ML18095A662
| ML18095A662 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 12/28/1990 |
| From: | Crimmins T Public Service Enterprise Group |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| GL-88-20, NLR-N90231, NUDOCS 9101030351 | |
| Download: ML18095A662 (25) | |
Text
Public Service Electric and Gas Company Thomas M. Crimmins, Jr. Public Service Electric and Gas Company P.O. Box 236, Hancocks Bridge, NJ 08038 609-339-4700 Vice President - Nuclear Engineering DEC 2 8 1990 NLR-N90231 U.S. Nuclear Regulatory Commission Document Control Desk Washington, D.C. 20555 Gentlemen:
GENERIC LETTER 88-20, MILESTONE COMPLETION
SUMMARY
REPORT SALEM GENERATING STATION UNIT NOS. 1 AND 2 DOCKET NOS. 50-272 AND 50-311 Public Service Electric and Gas Company (PSE&G) responded to Generic Letter (GL) 88-20 in a letter dated November 1, 1989.
PSE&G stated that a brief summary report would be forwarded to the NRC upon completion of each milestone.
Attached is our report summarizing the updates to the Salem Generating Station (SGS) Level 1 PRA analysis. This report documents the completion of the second GL 88-20 milestone.
Please contact us if you have any questions regarding this transmittal.
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Document Control Desk 2 NLR-N90231 DEC 2 8 1990 c Mr. J. c. Stone Licensing Project Manager - Salem Mr. T. Johnson Senior Resident Inspector Mr. T. Martin,* Administrator Region I Mr. Kent Tosch, Chief New Jersey Department of Environmental Protection Division of Environmental Quality Bureau of Nuclear Engineering CN 415 Trenton, NJ 08625
NLR-N90231 SALEM GENERATING STATION UPDATE TO THE LEVEL 1 PRA ANALYSIS
SUMMARY
OF RESULTS
Table of Contents Section 1.0 Introduction 1 2.0 Systems Analysis 1 2.1 Initiating Event Identification and 1 Quantification 2.2 Event Tree Development 2 2.3 Fault Tree Development 3 2.4 Dependent Failure Analysis 3 2.5 Human Reliability Analysis 3 2.6 Data Development 4 2.7 Accident Sequence (Core Damage) 4 Quantification 2.8 External and Spatially Dependent 5 Internal Event Analysis 3.0 References 7
List of Tables Table T-1 SGS Plant Damage States 9 T-2 Unit 1 Dominant Core Damage Sequences 12 T-3 Unit 2 Dominant Core Damage Sequences 14 T-4 Core Damage Frequency Comparison With 17 Other studies
List of Figures Figure Page F-1 Salem PRA Task Flow Chart 18 F-2 Sample Large LOCA Event Tree 19
ANALYSIS OF RESULTS
1.0 INTRODUCTION
A probabilistic risk assessment (PRA) of Salem Generating Station (SGS) was performed during the period of July 1987 through August 1988. The PRA for both Salem Units was updated during the period of August 1990 through November 1990. The SGS PRA includes a detailed analysis of core damage potential (Level 1 PRA, based on NUREG/CR-2300 terminology) including external events. External events analysis included a comprehensive screening of all types of external and spatially-dependent internal events, and a more detailed analysis of those events not screened out; internal flooding, internal fire and seismic. The analysis of containment response to core damage sequences and radionuclide release from the core (Level 2 PRA) will be completed at a later date.
The original SGS PRA included a detailed analysis of both units as they existed on July 1, 1987 (June 1988 for external events).
The update performed in 1990 addressed design changes incorporated from the original PRA completion date until August 1990.
Plant risk was analyzed for both high (startup) and low (shutdown) power operation. Accidents occurring during plant refueling or extended shutdowns were not considered. This approach is consistent with NRC guidance on individual plant examinations.
