ML18102B267
| ML18102B267 | |
| Person / Time | |
|---|---|
| Site: | Salem  |
| Issue date: | 04/30/1997 |
| From: | Olshan L NRC (Affiliation Not Assigned) |
| To: | Eliason L Public Service Enterprise Group |
| References | |
| NUDOCS 9705080295 | |
| Download: ML18102B267 (21) | |
Text
50-212}8!/
UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 April_30, 1997 Mr. Leon R. Eliason Chief Nuclear Officer & President-Nuclear Business Unit Public Service Electric and Gas Company Post Office Box 236 Hancocks Bridge, NJ 08038
SUBJECT:
REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF OPERATIONAL CONDITION DISCOVERED AT SALEM NUCLEAR GENERATING STATION. UNITS 1 AND 2
Dear Mr. Eliason:
Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) ana lys.i s of an operati ona 1 event which was discovered at the Salem Nuclear Generating Station. Units 1 and 2. on January 10. 1996 (Enclosure 1). and was reported in.Licensee Event Report CLER) No. 272/96-002.
This analysis was prepared by our contractor at the Oak Riege National Laboratory CORNL).
The results of this preliminary analysis indicate that this condition may be a precursor for 1996.
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 analys1s. 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 for us to incorporate your comments. perform any required reanalysis.
and prepare the final report of our analysis of this event in a timely manner.
you are requested to complete your review and to provide any comments within 30 days of receipt of this letter.
We have streamlined the ASP Program with the objective of significantly improving the time after an event in which the final precursor analysis of the event is made publicly available. *As soon as our final analysis of the event has been completed. we will provide for your information the final precursor analysis of the event and the resolution of your comments.
In previous years. licensees have had to wait until publication of the Annual Precursor Report (in some cases. up to 23 months after an event) for the final precursor analysis of an event and the resolution of their comments.
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
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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. 272/96-002. which documented the event.
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 follow-up review of events documented in LERs.
Your response to this request is voluntary and does not constitute a licensing requirement.
Docket Nos. 50-272/311 Sincerely, (Original signed by)
Lenny N. Olshan. Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Enclosures:
- 1.
Preliminary Accident Precursor Analysis
- 2.
Guidance for Performing Review
- 3.
LER No. 272/96-002
- cc w/encls:
See next page DISTRIBUTION:
, Docket File PUBLIC PDI-2 r/"f SVarga JStolz MO'Brien LOlshan OGC. 0-15818 ACRS. TWF JLinville. RI OFFICE I-2/PM NAME lshan:cw DOCUMENT NAME:
SGS96STD.PRL.
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- L. Eli as on April 30, 1997 specific actions in recovering from the event. and describes the specific information that you should provide to support such a claim.
Enclos~re 3 is a copy of LER No. 272/96-002. which documented the event.
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 follow-up review of events documented in LERs.
Your response to this request is voluntary and does not constitute a licensing requirement.
Docket Nos. 50-272/311
~~ex*
Y,.lt_, ~~JYrv Lenny N. Olshan. Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Enclosures:
- 1. Preliminary Accident Precursor Analysis
- 2.
Guidance for Performing Review
- 3.
LER No. 272/9D-002 cc w/encls:
See next page
- Mr. Leon R. Eli a son
- Public Service Electric & Gas Company
- cc:
Mark J. Wetterhahn. Esquire Winston & Strawn 1400 L Street NW Washington. DC 20005-3502 Richard Fryling, Jr.. Esquire Law Department - Tower SE 80 Park Place Newark. NJ 07101 Mr. D. F. Garchow General Manager - Salem Operations Salem Generating Station P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. Louis Storz Sr. 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 0509 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 Maryland Office 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. Elbert Simpson Salem Nucle.enerating Station.
