ML20212J881
| ML20212J881 | |
| Person / Time | |
|---|---|
| Site: | Prairie Island  |
| Issue date: | 09/28/1999 |
| From: | Kim T NRC (Affiliation Not Assigned) |
| To: | Richard Anderson NORTHERN STATES POWER CO. |
| References | |
| TAC-MA6561, NUDOCS 9910060024 | |
| Download: ML20212J881 (25) | |
Text
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r j NUCLEAR REGULATORY COMMISSION
- WASHINGTON, D.C. 20666 4 001
- 1 September 28, 1999 Mr. Roger O. Anderson, Director Nuclear Energy Engineering Northern 65es Power Company 414 Nicolk Mall Minneapons,' MN 55401 1
SUBJECT:
PRAIRIE ISLAND NUCLEAR GENERATING PLANT, UNIT 1 - REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF OPERATIONAL EVENT (TAC NO. MA6561)
Dear Mr. Anderson:
1 Enclosed for your review and comment is a copy of the preliminary Accident Sequence !
Precursor (ASP) analysis of an operational event that occurred at Prairie island Nuclear i
Generating Plant, Unit 1, on January 5,1999 (Euclosure 1). This event was reported in '
Licensee Event Report (LER) No. 282/99-001. The enclosed preliminary analysis was prepared by our contractor, the Oak Ridge National Laboratory (ORNL). The results of this preliminary analysis indicate that this event may be a precursor for 1999. 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.
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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 provide any comments within 30 days of receipt of this letter. We have streamlined the ASP Program with the objective of significantlyimproving the time after an event in which 1
the final precursor analysis of the condition is made publicly available. As soon as our final '
analysis of the condition has been completed, we will provide for your information the final precursor analysis of the condition and the resolution of your comments.
We have also enclosed several items to facilitate your review. Enclosure 2 contains specific guidance for performing the requested review, identifies the criteria that we will apply to j determine whether any credit should be given in the analysis for the use of licensee-identified j additional equipment or specific actions in recovering from the event, and describes the specific j information that you should provide to support such a claim.
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. R.O. Anderson 2 Please contact me 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.
Sincerely, a
A&
Tae Kim, Senior Project Manager, Section 1 Project Directorate ill l Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-282
Enclosures:
- 1. LER No. 282/99-001
- 2. Licensee Review Guidance 1
cc w/encis: See next page i
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t Mr. Roger O. Anderson, Director Prairie Island Nuclear Generating
- Northern States Power Company - Plant l
cc: 1 J. E. Silberg, Esquire Site Licensing Shaw, Pittman, Potts and Trowbridge Prairie Island Nuclear Generating 2300 N Street, N. W. Plant Washington DC 20037 Northern States Power Company 1717 Wakonade Drive East l Plant Manager . Welch, Minnesota 55089 Prairie Island Nuclear Generating Plant Tribal Council Northern States Power Company Prairie Island Indian Community l 1717 Wakonade Drive East ATTN: Environmental Department Welch, Minnesota 55089 5636 Sturgeon Lake Road l Welch, Minnesota 55089 Adonis A. Nebiett Assistant Attorney General Site General Manager Office of the Attorney General o rairie Island Nuclear Generating 455 Minnesota Street Plant Suite 900 Northern States Power Company St. Paul, Minnesota 55101-2127 1717 Wakonade Drive East Welch, Minnesota 55089 U.S. Nuclear Regulatory Commission Resident inspector's Office l 1719 Wakonade Drive East Welch, Minnesota 55089-9642 Regional Administrator, Region lll U.S. Nuclear Regulatory Commission 801 Warrenville Road Lisle, Illinois 60532 4351 Mr. Stephen Bloom, Administrator Goodhue County Courthouse Box 408 Red Wing, Minnesota 55066-0408 Commissioner Department of Public Service 121 Seventh Place East Suite 200 St. Paul, Minnesota 55101-2145 April 1999
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, m LER No. 282/99-001 LE.R No. 282/99-001 i Event
Description:
Reactor trip following the failure of the station auxiliary l transformer
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Date of Event: January 5,1999 Plant: Prairie Island, Unit i 1
Event Summary At approximately 1311 on January 5,1999, with Unit 1 operating at 100% power, an intemal fault occurred in the Unit I main (1M) transformer. The resulting explosion breached the IM transfonaer and expejled a large amount ofoil. The pool of oil ignited and bumed ~40 ft to the nonh of the transfomier. The fire brigade extinguished the burning oil fire at approximately 1325. Because of the fault, explosion, and S;r, boi the 1 M.
transformer and the Unit I reserve transformer (IR) were locked out. This caused the loss ofnon safegua'rds buses 11,12,13, and 14. Without these buses, electric power was lost to the reactor coolant pumps (RCPs);
Unit I was cooled by natural circulation (power was restored to the RCPs 7-8 h following the transformer i fault). No emergency diesel generators (EDGs) started. One safeguards bus never lost electric power (bus 16);
the other safeguards bus successfully transferred automatically to another power source (bus 15). The !
conditional core damage probability (CCDP) for this event is 3.0 x 104 Event Description At approximately 1311 on January 5,1999, Unit I was operat p 100% power. No electrical switching was being performed when an internal phase-to-phase fault on the 20-kV winding occurred in the 1 M transformer.
