PL&G panel fire data base established for panels located in the MCR, remote shutdown room, and motor control centers. The licensee concluded that the minimum effective damage radius for a postulated fire to cause significant fire damage is about four feet. Staff review has also found that only one out of 16 panel fires, which have actually occurred at various buildings of current operating plants, has spread more than one foot with respect to significant fire-induced damage.
The staff notes that this PL&G fire data has been used in developing a propagation characteristics curve which is used to obtain a severity factor for a given propagation distance to be analyzed for a postulated fire. The staff also notes that, during the fire review, 3 additional panel fires (which occurred at Rancho Seco, Calvert Cliffs, and Beaver Valley) have been added to the original 13 panel fires (analyzed in the STP PSA) and have been used to revise the propagation characteristics curve to obtain a revised severity factor. The licensee has also performed a sensitivity analysis of the revised severity factor on the overall control room fire scenario frequency estimate. The results of the above sensitivity analysis indicate that the incorporation of the additional three panel fire data points does not significantly increase the overall fire frequency estimate. The staff has reviewed these results and found them acceptable.
The staff has also evaluated the appropriateness of recovery actions to be performed by the MCR operators following a postulated fire in the MCR. The licensee stated that a fire in the MCR would disable safety system equipment
g l
l controls and instrument indications which could be restored by a transfer of control and monitoring actions to the auxiliary shutdown panels (ASP) subsequent to a manual reactor trip from the MCR and immediate abandonment of the MCR. Staff review found that credit for the transfer of equipment control and monitoring functions was not taken in the fire scenario frequency estimation method. However, operator recovery of safety system equipment from the ASP (a failure probability of 0.2 per demand) has been modeled in the fire scenario frequency estimation method. The staff reviewed the modeling aspects of the ASP actions and their failure probability assignment and found them acceptable.
3.2.3 Adeauacy of Analytical Steos The staff evaluated the adequacy of the analytical steps involved in the overall fire probabilistic method based on the responses provided to the j
staff's RAI for the 4.16 KV switchgear (SWG) zone (Zone 4) fires. A description of the analysis is provided in Section 6.4 and Appendix 6 of the TER.
3.2.3.1 Zone Specific initiatino Fire Freauency The method of estimating zone-specific initiating fire frequency was evaluated by the staff.
The overall SWG Zone 4 fire frequency is about 1.4 E-3 per reactor-year (Table 8.5-2 of the STP PSA) and is based on a systematic analysis of plant-specific information.
The Zone 4 frequency was estimated by multiplying the allocated frequency (0.048 per reactor-year) for the Mechanical and Electrical Auxiliary Building (MEAB) by a normalized area modification factor estimated for Zone 4.
The area factor is characterized by the fraction of floor area of a particular zone (in percent) of the total area of the building which contains that zone. The area factor for Zone 4 is about 1.4 percent.
The modification factor is characterized by the occupancy and the traffic pattern of a particular zone. This modification factor for each l
zone is assigned by the STP fire protection engineers and is based on the assumption that the frequency of a fire in any given zone is mostly influenced by the zone location in a given building and the combustible contents in that zone.
The assigned modification factor for Zone 4 is about 1.9.
Thus, the normalized area modification factor was computed by dividing the product of area factor and modification factor for Zone 4 by the sum of all the similar products for all zones in MEAB. The staff accepts the Zone 4 fire frequency along with the fire frequency estimate of 1.4 E-3 per reactor-year.
l The Zone 122 fire frequency estimate of 2.17 E-3 per reactor-year is one of the larger (4.5 percent) contributors to the overall fire frequency for the MAB but was screened from further consideration during the analysis. Thus, the staff evaluated the basis for the screening of fires in Zone 122 from the Level 3 evaluation. A fire in this zone results in a small LOCA event with a subsequent failure of the "C" train of the CCW system.
Since the additional system failures that are modeled as part of the Level 2 screening analysis fall into the Class 2 scenario (an event causing a transient or a LOCA event and one or more failures of trains of a single safety system), a potential core damage event following a Zone 122 fire will also incorporate failure of the remaining trains of the CCW system and the HHSI system trains.