Units 1 and 2 Richard Hartung Electric Service Evaluation Board of Regulatory Commissioners 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. David R. Powell. Manager Licensing and Regulation Nuclear Business Unit P.O. Box 236 Hancocks Bridge, NJ 08038 Mr. David Wersan Assistant Consumer Advocate Office of Consumer Advocate 1425 Strawberry Square Harrisburg, PA 17120 P. M. Goetz MGR. Joint Generation Atlantic Energy 6801 Black Horse Pike Egg Harbor Twp.. NJ 08234-4130 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 Senior Vice President - Nuclear Engineering Nuclear Department P.O. Box 236 Hancocks Bridge, New Jersey 08038
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LER No. 272/96-002 LER Nos. 272/96-002 Event
Description:
Charging pump suction valves from the RWST potentially unavailable due to pressure locking Date of Event:
January IO, 1996 Plant:
Salem 1 and 2 Event Summary During an evaluation for potential pressure locking and thermal binding in power-operated gate valves, as required by Generic Letter (GL) 95-07, personnel determined that the following valves on both units were subject to pressure locking (Fig. 1):
Valves SJl and SJ2 Valves lSJl 13 and 2SJ113 Valves 1 CS2 and 2CS2 Valves on the Refueling Water Storage Tank (RWST) supply line to the charging/safety injection pump suction Valves on the cross tie connection from the suction of the charging pumps to the suction of the safety injection (SI) pumps
-Isolation valves on the containment spray header Pressure locking of valves SJ 1 and SJ2 could prevent these valves from opening when required for safety injection. Pressure locking of valves 1SJ113 and 2SJ 113 could prevent these valves from opening if required during the recirculation phase of a loss-of-coolant accident (LOCA). Pressure locking of valves 1 CS2 and 2CS2 could impact the containment spray function prior to the recirculation phase of a LOCA.
In addition, the following valves were determined to be susceptible to thermal binding:
Valves PR6 and PR7 Power Operated Relief Valve (PORV) block valves Thermal binding of these block valves could render the associated PORV unavailable for feed-and-bleed operations if the block valve were to l>e closed prior to the existence of an accident condition.
Both units were shut down and defueled at the time of the evaluation. This analysis assumes the susceptible valves could impact fh~ plant response to a small-break LOCA, a steam generator tube rupture (SGTR), a PORV lifting and failing to reseat, and a reactor coolant pump seal package failure. An increase in the core damage probability (CDP) for a one-year period of 5.8 x 10"° was calculated over a nominal value for the same period of 3. 0 x 10-5* This increase in CDP is applicable to each unit.
1
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LER No. 272/96-002 Event Description On January 10, 1996, both units were shutdown and defueled. At that time, Public Service Electric and Gas Company determined that the RWST supply valves to the charging/SI pump suction, the valves on the cross tie connection from the suction of the charging pumps to the suction of the SI pumps, and the containment spray header isolation valves on both units were subject to pressure locking. Additionally, the PORV block valves on both units were determined to be subject to thermal binding.
Pressure locking occurs when the fluid in the valve bonnet is at a higher pressure than the adjacent piping at the time of the valve opening. The two most likely scenarios for elevating the pressure in the valve bonnet relative to the pressure in the valve system are given below.
I.
Thermal pressure locking (or bonnet heatup) can occur when an incompressible fluid is trapped in the valve bonnet (e.g., during valve closure), followed by heating-up of the volume in the bonnet. The bonnet heatup scenarios include heating the valve bonnet by an increase in the temperature of the environment during an accident, heatup due to an increase in the temperature of the process fluid on either side of the valye, etc. (Normal ambient temperature variation is not considered, because it occurs over a long time period and pressure changes tend to be alleviated through extremely small amounts of leakage. Further, operating experience shows that normal temperature variations are not a source of pressure locking events.)
- 2.
Hydraulic pressure locking (or pressure-trapping) can occur when an incompressible fluid is trapped in the valve bonnet, followed by depressurization of the adjacent piping prior to valve opening. Examples of hydraulic pressure locking scenarios include back-leakage past check valves, and system operating pressures that are higher than the system pressure when the valve is required to open.
Pressure locking is of concern because the pressure in the space between the two discs of a gate valve can become pressurized above the pressure assumed when sizing the valve's motor operator. This prevents the valve operator from opening the valve when required.
Thermal binding is a phenomenon where* temperature changes of the valve internal components cause the valve stem to expand after closure. This results in a higher required opening thrust that may be above the opening thrust assumed when sizing the valve motor operator.
The original plant designs at Salem 1 and 2 did not account for pressure locking and thermal binding effects.
In 1977, plant perso~el modified double-disc gate valves based on recommendations by Westinghouse. In 1986, a review of flexible wedge gate valves in response to INPO SOER 84-7 determined that the valves listed in this licensee event report (LER) were not susceptible to pressure locking or thermal binding. The more stringent requirements of GL 95-07 reversed this earlier conclusion for the above listed valves.