The fault caused an explosion in the transformer and an automatic Unit I turbine trip / reactor trip. The explosion breached the IM transformer tank and expelled a large amount of oil. The oil ignited during the explosion and bumed ~40 ft to the north of the transformer (i.e., away from the turbine building) and continued to burn while on the ground. The initial ground fire had flames -40 ft high with dense black smoke. Directly above where the fire was burning was a transmission tower with 161-kV lines from the site substation to the 1R transformer. The dense smoke and flames from the fire caused a phase-to-phase fault on the 151-kV lines.
This caused a lock out of the IR transformer. The losses of both the IR and IM transformers (the IM transformer was locked out because of the fault) caused the loss of non-safeguards buses 11.12,13, and 14.
As a result, both Unit 1 RCPs tripped off. With the loss of both RCPs, Unit I was cooled by natural circulation. No EDGs started; both safeguards buses remained energized from an offsite ac-power source.
A second interr.at explosion in the transformer expelled additional oil into the area of the original fire. Shortly after the explosion the control room dispatched the site fire brigade. The fire brigade responded to the area of i the fine and extinguished the burning oil fire before the Red Wing Fire Department arrived.
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{ ; AAer the initial response to the event was completed, personnel began restoring pov cr to non-safeguards buses
. I 1,12,13, and 14. By 1440, personnel had restored electric power to buses 13 and 14 from the 2RY source; restoring power to the 480-V ac buses 130,140,150,160, and 180 followed. This restored electric power to the lighting systems and auxiliary equipment. Electric power was restored to buses 11 and 12 from the 2RX source by 1821; the 11 and 12 RCPs were restarted at 1906 and 1835, respectively. Buses 15 and 16 were transferred to the 2RY source at 2133 ed 2130, respectively.
- Additional Event-Related Ir.(ormation The Unit i electrical line up (Fig.1) before the event was as follows:
' 4-kV safeguards bus 15 was supplied electric power from the IR transformer, a
4-kV safeguards bus 16 was supplied electric power from the Cooling Tower (CT) 1 I transformer, a
l 4-kV non-safegards buses 11 and 12 were supplied electric power from the IM transformer, 4-kV non-safcauards buses 13 and 14 were supplied electric power from the IM transformer, 480-Vac safeguards buses were supplied electric power from buses 15 and 16,
'+ 480-V ac non safeguards buses were supplied electric power from the buses 13 and 14.
l The explosion occurred at 1311. By 1319 (8 min aAer the explosion), the plant fire brigade started applying )
- an aqueous film forming foam using a 1.5-in fire hose on the burning oil. At 1325 (14 min aAer the explosion),
the plant fire brigade had completely extinguished the oil fire.
The IM transformer was locked out because of the fault and all ofits protective relaying functioned as intended. The dense smoke and flames from the fire caused a phase-to-phase fault on the 161-kV lines. This caused a lockout of the IR transformer. The losses of both the IR and IM transformers caused the loss of 1 non-safeguards buses 11,12,13, and 14. Equipment on Unit I that is powered from these buses includes the following:
'a both' RCPs,
.- . both main feedwater (MFW) pumps.
- both circulating water pumps,
= all condensate pumps,
.- all heater drain pumps, Lt he 11 cooling water pump,
. - all turbine building and auxiliary building lighting (except battery backed emergency lighting),
. the motor-driven fire pump,
_ spent fuel pool cooling, and all non-safeguards 480-V ac buses that are fed from buses 11,12,13, and 14.
Safeguards bus 16 was initially powered from CTl 1 and continued to be pwered from this source. AAer the IR transformer locked out, safeguards bus 15 fast transferred to the CTl I transformer. Because safeguards l'
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LER No. 282/99-001 1
' bus 15 successfully transferred automatically to another offsite power source, both safeguards buses remained energized during this event. Therefore, no EDG was required to start.
Unit I was returned to normal power operation January 12,1999, with a normal electrical distribution except that the IM transformer was isolated and out ofsersice.
Modeling Assumptions Because the fire did not appear to physically threaten any safety equipment, no potential fire related damage to any safety system was assumed. The event was modeled as a transient because the loss of offsite power to the non-safeguards buses resulted in a trip. The successful fast transfer of safeguards bus 15 was a key element in this event. Therefore, a basic event representing the potential failure of a safeguards bus to fast transfer to an alternate power source was added to the ac-power fault tree. The modified ac-power fault tree was added as an input to all the appropriate system fault trees used by the transient event tree. A loss of L normal offsite power to bus 15 flag was set to TRUE (i.e., probability = 1.0). This allowed the potential for a fast transfer failure and the need for an EDO start to be sim. lated.
Each of the four EDGs at Prairh hiand can supply the power requirements for the hot shutdown loads for its I associated unit and one trah of essential loads of the opposite unit in case of an SBO on the second unit l (Ref. 2). This is accomplished through two manual cross-tie breakers between buses 15 and 25 or buses 16 l and 26. A basic event was added (EPS-XHE-XE-XTIE) to the model to account for the failure of the operator to initiate the cross-tie between buses according to the established procedure (Ref. 3). This cross-tie basic event assumes that a safety injection signal does not exist on both units at the same time. EPS-XHE-XE-XTIE j 4
was set at 3.2 x 10 based on Prairie Island's individual plant examination (IPE, Ref. 2, Table 3.3-3). A basic l event was also added to the accident sequence precursor (ASP) model to account for t he mechanical failure of i the two' cross-tie breakers in series (Ref. 2, Table 3.3-1). The base-case common-cause failure probability of j the EDGs (EPS-DGN-CF-ALL) was adjusted from 1.6 x 104to 6.1 = 10" to account for all four EDGs (Ref.