2.0 SYSTEMS ANALYSIS 2.1 Initiating Event Identification and Quantification The comprehensive engineering evaluation [PRA Procedures Guide (Reference 3.1)] methodology was used to identify initiating events at SGS. This methodology involves a survey of initiating events from other studies, and a detailed analysis of the SGS design and operational experience. We included a comprehensive search for support system failures that cause a plant trip and affect safety systems. Such support failures are termed special initiators.
The SGS study yielded 61 internal initiating events. These events were grouped into categories to reduce the event tree development effort.
Event frequencies were obtained by several methodologies. The general transients were quantified using SGS-specific trip data (1982 through 1989) to update (single-stage Bayesian update) 1
industry-wide generic frequencies. Special initiators, such as loss of the Service Water (SW) system or Component Cooling (CC) system, were quantified by reevaluating the fault trees developed for these systems. LOCAs were quantified based on a survey of past PRAs. The resulting yearly frequencies of 5.4 (Unit 1) and 8.1 (Unit 2), for all initiators, compare favorably with industry-wide experience.
2.2 Event Tree Development Event trees were developed for most of the initiating event categories. Several categories can lead directly to core damage and therefore did not require event tree development.
Event trees graphically depict significant accident scenarios, starting with initiators and branching out into various combinations of safety system successes and failures. The various paths through the event trees are termed accident sequences. Outcomes involve either a successfully mitigated sequence or core damage. Each core damage sequence is assigned to a plant damage state (PDS) from Table T-1.
The support systems needed for the success of each top event are included in the system fault trees for each frontline system.
This methodology is called the "small event tree/large fault tree" or "fault tree linking" approach. It results in a relatively small number of accident sequences, but large and detailed fault trees.
Containment fan cooler and Containment Spray (CS) system status was modeled for those sequences requiring containment heat removal, or that lead to core damage. The containment isolation function was modeled as part of this update. These enhancements resulted in a complete characterization (available or unavailable) of containment systems that are important in determining the amount of radionuclide release as a result of core damage sequences.
Based on this information and other accident characteristics, all of the core damage sequences were assigned to PDSs. These PDSs characterize the sequences in terms of phenomena that are important to subsequent containment analyses.
A description of the PDSs is presented in Table T-1.
Most of the event trees are typical of PRA studies. However, several of the event trees are very simple in structure. These event trees deal with plant trips caused by the loss of systems such as SW or HVAC, which, if not recovered , can lead directly to core damage. The event trees developed for these initiators also model system recovery. If recovery is not possible, then the sequences were assumed to lead directly to core damage.
2
Loss of Reactor Coolant Pump (RCP) seal cooling, and subsequent RCP seal LOCAs, were modeled during station blackout and following other transients. If all seal cooling is lost, a simple RCP seal LOCA model was used that assumed a 0.5 probability of a 250 gpm LOCA/RCP at 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and a 1.0 probability at the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> point.
2.3 Fault Tree Development Many of the systems modeled in the event tree top events were developed into detailed fault trees. The fault trees were used to develop and depict the logical interrelations of basic events (e.g., pump, valve, electrical faults) that lead to system failure. A total of 140 fault trees were developed for 20 systems.
2.4 Dependent Failure Analysis The PRA Procedures Guide lists nine different types of dependent failures that should be considered in a comprehensive PRA. The SGS PRA includes an accounting for each type. The dependent failure data developed, and the treatment of this data in quantifying the contribution from dependent failure events, is consistent with that recommended by the NRC for individual plant examinations (Reference 3.3).
Parametric modeling of dependent failures of similar components was performed, in addition to explicit modeling of known dependent failure mechanisms. This involved the identification of similar active components (e.g., valves, pumps) within systems, and adding dependent failure events to the system fault trees. Quantification of these parametric dependent failure events was performed using the multiple Greek letter methodology (Reference 3.2).