2
LER No. 272/96-002 Licensee personnel determined that valves SJI and SJ2 were subject to the "pressure-trapping" effect. A maximum bonnet pressure of 96 psig was estimated, based on quarterly surveillance testing that recirculated water from the residual heat removal (RHR) pump discharge to the RWST suction line where SJI and SJ2 are located. The licensee indicated that once this increased bonnet pressure was established, there was no mechanism for the pressure to be relieved (assumption used in response to GL 95-07). At degraded voltage conditions, the licensee could not guarantee sufficient thrust would be generated by the motor operator to overcome the bonnet pressure. This would result in a loss of high head injection, though the charging pumps would be available for high pressure recirculation.
Valves 1SJ113 and 2SJ 113 were determined to be subject to both the "pressure-trapping" effect and "bonnet heatup." The maximum bonnet pressure was estimated to be 225 psig. Again, once this increased bonnet pressure was established, there was no mechanism for the pressure to be relieved. The "bonnet heatup" occurs in the first two minutes following the initiation of the hot leg recirculation phase of a LOeA. The "pressure-trapping" is the result of surveillance testing.
Valves 1 es2 and 2es2 were determined to be subject to the "pressure-trapping" effect. A maximum bonnet pressure was estimated at 250 psig as a result of surveillance testing of the containment spray pumps immediately upstream of the valves. Pump start on a containment high pressure may relieve the high pressure on the upstream side of the disc and allow the valves to open.
Valves PR6 and PR7 were determined to be subject to thermal binding. These valves are normally open at power unless they are cycled for surveillance testing or there is a fault on the PORV.
Additional Event-Related Information The charging system (eVe) consists of two centrifugal charging pumps and one positive displacement pump.
On a safety injection (SI) signal, the centrifugal charging pumps provide for high head safety injection. If valves SH and SJ2 fail closed, the safety injection function of the charging pumps is defeated. However, assuming the charging pumps were throttled back following the failure of SJI and SJ2 prior to damage from a loss of suction, they would still be capable of providing service in the (piggyback) recirculation mode. The two safety injection pumps provide for intermediate head safecy injection. Failure of valves SJI and SJ2 does not impact this mode of injection into the reactor coolant system.
Piggyback recirculation to the charging system and the SI system is provided separately by the individual RHR pumps. The A RHR pump provides for piggyback recirculation to the SI pumps' suction header. The B RHR pump provides for piggyback recirculation to the eve suction header. Valves 1SJI13 and 2SJ1 13 are in parallel and connect the eve and SI suction headers together. This provides an alternate path for recirculation to either the eve or SI system should the primary path fail. Therefore, failure of both SJ 113 valves does not fail piggyback recirculation without an additional failure occurring.
The containment spray system takes a suction from the RWST and delivers spray flow to the containment via valves 1 es2 and 2es2. A failure of these valves to open would preclude containment spray using the containment spray pumps. Downstream of the CS2 valves, a connection from the discharge of the RHR 3
~:
LER No. 272/96-002 pumps exists to provide containment spray in the recirculation phase of a LOCA. This path would be unaffected by a failure of the CS2 valves. Additionally, there are five containment cooler units that will limit the pressure increase in containment, assuming all five units operate without failure.
Modeling Assumptions Valves SJl and SJ2 were considered to be unavailable due to pressure locking following a small-break LOCA (SLOCA). The charging pumps or the SI pumps are required to protect the core during a SLOCA. Since the pressure locking mechanism was assumed to be :from "pressure-trapping," the condition was assumed to have existed for a one-year period following surveillance testing that recirculated higher pressure water back to the RWST. Basic event CVC-MOV-CC-SUCT represents the combination of SJI and SJ2 failing closed, so this event was set to "TRUE" (failed). The common cause failure of SJI and SJ2 was removed by setting basic event CVC-MOV-CF-SUCT to "FALSE" (not possible).
The NRC's simplified, plant-specific models used in ASP analyses currently do not include models for 1 large-break and medium-break LOCAs. These larger LOCAs are predicted to remove all decay heat out of the break location. Therefore, accumulator response and the progression to the ~ecirculation mode are the key elements in a large-break or medium-break LOCA event tree. Those responses are not significantly impacted by the valve failures reported in the LER. Thus, no effort was made to model these accident conditions.
