ML17158B730
| ML17158B730 | |
| Person / Time | |
|---|---|
| Site: | Susquehanna  |
| Issue date: | 07/17/1996 |
| From: | Poslusny C NRC (Affiliation Not Assigned) |
| To: | Byram R PENNSYLVANIA POWER & LIGHT CO. |
| References | |
| NUDOCS 9607230102 | |
| Download: ML17158B730 (28) | |
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UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 205554001 July 17, 1996 Mr. Robert G.
Byram Senior Vice President-Nuclear Pennsylvania Power and Light Company 2 North Ninth Street Allentown, PA 18101
SUBJECT:
REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF AN EVENT AT SUS(UEHANNA STEAM ELECTRIC STATION, UNIT 1
Dear Mr. Byram:
Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) analysis of an operational event which was discovered at the Susquehanna Steam Electric Station on November 19, 1995 (Enclosure 1),
and was reported in Licensee Event Report (LER) No. 387/95-013.
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 a
precursor for 1995.
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 gi.ven 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 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.
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Byram We have also enclosed several items to facilitate your review.
Enclosure 2
contains specific guidance for performing the requested review, identifies the criteria which we will apply to determine whethe'r any credit should be given in the analysis for the use of licensee-identified'dditional'qu'ipment or specific actions in recovering from the event, and describes the specific information that you should provide to support'uch a claim.,
Enclosure 3 is a
copy of LER No. 387/95-013, which documented the event.
I Please contact me at 301-415-1402 if you have any questions regarding this request.
This request is covered by the existing OHB 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.
Sincerely,
/s/
Docket No. 50-387 Chester
- Poslusny, Senior Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Enclosures:
1.
2.
3.
Preliminary ASP Guidance for licensee's review of preliminary ASP analysis LER No. 387/95-013 cc w/encls:
See next page DISTRIBUTION:
Docket File PUBLIC PDI-1 Reading SVarga JZwolinski JStolz HO'rien w/o encl s.
CPoslusny w/o encls.
- WPasciak, RGN-I SMays w/o encls.
OFFICE P
PDI-2 P
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NAME I/
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DATE I
I 96 l
4 96 OFFICIAL RECORD COPY DOCUMENT NAME:
A: iSUSQUEHANNAiSU-ASP. LTR 96
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Byram We have also enclosed several items to facilitate your review.
Enclosure 2
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 fr'om the event, and describes the specific information that you should provide to support. such a claim.
Enclosure 3 is a
copy of LER No. 387/95-013, which documented the event.
Please contact me at 301-415-1402 if you have any questions regarding this request.
This request is covered by the existing OHB clearance number (3150-0104) for NRC staff follow-up review of events documented in LERs.
Your response to this'request i.s voluntary and does not constitute a licensing requirement.
Sincerely, Docket No. 50-387 Chester Poslusn
, Senior Project Manager Project Directorate I-2 Division of Reactor Projects - I/II Office of Nuclear Reactor Regulation
Enclosures:
1.
Preliminary ASP 2.
Gui'dance for licensee's review of preliminary ASP analysis 3.
LER No. 387/95-013 cc w/encls:
See next page
Mr. Robert G.
Byram Pennsylvania Power
- 5. Light Company Susquehanna Steam Electric Station, Units 1
E 2
CC:
Jay Silberg,,Esq.
- Shaw, Pittman, Potts
- 5. Trowbridge 2300 N Street N.W.
Washington, D.C.
20037 Bryan A. Snapp, Esq.
Assistant Corporate Counsel Pennsylvania Power 5 Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Mr. J.
M. Kenny Licensing Group Supervisor Pennsylvania Power E Light Company 2 North Ninth Street Allentown, Pennsylvania 18101 Mrs. Maitri Banerjee Senior Resident Inspector U. S. Nuclear Regulatory Commission P.O.
Box 35 Berwick, Pennsylvania 18603-0035 Mr. William P. Dornsife, Director Bureau of Radiation Protection Pennsylvania Department of Environmental Resources P.
O.
Box 8469 Harrisburg, Pennsylvania 17105-8469 Mr. Jesse C. Tilton, III Allegheny Elec. Cooperative, Inc.