2.5 Human Reliability Analysis The SGS PRA Human Reliability Analysis (HRA) task was divided into three subtasks: screening analysis of human errors before an accident (e.g., miscalibration and failure to restore components following test or maintenance), screening analysis of operator errors during an accident, and refined analysis of dominant human errors. The same operator actions were applied to the Unit 1 and Unit 2 models.
The miscalibration and restoration errors were quantified on a screening basis, using the Technique for Human Error Rate Prediction (THERP), and the Handbook of Reliability with Emphasis on Nuclear Power Plant Operations (Reference 3.4).
Operator errors during an accident were subdivided into operator errors modeled in the fault trees, operator errors modeled as top 3
events in the event trees, and recovery actions applied to the sequence cutsets. Operator errors modeled in the fault trees were quantified (screening basis) based on skill-, rule-, or knowledge-~ased actions, as outlined in the Systematic Human Actions Reliability Procedure (SHARP) screening methodology (Reference 3.5). This methodology was modified somewhat to reflect time-reliability correlation concerns (Reference 3.6).
Operator errors modeled in the event trees were screened based on: a survey of previous PRA HRA results, the modified SHARP methodology, or other methods. Recovery actions were screened based mainly on the modified SHARP methodology. Recovery actions were screened based mainly on the modified SHARP methodology.
Twenty of the human errors important to core melt frequency were refined using the Accident Sequence Evaluation Program (ASEP) nominal HRA procedure (Reference 3.7).
2.6 Data Development Data development involves quantification of the failure probabilities of basic events in the fault trees, and any event tree top events not developed into fault trees. A comprehensive generic database was developed based on all available sources.
This database was then supplemented by SGS-specific data on: test and maintenance outages, pumps in most systems, containment fan cooling units; diesel generators, and the gas turbine.
SGS-specific test and maintenance data were used directly. Pump and diesel generator failure rates were obtained by updating generic failure rates (single-stage Bayesian update) using the SGS-specific data.
2.7 Accident Seqµence Ccore damage) Quantification Accident sequences leading to core damage were quantified by using the fault tree linking technique [PRA Procedure Guide (Reference 3.8)]. The SETS computer code (References 3.8 and 3.9) was used to perform the accident sequence cutset Boolean reduction and cutset quantification. cutsets obtained from the SETS runs were then modified by: removing combinations of test and maintenance events that occurring together would violate Technical Specifications, removing cutsets that were operationally impossible, and adding recovery factors wherever appropriate.
- The results of the quantification are indicated in Tables T-2 and T-3. The total core damage frequency from internal events is 4.8E-5 (Unit 1) and 5.2E-5 (Unit 2) per year.
The updated PRA model results reflect some major changes when compared with the 1987 model results. The emergency switchgear ventilation system success criteria have been relaxed, based on a 4
reanalysis of the heat removal calculations. The previous requirement of 2 of 3 supply fans and 2 of 3 exhaust fans at each elevation, was changed to 1 of 3 supply fans and 1 of 3 exhaust fans at the 84 foot elevation, and 1 of 2 of the large exhaust fans at the 64 foot elevation. This less restrictive system success criteria, significantly reduced the highest frequency core damage sequence from the 1987 results. A second change involves the charging pump dependance on the cc system for pump seal cooling. Further investigation revealed that the charging pumps can operate without seal cooling. This break in dependency significantly reduced the second highest frequency core damage sequence from the 1987 model.
There are (12) Unit 1 and (15) Unit 2 core damage sequences with frequences greater than 1.0E-6 per year. The dominant initiating events for both Units are Station Blackout and Loss of Switchgear HVAC. These two initiators contribute more than 70% to the total internal events core damage frequency for both Units. Transients with the Power Conversion System available contribute approximately 9%. LOCAs contribute about 9% to the core damage frequency for both Units.
The SGS core damage frequencies for internal events are compared with other PWR PRAs in Table T-4. Overall results for SGS are typical of PWRs.