4, Table 5-9, au= 0.0116; and Table 5 13, a. = 0.0146).
Because of the loss of power to non safeguards buses 11,12,13, and 14, basic esents MFW-SYS-TRIP and MFW-SYS-UNAVAIL were set to TRUE (indicating MFW would be unavailable following the trip).
Additionally, the non recovery probabilities were set to 1.0 to indicate that MFW would not be restored in the short-term (i.e., M FW-XHE-ERROR and MFW-XHE-NOREC)-it took 90 min to restore ac power to buses 11 and 12 and ~5 h to restore ac power to buses 13 and 14.
Each motor-driven AFW pump (one per unit) can be cross-tied to supply feedwater to the opposite unit. To account for additional sources of feedwater given a loss of MFW, a basic event was added (AFW-XHE-XE-XTIE) to the ASP model to account for the failure o 'the operator to initiate the cross-tie between units. AFW-XHE-XE-XTIE was set at 3.2 x 102 based on Prairie Island's individual plant examination (Ref. 2, Table 3.3-3). A basic event was also added to the AS P model to account for the potential failure of the cross-tie valves.
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LER No. 282/99-001 1
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Analysis Results The CCDP associated with the transformer explosion and fire is estimated to be 3.0 x 10 4 The dominant core damage sequence for this event (Sequence 20 on Fig. 2) involves the following events:
~ a' successful reactor trip, - '
- l a failure of AFW, a failure and nonrecovery of MFW, and a failure of the operators to establish feed-and-bleed cooling.
This sequence (sequence 20) accounts for 85% of the total contribution to the CCDP. All of the dominant sequences are driven by the loss of MFW.
One sequence (sequence 7) involves an RCS cooldown that because of the lack of ac power to the RCPs would i be by natural circulation. Natural circulation cooling is not specifically modeled in the ASP models. Because '
1 this places a greater burden on the operator to complete successfully, the CCDP contribution from this l sequence may actually be higher.
The expanded modeling of the multiple ac power source alternatives prevented any emergency power basic event being among the dominant sequence cut sets. This is because the 13.8-kV power lines were available as was the ability to cross-tie the Unit I buses to Unit 2 buses. Each unit EDG is also backed by an EDG from the oppe 4 onit.
i Definitions and probabilities for selected basic events are shodu in Table 1. 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.
-Acronyms IM Unit 1, main transformer IR Unit 1, reserve transformer AFW auxiliary feedwater system
-ASP accident sequence precursor ATWS anticipated transient without scram CCDP conditional core damage probability CT cooling tower EDG emergency diesel generator HPI high-pressure injection -
HPR high-pressure recirculation IPE individual plant examination IRRAS Integrated Reliability and Risk Analysis System 4 July 12,1999
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.kV- kilovolts -
LOCA _ . loss-of coolant accident LOOP loss of oit site power i MFW main feedwater l MOV motor-operated valve l
PORV power-operated relief valve l RCP reactor coolant pump RCS reactor coolant system RHR' residual heat removal RPS reactor protection system RWST refueling water storage tank l SRV safety relief valve l
References
- 1. LER 50-282/99-001," Reactor Trip Following Failure of the Station Auxiliary Transformer," February 4,1999.
- 2. Prairie Island N ar Generating Plant, individual Plant Examination.
- 3. Prairie Island Procedure IECA-0.0, Rev. I1, " Loss of All Safeguards AC Power."
- 4. Common-Cause Failure Parameter Estimations, NUREGICR-5491,0ctober l998.
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Fig. 2 Dominant core damage sequence for LER No. 282/99-001.