212 Locust Street P.O.
Box 1266 Harrisburg, Pennsylvania 17108-1266 Regional Administrator, Region I
U.S. Nuclear Regulatory Commission 475 Allendale Road King of Prussia, Pennsylvania 19406 Mr. Harold G. Stanley Vice President-Nuclear Operations Susquehanna Steam Electric Station Pennsylvania Power and Light Company Box 467 Berwick, Pennsylvania 18603 Mr. Herbert D. Woodeshick Special Office of the President Pennsylvania Power and Light Company Rural Route 1,
Box 1797 Berwick, Pennsylvania 18603 George T. Jones Vice President-Nuclear Engineering Pennsylvania Power and Light Company 2 North Ninth Street Allentown, Pennsyl vani a 18101 Dr. Judith Johnsrud National Energy Committee Sierra Club 433 Orlando Avenue State College, PA 16803 Chairman Board of Supervisors 738 East Third Street
- Berwick, PA 18603
LER No. 387/95-013 LER No. 387/95-013 Event
Description:
HPCI Injection Valve Potentially Unavailable due to Thermally-Induced Pressure Locking Date ofEvent:
November 19, 1995 Plant:
. Susquehanna 1
Event Summary Pennsylvania Power & Light (PP&L)'s review of Generic Letter 95-07 concluded that thc High Pressure Coolant Injection (HPCI) and Reactor Core Isolation Cooling (RCIC) system injection valves at Susquehanna 1 and 2 were subject to prcssure locking, which could preclude system operation
[Ref.
1].
During disassembly of the'Unit 1 HPCI injection valve to perform a modification that would preclude pressure locking, deformation of the valve's internals indicative of extremely high valve bonnet pressure was found.
Although the valve was successfully stroked aAcr the unit was shut down and depressurized and before the damage was discovered, this analysis assumes the HPCI valve would have failed to opcratc if required following a scram while at power once the bonnet over-pressurization occurred, and estimates a conditional core damage probability (CCDP) over a one-year period of 2.2
>< 10'.
Uncertainty in thc impact of the pressure locking problem contributes to a substantial uncertainty in this core damage probability estimate.
Event Description PP&L's review ofGeneric Letter 95-07 [Ref. 2] identified both thc HPCI and RCIC injection valves for both units'as susceptible to thermally-induced pressure locking.
On November 11, 1995, Unit 1 was shut down to perform a repair of the main generator.
During this outage, a modification to prevent thermally-induced prcssure locking was performed on the HPCI and RCIC injection valves.
This modification consisted of Enclosure 1
LER No. 387/95-013 drilling a pressure relief hole in the downstream side of each valve disk.
There were no provisions for pressure reliefor equalization in the original valve designs.
During disassembly of the HPCI injection valve, the following damage was observed:
the valve bonnet pressure seal segmented retaining ring was bent approximately 0.135 in., the prcssure seal spacer ring was bent, and the packing follower flang was bent approximately 0.25 in. The damage was caused by pressure in the valve bonnet, which resulted in forces great enough to deform these components.
PP&L dctermincd that valve damage was caused by thermally-induced pressure locking. The internal bonnet pressure required to cause the observed valve damage was estimated to have been between 3000-7000 psig.
I These pressures would prevent the HPCI injection valve from opening ifit had been demanded.
Thc valve was considered unavailable for an indeterminate amount of time between April 1992 (when the valve was previously disassembled) and November 11, 1995.
The HPCI injection valve was not challenged, except for testing with the unit shut down and depressurizcd, during this time period.
No damage was observed when the RCIC valve was disassembled for its modification. The Unit 2 HPCI and RCIC injection valves were stroked to confirm operability (this may not confirm that the valves would have operated during all plant conditions).
These valves were to have, holes drilled to prevent pressure locking at a future date.
Unit 2 procedures were also revised to minimize thc likelihood of HPCI and RCIC injection valve pressure locking.
Additional Event-Related Information NRC Information Notice 96-08 provides additional information concerning this event [Ref. 3]. The HPCI injection valve is a 14-in flexible-wedge motor-operated pressure seal gate valve.