Thus, the
l resulting core damage frequency was estimated as about 1.5 E-7 per reactor-year. Also, the licensee's sensitivity analyses, in which the geometry and i
severity factors (that are evaluated as part of the Level 3 evaluation stage) for this Zone 122 were removed altogether, indicate that the fire-induced core damage frequency (end state 43) for Zone 122 is about 2 E-6 per reactor-year which is only about 1.2 percent of the overall CDF. The staff finds these analytical steps used in the CDF estimates from fires to be acceptable.
3.2.3.2 Random Failure Contributions The modeling adequacy of the random failure contributions for Zone 4 fires, as part of the Level 1 and Level 2 screening stages, and the appropriateness of the licensee's assignment of severity reduction factors as part of the Level 3 evaluation stage of the PSA fire risk analysis, were evaluated by the staff.
Since the original PSA did not provide sufficient documentation for these review topics, the licensee provided its response, in detail, to the staff's RAI. The frequencies of fire scenarios (end states 11, 12, 15, 16, 19, and 20) for Zone 4 were estimated and compared with the frequency estimates of the corresponding end states of a transient event. At the Level 1 screening stage, the fire scenario end states with frequencies less than one percent of the frequency estimate of the corresponding and state of the transient event, were screened out from further analysis. At the Level 2 screening stage, credit was taken for these safety systems which are not affected by Zone 4 fires, and the fire frequencies for all resulting sequences (end states 11, 12,15,16,19, and 20) were estimated (Tables 4-9 and 4-11 of Appendix 6 of NUREG/CR-5606). Then, the fire sequences (end states) with frequencies less than one tenth of one percent of the total core damage frequency estimate for the transient events (about 1.7 E-7 per reactor-year) were screened out from further analysis.
In summary, for Zone 4, at the Level I screening, all sequences passed for Level 2 screening analysis. At the Level 2 screening, only end states 11 and 12 passed for Level 3 evaluation.
The Level 3 evaluation took into account the severity reduction factors in addition to credit for the systems unaffected by the Zone 4 fire. The reduction factors reflected the conditional probability of failures of the fire-induced safety system components such as power cables, control cables and circuit breakers of CCW pump A, ECW pump A and AFW pump A; control cables of the PDP; control cables of pressurizer PORV 655A; the control cables and power cables of the pressurizer PORV 655A block valve; and the ventilation fan motor contactors of AFW pump A and CCW pump A.
The staff believes that the Level 3 analysis conducted by the licensee for zone 4 is a realistic fire probabilistic analysis. Therefore, the staff accepts the results of the Level 3 evaluation results provided by the licensee for Zone 4 fires. The staff also notes that the severity reduction factors were assigned based on l
engineering judgment and knowledge obtained from previous fire PRAs.
3.2.3.3 Fire Seouence Freauencies for Cable Screadino Rooms The staff evaluated critical modeling aspects involved in estimating the zone specific fire sequence frequencies for cable spreading zones / rooms (CSZ).
i There are three CSZs (Zone 47, Zone 57, and Zone 60) evaluated in deta:1 for the STP facility.
The total fire frequency for all these zones is about 2.4 z7
Io.
' (~
E-3 per reactor-year. A large portion of this estimate (1.07E-3 per reactor-year) has been allocated t'o Zone 47. These estimates are based on a systematic documentation of all reported events (cable fires, panel fires, and transient combustible fires) for a typical auxiliary or reactor building of a nuclear power facility since 1987.
The total fire frequency estimated by the STP PSA for the auxiliary building is about 4.8 E-2 per reactor-year. This i
l frequency was then partitioned according to the area and the occupancy and traffic characteristics of each of the three CSZs zones indicated above. The staff noted that such a method of estimating fire initiating frequency data is different from past fire risk analysis practices in that past fire PRAs have estimated the fire initiating frequency for a CSZ based on reported data for i
the auxiliary building alone. As part of the resolution of this data modeling issue, the licensee provided, in response to the staff's RAI, the results of a sensitivity analysis, specifically the impact on the overall core damage frequency of increasing (by a factor of 10) the CS zone fire frequency. The impact was found to be an insignificant increase over the originally estimated overall fire sequence frequency estimate. The staff accepts the results.
