ML18101A599
| ML18101A599 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 03/15/1995 |
| From: | Olshan L Office of Nuclear Reactor Regulation |
| To: | Eliason L Public Service Enterprise Group |
| References | |
| NUDOCS 9503280061 | |
| Download: ML18101A599 (15) | |
Text
..
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555--0001 Hr. Leon R. Eliason Chief Nuclear Officer & President-Nuclear Business Unit Public Service Electric and Gas Company P.O. Box 236 Hancocks Bridge, NJ 08038 March 15, 1995
SUBJECT:
REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF REACTOR SHUTDOWN AND TWO AUTOMATIC ACTUATIONS OF THE SAFETY INJECTION SYSTEM AT SALEM NUCLEAR GENERATING STATION, UNIT 1
Dear Mr. Eliason:
Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) analysis of an automatic reactor shutdown and two automatic actuations of the safety injection system which occurred at the Salem Nuclear Generating station, Units 1 and 2 on April 7, 1994, and was
~eported in Licensee Event Report (LER) No. 94-007-01 (Enclosure 1). This analysis was prepared by our contractor at the Oak Ridge National Laboratory (ORNL).
The results of this preliminary analysis indicate that this event may be included in the 1994 Precursor Report.
In assessing operational events, an effort was made to make the ASP models as realistic as possible regarding the specific features and response of a given plant to various accident sequence initiators.
We realize that licensees may have additional systems and emergency procedures, or other features at their plants that might affect the analysis. Therefore, we are providing you an opportunity to review and comment on the technical adequacy of the preliminary ASP analysis, including the depiction of plant equipment and equipment capabilities.
Upon receipt and evaluation of your comments, we will revise the conditional core damage probability calculations where necessary to consider the specific information you have provided.
The object of the review process is to provide as realistic an analysis of the significance of the* event as possible.
In order to incorporate your comments and meet our schedule for issuance of the 1994 Precursor Report, you are requested to complete your review and to provide any comments within 30 days of receipt of this letter.
We have also enclosed several items to facilitate your review.
contains specific guidance for performing the requested review, identifies the criteria which we will apply to determine whether any credit should be given in the analysis for the use of licensee-identified additional equipment or specific actions in recovering from the event, and describes the specific information that you should provide to support such a claim. is a copy of LER No. 94-007-01, which documented the event.
270002 r-- 95032800~~ 6~856~72 PDR ADO PDR s
The final resolution of each licensee's comment on the preliminary ASP analyses will be documented in a separate appendix of the 1994 Precursor Report, NUREG/CR-4674.
Public Service Electric and Gas Company is on the distribution list for NUREG/CR-4674.
Please contact me at {301) 415-1419 if you have any questions regarding this request. This request is covered by the existing OMB clearance number {3150-0104) for NRC staff followup review of events documented in LERs.
Your response to this request is voluntary and does not constitute a licensing requirement.
Docket No.
50~272
Enclosures:
As stated cc w/encls:
See next page DISTRIBUTION Docket File PUBLIC PDI-2 Reading SVarga JZwol inski SVarga LOlshan MO'Brien OGC ACRS{4)
JWhite, RGN-I OFFICE NAME DATE "l:; :!! 95 DI-2 PM
,/ LOlshan:rb B tl""l:>/95 OFFICIAL RECORD COPY DOCUMENT NAME:
SAPRECUR.GEN Sincerely,
/S/
Leonard N. Olshan, Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
L. Eli as on The final resolution of each licensee's comment on the preliminary ASP analyses will be documented in a separate appendix of the 1994 Precursor Report, NUREG/CR-4674.
Public Service Electric and Gas Company is on the distribution list for NUREG/CR-4674.
Please contact me at (301) 415-1419 if you have any questions regarding this request. This request is covered by the existing OMB clearance number (3150-0104) for NRC staff followup review of events documented in LERs.
Your response to this request is voluntary and does not constitute a licensing requirement.
Docket No. 50-272
Enclosures:
As stated cc w/encls:
See next page Sincerely,
- ie um af)f.;A Leonard N. Olshan, Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Mr. Leon R. El i a son e Public Service Electric & Gas Company cc:
Mark J. Wetterhahn, Esquire Winston & Strawn 1400 L St~eet NW.