The valve is installed downstream from the HPCI pump, about three piping diameters from tlie feedhvater system piping.
The licensee believes heat from thc feedwater system caused the thermally induced pressure locking and valve damage.
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LER No. 387/95-013 Pressure locking is a phenomenon where water trapped in the bonnet cavity and in thc space between the two disks of a parallel-disk gate valve is prcssurizcd above the pressure assumed when sizing thc valve's motor operator.
This prevents the valve operator from opening the valve when required.
Water can enter a valve bonnet during normal valve cycling or when a differential pressure moves a disk away from its seat, creating a path to either increase fluid pressure or fillthe bonnet with high-pressure fluid. A subsequent increase in the temperature ofthe fluid in thc valve bonnet willcause an increase in bonnet cavity pressure due to thermal expansion ofthe fluid.
The bonnet pressure that damaged the pressure seal spaccr and segmented retaining ring was estimated from the bending seen in the retaining ring. The retaining ring consists of four scgmcnts and has an inner diameter of 13.6 in, an outer diameter of 15.6 in, and is 0.875 in hick. The ring was bent approximately 0.135 in. The valve vendor calculated the load required to bend the ring to this extent to be approximately one million
- pounds, which corresponds to the 3000-7000 psig estimated internal bonnet pressure.
The licensee considered these pressures to be threshold values for physical damage to the valve. An engineering analysis by thc liccnscc demonstrated that heatup of fluid trapped in the valve bonnet could be sufficient to cause a
pressure of this magnitude.
At these differential pressures, the HPCI injection valve actuator did not have sufficient thrust capability to open the valve.
No inservice testing was performed on thc HPCI injection valve during power operation because thc liccnsec had a cold shutdown justification for this valve that supported operational testing only when the unit was shut down. The valve was operated when the unit was shut down.
Modeling Assumptions This analysis assumes that the HPCI system injection valve was unavailable duc to pressure locking or valve damage once thc overpressurization condition occurred.
Since the date when the valve damage occurred is unknown, the best estimate is one-half ofthe time since the valve was previously disassembled, or 22 months.
This period is longer than the longest unavailability period used in an Accident Sequence Precursor (ASP) analysis, one year.
For thc purposes of this analysis, thc valve was assumed to be unavailable for 6134 h.
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LER No. 387/95-013 This period corresponds to one year ofoperation with thc unit critical 70% of the time. To refiect the valve unavailability, thc supercomponent that includes the HPCI injection valve, HCI-TDP-FC-TRAIN, and the basic event representing failure to recover the HPCI system, HCI-XHE-XE-ERROR, were both set to TRUE.
Since no damage was observed when the RCIC valve was disassembled, this valve was assumed to be operable and not vulnerable to prcssure locking during normal plant operation.
The nominal operability of this valve following a scram is supported by the use of RCIC following a number of scrams from power at Susquehanna.
Thc potential use of HPCI following a nominal scram is also supported by historic experience.
Based on a review of Licenscc Event Reports (LERs) associated with scrams at Susquehanna 1 and 2, at least 11 scrams from power have occurred at both units since 1984 in which RCIC and/or HPCI ivere apparently demanded and used for reactor pressure vessel makeup.
No LERs reported HPCI or RCIC injection valve problems following a scram from power. For this reason, the HPCI valve for Unit I only was assumed to be inoperable only aAer the overpressurization condition occurred.
[Note that the apparent operability ofboth system valves following nominal scrams does not preclude inoperability under conditions in which the reactor prcssure vessel (RPV) would be partially depresswizcd for example, following a medium-brcak LOCA.
However, because of the maximum one-year unavailability period assumed in the ASP program, this potential concern does not incrcasc the conditional'core damage probability estimated for the event.]
The ASP Program typically considers thc potential for core damage following three postulated initiating events in boiling water reactors:
transient, loss of offsite power (LOOP), and small-break LOCA.
Supercomponent-based linked fault tree models arc available for each of these postulated initiating events.