The modeling aspects of additional failures of the systems and components (unaffected by the postulated Zone 47 fire) modeled as part of the level 2 i
screening analysis were evaluated by the staff and were found to be acceptable l
to the staff.
l The adequacy of the licensee's assignment of reduction factors modeled as part i
of the Level 3 screening analysis was evaluated by the staff. As indicated in previous paragraphs, the licensee also performed a sensitivity analysis by removing altogether the geometry and severity factors as part of estimating the fire-induced core damage frequency for the CSZ fires. The results of this sensitivity analysis found that the Zone 47 fire yielded a total core damage frequency estimate (1.34 E-6 per reactor-year) calculated for four end states (53, 59, 66, and 72). This is considered a bounding estimate of fire-induced core damage frequency.
The staff accepts these results.
3.2.3.4 Fire Seauence Frecuencies for Turbine Buildina The details of the turbine building (TB) fires and their significance on the overall fire sequence frequency estimates were provided in the licensee's response to the staff's RAI in this review area.
Based on these responses, the staff evaluated critical modeling aspects involved in estimating the fire sequence frequencies for turbine building fires and fires in the 13.8 KV switchgear room. The total TB fire frequency involving a non-recoverable loss of offsite power is about 2.23 E-3 per reactor-year.
The staff notes that this frequency estimate consists of large TB fires and 13.8 KV switchgear room l
fires.
The TB large fire frequency is about 2 E-3 per reactor-year. This estimate was based on the allocated TB fire frequency (0.047 events per year during plant operation) and one large fire event assigned to the TB of the STP i
facility out of a total of 23 TB fire events, which have been reported for various nuclear facilities in the United States and Europe. The PSA has I
characterized 13 fires out of 23 TB fire events that involved a main turbine-generator located in the TB of a typical nuclear power plant. However, only i
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one of the TB fire events has been characterized as a fire event large enough to potentially disable both the 125 V DC control power cables from the TB 3
i battery bus and the 125 V DC control cables of the EAB battery bus. The large i
fire event is one that could result from a rupture of a hydraulic oil line located in a typical TB.
Since these control power cables control the 1
switchgears of 13.8 KV buses F, G, and H, given a large fire in the TB, a loss of offsite power event could occur with no timely recovery. The assigned l
conditional probability is about 0.043 per demand. The staff accepts the licensee's frequency estimate of the large TB fire.
i The 13.8 KV switchgear room fire frequency is about 1.9 E-4 per reactor-year.
This estimate was based on the allocated mean TB fire frequency (0.047 events l
per year) and an adjustment factor assigned on a Bayesian estimate (a prior j
distribution of zero TB switchgear fire events out of 23 TB fire events) for i
the fraction of the TB fires that occurred in a TB switchgear. The fraction i
of the TB fires applicable for the switchgear room is estimated to be about 0.04.
The adjustment factor takes into account an assumption that about ten i
percent of the total TB fires could result in damage to all three 13.8 KV buses. The above ten percent assignment is based on the fact that the switchgear cabinets of buses F, G and H are widely separated apart. The staff accepts the licensee's frequency estimate of the 13.8 KV switch gear room fire.
1 As part of the Level 1 screening analysis, an estimate for the frequency of a j
non-recoverable loss of offsite power event was obtained (see pages 309 thru l
j 312 of the TER). This estimate is about 0.046 per year.
Since the total TB fire frequency (2.2 E-3 per year) involving a non-recoverable loss of offsite power event is greater than one percent of the corresponding transient event frequency (0.0l*0.046 - 4.6 E-4 per year), the licensee further evaluated the TB fire scenario analysis as part of the Level 2 screening analysis.
Level 2 screening considered the dominant additional system failures that must occur i
s before core damage as well as an independent failure of the 138 KV emergency line (referred to as The Blessing Line). After including the additional failures, the TB fire-induced core damage frequency estimate was about 3 E-7 l
per reactor-year.