Washington, DC 20005-3502 Richard Fryling, Jr., Esquire Law Department - Tower SE 80 Park Place Newark, NJ 07101 Mr. John Summers General Manager - Salem Operations Salem Generating Station P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. J. Hagan Vice President - Nuclear Operations Nuclear Department P.O. Box 236 Hancocks Bridge, New Jersey 08038 Mr. Charles S. Marschall, Senior Resident Inspector Salem Generating Station U.S. Nuclear Regulatory Commission Drawer I Hancocks Bridge, NJ 08038 Dr. Jill Lipoti, Asst. Director Radiation Protection Programs NJ Department of Environmental Protection and Energy CN 415 Trenton, NJ 08625-0415 Maryl and Off..i.,.ce of People's Counsel 6 St. Paul Street, 21st Floor Suite 2102 Baltimore, Maryland 21202 Ms; R. A. Kankus Joint Owner Affairs PECO Energy Company 965 Chesterbrook Blvd., 63C-5 Wayne, PA 19087 Mr. S. LaBruna Vice President - Nuclear Engineering Nuclear Department P.O. Box 236 Hancocks Bridge, New Jersey 08038 e
Salem Nuclear Generating Station, Units 1 and 2 Richard Hartung Electric Service Evaluation Board of Regulatory Commis6ioners 2 Gateway Center, Tenth Floor Newark, NJ 07102 Regional Administrator, Region I U. S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, PA 19406 Lower Alloways Creek Township c/o Mary 0. Henderson, Clerk Municipal Building, P.O. Box 157 Hancocks Bridge, NJ 08038 Mr. Frank X. Thomson, Jr., Manager Licensing and Regulation Nuclear Department P.O. Box 236 Hancocks Bridge, NJ 08038 Mr.. David Wersan Assistant Consumer Advocate Office of Consumer Advocate 1425 Strawberry Square Harrisburg, PA 17120 Ms. P. J. Curham MGR. Joint Generation Department Atlantic Electric Company P.O. Box 1500 6801 Black Horse Pike Pleasantville, NJ 08232 Carl D. Schaefer External Operations - Nuclear Delmarva Power & Light Company P.O. Box 231 Wilmington, DE 19899 Public Service Commission of Maryland Engineering Division Chief Engineer 6 St. Paul Centre Baltimore, MD 21202-6806
A.1-1 A~l 272/94-007 Rev. 1 Event
Description:
Reactor trip, two safety injection actuations, and solid pressurizer operation Date of Event:
April 7, 1994 Plant:
Salem 1 A.1.1 Summary Salem 1 was reducing power in preparation for tal<lng the main turbine off-line becatise of circulating water (CW) system problems caused by large quantities of river marsh grass and debris that were clogging the intake structure. Following an unexpected reactor trip, two safety injections were automatically initiated.
The first, caused by a main steam pressure pulse, resulted in the pressurizer filling* completely with water (solid condition). The second was caused by a rapid decrease in reactor system pressure, when a secondary safety valve opened with the pressurizer solid.
The pressurizer power operated relief valves (PORVs) actuated over 300 times during event and passed a significant quantity of water. The conditional core damage probability estimated for the event is 8.4 x 10-s. The relative significance of this event compared to other postulated events at Salem is shown in Figure A.1.0-(to be provided in final report).
A.1.2 Event Description Salem I.was operating at reduced power on April 7, 1994, because seasonal river marsh grass and debris were severely affecting the CW intake structure. A load reduction was in progress to take the main turbine off-line following the clogging of several traveling screens and numerous CW piimp trips. Reactor power was reduced to 7% by inserting control rods and by increasing the boron concentration in the reactor coolant system.
Initially, during the downpower maneuver, operators reduced turbine power ahead of reactor power and the resulting power mismatch caused a slightly higher than normal reactor coolant system (RCS) temperature.
AtJ043 hours, the nuclear shift supervisor (NSS) directed the operator controlling reactor power to go to the.
electrical distribution panel and begin shifting plant loads to offsite power sources. At the time, the control room crew believed the plant was stable; however, they failed to recognize that reactor power was still decreasing due to the delayed effect of the boron that had been added. This led to a reversal of the power mismatch and a decreasing RCS temperature.