Medium-brcak LOCAs are not currently modeled but are of concern in this analysis because of the potential impact of HPCI on plant response to this initiator. Following a medium-break LOCA, HPCI is assumed to bc required until RP V prcssure decreases to the point that the low-pressure systems (e.g., low-pressure coolant injection and low-prcssure core spray) can provide makeup. IfHPCI is unavailable, the operators must utilize the automatic depressurization system to quickly reduce RPV pressure to the operating pressure of the low-pressure systems.
Because of the potential importance of HPCI in mitigating a medium-break LOCA, a model for this, initiating event was developed for this analysis.
This model is based on transient sequences
LER No. 387/95-013 following two postulated stuck-open Safety Relief Valves (SRVs); these sequences are similar to a medium-break LOCA.
Analysis Results The CCDP estimated for the event is 2.2
>< 10'.
This is an increase of 1.9
>< 10'(a factor of 6.5) over the nominal core damage probability (CDP) for the unavailability period utilized in the analysis, 3.4 x 10
. This is the maximum impact of HPCI valve prcssure locking; the actual increase could vaiy from zero (ifthe injection valve was actually not impacted by pressure locking) to this value.
The dominant sequence (sequence number 62 in Figure 1) contributes about 55% to the conditional probability estimate for the event and involves:
~
a postulated transient with failure ofthe power conversion system (PCS),
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two SRVs that fail to close,
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failure ofHPCI due to injection valve pressure locking, and
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failure ofautomatic dcpressurization.
The dominant cut set involves the postulated transient, PCS hardware component failures, failure of the two SRVs to close, and an operator error that prevents depressurization.
Definitions and probabilities for selected basic events are shown in Table 1.
The conditional probabilities associated with thc 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.
Cut sets associated with each scquencc are shown in Table 5.
A greater than usual uncertainty is associated with this estimate, driven, in part, by the uncertainty associated with the frequency of a medium-break LOCA (none have occurred) and on assumptions regarding the inoperability of the HPCI injection valve because of the pressure-locking problem.
LER No. 387/95-013 Acronyms ASP CCDP CDP HPCI LER LOCA LOOP Accident Sequence Precursor Conditional Core Damage Probability Core Damage Probability High Pressure Coolant Injection Licensee Event Report Loss-of-Coolant Accident Loss of Offsite Power MLOCA Medium Break LOCA PCS PP&L RCIC RPV SDC SLC SRV SPC Power Conversion System Pennsylvania Power &Light Residual Heat Removal Reactor Core Isolation Cooling Reactor Protection System Reactor Prcssure Vessel Shutdown Cooling Standby Liquid Control Safety Relief Valve Suppression Pool Cooling References 2.
LER 387/95-013, Rev. 0, "Thermally Induced Prcssure Locking of the HPCI Injection Valve,"
January 2, 1996.
Generic Letter 95-07, "Pressure Locking and Thermal Binding of Safety-Related Power-Operated gate Valves," August 17, 1995.
NRC Information Notice 96-08, "Thermally Induced Pressure locking of a High Prcssure Coolant Injection Gate Valve," February 5, 1996.
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LER No. 387/95-013 Table 1. Definitions and probabilities for selected basic events for LER No. 387/95-013 Event name ADS-SRV-CC-VALVS ADS-XHE-XE-EMLOC ADS-XHE-XE-ERROR Description ADS Valves Fail to Open Operator Error Prevents Dcpressurization (MLOCA)
Operator Error Prevents De pressurization Base probability 3.7 E403 1.0 E402 1.0 E403 Current probability 3.7 E403 1,0 E402 1.0 E403 Type Modified for this event No No No ADS-XHE-XE-NOREC Operator Fails to Recover ADS 7.1 E401 7.1 E401 No CRD-MDP-FC-TRNA Train A Failures 7.2 E404 7.2 E404 No CRD-MDP-FC-TRNB Train B Failures CRD-XHE-XE-ERROR Operator Fails to AlignCRD CRD-XHE-XE-NOREC Operator Fails to Recover CRD 7.2 E403 1.0 E402 1.0 E+000 7.2 E403 1.0 E402 1.0 E+000 No No CSS-XHE-XE-ERROR CSS-XHE-XE-NOREC CVS-XHE-XE-VENT EPS-DGN-CF-DGNS EPS-DGN-FC-DGA EPS-DGN-FC-DGB EPS-XHE-XE-NOREC HCI-TDP-FC-TRAIN HCI-XHE-XE-NOREC MFW-SYS-VF-FEEDW MFW-XHE-XE-NOREC Operator Fails to Align/Actuate Containment Sprays Operator Fails to Recover Containment Sprays Operator Fails to Vent Containment.