Similar to valves SJI and SJ2, lSJI 13, and 2SJI 13 were considered to be unavailable due to pressure locking following a SLOCA. These valves are not specifically included in the NRC's simplified models; therefore, a basic event representing the probability of failure of lSJl 13 and 2SJI 13 was added (HPR-MOV-CC-HPI)
( base failure probability of 9.0 E-06) to the high pressure recirculation (HPR) and the HPR-L (LOOP) fault trees. This basic event was added via an OR gate with a new basic event (HPR-HPI-FM-CVC or HPR-CVC-FM-HPI) representing the success of the recirculation flow path elements in the opposite RHR train.
Subsequently, basic event HPR-MOV-CC-HPI was set to "TRUE" (failed).
The PORV block valves (PR6 and PR7) were not con5idered in the analysis. These valves are subject to thermal binding, which can be mitigated over time. Additionally, these valves would need to be closed at the initiation of an accident to impact the ability of the unit to conduct feed and bleed operations. The Salem IPE indicates the probability of PR6 or PR7 being closed could range as high as 3.2 x 10-s. When combined with the probability of an accident condition requiring feed and bleed, consideration of a PORV block valve failure becomes insignificant for analysis purposes. Additionally, the Salem FSAR does not take credit for the PORV valves mitigating the severity of any accident.
It was assumed that the failure of the containment spray valves would not impact the probability of core damage. The licensee *considered that the containment spray pump start following a SI signal would likely relieve pressure on 1 CS2 and 2CS2, allowing these valves to open. Furthermore, there appear to be several alternatives to reduce containment pressure if required.
4
\\ I LER No. 272/96-002 The plant-specific model of the plant's response to a SGTR was modified. Previously, a loss of the high pressure injection function led directly to core damage. For this analysis, the possibility of lowering RCS pressure below the steam generator safety valve set point within 30 min was considered following the loss of high pressure injection capability by adding a basic event, PCS-XHE-DEPR-30. Based on the operator burden under a short time constraint, a failure probability of 0.1 was assigned to PCS-XHE-DEPR-30.
The probability associated with the basic event for the failure of the operator to switch the AFW system water supply to a backup source (AFW-XHE-XA-CST) was reduced from 4.0 x io-2 to 1.0 x 10-3. This change was based on the relatively large size of the nonnal AFW water supply (200,000 gallons) and the added time which the operator would have to switch to a backup source of water.
Analysis Results This event is most sensitive to a SLOCA sequence which accounts for 81 % of the increase in the CDP for the 1-year period analyzed. An overall increase of 5.8 x 10-6 in the CDP was calculated. This is above a base probability for core damage (the CDP) for the same period of 3.0 x 10-5_ The dominant core damage sequence, highlighted as sequence number 06 on the event tree in Fig. 2, involves:
a SLOCA, the successful trip of the reactor, the successful operation of the auxiliary feedwater (AFW) system, and the failure of the RPI system (SI pumps) combined with the initial injection phase failure of the eve system.
The next most significant sequence involves a SGTR and contributes 13% of the total increase in the CDP.
This sequence also leads to core damage based on a failure of the RPI system and a failure to depressurize the RCS in a timely manner. Loss of RPI is the primary failure mechanism involved in all of the most dominant core damage sequences.
The first sequence that involves a failure of RPR or t:P.e failure of valves ISJI 13 and 2SJI 13 is LOOP sequence number 10. This sequence contributes less than 1% to the total increase in the CDP. Therefore, the only significant valve failure related to this analysis from the LER involves the pressure locking of valves SJI and SJ2.
Definitions and probabilities for selected basic events are shown in Table I. The conditional probabilities associated with the highest probability sequences are shown in Table 2. Table 3 lists the sequence logic associated with the sequences listed in Table 2. Table 4 describes the system names associated with the dominant sequences. Minimal cut sets associated with the dominant sequences are shown in Table 5.
5
Acronyms CCDP CDP eve GL HPI HPR IPE IRRAS LER LOCA LOOP MOV PORV PWR RCS RHR RWST SGTR SLOCA SI References conditional core damage probability core damage probability charging system generic letter high pressure injection high pressure recirculation individual plant examination Integrated Reliability and Risk Analysis System licensee event report loss of coolant accident loss of offsite power motor operated valve power operated relief valve pressurized water reactor reactor coolant system residual heat removal refueling water storage tank steam generator tube rupture small-break loss of coolant accident safety injection LER No. 272/96-002
- 1.