At 1045 hours0.0121 days <br />0.29 hours <br />0.00173 weeks <br />3.976225e-4 months <br />, the NSS identified the resulting overcooling condition, went to the reactor control panel, and -
began withdrawing control rods to raise RCS temperature. Then he turned over rod control operation back to the original operator. This operator continued to withdraw the control rods, and reactor power increased from approximately 7 to 25% of full power. Since the reactor had dropped below 10% power, the power range high neutron flux-low setpoint trip had automatically reinstated establishing a 25% power reactor trip setpoint. At I 04 7 hoilrs, reactor power reached this level and the reactor tripped.
Almost immediately following the reactor trip, an automatic safety injection (SI) signal actuated. The SI occurred only on the train A logic and was caused by high steam flow coincident with low RCS temperature.
Th.e*licensee later determined that the high steam flow signal was the result of a short-duration pressure pulse created in the main steam lines by the closing of the turbine stop valves. when the turbine tripped. Because of the short duration of the pressure pulse, only SI train A actuated and a nUlllber of components had to be
A.1-2 manually placed in their SI positions. This included some of the main steam isolation valves (MSIVs) and main feedwater isolation valves, which were closed from the control room. The main feedwater (MFW) pumps were also manually tripped. SI train A was reset with its automatic actuation in the "blocked" position. SI train B actuation logic remained armed.
Once the MSIVs were closed, the primary coolant system continued to heat up because of decay heat and the running reactor coolant pumps. This caused steam generator (SG) pressure to increase. Due to a design problem in the valve controllers for the main steam atmospheric relief valves, these valves did not automatically open to control SG pressure, nor did the secondary nuclear operator manually open the valves as required to prevent fifting the SG safety relief valves (the operator was occupied with the many manual valve repositionings required after the single-train SI actuation).
As a result of the primary heatup and the water added by the SI, the pressurizer filled to solid or near-solid conditions, and the pressurizer power-operated relief valves (PORVs) periodically opened to control primary pressure. Shortly before 1126 hours0.013 days <br />0.313 hours <br />0.00186 weeks <br />4.28443e-4 months <br />, SG pressure increased to the safety valve lift setpoint in the No. 11 SG.
The opening of two SG safety valves caused a primary system cooldown, and due to the solid water state of the primary system, primary system pressure rapidly decreased. At 1126 hours0.013 days <br />0.313 hours <br />0.00186 weeks <br />4.28443e-4 months <br />, primary pressure decreased to the SI setpoint of 17~5 psig. Since train B of the SI logic remained armed, a second automatic SI was actuated by that train of logic. The operators had also identified the decreasing RCS pressure and manually initiated SI moments after the automatic actuation.
At 1149 hours0.0133 days <br />0.319 hours <br />0.0019 weeks <br />4.371945e-4 months <br />, the pressurizer relief tank (PRT) rupture disk ruptured to relieve the increasing tank pressure that resulted from the volume of primary inventory discharged through the PORVs. The PORVs actuated over 300 times to relieve water to the PRT. Following the event, both PORVs were inspected. The stem of PORV PR2 was galled and there was severe wear along part of the plug and cage. Some wear was also found on the plug and cage of PORV PRl, and there was a possible cut in the valve seat. Damaged parts were to be replaced prior to the unit's returning to power. There was no indication that any primary safety valve lifted during the event.
The operators were faced with the task of cooiing down the plant from normal operating temperature and
- pressure without having a steam bubble in the pressurizer to accommodate pressure fluctuations. Once SI was terminated, operators controlled primary pressure through a combination of charging and letdown using the chemical and volume control system. Significant variations in RCS pressure in response to minor temperature changes were prevented by keeping the reactor coolant pumps (RCPs) running and by recovering a bubble in the pressurizer prior to initiating a plant cooldown (with the RCPs tripped, a one-degree change in temperature could have resulted in a 100 psi change in RCS pressure).