Common Cause Failure of Diesel Gcncrators Diesel Generator A Failure Diesel Generator B Failure Operator Fails to Recover Emcrgcncy Power HPCI Train Lcvcl Failures Operator Fails to Recover HPCI MFW Hardware Components Fail Operators Fail to Recover Feedwater 1.0 E402 1.0 E+000 1.0 E402 3.5 E404 1.9 E402 1.9 E402 5.0 E401 8.6 E402 7.0 E401 4.6 E401 34 E401 1,0 E-002 1.0 E+000 1.0 E402 3.5 E404 1.9 E-002 1.9 E-002 5.0 E401 1.0 E+000 1.0 E+000 4.6 E-OO I 3.4 E401 TRUE TRUE No No No No No No No Yes Yes No No
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LER No. 387/95-013 Table 1. Definitions and pr'obabilities for selected basic events for LER No. 387/95-013 Event name PCS-SYS-VF-MISC PPR-SRV-OO-2VLVS RCI-TDP-FC-TRAIN RCI-XHE-XE-NOREC RHR-MDP-CF-MDPS RHR-MOV40-BYPSA RHR-MOV~BYPSB RPS-SYS-FC-MECH RRS-XHE-XE-ERROR SDC-XHE-XE-ERROR SDC-XHE-XE-NOREC SLC-EPV-CF-VALVS SLC-MDP<F-MDPS SLC-PSF-FC-MISC SLC-XHE-XE-INIT SLC-XHE-XE-NOREC SPC-XHE-XE-ERROR SPC-XHE-XE-NOREC SRV Description PCS Hardware Component Failures Two SRVs Fail to Close RCIC Train Component Failures Operator Fails to Recover RCIC Common Cause Failure of RHR Pumps RHR Heat Exchanger A Bypass Valves Fail to Close RHR Heat Exchanger B Bypass Valves Fail to Close Mechanical Failures ofthc RPS Operator Fails to Trip the Recirculation Pumps Operator Fails to Align/Actuate SDC Operator Fails to Recover SDC Common Cause Failure ofSLC Explosive Valves Common Cause Failure ofSLC Motor-Driven Pumps SLC Serial Component Failures Operator Fails to Initiate SLC Operator Fails to Recover SLC Operator Fails to Align/Actuate SPC Operator Fails to Recover SPC One or Less SRVs Fails to Close Base probability 1.7 E401 2.0 E403 8.7 E402 7.0 E401 7.0 E405 3.0 E403 3.0 E403 1.0 E405 1.0 E402 1.0 E-002 1.0 E+000 2.6 E404 6.3 E404 2.0 E404 1.0 E402 I.O E+000 1.0 E402 1.0 E+000 2.2 E403 Current probability 1.7 E401 2.0 E-003 8.7 E402 7.0 E401 7,0 E405 3.0 E403 3.0 E-003 1.0 E-005 1.0 E402 1.0 E402 1.0 E+000 2.6 E404 6,3 E404 2.0 E404 1.0 E402 1.0 E&00 1.0 E402 1.0 E+000 2.2 E-003 Type Modified for this event No No No No No No No No No No No No No No No No No No No
LER No. 387/95-013 Table 2. Sequence conditional probabilities for LER No. 387/95-013 Event tree name TRAN MLOCA LOOP LOOP LOOP LOOP TRAN TRAN TRAN TRAN Sequence name 62 31 49 70 74 24 04 80-15 31 80-16 Conditional core damage probability (CCDP) 1.2 E-005 3.7 E-006 2.0 E-006 8.4 E-007 7.9 E-007 6.4 E-007 3.9 E-007 3.1 E-007 2.9 E-007 2.8 E-007 Core damage probability (CDP) 7.2 E-007 2.2 E-007 1.2 E-007 5.0 E-008 7.9 E-007 4.0 E-008 3.9 E-007 3.1 E-007 1.9 E-008 2.8 E-007 Importance (CCDP-CDP) 1.1 E-005 3.5 E-006 1.8 E-006 7.9 E-007 0.0 E+000 6.0 E-007 0.0 E+000 0.0 E+000 2.7 E-007 0.0 E+000 Percent Contribution to total CCDP 54.8 17.2 9.1 3.8 1.8 1.4 1.3 1.3 Total (all sequences) 2.1 E-005
.'crccnt Contribution to total CCDP.