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rabie 1. Definitions and Probabilities for Selected Basic Events for LER No. 282/99-001 Modified Event Base Current for this name Description probability probability Type event E-LOOP Initiating Event-LOOP (excludes 1.6 E-005 0.0 E+000 Yes l the Probability of Recovering Offsite Power in the Short Term)
E SGTR Initiating Event-Steam Generator 1.6 E 006 0.0 E+000 Yes Tube Rupture E SLOCA Initiating Event-Sm'all-Break 2.3 E-006 0.0 E-000 Yes LOCA E TRANS Initiating Event-Transient 2.5 E-004 1.0 E+000 Yes ACP-BAC-LP.I A Division 1 A Pewer 4160-V ac 9.0 E 005 9.0 E 005 No Bus Fails ACP-BAC-LP-1 B Division IB Power 4160 V ac 9.0 E-005 9 0 E 005 No Bus Fails AFW AOV-CC TDP Steam Supply Air-Operated 1.0 E 003 1.0 E 003 No Valve 31998 Fails to Op:n AFW MDP-FC-1 AFW Motor-Drisen Pump 12 3 9 E-003 3 9 E-003 No Fails AFW-PMP-CF ALL Common Cause Failure of AFW 21 E-004 21 E-004 NEW Yes Pumps AFW-TDP-FC-TDP AFW Turbine Dmen Pump Fails 3.2 E-002 3 2 E 002 No HPI-MDP-CF-ALL Common-Cause Failure of the 7.8 E-004 7.8 E-004 No High-Pressure injection (HPI)
Pumps HPI-XHE-XM-FB Operator Fails to Initiate Feed- 1.0 E-002 1.0 E-002 No and-Bleed Cooling HPR-MOV-CC-SMPA Sump Recirculation Motor- 6.0 E-003 6.0 E-003 No Operated Valves (MOVs)32075 and 32077 Fail HPR MOV CC-SMPB Sump Recirculation MOVs 6 0 E4)03 6 0 E 003 No 32076 and 32078 Fail HPR-MOV CF DIS Common <ause Failure of the 2.6 E-004 2.6 E-004 No MOVs on the Residualliest Removal (RHR) Discharge to the HP1 8 July 12,1999
- ' I LER No. 282/99-001 Table 1. Definitions and Probabilities for Selected Basic Events for l
LER No. 282/99-001 (Continued) i Modified Event Base Current for this name Description probability probability Type event I
IIPR-MOV-CF MFAB Common-Cause Failure of the 2.6 E 004 2.6 E-004 No MOVs on the Refueling Water i Storage Tank (RWST) Mini-Flow Line to Close i IIPR-MOV CF-RWST Common-Cause Failure of the 2.6 E-004 2 6 E 004 No i Isolation MOVs for the RWST ,
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IIPR MOV-CF-SMP Common-Cause Failure of the 1.1 E 003 1.1 E 003 No Sump Recirculation MOVs IIPR XIIE-XM Operator Fails to Initiate liigh- 1.0 E 003 1.0 E 003 No Pressure Recirculation (IIPR)
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LOSP-A Loss of Division A OfTsite Power 1.0 E+000 1.0 E+000 TRUE Yes Flag MFW-SYS TRIP Main Feedwater (MFW) System 8 0 E 001 1.0 E+000 TRUE Yes Unavailable Given a Reactor Trip MFW SYS-UNAVAIL MFW Unasailable 2.0 E-001 1.0 E+000 TRUE Yes MFW XIIE-ERROR Operator Fails to Restor MFW 5 0 E 002 1.0 E+000 Yes flow MFW XIIE-NOREC Operator fails to Recover MFW 2 0 E-001 1.0 E+000 Yes Flow PCS-VCF IIW Turbine Bypass Vahes / 3 0 E-003 1.0 E+000 TRUE Yes Condenser / Circulation Failures PCS-XHE-XO SEC Operator Fails to Establish 2 0 E-001 2.0 E-001 No Secondary Cooling PPR-MOV-OO-BLK1 Block Valve to Power-Operated 3.0 E-003 3.0 E-003 No Relief Valve (PORV) 1 Fails to Close PPR MOV-OO-BLK2 Block Valve to PORV 2 Fails to 3.0 E 003 3.0 E 003 No Close PPR-SRV-CC PRV1 PORV 1 Fails to Open on 6.3 E 003 6.3 E-003 No Demand 9 July 12,1999
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LER No. 282/99-001 Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 282/99-001 (Continued)'
Modified f Event Base Current for this name Description probability probability Type event j l
PPR SRV-CC PRV2 PORV 2 Fails to Open on 6.3 E-003 6.3 E-003 No Demand PPR-SRV CC-RCS Relief Valves Fails to Open and 4.4 E-004 4.4 E-004 No Thereby Fail to Limit the Pressure in the RCS PPR SRV CO TRAN PORVa' Safety Relief Valves 4.0 E-002 4.0 E-002 No (SRVs)Open During Transient PPR SRV-OO-PRV) PORV I Fails to Reclose After 3.0 E-002 3 0 E-002 No Opening PPR SRV-OO-PRV2 PORV 2 Fails to Reclose After 3.0 E-002 3 0 E-002 No Opening PPR XIE XM-BLK Operator Fails to Close PORV 1.0 E-003 1.0 E-003 No Block Valves RCS-PIIN-MODPOOR Insumciently Negative Moderator 14 E 002 1.4 E 002 No Temperature Coemeient RCS-PIIN-PL Reactor Power Levelis Iligh 9.0 E-001 9.0 E 001 No RIIR MDP-CF ALL Common-Cause Failure of the 5 6 E-004 5.6 E-004 No RIIR Pumps RilR-MOV-CF RWST Common-Cause Failure of the 2 6 E-004 2.6 E-004 No RWST Isolation MOVs RPS-BKR FC-FTO Reactor Protection System (RPS) 5.7 E-006 5.7 E 006 No Breakers Fail to Open RPS-VCF-FO-ELEC Control Rod Drives Remain 4.3 E-004 4.3 E-004 No Energized RPS VCF FO-MECli Control Rod Drise Assemblies 8.9 E-008 8 9 E-008 No Fail toinsert RPS XIIE-ERROR Operator Fails to De-Energue 2.0 E-001 2.0 E 001 No Motor-Generator Sets i RPS-X1E-XM-SCRAM Operator Fails to Manually Trip 1.0 E-002 1.0 E-002 No l the Reactor 10 July 12,1999 l