At 1316 hours0.0152 days <br />0.366 hours <br />0.00218 weeks <br />5.00738e-4 months <br />, the licensee voluntarily declared an Alert in order to assure the actuation of the Technical Support Center (TSC) to provide the operators with any technical assistance that might be required as they cooled down the plant. By 1410 hours0.0163 days <br />0.392 hours <br />0.00233 weeks <br />5.36505e-4 months <br />, the TSC had been staffed, and at 1511 hours0.0175 days <br />0.42 hours <br />0.0025 weeks <br />5.749355e-4 months <br /> the operators restored a bubble in the pressurizer.
Guidance for reestablishing a steam space in the pressurizer for pressure control was available to the operators by use of the Critical Safety Function Coolant Inventory Status Tree yellow path "Response to High Pressurizer Level." However, this was not used. The operators were unaware of a yellow path to establish a pressurizer bubble. Instead, the operators continued through the Emergency Operating Procedure (EOP) for SI termination and, with technical support from the TSC, reestablished the steam space in the pressurizer outside of direct EOP guidance.
The Salem and Hope Creek service water systems were unaffected by the river debris that clogged the Salem CW intake structure.
A.1-3 Addition information concerning this event is provided in Augmented Inspection Team (AIT) Report 50-272-94-80 dated June 24, 1994.
A.1.3 Additional Event-Related Information The Salem charging system includes three pumps: two centrifugal charging pumps and one positive displacement pump. The shutoff head of the centrifugal pumps is 2670 psig, well above the PORV setpoint of 2330 psig.
The AIT report for the event noted that the Salem FSAR analyses include an allowance of 20 min to reset SI following inadvertent actuations. Westinghouse Electric Corporation (the NSSS vendor) analyses assume a shorter, 10 min operator response time. A June 30, 1993, letter from Westinghoi.ise to the licensee noted that potentially nonconservative assumptions had been used in the licensing analysis of the Inadvertent Operation of the ECCS at Power accident, and that a water solid condition could occur in less than the 10 min operator action time assumed by Westinghouse to identify the event and terminate the source of fluid increasing the RCS inventory. The AIT concluded that the Westinghouse assumed 10-min time period may need to be reexamined in light of this event. The Salem operators took about 17 min to terminate safety injection following the first SI and 12 min to terminate safety injection following the second SI. The pressurizer became water solid during the event, although the plant operators responded appropriately to the inadvertent SI actuations in accordance with approved EOPs.
A.1.4 Modeling Assumptions The event has been modeled as a reactor trip with a recoverable loss of main feedwater and challenged primary PORVs. The main steam and main feedwater isolation valves were closed, and the main feedwater pumps were tripped following the reactor trip. This rendered the MFW system unavailable, but recoverable, for secondary side decay heat removal.
The primary PORVs were repeatedly challenged by the combination of safety injection flow and reactor coolant heatup. Because of the solid water condition in the pressurizer and the large number {>300) of PORV lifts, both PORVs were assumed to have passed a significant amount of water. The combined PORV failure to close probability (for both valves) was revised to 0.14, This is the probability wied in the ASP models for relief valve failure to close following A TWS, which would also involve water relief. Finally, since the water-solid pressurizer could not have occurred without successful high-pressure injection, sequences involving high-pressure injection failure were not considered in the analysis (this event would not have met the precursor selection criteria without the solid pressurizer);
The SAPHIRE-based ASP model for Salem was modified to reflect the above conditions by setting the probability of a reactor trip {IE-TRANS) and PORV challenge (PPR-SRV-CO-TRAN) to 1.0, the failure of main feedwater (MFW-SYS".TRIP) to TRUE, and the probability of PORV PRl and PR2 failing to close (PPR-SRV-00-1 and -2) to 0.0726 (to achieve an overall failure to lose probability for either PORV of 0.14).
Basic events and their probabilities are shown in Table A.1.1.
The ASP event tree for a transient at Salem is shown in Figure A.1.1. Transient sequences 8 and 16 (which involve HPI failure following a failure of the PORVs to close), plus those cutsets in sequence 20 (which
-involves failure of feed and bleed following auxiliary feedwater and MFW failure) associated with failure of the HPI systems, were excluded. (This had no impact on the analysis results.)
L A.1-4 A.1.5 Analysis Results The estimated conditional core damage probability associated with this event is 8.4 x 10-5* The dominant core damage sequence, highlighted on the event tree in Figure A.1.1, involves a postulated nonrecoverable failure of secondary side cooling and failure of the operators to initiate feed and bleed. The potential failure of the PORVs to close has little impact on the analysis results.