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LER No. 387/95-013 Table 3. Sequence logic for dominant sequences for LER No. 387/95-013 Event tree name Sequence name Logic TRAN MLOCA LOOP LOOP LOOP LOOP TRAN TRAN TRAN TRAN 62 70 74 04 80-15 80-16
/RPS, PCS, P2, HCI, ADM HCI, ADM
/RP1, /EPS, P2, HCI, ADM
/RP I, EPS, /OEP, /SRV, HCI, RCI
/RP I, /EPS, /SRV, HCI, RCI, ADS, CRDL
/RPS, PCS, /SRV, /MFW, RHR, CVS RPS, /RRS, SLC
/RPS; PCS, /SRV, MFW, HCI, RCI, ADS, CRD RPS, RRS 11
LER No, 387/95-013 Table 4. System names for LER No. 387/95-013 System name ADM ADS CRDL CVS EPS HCI MFW OEP P2 PCS RCI SLC SRV Logic Automatic Depressurization Fails (MLOCA)
Automatic Depressurization Fails Insufficient CRD Flow to RCS Insufficient CRD Flow to RCS Containment (Suppression Pool) Venting Emergency Power System Fails HPCI Fails to Provide Suflicicnt Flow to Reactor Vcsscl Failure ofMain Feedwater System Offsite Power Recovery Two SRVs Fail to Close Power Conversion System RCIC Fails to Provide Sufficient Flow to RCS Residual Heat Removal Fails Reactor Shutdown Fails Reactor Shutdown Fails Recirculation Pump Trip Standby Liquid Control Fails One or Less SRVs Fail to Close 12
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I LER No. 387/95-013 Table 5. Conditional cut sets for higher probability sequences for LER No. 387/95-013 Cut set No.
Percent Contribution Conditional Probability'ut sets TRANSequence 62 79.2 20.8 MLOCASequence 31 1.2 E-005 9.5 E-006 2.5 E-006 3.7 E-006 PCS-SYS-VF-MISC, PPR-SRV-OO-2VLVS, ADS-XHE-XE-EMLOC PCS-SYS-VF-MISC, PPR-SRV-OO-2VLVS, ADS-SRV-CC-VALVS, ADS-XHE-XE-NOREC 79.2 20.8 2 9 E PP6 ADS-XHE-XE-EMLOC 7 7 E PQ7 ADS-SRVZC-VALVS,ADS-XHE-XE-NOREC LOOP Sequence 49 79.2 20.8 LOOP Sequence 70 1
99.9 LOOP Sequence 74 2.0 E-006 1.6 E-006 4.2 E-007 8.4 E-007 8.4 E-007 7.9 E-007 PPR-SRV-OO-2VLVS, ADS-XHE-XE-EMLOC PPR-SRV40-2VLVS, ADS-SRV-CC-VALVS,ADS-XHE-XE-NOREC "8>4OI, ':v~.""g>>:" $g ":~'.'4'p> g.'g"jQ~.'.jg~kP~+<'"'0:"j'jj)>/<'."N:4'P5ja x~:."..:c.:jgj)
EPS-DGN-CF-DGNS, EPS-XHE-XE-NOREC, /SRV, RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC 1