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Table 1. Definitions and Probabilities for Selected Basic Events for LER No. 282/99-001 (Continued)
J Modified Event Base Current for this name Description probability probability Tyra event TRANS-07 NREC Transfer Sequence 07 1.0 E+000 1.0 E+000 No Nonrecovery Probability (Failure to Recover HPR)
TRANS-19-NREC Transfer Sequence 19 2 6 E-031 2 6 E-001 No Nonrecosery Probability IFailure to Recover AFW (0.26),
SGCOOL (1.0), and HPR (1,0)]
TRANS 20-NREC Transfer Sequence 20 2.2 E-001 2.2 E 001 No Nonrecovery Probabihty [ Failure to Recover AFW (0.26) and F&B (0 84))
]
1 TRANS-21-15-NREC Transfer Sequence 21 15 1.0 E+000 1.0 E+0'X) No Nonrecovery Probabihty (Failure to Recoser AFW ATWS)
TRANS-21-16-NREC Transfer Sequence 21-16 1.0 E 000 1.0 E+000 !o Nonrecovery Probability (No Recovery Options Available)
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1 Table 2. Sequence Conditional Probabilities for LER No. 282/99-001 ;
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Conditional Event tree Sequence core damage Percent name number probability contribution 4CCDP)
TRANS 20 2.5 E-006 84.5 l
TRANS 21-15 . 2.1 E-007 6.9 i
TRANS 19 1.1 E-007 3.6 TRANS 21-16 7.2 E-008 2.4 TRANS 07 4.7 E-008 1.6 Total (all sequences) 3.0 E-006 Table 3. Sequence Logic for Dominant Sequences for LEP No. 282/99-001 Event tree name Sequence Logic number TRANS 20 /RT, AFW, MFW-T, F&B TRANS 21 15 RT, /RCSPRESS, MFW-A, AFW-ATWS TRANS 19 /RT, AFW, MFW-T, /F&B, SGCOOL, HPR TRANS ?.1 -16 RT,RCSPRESS TRANS 07 /RT, /AFW, PORV, PORV-RES, /HPI, COOLDOWN, HPR
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i Table 4. System Names for LER No. 282/99-001 )
System name Logic AFW-ATWS No or insumcient AFW Flow during an Ar.ticipated Transient Without Scram (ATWS) Event ;
i AFW Nor or Insumcient AFW Flow COOLDOWN RCS Cooldown to RHR Pressuie using the Turbine Bypass Valves, etc.
F&B Failure to Provide Feed-and-Bleed Cooling HPI No or Insumcient Flow from the HPI System HPR No or Insumcient Flow into the RCS Cold Legs MFW-A Failure of the Main Feedwater System (MFW) During an ABVS Event MFW-T Failure of MFW during a Transient PORV PORVs/SRVs Open during a Transient PORV RES PORVs, Block Valves, and SRVs Fail to Reclose RCSPRESS Failure to Limit RCS Pressure <3200 psi RT Reactor Fails to Trip during a Transient SGCOOL Failure of Secondary Cooling i
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Table 5. Conditional Cut Sets for Higher Probability Sequences for LER No. 282/99-001 l
Cut set Percent number contribution CCDP' Cut sets6 l
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TRANS Sequence 20 2.5 E-006 c4 g t e ,- " ' 't . , ,
1 18.4 4.6 E-007 AFW PMP-CF-ALL,MFW SYS-UNAVAIL,MFW XIE-NOREC, 1IPI-XHE XM FB, TRANS-20-NREC i 2 18.4 4.6 E-007 AFW-PMP-CF-ALL, MFW-SYS-TRIP, MFW-XIE-ERROR, HPI-XIE-XM-FB, TRANS-20-NREC 3 11.6 2.9 E-007 AFW PMP-CF ALL, MFW-SYS-UNAVAIL, MFW XIE-NOREC, PPR SRV-CC PRVI,TRANS-20-NREC 4 11.6 2.9 E-007 AFW-PMP-CF-ALL, MFW-SYS-UNAVAIL, MFW-XIE-NOREC, l PPR SRV-CC PRV2,TRANS-20-NREC 5 11.6 2.9 E-007 AFW FMP-CF-ALL, MFW-SYS-TRIP, MFW XIE-ERROR, PPR SRV CC-PRV1, TRANS-20-h%EC 6 11.6 2.9 E-007 AFW PMP-CF-ALL,MFWSYS-TRIP,MFW-X1IE ERROR, PPR.SRV-CC-PRV2, TRANS-20-NREC 7 1.4 3.6 E-008 ANPMP-CF-ALL, MFW SYS UNAVAIL, MFW XIE-NOREC, j
}IPI-MDP-CF-ALL, TRANS-20-NREC 8 1.4 3.6 E-008 AFEPMP-CF-ALL, MFW-SYS-TRIP, MFW XIE-ERROR, l lIPI-MDP-CF ALL, TRANS-20-NREC !