Definitions and probabilities for basic events are shown in Table A.1.1. Sequence conditional probabilities for transient sequences 5, 19, 20, and 21-8 are shown in Table A.1.2. Cutsets associated with sequences (the four highest probability sequences) are shown in Table A.1.3.
A.1-5 IE-TRAHS r RT I AfW I
MfW I PORV I
PORV-RES I HPI I
f&B I SGCOOL jcOOLDOWH
[
RHR l HPR I
SEQ I EHD-STATE fREQ 1
OK 2
OK I
3 OK I
I 4
bK I
5 CD I
6 OK I
7 CD B
CD 9
OK 10 OK I
11 OK l
I 12 OK l
13 CD I
14 OK I
15 CD 16 CD I
17 OK I
I I
18 OK I
I 19 CD 20 CD 21 T
ATWS TRANSIENT EVENT TREE SALEM 1 & 2 ASP PWR B Fig. A-1.1 Dominant core damage sequence for LER 2 72/94-007.
A.1-6 Table A.1.1. Selected Basic Events for LER 272/94-007 Name Description Calculated Modified for probability this event?
I AFW-XHE-NOREC OPERA TOR FAILS TO RECOVER AFW SYSTEM 2.600E-001 N
AFW-XHE-NREC-A TW OPERA TOR FAILS TO RECOVER AFW SYSTEM - A TWS l.OOOE+oOO N
AFW-XHE-XA-CST OPERA TOR FAILS TO INITIATE BACKUP WATER SUPPLY 4.000E-002 N
AFW-XHE-XA-CSTA OPERATOR FAILS TO INITIATE BACKUP WATER SUPPLY 4.000E-002 N
(ATWS)
HPI-XHE-XM-FB OPERA TOR FAILS TO INITIATE FEED AND BLEED l.OOOE-002 N
COOLING HPR-MOV-CF-RHR COMMON-CAUSE FAILURE OF HPI/RHR SUCTION MOVs 2.640E-004 N
TO OPEN/REMAIN OPEN HPR-MOV-CF-RWST CCF OF RWST ISOLATION VALVES SI 8812A AND B 2.640E-004 N
HPR-MOV-CF~SMP CCF OF THE SUMP ISOLATION VAL YES SI 88 lA AND B 2.640E-004 N
HPR-XHE-NOREC OPERATOR FAILS TO RECOVER THE HPR SYSTEM l.OOOE+oOO N
HPR-XHE-XM OPERATOR FAILS TO INITIATE HPR l.OOOE-003 N
IE-TRANS Transient Initiating Event 1.000E+OOO y
MFW-SYS-TRIP MAIN FEEDWATER SYSTEM TRIPS 1.000E+OOO y
MFW-XHE~NOREC OPERATOR FAILS TO RECOVER MAIN FEEDWATER 3.400E-001 N
PCS-XHE-XO-SEC OPERATOR FAILS TO ESTABLISH SECONDARY COOLING 2.000E-001 N
PPR-SRV-CC-1 PORVl FAILS TO OPEN ON DEMAND 6.300E-003 N
PPR-SRV-CC-2 PORV2 FAILS TO OPEN ON DEMAND 6.300E-003 N
PPR-SRV-CO-TRAN PORVs OPEN DURING TRANSIENT 1.000E+OOO y
PPR-SRV-00-1 PORVl FAILS TO RECLOSE AFfER OPENING 7.260E-002 y
PPR-SRV-00-2 PORV2 FAILS TO RECLOSE AFfER OPENING 7.260E-002 y
PPR-XHE-NOREC OPERATOR FAILS TO CLOSE PORVs OR BLOCK VALVES l.lOOE-002 N
RHR-MDP-CF-ALL RHR PUMP COMMON CAUSE FAILURES 5.600E-004 N
RHR-XHE-NOREC OPERATOR FAILS TO RECOVER THE RHR SYSTEM 1.000E+oOO N
RPS-VCF-FO REACTOR TRIP SYSTEM FAILS 6.000E-005 N
RPS-XHE-XM-SCRAM OPERATOR FAILS TO MANUALLY TRIP THE REACTOR 3.400E-001 N
A.1-7 Table A.1.2. Sequence Conditional Probabilities for LER 272/94-007*
Event tree Sequence Current frequency
% contribution name name TRANS 20 8.009E-005 95.3 TRANS 19 l.875E-006 2.2 TRANS 5
9.371E-007 1.1 TRANS 21-8 8.398E-007 1.0 TOTALS 8.406E-005
- Sequences with <1.0% contribution not shown.