100.0 LOOP Sequence 24 7 9 E PQ7 RPS-SYS-FC-MECH 6.
19.5 18.5 18.5 14.0 1.2 E-007 1.2 E-007 1.2 E-007 9.0 E-008
/SRV, RCI-XHE-XE-NOREC, RCI-TDP-FC-TRAIN, ADS-SRV-CC-VALVS,ADS-XHE-XE-NOREC, CRD-XHE-XE-ERROR EPS-DGN-FC-DGA, EPS-XHE-XE-NOREC, /SRV RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRV-CC-VALVS, ADS-XHE-XE-NOREC, CRD-XHE-XE-NOREC EPS-DGN-FC-DGB, EPS-XHE-XE-NOREC, /SRV RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRVCC-VALVS, ADS-XHE-XE-NOREC, CRD-XHE-XE-NOREC
/SRV, RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRV-CC-VALVS,ADS-XHE-XE-NOREC, CRD-MDP-FC-TRNB, CRD-XHE-XE-NOREC 13
LER No. 387/95-013 Table 5. Conditional cut sets for higher probability sequences for LER No. 387/95-013 Cut set No.
Percent Contribution 7.4 7.0 7.0 5.3 1.4 Conditional Probability'.7 E-008 4.7 E-008 4.7 E-008 3.4 E-008 9.0 E-009 Cut sets
/SRV, RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-XHE-XE-ERROR, CRD-XHE-XE-ERROR EPS-DGN-FC-DGA, EPS-XHE-XE-NOREC, /SRV RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-XHE-XE-ERROR, CRD-XHE-XE-NOREC EPS-DGN-FC-DGB, EPS-XHE-XE-NOREC, /SRV RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-XHE-XE-ERROR, CRD-XHE-XE-NOREC
/SRV, RCI-TDP.FC-TRAIN, RCI-XHE-XE-NOREC, ADS-XHE-XE-ERROR, CRD-MDP-FC-TRNB, CRD-XHE-XE-NOREC I
/SRV, RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRVCC-VALVS,ADS-XHE-XE-NOREC, CRD-MDP-FC-TRNA, CRD-XHE-XE-NOREC TRAN Sequence 04 84.1 10.8 1.2 TRAN Sequence 80-15 89.7 5.6 2.3 1.8 TRAN Sequence 31 39.9 3.
3.3 E-007 4.2 E-008 4.7 E-009 3.1 E-007 2.8 E-007 1.7 E-008 7.1 E-009 5.6 E-009 2.9 E-007 1.2 E-007 PCS-SYS-VF-MISC, /SRV, RHR-MDP-CF-MDPS, SDC-XHE-XE-NOREC, SPC-XHE-XE-NOREC, CVS-XHE-XE-VENT, CSS-XHE-XE-NOREC PCS-SYS-VF-MISC, /SRV, RHR-MOV-OO-BYPSA.
RHR-MOV-OO-BYPSB, SDC-XHE-XE-NOREC, SPC-XHE-XE-NOREC, CVS-XHE-XE-VENT,CSS-XHE-XE-NOREC PCS-SYS-VF-MISC, /SRV, SDC-XHE-XE-ERROR, SPC-XHE-XE-ERROR, CVS-XHE-XE-VENT,CSS-XHE-XE-NOREC RPS-SYS-FC-MECH, SLC-XHE-XE-INIT RPS-SYS-FC-MECH, SLC-MDP-CF-MDPS, SLC-XHE-XE-NOREC RPS-SYS-FC-MECH, SLC-EPVZF-VALVS,SLC-XHE-XE-NOREC RPS-SYS-FC-MECH, SLC-PSF-FC-MISC, SLC-XHE-XE-NOREC PCS-SYS-VF-MISC, /SRV, MFW-SYS-VF-FEEDW, MFW-XHE-XE-NOREC,RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRV-CC-VALVS,ADS-XHE-XE-NOREC, CRD-XHE-XE-ERROR 14
s LER No. 387/95-013 Table 5. Conditional cut sets for higher probability sequences for LER No. 387/95-013 Cut set No.
Percent Contribution 28.7 15.2 10.9 1.0 Conditional Probability'.3 E-008 4.4 E-008 3.2 E-008 8.1 E-009 2.9 E-009 Cut sets PCS-SYS-VF-MISC, /SRV, MFW-SYS-VF-FEEDW, MFW-XHE-'XE-NOREC,RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRV-CC-VALVS,ADS-XHE-XE-NOREC, CRD-MDP-FC-TRNB, CRD-XHE-XE-NOREC PCS-SYS-VF-MISC, /SRV, MFW-SYS-VF-FEEDW, MFW-XHE-XE-NOREC, RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC.