2.8 External and Spatially Dependent Internal Event Analysis The external and spatially dependent internal event analysis task considered core damage contributions from events internal and external (i.e., fire, flooding, seismic, tornadoes, hurricanes, and transportation accidents) to the plant. This comprehensive analysis used several screening approaches to eliminate events from further consideration. Seismic, internal fire, and internal flooding could not be screened out and required refined analyses. Analysis conclusions are described below.
The internal flooding analysis looked at flood-related events such as: equipment submergence, water spray, stream flooding, pipe whip, and inadvertent actuation of fire sprinkler systems.
Sources of flooding included leakage from: piping, heat exchangers, tanks, gaskets, valve stems, normally running pumps, and isolation valves. For areas analyzed in detail, the flooding frequencies resulted from an inventory of the applicable pipes and components in the area, previously determined leakage failure rates, and internal events analysis Appendix c data. The analysis determined that each Salem Unit has six flooding sequences with frequencies greater than 1.0E-7 per year, and a total core damage frequency from internal flooding of 1.8E-5 per year.
5
y Flood-initiated core damage sequences, from the 1988 analysis, were reexamined as part of this PRA update. Three sequences with frequencies previously determined to be greater than 1.0E-7, were reclassified as less than 1.0E-7. This reclassification resulted from an in-depth review that included a plant walkdown.
These three sequences are discussed in more detail below.
The first sequence only applied_to Unit 1 *. It involved a steamline break outside the 84 foot elevation switchgear room, and was assumed to propagate into the switchgear area. The more recent review revealed that the only water source in the corridor is a low pressure hot water source. This source is not in operation all year and could not supply sufficiently high energy steam for the scenario to progress to core damage. Additionally, the switchgear room is closed off from the corridor and no penetrations exist.
The second sequence involved a pipe break in a Service Water bay that fortuitously sprays all three pumps in the bay. The sequence included random failures (i.e., not related to the spray) of the pumps in the other bay that would lead to a loss of all Service Water and eventual core damage. The most recent review revealed that the three pumps are physically arranged in a triangle within the bay. The chances of spraying all three pumps from a single break is very low. Service Water header pressure is indicated in the control room, and a low pressure condition generates an alarm. Operator action to remove the affected pumps from service would further reduce the frequency of the scenario progressing to pump failure. Based on these arguments, the sequence frequency was reduced from 1.65E-5 to less than 1.0E-7 per year.
The third highest frequency sequence, from the 1988 analysis, involved leakage from the cc system that results in cc system train isolation, with subsequent loss of RCP thermal barrier cooling and charging pump seal cooling. The charging pump loss also eliminates RCP seal injection flow. A resultant RCP seal LOCA with failure of cold leg recirculation (high pressure) was assumed to result in core damage. The 1990 review revealed that the charging pumps can operate successfully without seal cooling, thereby preventing the loss of RCP seal injection. Breaking the charging pump dependance on the CC system for seal cooling reduces the sequence frequency below 1.0E-7 per year.
Currently, four Unit 1 and three Unit 2 internal flooding core damage sequences have frequencies greater than 1.0E-6 per year.
Internal fire analysis for SGS involved a comprehensive review of fire areas. Fire ignition frequencies for each fire area were based on contributions from the following: welding, motors, motor control centers (MCC), hot pipe surfaces, cabling, and electrical panels. Fire growth to damaging sizes was modeled using a 6
wr.:-- I f' six-parameter fire model. This model incorporated such factors as: transient combustible occupancy times, transient combustible area coverage, combustible ignitability, potential for cable damage, and automatic/manual suppression~ Cable and electrical panel fires were modeled to a lesser degree. Random component failures, not associated with the fire, were considered in the core damage evaluation.
The 1990 review did not change the results obtained in the original analysis. Nine Unit 1 and sixteen Unit 2 sequences have core damage frequencies greater than 1.0E-7 per year. The dominant fire areas include the relay room, control room, and the electrical penetration areas. The total core damage frequency from internal fires is 6.0E-5 per year for both Salem Units.