A.1-8 Table A.1.3. Conditional Cutsets for Higher Probability Sequences for LER 272/94-007*
Cutset No.
Sequence 20:
2 3
Sequence 19:
2 3
4 5
Sequence 05:
2 Sequence 21-8:
%cut set 44.l 27.8 27.8 37.7 21.1 9.9 9.9 9.9 47.7 47.7 97.1 Current frequency 8.009E-005 3.536E-005 2.228E-005 2.228E-005 l.875E-006 7.072E-007 3.960E-007 I.867E-007 l.867E-007 l.867E-007 9.371E-007 4.472E-007 4.472E-007 8.398E-007 8.160E-007 Cutset IE-TRAN, AFW-XHE-NOREC, HPI-XHE-XM-FB, MFW-XHE-NOREC, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, MFW-XHE-NOREC, PPR-SRV-CC-2, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, MFW-XHE-NOREC, PPR-SRV-CC-1, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, HPR-XHE-XM, MFW-XHE-NOREC, PCS-XI-IE-XO-SEC, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, HPR-XHE-NOREC, MFW-XHE-NOREC, PCS-XI-IE-XO-SEC, RHR-MDP-CF-ALL, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, HPR-MOV-CF-RWST, HPR-XHE-NOREC, MFW-XHE-NOREC, PCS-XI-IE-XO-SEC, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, HPR-MOV-CF-SMP, HPR-XHE-NOREC, MFW-XHE-NOREC, PCS-XI-IE-XO-SEC, AFW-XHE-XA-CST IE-TRAN, AFW-XHE-NOREC, HPR-MOV-CF-RHR, HPR-XHE-NOREC, MFW-XHE-NOREC, PCS-XI-IE-XO-SEC, AFW-XHE-XA-CST IE-TRAN, HPR-XHE-NOREC, PPR-SRV-CO-TRAN, PPR-SRV-00-2, PPR-XHE-NOREC, RHR-MDP-CF-ALL, RHR-XHE-NOREC IE-TRAN, HPR-XHE-NOREC, PPR-SRV-CO-TRAN, PPR-SRV-00-1, PPR-XHE-NOREC, RHR-MDP-CF-ALL, RHR-XHE-NOREC IE-TRAN, AFW-XHE-XA-CSTA, AFW-XHE-NREC-AlW, RPS-VCF-FO, RPS-XHE-XM-SCRAM
- Cutsets with small percentage contributions are not shown.
Background
GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS The preliminary precursor analysis of an operational event that occurred at your plant has been provided for your review. This analysis was perfonned as a part of the NRC's Accident Sequence Precursor (ASP)
Program. The ASP Program uses probabilistic risk assessment techniques to provide estimates of operating event significance in tenns of the potential for core damage. The types of events evaluated include actual initiating events such as*a loss of off-site power (LOOP) or Loss-of-Coolant Accident (LOCA), degradation of plant conditions, and safety equipment failures or unavailabilities that could increase the probability of core damage from postulated accident sequences. This preliminary analysis was conducted using the infonnation contained in the plant-specific final safety analysis report (FSAR), individual plant examination (IPE), and the licensee event report (LER) for this event.
Modeling Techniques The models used for the analysis of 1994 events were developed by the Idaho National Engineering Laboratory (INEL ). The models were developed using the Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE) software. The models are based on linked fault trees. Four initiating events are considered: (1) transients, (2) loss-of-coolant accidents (LOCAs), (3) loss of offsite power (LOOPs), and (4) Steam Generator Tube Ruptures (PWR only). Fault trees were developed for each top event on the event trees to a supercomponent level of detail. The only support system currently modeled is the electric power system.