ADS-XHE-XE-ERROR, CRD-XHE-XE-ERROR PCS-SYS-VF-MISC, /SRV, MFW-SYS-VF-FEEDW, MFW-XHE-XE-NOREC, RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-XHE'K-ERROR, CRD-MDP-FC-TRNB, CRD-XHE-XE-NOREC PCS-SYS-VF-MISC, /SRV, MFW-SYS-VF-FEEDW, MFW-XHE-XE-NOREC,RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-SRV~-VALVS,ADS-XHE-XE-NOREC, CRD-MDP-FC-TRNA, CRD-XHE-XE-NOREC PCS-SYS-VF-MISC, /SRV, MFW-SYS-VF-FEEDW, MFW-XHE-XE-NOREC,RCI-TDP-FC-TRAIN, RCI-XHE-XE-NOREC, ADS-XHE-XE-ERROR, CRD-MDP-FC-TRNA, CRD-XHE-XE-NOREC TRANSequence 80-16 98.0 Total (all sequences) 2.8 E-007 2.7 E-007 2.1 E-005 RPS-SYS-FC-MECH, RRS-XHE-XE-ERROR Thc conditional probability for each cut set is determined by multiplying thc probability that thc portion of the sequence that makes thc precursor visible (e.g., thc system with a failure is dcmandcd) willoccur during thc duration of thc event by the probabilities of the remaining basic cvcnts in the minimal cut sct. This can be approximated by I - e~, where p is dctcrmined by multiplying thc expected number of initiators that occur during the duration'of the cvcnt by thc probabilities of the basic events in that minimal cut sct.
Thc expected number of initiators is given by At, where A, is the frequency of thc initiating event (given on a pcr hour basis), and t is the duration time ofthc event (in this case, 6I34 h). This approximation is conservative for prccursors made visible by thc initiating event.
Thc frcqucncies ofintcrcst for this event arc: A r ~ 1.29 x 10'/h,~
4.9 x 10~/h, and~
4,57 x 10~/h.
15
GUIDANCE FOR LICENSEE REVIEW OF PRELIMINARY ASP ANALYSIS
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 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.
Nodeling 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:
(I) 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 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.
.Enclosure 2
Appendix H of Reference I 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
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 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 response.
This includes:
normal or emergency operating procedures.
piping and instrumentation diagrams (PLIDs),
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 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
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:
(I) 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 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, Hartin Marietta Energy Systems, Inc.,
Oak Ridge National Laboratory and Science Applications International Corp.,
December 199S.
Docket No.
50-XXX Hr. John Jones Vice President, Nuclear Operations Utility XYZ P.O.
Box 123 City, State ZIP
Dear Hr. Jones:
SUBJECT:
REVIEW OF PRELIMINARY ACCIDENT SEQUENCE PRECURSOR ANALYSIS OF
[EVENT/CONDITION] AT PLANT ABC Enclosed for your review and comment is a copy of the preliminary Accident Sequence Precursor (ASP) analysis of an operational
[EVENT/CONDITION] which
[OCCURRED/WAS DISCOVERED] at
[PLANT NAME] on
[DATE] (Enclosure 1),
and was reported in Licensee Event Report (LER) No.
[LER NUMBER].
This analysis was prepared by our contractor at the Oak Ridge National Laboratory (ORNL).
The results of this preliminary analysis indicate that this
[EVENT/CONDITION] may be a precursor for 1995.
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 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'recursor 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.
Enclosure 2
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 lic'ensee-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.
Enclosure 3 is a
copy of LER No.
[LER NUMBER], which documented the event.
I
Please contact me at
[PROJECT MANAGER'S TELEPHONE NUMBER] if you have any questions regarding this request.
This request is covered by the existing OHB 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,
[PROJECT MANAGER NAME, TITLE]
[PM'S PROJECT DIRECTORATE]
fPROJECT DIRECTORATE DIVISION]
Office of Nuclear Reactor Regulation