LER272/96-002, Rev. 1, "Motor Operated Gate valves Susceptible to Pressure Locking and Thennal Binding," February 9, 1996.
- 2.
Salem Generating Station Individual Plant Examination, July, 1993.
- 3.
Salem Generating Station Updated Final Safety Analysis Report, Volume 3.
- 4.
Phone conversation with Dennis Hassler and Bob Lewis, Salem Generating Station, February 13, 1997.
6
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LER No. 272/96-002 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 272/96-002 Modified Event Base Current for this name Description probability probability Type event IE-LOOP Initiating Event-Loss-of-Offsite 8.5 E-006 8.5 E-006 No Power IE-SGTR Initiating Event - Steam Generator 1.6 E-006 1.6 E-006 No Tube Rupture IE-SLOCA Initiating Event - Small-Break 1.0 E-006 1.0 E-006 No Loss-of-Coolant Accident IE-TRANS Initiating Event-Transient 5.3 E-004 5.3 E-004 No AFW-PMP-CF-ALL Common-Cause Failure of AFW 2.8 E-004 2.8 E-004 No Pumps AFW-XHE-NOREC Operator Fails to Recover the 2.6 E-001 2.6 E-001 No AFW System AFW-XHE-XA-CST Operator Fails to Initiate Back-up 4.0 E-002 1.0 E-003 Yes Water Supply CVC-MOV-CC-SUCT Failure ofCVC RWS1' Suction 1.1 E-004 1.0 E+oOO TRUE Yes MOVs to Open (SJl and SJ2)
CVC-MOV-CF-SUCT CVC-HPI RWST Suction fails to 2.6 E-004 2.6 E-004 FALSE Yes Open (SJ! and SJ2) CCF HPI-MDP-CF-ALL Common-Cause Failure of HP!
7.8 E-004 7.8 E-004 No Motor-Driven Pumps HPI-MDP-FC-IA HP! Train A Fails 3.9 E-003 3.9 E-003 No HPI-MDP-FC-IB HP! Train B Fails 3.9 E-003 3.9 E-003 No HPI-MOV-OC-SUCT HP! Suction Valves Fail (SJ30) 1.4 E-004 1.4 E-004 No HPI-XHE-NOREC Operator Fails to Recover the HPI 8.4 E-001 8.4 E-001 No System HPI-XHE-XM-FB Operator Fails to Initiate Feed-and-1.0 E-002 LO E-002 No Bleed Cooling HPR-CVC-FM-HPI HPR path to CVC from HPI Fails 7.0 E-003 7.0 E-003 NEW Yes (excludes failure of SJ 113 valves)
HPR-CVC-FM-HPI HPR path to HPI from CVC Fails 7.0 E-003 7.0 E-003 NEW Yes (excludes failure of SJ 113 valves) 9
LER No. 272/96-002 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 272/96-002 Modified Event Base Current for this name Description probability probability Type event HPR-MOV-CC-HPI Failure of SJl 13 Suction Cross-9.0 E-006 1.0 E+oOO NEW/
Yes CoMect Valves TRUE MFW-SYS-TRIP MFW System Trips 2.0 E-001 2.0 E-001 No MFW-XHE-NOREC Operator Fails to Recover MFW 3.4 E-001 3.4 E-001 No PCS-XHE-DEPR-30 Operator Fails to Depressurize 1.0 E-001 1.0 E-001 NEW Yes RCS Within 30 Minutes (SGTR-Loss ofHPI)
PPR-MOV-00-BLKl PORV 1 Block Valve Fails to 3.0 E-003 3.0 E-003 No Close PPR-MOV-OO-BLK2 PORV 2 Block Valve Fails to 3.0 E-003 3.0 E-003 No Close PPR-SRV-CC-1 PORV I Fails to Open on Demand 3.0 E-002 3.0 E-002 No PPR-SRV-CC-2 PORV 2 Fails to Open on Demand 3.0 E-002 3.0 E-002 No PPR-SRV-CO-TRAN PORVs Open During Transient 4.0 E-002 4.0 E-002 No PPR-SRV-00-1 PORV 1 Fails to Reclose After 3.0 E-002 3.0 E-002 No Opening PPR-SRV-00-2 PORV 2 Fails to Reclose After 3.0 E-002 3.0 E-002 No Opening PPR-XHE-NOREC Operator Fails to Close PORVs or I.I E-002 1.1 E-002 No Block Valves 10
LER No. 272/96-002 Table 2. Sequence Conditional Probabilities for LER No. 272/96-002 Event tree name SLOCA SGTR TRANS TRANS Sequence name 06 08 08 20 Total (all sequences)
- Percent contribution to th.e total importance.