TRANS Sequence 21-15 2.1 E-007 1 67.2 1.4 E-007 RPS-VCF FO ELEC, RPS-XIIE-XM-SCRAM, MFW SYS-UNAVAIL, AFW-TDP-FC TDP, TRANS-21 15-NREC 2 17.8 3.6 E-008 RPS BKR FC-FTO,RPS XIE ERROR,MNSYS-UNAVAIL, AFW TDP-FC-TDP, TRANS-21 15-NREC 3 82 1.7 E-008 RPS VCF-FO-ELEC,RPS-XIE-XM SCRAM,MFW SYS-UNAVAIL, AFW-MDP-FC-1, TRANS-21-15 NREC 4 2.2 4.4 E-009 RPS-BKR FC FTO,RPS XIE ERROR MFW-SYS-UNAVAIL, AFW-MDP-FC 1.TRANS-21-15-h1EC 5 2.1 4.3 E-009 RPS-VCF-FO-ELEC,RPS-X}E-XM SCRAM,MFW-SYS-UNAVAIL, AFW AOV-CC-TDP, TRANS-21 15-NREC 6 1.4 2.8 E-009 RPS-VCF-FO-MECH, MFW SYS-UNAVAIL, AFW-TDP FC-TDP, TRANS 21 15 NREC 14 July 12,1999
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l LER No. 282/99-001 i
l Table 5 Conditional Cut Sets for Higher Probability Sequences for LER No. 282/99-001 (continued)
Cut set Percent number contribution CCDP' Cut sets 6 TRANS Sequence 19 1.1 E-007 's i I,[h)%gNM M%$$% Le 1 11.2 1.2 E-008 AN-PMP-CF-ALL, MFW SYS-UNAVAIL, MFW-XIE-NOREC, PCS-X}E-XO-SEC, HPR-MOV CF-SMP, TRANS-19-NREC 2 11.2 1.2 E-008 AN-PMP-CF-ALL, MFW-SYS-TRIP, MFW-XIE-ERROR, PCS-XIE XO-SEC,HPR-MOV-CF-SMP,TRANS 19-NREC 3 10.2 1,1 E-008 AFW-FMP-CF-ALL, MFW-SYS UNAVAIL,MFW XIIE-NOREC, 8
PCS XIE-XO-SEC,IIPR XIE XM,TRANS-19 NREC 4 10.2 1.1 E-008 AN-PMP-CF-ALL, MN-SYS-TRIP, MFW-XIE-ERROR, PCS-XIE-XO-SEC, HPR-XilE XM, TLANS-19-NREC 5 5.7 6.1 E-009 AN-PMP-CF-ALL,MFW SYS-TRIF,MFW-XIE-ERROR, FCS-X1E XO-SEC, RHR-MDP-CF-ALL, TRANS-19-NREC 6 5.7 6.1 E-009 AN-PMP-CF-ALL, MFW SYS-UNAVAIL, MFW-XIE-NOREC, j
PCS-XIE XO.SEC,RHR-MDP-CF ALL,TRANS 19-NREC 3 i
7 2.7 2.9 E-009 AN-PMP CF ALL, MFW SYS-TRIP, MFW XIE-ERROR, PCS-XIE XO-SEC, RHR-MOV CF-RWST TRANS-19-NREC j
8 2.7 2.9 E-009 AFW PMP CF-ALL, MFW SYS-UNAVAIL, MFW-XIE-NOREC, PCS-XIE-XO-SEC, RHR-MOV-CF-RWST, TRANS-19-NREC l
l 9 2.7 2.9 E-009 AN PMP-CF-ALL, MFW SYS-TRIP, MFW-XIE-ERROR, PCS XIE XO SEC,1 IPR MOV-CF MFAB, TRANS-19-NREC 10 2.7 2.9 E-009 AN-PMP-CF-ALL, MFW SYS-TRIP, MFW-XHE-ERROR, PCS-XHE-XO-SEC HPR-MOV-CF-DIS TRANS 19 NREC l 11 2.7 2.9 E-009 AN PMP CF-ALL,MFW SYS UNAVAIL,MFW-XIE-NOREC, PCS XIE-XO-SEC, HPR-MOV-CF-DIS, TRANS-19-NREC I
i 12 2.7 2.9 E-009 AM PMP CF ALL,MN SYS-TRIP,MFW-XIE-ERROR, l PCS.XHE XO SEC,IIPR MOV-CF-RWST,TRANS 19-NREC ;
13 2.7 2.9 E-009 AN PMP-CF-ALL, MFW SYS-UNAVAIL, MFW XIE NOREC, PCS-XIE XO-SEC,HPR-MOV-CF MFAB,TRANS 19-NREC 14 2.7 2.9 E-009 AN PMP-CF ALL,MIW SYS-UNAVAIL, MFW XIE NOREC, PCS-XIE-XO-SEC, HPR-MOV-CF-RWST. TRANS-19-NREC 15 July 12,1999 I
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- I
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~
! LER No. 282/99-00I i
Table 5. Conditional Cut Sets for Higher Probability Sequences for i LER No. 2E2/99-001 (continued) j
. Cut set Percent number contribution CCDP' Cut sets
TRANS Sequence 21 16 7.2 E-008 r 2
"dINNf6 @f(MIN @g[9@
l 1 75.1 5.4 E-008 RPS-VCF-FO-ELEC,RPS-XIE-XM-SCRAM,RCS-PIIN-PL RCS-PiD&MODPOOR.TRANS-21 16-NREC 2 19.9 E-00g RPS-BKR-FC-FTO, RPS-XI E-ERROR, RCS-PIIN-PL, RCS-PIIN. i MODPOOR, TRANS-21 16-NREC 3 2.6 1.9 E-009 RPS-VCF FO-ELEC, RPS-XIE XM SCRAM,PPR SRV CC-RCS, TRANS-21-16-NREC !