Seismic risk analysis for SGS involved the following: a seismic hazard analysis, a systems analysis to model both random failures and seismic-induced failures, and plant-specific fragility evaluations on important components and structures. Dominant core damage contributors include: control room ceiling panels, 115vac vital instrument buses, ventilation vital control center cabinets, Safeguards Equipment Control (SEC) cabinets in the relay room, SW system vital control center cabinets, diesel generator vital control center and local control cabinets, cc system surge tank, SW system intake structure and HVAC fans. The seismic-induced core damage frequency for each Unit is 3.lE-5 per year.
3.0 REFERENCES
3.1 PRA Procedure Guide. NUREG/CR-2300, January 1983.
3.2 Classification and Analysis of Reactor Operating Experience Involving Dependent Events. EPRI NP-3967, Electric Power Research Institute, June 1985 3.3 Procedures for Treating Common cause Failures in Safety and Reliability Studies, Procedural Framework and Examples. PLG, Inc., January 1988. NUREG/CR-4780, Vol.1, EPRI NP-5613, 3.4 Handbook of Human Reliability Analysis With Emohasis on Nuclear Power Plant Operation. NUREG/CR-1278, August 1983.
3.5 Systematic Human Action Reliability Procedure (SHARP).
EPRI NP-3583, Electric Power Research Institute, June 1984.
7
3.6 Post Event Human Decision Errors: Operator Action Tree/Time Reliability Correlation. NUREG/CR-3010, November 1982.
3.7 Accident Sequence Evaluation Program Human Reliability Analysis Procedure. NUREG/CR-4772, February 1987.
3.8 SETS Reference Manual* __ NUREG/CR-4213, May 1985.
3.9 SETS User's Manual for Accident Sequence Analysis.
NUREG/CR-3547, January 1984.
3.10 Development of Transient Initiating Event Frequencies for Use in Probabilistic Risk Assessment.
NUREG/CR-3862, June 1984.
3.11 Evaluation of Station Blackout Accidents at Nuclear Power Plants. NUREG-1032 (Draft for Comment), May 1985.
3.12 Guidelines and Technical Bases for NUMARC Initiatives for Addressing Station Blackout at Light Water Reactors. NUMARC-8700, November 1987.
8
Table T-1 SGS Plant Damage States A - Plant Damage State (PDS) Identifier B - Primary System Pressure at Head Failure C - Coolant Injection/Recirculation Availability D - Containment Cooling E - Containment Spray F - Containment Isolation G - Notes A ~ .Q .Q.* ~ F ~
ClA High Injection Yes Yes Yes ClB High Injection Yes No Yes ClC High Injection No Yes Yes ClD High Injection No No Yes ClE High Injection Yes Yes No ClF High Injection Yes No No ClG High Injection No Yes No ClH High Injection No No No C2A High Inj/Recirc Yes Yes Yes C2B High Inj/Recirc Yes No Yes C2C High Inj/Recirc No Yes Yes C2D High Inj/Recirc No No Yes C2E High Inj/Recirc Yes Yes No C2F High Inj/Recirc Yes No No 9
Table T-1 (cont.)
SGS Plant Damage States A B c .Q E F ,{i C2G High Inj/Recirc No Yes No C2H High Inj/Recirc No No No C3A High None Yes Yes Yes C3B High None Yes No Yes C3C High None No Yes Yes C3D High None No No Yes C3E High None Yes Yes. No C3F High None Yes No No C3G High None No Yes No C3H High None No No No C4A Low Injection Yes Yes Yes C4B Low Injection Yes No Yes C4C Low Injection No Yes Yes C4D Low Injection No No Yes C4E Low Injection Yes Yes No C4F Low Injection Yes No No C4G Low Injection No Yes No C4H Low Injection No No No CSA Low Inj/Recirc Yes Yes Yes C5B Low Inj/Recirc Yes No Yes C5C Low Inj/Recirc No Yes Yes 10
Table T-1 (cont.)