The models may be modified to include additional detail for the systems/components of interest for a particular event. This may include additional equipment or mitigation strategies as outlined in the FSAR or IPE. Probabilities are modified to reflect the particular circumstances of the event being analyzed.
Guidance for Peer Review Comments regarding the analysis should address:
Does the "Event Description" section accurately describe the event as it occurred?
Does the "Additional Event-Related lnfonnation" section provide accurate additional information concerning the configuration of the plant and the operation of and procedures associated with relevant systems?
Does the "Modeling Assumptions" section accurately describe the modeling done for the event? Is the modeling of the event appropriate for the events that occurred or that had the potential to occur under the event conditions? This also includes assumptions regarding the likelihood of equipment recovery.
Appendix E of Reference 1 provides examples of comments and responses for previous ASP analyses.
Criteria for Evaluating Comments Modifications to the event analysis may be made based on the comments that you provide. Specific documentation will be required to consider modifications to the event analysis. References should be made to portions of the LER, AIT, or other event documentation concerning the sequence of events, System and component capabilities should be supported by references to the FSAR, IPE, plant procedures, or analyses.
Comments related to operator response time., and capabilities should reference plant procedures, the FSAR, the IPE, or applicable operator response models. Assumptions used in determining failure probabilities
- should be clearly stated.
Criteria for Evaluating Additional Recovery Measures Additional systems, equipment, or specific recovery actions may be considered for incorporation into the analysis. However, to assess the viability and effectiveness of the components and methods, the appropriate documentation must be included in your response. This includes:
nomial or emergency operating procedures,*
piping and instrumentation diagrams (P&IDs),*
electrical one-line diagrams,*
results of thermal-hydraulic analyses, and operator training (both procedures and simulator),* etc.
- Systems, equipment, or specific recovery actions that were not in place at the time of the event will not be considered. Also, the documentation should address the impact (both positive and negative) of the use of the specific recovery measure on:
the sequence of events, the timing of events, the probability of operator error in using the system or equipment, and other systems/processes already modeled in the analysis (including operator actions).
For example, Plant A (a PWR) experiences a reactor trip, and, during the subsequent recovery, it is discovered that one train of the auxiliary feedwater (AFW) system is unavailable. Absent any further information regrading this event, the ASP Program would analyze it as a reactor trip with one train of AFW unavailable. The AFW modeling would be patterned after information gathered either from the plant FSAR or the IPE. However, if information is received about the use of an additional system (such as a standby steam generator feedwater system) in recovering from this event, the transient would be modeled as a reactor trip with one train of AFW unavailable, but this unavailability would be mitigated by the use of the standby feedwater system. The mitigation effect for the standby feedwater system would be credited in the analysis provided that the following material was available:
standby feedwater system characteristics are documented in the FSAR or accounted for.in the IPE, procedures for using the system during recovery existed at the time of the event, the plant operators had been trained in the use of the system prior to the event, a clear diagram of the system is available (either in the FSAR, IPE, or supplied by the licensee),
- Revision or practices at the time the event occurred.
previous analyses have indicated that there would be sufficient time available to implement the procedure successfully under the circumstances of the event under analysis, the effects of using the standby feedwater system have on the operation and recovery of systems or procedures that are already included in the event modeling. In this case, use of the standby feedwater system may reduce the likelihood of recovering failed AFW equipment or in,itiating feed-and-bleed due to time and personnel constraints.
Materials Provided for Review The following materials-have been provided in the package to facilitate your review of the preliminary analysis of the operational event.
The specific LER, augmented inspection team (AIT) report, or other pertinent reports.
A summary of the calculational results. An event tree with the dominant sequence(s) highlighted. Three tables in the analysis indicate (1) a summary of the relevant basic events including modifications to the probabilities reflect the circumstances of the event, (2) the dominant core damage sequences, and (3) cut sets for the dominant core damage sequences.
Schedule Please refer to the transmittal letter for schedules and procedures for submitting your comments.
References
- 1.
L. N. Vanden Heuvel et al., Precursors to Potential Severe Core Damage Accidents: 1993,.A Status Report, USNRC ReportNUREG/CR-4674 (ORNL/NOAC-232, Volumes 19 and 20), Martin Marietta Energy Systems, Inc., Oak Ridge National Laboratory and Science Applications International Corp.,
September 1994.