4 1.6 1.1 E-009 RPS-VCF-FO-MECil, RCS-PHN-PL, RCS-PIIN-MODPOOR, TRANS-21 16-NREC ;
TRANS Sequence 07 4.7 E-008 ,
PCS-VCF-IIW, HPR MOV-CF-SMP. TRANS-07-NREC 2 8.5 4.0 E-009 PPR SRV-CO-TRAN, PPR SRV-OO-PRV2, PPR-MOV-OO-BLK2, PCS-VCF-HW,IIPR MOV-CF-SMP, TRANS47-NREC 3 7.7 3.6 E-009 PPR SRV-CO-TRAN,PPR-SRV-OO-PRV1,PPR-MOV-OO-BLK1, PCS-VCF-HW,IIPR XHE XM,TRANS-07-NREC 4 7,7 3.6 E-009 PPR-SRV-CO-TRAN, PPR-SRV.OO.PRV2, PPR-MOV-OO-BLK2.
PCS-VCF-HW,IIPR XIE-XM, TRANS-07-NREC 5 4.3 2.0 E-009 PPR SRV-CO TRAN, PPR-SRV-OO-PRV2,PPR MOV-OG-BLK2, PCS-VCF HW,RHR-MDP-CF ALL,TRANS-07-NREC 6 4.3 2.0 E-009 PPR-SRV-CO-TRAN,PPR-SRV-OO-PRVI,PPR MOV-OO-BLK1, PCS-VCF-HW,RIIR MDP-CF ALL,TRANS-07-NREC 7 2.8 11 E-009 PPR SRV CO-TRAN,PPR SRV-OO-PRV1.PPR-XIIE XM-BLK, PCS-VCT-HW,1 IPR MOV-CF-SMP, TRANS-07-NREC 8 2.8 1.3 E-009 PPR SRV CO-TRAN, PPR SRV-OO-PRV2, PPR XIE-XM-BLK, PCS-VCF-IIW,HPR MOV-CF-SMP.TRANS-07-NREC 9 2.6 1.2 E-009 PPR SRV-CO-TRAN, PPR-SRV.OO-PRV2,PPR XIE XM BLK, PCS-VCF-HW, HPR XIE XM, TRANS-07-NREC 10 2.6 1.2 E-009 PPR SRV CO-TRAN,PPR SRV-OO-PRVI,PPR XIE-XM-BLK, PCS-VCF-HW, HPR XHE-XM, TRANS-07-NREC i
1 16 Juh12,1999
p ,
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t L
j LER No. 282/99-001 Table 5. Conditional Cut Sets for Higher Probability Sequences for
- LER No 282/99-001 (continued)
Cut set Percent number contribution CCDP' Cut sets 6 i i1 2.0 9.5 E-010 PPR SRV-CO-TRAN,PPR-SRV-OO-PRVI,PPR-MOV-OO-BLKl.
PCS VCFIIW,1 IPR MOVCF-MFAB TRANS 07-NREC ;
12 2.0 9.5 E-010 PPR SRV-CO TRAN,PPR-SRV-OO-PRV1,PPR M OV-OO BLKl.
PCS-VCF-HW,HPR-MOV-CF-DIS TRANS-07 NREC 13 2.0 9.5 E-010 PPR SRV CO-TRAN, PPR SRV-OO-PRVI, PPR MOV-OO-BLK1, PCS VCF IIW, HPR-MOV-CF-RWST, TRANS-07-NREC 14 2.0 9.5 E-010 PPR-SRV-CO TRAN, PPR SRV-OO-PRVI, PPR MOV-OO-BLK1, ,
PCS-VCF-HW, RHR-MOV-CF-RWST, TRANS47-NREC 15 2.0 9.5 E-010 PPR SRV-CO-TRAN,PPR SRV-OO-PRV2,PPR-MOV-OO-BLK2, PCS-VCF HW,IIPR-MOV-CF DIS, TRANS-07-NREC 16 2.0 9.5 E-010 PPR SRV-CO-TRAN,PPR-SRV-OO-PRV2,PPR MOV-OO-BLK2.
PCS VCF-IfW HPR MOV-CF-MFAB.TRANS-07 NREC 17 2.0 9.5 E-010 PPR SRV-CO-TRAN,PPR SRV-OO-PRV2,PPR-MOV-QO-BLK2, PCS-VCF-IIW,HPR MOV CF-RWST TRANS-07-NREC 18 2.0 9.5 E-010 PPR-SRV-CO-TRAN, PPR SRV-OO-PRV2, PPR-MOV-OO-BLK2, PCS-VCF-IIW, RHR-MOV-CF-RWST. TRANS47-NREC 19 14 6.7 E-010 PPR-SRV-CO-TRAN,PPR SRV OO-PR"1,PPR XHE-XM-BLK.