SGS Plant Damage States A B .Q 1J E .l G C5D Low Inj/Recirc No No Yes C5E Low Inj/Recirc Yes Yes No C5F Low Inj/Recirc Yes No No C5G Low Inj}Recirc No Yes No C5H Low Inj/Recirc No No No C6A Low None Yes Yes Yes C6B Low N.one Ye.s No Yes C6C Low None No Yes Yes C6D Low None** No No Yes C6E Low None Yes Yes No C6F Low None Yes No No C6G Low None No Yes No C6H Low None No No No ClA' through C6H' Similar to ClA thru C6D but with unisolated SGTR C7 Interfacing system LOCA (RHS) 11
Table T-2 Unit 1 Dominant Core Damage Sequences Core Damage Plant Core Damage Sequence Frequency Damage Sequence Identifier Per Year State Description
- 1. TvsRvsRd2 8.6E-6 CJD Loss of switchgear ventilation (VSW),
failure to recover VSW within 2 H, and failure to provide alternate cooling by opening doors and using portable fans.
- 2. TDENr1RsLNr4 6.4E-6 C6D Station Blackout, RCP seal LOCA at 2 H, and failure to recover offsite power by 4 H.
J. TNEVSW J.9E-6 CJD Transient, loss of vsw and failure to provide alternate cooling.
- 4. TDENr1Nr4Nr6 J.2E-6 C6D Station Blackout, RCP seal LOCA at 4 H, and failure to recover offsite power within 6 H.
- 5. TDEPc4Nr1 2.6E-6 CJA Station Blackout, failure of PORV to reclose, and failure to recover power within 6 H.
- 6. TDEPC4NR1NR4NR6 1.9JE-6 CJD Station Blackout, PORV LOCA, failure to recover offsite power in 6 H.
- 7. TDEHA2NR1NR4NR6 1.9E-6 CJD Station Blackout, loss of aux. feed sys.(AFS), failure to recover offsite power in 6 H.
12
Table T-2 (cont.)
Unit 1 Dominant Core Damage Sequences Core Damage Plant Core Damage Sequence Frequency Damage Sequence Identifier Per Year state Description
- 8. S1Uh2 1.6E-6 C6A Intermediate LOCA with failure of high pressure coolant injection.
- 9. s2WhYsr 1.5E-6 C4A small LOCA, failure of cold leg recirc.
(high pressure), and failure of containment spray sys. (CSS) recirc.
10.SlWhYsr 1.5E-6 C4A Intermediate LOCA, failure of cold leg recirc. (high pressure), and failure of CSS recirc.
11.TtRsc 1.4E-6 C6A Transient with power conversion sys.
(PCS) available and failure of RCP seal cooling (no high pressure coolant injection available).
12.TFBlFBP0-40 1.lE-6 ClA Feedwater l.ine break, 86 left unisolated, PORVs fail to open for feed-and-bleed cooling.
Total 3.6E-5 (75% of total core damage frequency) 13
Table T-J Unit 2 Dominant Core Damage Sequences Core Damage Plant Core Damage Sequence Frequency Damage Sequence Identifier Per Year State Description
- 1. TvsRvsRd2 8.6E-6 CJD Loss of VSW, failure to recover VSW within 2 H, and failure to provide alternate cooling by opening doors and using portable fans.
- 2. TDENr1RsLNr4 6.4E-6 C6D Station Blackout, RCP seal LOCA at 2 H, and failure to recover offsite power by 4 H.
J. TNEVSW 3.9E-6 CJD Transient, loss of VSW and failure to provide alternate cooling.
- 4. TDENr1Nr4Nr6 J.2E-6 C6D Station Blackout, RCP seal LOCA at 4 H, and failure to recover offsite power within 6H.