Conditional core damage probability (CCDP) 4.8 E-006 7.$ E-007 8.6 E-008 1.7 E-006 3.6 E-005 Core damage Importance Percent probability (CCDP-CDP) contribution 2
(CDP) 4.2 E-008 4.8 E-006 82.1
.6.9 E-009 7.8 E-007 13.3 7.5 E-010 8.5 E-008 1.4 1.7 E-006 6.0 E-008 1.0 3.0E-005 5.8 E-006 111111111111111111111111111111111111111111111111111111111111111111111111111 11
,' 'f LER No. 272/96-002 Table 3. Sequence Logic for Dominant Sequences for LER No. 272/96-002 Event tree name Sequence name Logic SLOCA 06
/RT, /AFW, HPI, RCS-HPI TRANS 08
/RT, /AFW, PORV, PORV-RES, HPI TRANS 20
/RT, AFW, MFW, F&B Table 4. System Names for LER No. 272/96-002 System name Logic AFW No or Insufficient AFW Flow F&B Failure to Provide Feed-and-Bleed Cooling HPI No or Insufficient HPI Flow MFW Failure of the MFW System PORV PORVs Open During Transient PORV-RES PORVs Fail to Reseat RCS-HPI Failure to Depressurize RCS<SG Relief Within 30 Minutes (HPI Fails)
RT-Reactor Fails to Trip During Transient 12
LER No. 272/96-002 Table 5. Conditional Cut Sets for Higher Probability Sequences for LER No. 272/96-002 Cut set Percent number Contribution*
SLOCA Sequence 06 I
83.3 2
15.0 3
1.6 SGTR Sequence 08 I
82.1 2
14.1 3
1.5 TRANS Sequence 08 1
32.9 2
32.9 3
9.1 4
9.1 5
5.9 6
5.9 7
1.6 8
1.6 Change in CCDP (lmportance)b 4.8 E-006 4.0 E-006 7.2 E-007 7.8 E-008 7.8 E-007 6.4 E-007 I.I E-007 1.2 E-008 8.5 E-008 2.8 E-008 2.8 E-008 7.7 E-009 7.7 E-009 5.0 E-009 5.0 E-009 1.4E-009 1.4 E-009 Cut setsc CVC-MOV-CC-SUCT, HPI-MDP-CF-ALL, HPI-XHE-NOREC CVC-MOV-CC-SUCT, HPI-MOV-OC-SUCT, HPI-XHE-NOREC CVC-MOV-CC-SUCT, HPI-MDP-FC-lA, HPI-MDP-FC-IA, HPI-XHE-NOREC CVC-MOV-CC-SUCT, HPI-MDP-CF-ALL, HPI-XHE-NOREC, PCS-XHE-DEPR-30 CVC-MOV-CC-SUCT, HPI-MOV-OC-SUCT, HPI-XHE-NOREC, PCS-XHE-DEPR-30 CVC-MOV-CC-SUCT, HPI-MDP-FC-IA, HPI-MDP-FC-IA, HPl-XHE-NOREC, PCS-XHE-DEPR-30 PPR-SRV-CO-TRAN, PPR-SRV-00-2, PPR-XHE-NOREC, CVC-MOV-CC-SUCT, HPI-MDP-CF-ALL, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-1, PPR-XHE-NOREC, CVC-MOV-CC-SUCT, HPI-MDP-CF-ALL, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-2, PPR-MOV-OO-BLK2, CVC-MOV-CC-SUCT, HPI-MDP-CF-ALL, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-1, PPR-MOV-00-BLKl, CVC-MOV-CC-SUCT, HPI-MDP-CF-ALL, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-2, PPR-XHE-NOREC, CVC-MOV-CC-SUCT, HPI-MOV-OC-SUCT, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-1, PPR-XHE-NOREC, CVC-MOV-CC-SUCT, HPI-MOV-OC-SUCT, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-2, PPR-MOV-OO-BLK2, CVC-MOV-CC-SUCT,HPl-MOV-OC-SUCT, HPI-XHE-NOREC PPR-SRV-CO-TRAN, PPR-SRV-00-1, PPR-MOV-00-BLKI, CVC-MOV-CC-SUCT,HPI-MOV-OC-SUCT, HPI-XHE-NOREC 13
LER No. 2 72/96-002 Table 5. Conditional Cut Sets for Higher Probability Sequences for LER No. 272/96-002 Cut set number Percent Contribution*
Trans Sequence 20 I
60.0 2
16.7 3
11.3 Total (all sequences)
Change in CCDP (lmportancet 6.0 E-008 3.6 E-008 1.0 E-008 6.8 E-009 5.8 E-006 8Percent contribution to the sequence total importance Cut setsc AFW*XHE-XA..CST, AFW*XHE*NOREC, MFW-SYS-TRIP, MFW-XHE-NOREC, CVC-MOV..CC-SUCT, HPl-MDP..CF-ALL, HPI-XHE-NOREC AFW-PMP..CF-ALL, AFW-XHE-NOREC, MFW-SYS-TRIP, MFW-XHE-NOREC, CVC-MOV..CC-SUCT, HPl-MDP-CF-ALL, HPl-XHE-NOREC AFW-XHE-XA..CST, AFW-XHE-NOREC, MFW-SYS-TRIP, MFW-XHE-NOREC, CVC-MOV..CC-SUCT, HPI-MOV-OC-SUCT, HPI-XHE-NOREC 1The change in conditional probability (importance) is determined by calculating the conditional probability for the period in which the condition existed, and subtracting the conditional-probability for the same period but with plant equipment assumed to be operating nominally. The conditional