PCS-VCF-liW, RHR-MDP-CF ALL, TF e QS-07-NREC 20 1.4 6.7 E-010 PPR-SRV-CO-TRAN, PPR SRV 90-PRV2, PPR-XHE-XM-BLK, PCS-VCF-HW, RHR-MDP-CFdLL, TRANS-07 NREC 21 1.4 6.7 E-010 PPR-SRV-CO-TRAN,PPR SRV OO-PRVI, ACP-BAC-LP-1B, PCS VCF IIW,HPR-MOV-CC-SMPA, TRANS-07-NREC 22 1.4 6.7 E-010 PPR SRV-CO-TRAN,PPR SRV-OO-PhVI, ACP-BAC-LP 1 A, PCS-VCF-IIW, HPR MOV CC SMPB,TRANS-07-NREC p n p Total (all sequences) 3,0 E-006 Ce
'The conditional probability for each cut set is determined by multiplying the probabihty of the initiating event by the probabilities of the basic es ents in that minimal cut set. The probability of the initie'ine, events are given in Table I and begin with the designator "IE "
The probabilities for the basic events also are given in Table 1.
hsic e vents LOSP-A,1/JW SYS TRIP, MFW-SYS-UNAYML,and PCS-VCI-IIW are TRUE type events w hich are not normally included in the output of fault tree reduction programs but have been added to aid in understanding the sequences to potential core damage associated with the event.
l 17 July 12,1999
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i l
. GUIDANCE FOR LICENSEE REVIEW OF '
PRELIMINARY ASP ANALYSIS l
Background !
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 probabir.3 tic risk assessment techniques to provide estimates of operating event significance in terms of the potential for core damage. The types of events evaluated include actualinitiating 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 co.o 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 j examination (IPE), and the licansee event report (LER) for this event.
i Modeling Techniques !
The models used for the analysis of 1998 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) i loss of coolant accidents (LOCAs), (3) losses of offsite power (LOOPS), and (4) steam j 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 rnodified 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 information concerning the configuration of the plant and the operation of and procedures associated with relevant systems?
e 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.
Enclosure 2
I 2
Appendix G 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. Commerits 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 specific 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 asponse.
This includes:
normal or emergency operating procedures,'
piping and instrumentation diagrams (P&lDs),*
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 k
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 '
' Revision or practices at the time the event occurred.
H 1
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l: 3 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, l
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.
i Materials Provided for Review l
The following materials have been provided in the package to facilitate your review of the l preliminary analysis of the operational event.
e The specific LER, NRC inspection report, or other pertinent reports. l e 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 1
. 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.
I Schedule -
Please refer to the transmittal letter for schedules and procedures for submitting your comments.
Reference R. J. Belles et al.," Precursors to Potential Severe Core Damage Accidents: 1997, A Status Report," USNRC Report NUREG/OR-4674 (ORNL/NOAC-232) Volume 26, Lockheed Martin Energy Research Corp., Oak Ridge National Laboratory, and Science Applications International Corp., Oak Ridge, Tennessee, November 1998.
l
..5 R.O. Anderson -2 September 28, 1999 Please contact me if you have any questions regarding this request. This request is covered by the existing OMB clearence 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.
1 Sincerely, Original signed by:
Tae Kim, Senior Project Manager, Section 1 Project Directorate ill Division of Licensing Project Management Office of Nuciear Reactor Regulation Docket No. 50-282
Enclosures:
- 1. LER No. 282/99-001 I
- 2. Licensee Review Guidance cc w/encls: See next page J
DISTRIBUTION:
Docket File (50-282,50-306)
PUBLIC PDill-1 Reading T. J. Kim (2)
OGC ACRS R. Lanksbury, Rlli R. Scholl (e-mail SE) l P. O'Reilly, RES S. Mays, RES DOCUMENT NAME: G:\WPDOCS\ PRAIRIE \ EVENT 99.WPD j OFC PM:PD31 E LA:PD31_ , E SC:PD21,n l E f NAME TJKim 7#/C. RBoulinMh CCraidM i DATE 9 / 2 7 /69 't /d% /99 4/J/\ /99 OFFICIAL RECORD COPY
(. W l
J R'.OIdnderson -2 September 28, 1999 Please contact me if you ha'.e 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 j licensing requirement. '
Sincerely, l
Original signed by:
Tae Kim, Senior Project Manager, Section 1 Project Directorate 111 ,
Division of Licensing Project Management l Office of Nuclear Reactor Regulation Docket No. 50-282
Enclosures:
- 1. LER No. 282/99-001
- 2. Licensee Review Guidance l
1 cc w/encis: See next page DISTRIBUTION:
Docket File (50 282,50-306)
PUBLIC PDill 1 Reading T. J. Kim (2)
OGC ACRS R. Lanksbury, Riti R. Scholl (e-mail SE)
P. O'Reilly, RES S. Mays, RES DOCUMENT NAME: G:\WPDOCS\ PRAIRIE \ EVENT 99.WPD
- OFC PM
- PD31 E LA:PD31_ , E SC:PD31,n l E
} NAME TJKim 7)/C. RBoulindfTN6% CCraifflb DATE f// 78/69 't /dh /99 C(/)X /99 f
OFFICIAL RECORD COPY