Since this estimate is greater than one tenth of one i
percent of the transient-induced core damage frequency (about 2 E-7 per
{
reactor-year), a level 3 evaluation wauld normally have been conducted by the i
licensee. However, the licensee stated that the Level 2 evaluation included some very conservttive assumptions. Therefore, a Level 3 evaluation, which calls for incorporation of reduction factors of the affected systems in the TB fire sequences, was not performed. The staff accepts the licensee's analysis for concluding the TB fires to be insignificant contributors to the CDF and for not considering them further.
3.2.4 Staff Observations of The South Texas PSA i
1.
Tht STP facility is a three-train plant and includes physical separations for the safety system components and cable routings. The barriers (walls, 1
ceilings, floors, curtains, doors, and penetrations) separating the critical fire zones have been built to withstand a three-hour fire in all fire zones analyzed in the STP PSA. The staff's review of.the STP fire l
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J PSA indicates that the removal of credit for the suppression and detection systems could result in an increase of about 2 E-5 per reactor-year in the i
overall core damage frequency.
2.
The MCR for the STP facility has been designed and built such that a fire j
in any given control panel would be detected in a timely fashion by the smoke detectors placed near the intake to the HVAC system inside the i
enclosed control panel housing. Also, to a great extent, separation between controls in a given panel has been provided.
For postulated MCR fires, operation from the remote ASP, in addition to its defined i
functions, was found to be very useful, including the establishment of seal cooling by means of the TSC diesel generator and the PDP system.
1 3.
The staff notes the licensee's assigned estimates of the fire scenario-i specific severity reduction factors modeled for various safety systems and components in the STP fire PSA and acknowledges that they are one-of-a-kind analyses.
However, these factors are not based on a formal fire
)
engineering type analysis, but based on engineering judgments by thermal 1
experts.
i 4.
A zone-specific walk-down by the staff indicates that the sprinkler and spray nozzles are located above the cable trays and have fusible links.
i The. fire suppression system of the STP facility does not make use of j
carbon dioxide as a suppression agent.
5.
While the estimate of the TB fire-induced core damage frequency is about 3 E-7 per reactor-year, the staff also notes that the STP facility has an additional offsite AC power line (138 KV) that will not be damaged by the I
postulated TB fires.
This additional 138 KV line is also expected to i
provide independent AC power to the in-plant safety system equipment i
following a TB fire scenario. The staff believes that the above site l
feature is unique to the STP facility, and has resulted in a significant reduction in overall fire core damage frequency estimates.
j 4.0 Conclusions 1
The questions raised by the staff and SNL have been satisfactorily addressed by the licensee.
Staff review has identified both modeling optimism and i
pessimism in the PSA. Overall, the modeling optimism and pessimism have been i
found to have negligible impact on the PSA's estimate of the overall core damage frequency.
The PSA has estimated the overall mean core damage frequency to be 1.7 E-4 per reactor-year. This frequency estimate is well within the range of core damage frequency estimates provided for similar i
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Westinghouse PWR facilities. However, it should be noted that, unlike other PWR facilities, the STP facility has been built to operate based on an "N+2" concept (except for postulated pipe break events and station blackout events).
The mean core damage frequency (1.7 E-4 per reactor-year) estimated for the i
STP facility is based on significant separation (both electrically and mechanically) of the three safety system trains (N+2 concept) for each unit of a
the two unit facility. However, the small difference between the core damage i
l l
i i
frequency estimate for the STP facility and that for other similar Westinghouse plants is primarily due to the fact that the siition blackout sequences at the SIP facility have been found to have only an "N+1" protection as is the case for other PWR facilities.
4.1 Internal Events The staff has reviewed the methods, data, and assumptions of the STP PSA, along with the licensee's response to the staff's questions during the PSA review. The review results indicate that there is no unique outlier that contributes significantly (a single sequence exceeding well above IE-4 per reactor-year) to the overall mean core damage frequency. This is primarily due to the additional redundancy for the safety systems and the provisions for separation of various safety systems which have been built into the facility.
However, one sequence out of many hundreds of sequences (a total of 225 sequences that have a frequency estimate greater than IE-7 per reactor-year) has been estimated to have a frequency estimate of more than IE-5 per reactor-year. This sequence is a station blackout sequence involving failure of the turbine-driven train of the AFW system.
it should be noted that, because of this sequence, the facility has been found not to have an "N+2" protection.