- 5. TDEPc4Nrl 2.6E-6 CJA Station Blackout, failure of PORV to reclose, and failure to recover offsite power within 6 H.
- 6. TtRsc 2.0E-6 C6A Transient with PCS available and failure of RCP seal cooling (no high-pressure coolant injection available).
14
Table T-J (cont.)
Unit 2 Dominant Core Damage Sequences Core Damage Plant Core Damage Sequence Frequency Damage Sequence Identifier Per Year State Description
- 7. TDEPC4NR1NR4NR6 1.9JE-6 CJD Station Blackout, PORV LOCA, failure to recover offsite power in 6 H.
- 8. TDEHA2NR1NR4NR6 1.9E-6 CJD Station Blackout, loss of AFS, failure to recover offsite power in 6 H.
- 9. S1Uh2 1.6E-6 C6A Intermediate LOCA with failure of high pressure coolant injection.
10.S2WhYsr 1.5E-6 C4A Small LOCA, failure of cold leg recirc. (high pressure), and failure of CSS recirc.
11.SlWhYsr 1.5E-6 C4A Intermediate LOCA, failure of cold leg recirc. (high pressure), and failure of CSS recirc.
12.TPHMHAP2 1.4E-6 C4A Transient with PCS unavailable, loss of all secondary cooling.
lJ.TPRSC 1. 2E-6 C6A Transient with PCS unavailable, failure of RCP seal cooling (no high pressure coolant injection available).
15
1-* I "'
Table T-3 (cont.)
Unit 2 Dominant Core Damage Sequences Core Damage Plant Core Damage Sequence Frequency Damage Sequence Identifier Per Year State Description 14.TPHMAUHYFYSI 1.2E-6 CJB Transient with PCS unavailable, loss of secondary cooling, failure of high pressure injection, CFCUs, and spray injection.
15.TFBlFBP0-40 1.lE-6 C1A Feedwater line break, 86 left unisolated, PORVs fail to open for feed-and-bleed cooling.
Total 4.0E-5 (77% of total core damage frequency) 16
Table T-4 Core Damage Frequency Comparison With Other studies Internal Events Core Damage PRA Study Frequency/Yr Cmeanl a
- 1. Crystal River 3 (IREP) 3.7E-4
- 2. Seabrook (Utility) 1.7E-4
- 3. Calvert Cliffs (IREP) 1.3E-4
- 4. Indiari Point 3 (Utility) 1.2E-4
- 5. Indian Point 2 (Utility) 8.7E-5
- 6. SGS 2 (Utility) 5.2E-5
- 7. AN0-1 (!REP) 5.0E-5
- 8. Oconee (NSAC) 5.0E-5
- 9. SGS 1 (Utility) 4.8E-5
- 10. Millstone 3 (Utility) 4.5E-5
- 11. Zion (Utility) 3.4E-5 a
For PRAs with external event analyses (including internal fire, internal flooding, and seismic), only the result from the internal events is presented.
17
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- 6. AYf NONE
- 7. AYfYsr C5C 8, AYfYsrYci C5G
- 9. AYflll C4A
- 10. AYfllLYci C4E
- 11. AYfllLYsr C4C
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- 13. AYfYsi NONE
- 14. AYfYsiYsr C5D
- 15. AYfYsiYsrYci C5H
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- 18. AYfYsillLYsr C4D
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- 2. AULYsr C6A
- 3. AULYsrYci C6E 4-. *'Ai.IL Ysi C6B
- 5. AULYsiYci C6F
- 6. AULYf C6A
- 7. AUlYfYci C6E
- 8. AULYfYsr C6C 9*; AULYfYsrYci C6G
- 0. AULYfYsi C60
- 1. AULYfYsiYci C6H
- 2. AUa2 C6A
- 3. AUa2Yci C6E
- 4. AUa2Ysr C6A
- 5. AUa2YsrYci C6E
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- 7. AUa2YfYsiYsrYci C6H 19