probability for each cut set within a sequence is determined by multiplying the probability that the portion of the sequence that makes the precursor visible (e.g., the system with a failure is demanded) will occur during the duration of the event by the probabilities of the remaining basic events in the minimal cut set. This can be approximated by 1 - e*P, where p is determined by multiplying the expected number of initiators that occur during the duration of the event by the probabilities of the basic events in that minimal cut set. The expected number of initiators *is given by.lt, where.l is the frequency of the initiating event (given on a per-hour basis), and t is the duration time of the event. This approximation is conservative for precursors made visible by the initiating event.
The frequencies of interest for this event are:.l TRANS= 5.3 x 10.. /h, A1.00p = 8.5 x 10-6/h, A.SLOCA = 1.0 x 10-6/h, and AsGTR = 1.6 x 10-6/h.
cBasic event CVC-MOV-CC-SUCT is a type TRUE event. This type of event is not normally included in the output of the fault tree reduction process. This event has been added to aid in.understanding the sequences to potential core damage associated with the event.
14
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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 performed 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 terms 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 information 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 1995 and 1996 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 types of initiating events are considered: (1) transients, (2) loss-of-coolant accidents (LOCAs), (3) losses 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 Information" section provide accurate additional lnformation 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.
Enclsoure 2
..J Appendix H of Reference I provides examples of comments and responses for p~evious ASP analyses.
Criteria for Evaluating Convnents 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 times 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 ~pecific recovery actions may be considered for incorporation into the analysis.
However, to assess the viability and effectiveness of the equipment and methods, the appropriate documentation must be included in your response., This includes:
normal 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 speciffc 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 a~xiliary feedwater (AFW) system is unavailable. Absent any further information regrading this event, the ASP Program would analyze it as a reactor trip with one tr_ain 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
- Revision or practices at the time the event occurred..
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),
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 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 initiating 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 calculation results.
An event tree with the dominant sequence(s) highlighted.
Four tables in the analysis indicate:
(1) a summary of the relevant basic events, including modifications to the probabilities to reflect the circumstances of the event, {2) the dominant core damage sequences, (3) the system names for the systems cited in the dominant core damage sequences, and (4) 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: 1994, A Status Report, USNRC Report NUREG/CR-4674 (ORNL/NOAC-232) Volumes 21 and 22, Martin Marietta Energy Systems, Inc., Oak Ridge National Laboratory and Science Applications International Corp.,
December 1995.