This is the major reason that the STP facility has the same core damage frequency estimate that could be expected for a plant built on a "N+1" concept. However, the staff does not consider a frequency estimate of IE-5 for any decay heat removal sequence as an outlier for any licensed nuclear faciTity in the U.S.
There are 21 sequences that have been estimated to have a frequency of more than IE-6 per reactor-year. These 21 sequences r.nd the rem-inder of thousands of sequences that have a frequency estimate of greater than li-8 per reactor-year collectively yielded a core damage frequency of more than IE-4 per reactor-year.
The remainder of sequences (those with frequency estimates of less than IE-8 per reactor year) contributed approximately 7E-5 per reactor year to the overall CDF.
This is a normally expected estimate for a typical Westinghouse PWR plant that has been built and licensed to operate on an "N+1" concept. This level of CDF can be expec'.d from normal random failures of safety system components.
4 The staff accepts the PSA's logical minimum number of safety system trains needed to prevent a core damage event following a transient or a LOCA event.
It also accepts, for accident management purposes, the steam generator' boil-dry time, and the seal failure time as calculated during the PSA review.
4.2 Fire Analysis Based on its review of the zone-specific details related to fire screening methods, fire data analysis, associated assumptions, and fire protection i
features bu'.lt into the STP fccility along with the licensee's response to the staff's three sets of RAls during the fire review process, the staff concludes that the frequency of a single fire sequence at the STP facility is not expected to exceed an estimate of about 2E-7 per reactor-year. The staff also concludes that, on the basis of a conservative analysis, the frequency of a a
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of about 2E-6 per reactor-year. single fire sequence at the STP facility is n impact of removing the geometry and severity factors used to model t propagation and suppression characteristics, from a pro uncertainty range of core damage frequencies resulting from fires.
staff's review of the zone specific fire analysis supports this conclusion The to the staff with the exception of improvements in docum review topics as indicated in the licensee's response to the staff's RAI.
The application of various screening criteria is useful only to assure that the frequency of a single fire sequence will not exceed an estimate of 2 E-7 contribution to the overall core damage frequency estimate and i uncertainty.
However, the staff believes that the fire risk analysis based on criterion) is useful in identifying and/or exploring significant vulnerabilities within the limited review resources.
The staff also concludes that the licensee's overall fire analysis is acceptable to demonstrate that a postulated fire in any given fire zone will not result in a core damage event with a frequency which will exceed, on a realistic basis, one percent of the overall transient-induced frequency estimate.
This statement is based on the zone-specific and realistic fire analyhis, and a systematic comparison of the above results with the corresponding transient-induced sequence analysis results. This statement is also based on the fact that the licensee's fire analysis reflects the location of the safety system equipment and the cable routing, which are based on a three train design concep(t. including three separate fire zones for each safety system)
The only exceptions to the above are the fire zones located in the MCR and the TB, for which detailed location-dependent analyses have been performed to demonstrate that the fires are inconsequential contributors to the core damage frequency.
There is no unique design feature that contributes a substantial increase in the overall core damage frequency due to the postulated zone-specific fires.
However, the unique design Nature related to the way of routing of the offsite AC power supply c es to the TB of the STP facility is found to have significantly reduced the overall fire-induced core damage frequency.
Attachments:
1.
Technical Evaluation Report 2.
Figure Principal Contributor:
- e. Chelliah Date: January 21, 1992 l
l l
l
h South Texas Facility 1
Total Core Damage Frequency: 1.7E-4 /RY i
60 ti 50
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40
(
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20 10 0-Loos of AC Tranelente 8GTR HMC Loss 125 DC Lose Other Evente g
E % of Total Frequency l
Figure 1: A Relative Contribution of Events to CDF Selsmic ' vents contribute only 1E l
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Sout1 Texas Facility Total Core Damage Frequency: 1.7E-4 /RY Loss of AC E
Other Events
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125 DC Loss Transients
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Figure 1: A Relative Contribution of Events to CDF Setemic Events Contribute only 1%.
r
Appendix B STAFF EVALUATION REPORT OF SOUTH TEXAS IPEEE SEISMIC 4
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