ML17241A470
| ML17241A470 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 09/25/1999 |
| From: | Stall J FLORIDA POWER & LIGHT CO. |
| To: | NRC OFFICE OF INFORMATION RESOURCES MANAGEMENT (IRM) |
| References | |
| L-99-215, NUDOCS 9910050281 | |
| Download: ML17241A470 (35) | |
Text
C2kTEaOZr REGULA RY INFORMATION DISTRI'BUTIO SYSTEM (RIDS)
ACCESSION NBR: 9910050281 DOC.DATE: 99/09/25 NOTARIZED: NO DOCKET ¹ FACIL:50-335 St. Lucie Plant, Unit 1, Florida Power E.Light Co. 05000335 3'0-P 83 St. Lucie Plant, Unit 2, Florida Power S Light Co. 05000389 AUTH.NAiAE AUTHOR AFFILIATION STALL,J.A. Florida Power & Light Co.
RECIP.NME RECIPIENT AFFILIATION Records Management Branch (Document Control Desk)
SUBJECT:
Forwards info requested by NRC staff during 990916 telcon to complete staf f review of request for risk-informed extension of action completion/AOT specified for inoperable train of LPSI sys at plant.
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Florida Power & light Company, 6351 S. Ocean Drive, Jensen Beach, Fl34S57 L-99-215 September 25, 1999 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555 Re: St. Lucie Unit1 and Unit2 Docket Nos. 50-335 and 50-389 Proposed License Amendments LPSI System Risk Informed AOT Extension Res onse to Re uest for Additional Information Ref: FPL Letter L-99-079: J.A. Stall (FPL) to NRC (DCD), St. Lucie Unit 1 and Unit 2, Docket Nos. 50-335 and 50-389, Proposed License Amendments, LPSI System Risk Informed AOT Extension; June'1, 1999.
The enclosure with this letter provides information requested by the NRC staff during a telephone conversation with FPL on September 16, 1999. The information is deemed necessary to complete the staffs review of our request for a risk-informed extension of the action completion/allowed outage time (AOT) specified for an inoperable train of the Low Pressure Safety Injection (LPSI) system at St. Lucie Units 1 and 2.
Please contact us if there are any questions about the enclosed response or the reference proposed license amendments.
Very truly yours, J. A. Stall Vice President St. Lucie Plant JAS/RLD Ogi,"tea'4 Enclosure
'c:
Regional Administrator, Region II, USNRC Senior Resident Inspector, USNRC, St. Lucie Plant 99i005028i 990925 ADOCK 05000335'DR P PDR an FPl Group company
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L-99-215 I
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ENCLOSURE PAGE 1 OF 22 RESPONSE TO REQUEST FOR ADDITIONALINFORMATION ST. LUCIE UNITS 1 AND 2 LPSI SYSTEM RISK INFORMED AOT EXTENSION ENGINEERING EVALUATIONPSL-ENG-SERS-99-048, RO (ABRIDGED/EDITED)
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L-99-215 ENCLOSURE PAGE 2 of 22 ST. LUCIE PLANT UNITS 1 AND 2 RESPONSE TO NRC RAI Re: LPSI AOT PLA FPL letter L-99-079 (Reference 1) submitted FPL's Proposed License Amendments (PLAs) for St. Lucie Units 1 and 2 to increase the Allowable Outage Time (AOT) for a single Low Pressure Safety Injection (LPSI) train
&om 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to 7 days (168 hours0.00194 days <br />0.0467 hours <br />2.777778e-4 weeks <br />6.3924e-5 months <br />). 'Ibis evaluation documents responses to a NRC request for additional information regarding the PSA input to this Technical Specification change request.
each licensee to furnish, r ' l in its submittal, infornkation on PRA quality including:
- "" 'll'"i'equire I. Veri kcation that tike PRA re ects the as-build/as-o crated lant R~es onse: Section 3.2.2 of Reference l addressed this as follows:
The St. Lucie contribution to the 1995 preparation of CE NPSD-995 (Reference 2) was generated using the IPE models developed in response to Generic Letter (GL) SS-20, Individual Plant Examination for Severe Accident Viklnerabilities, and associated supplements. Subsequently in 1997, the NRC completed its review of the GL 88-20 submittals and in a letter to FPL dated July 21, 1997,
Subject:
Staff Evaluation Report of St.
Lucie, Units 1 and 2, Individual Plant Examination (IPE) Submittal TAC Nos. M74473 AND M74474, the NRC staff stated, "The NRC staff concluded that the FPL IPE process is capable of identifying the most likely severe accidents and severe accident vulnerabilities for St. Lucie, Units 1 and 2, and, therefore, meets the intent of GL 8S-20."
Since then, FPL has updated both the models and the reliability/unavailability databases for St. Lucie Units 1 and 2. The updated models and databases were then used to re-calculate the risk numbers for the units. A summary of the major changes (also discussed in Reference 1) is provided in the response to question 2, and additional discussion regarding PSA updates is provided in the response to question 4 below.
Additional information not in the PLA: Before performing the risk assessment for the LPSI PLA, FPL reviewed all design changes implemented since the last PRA update and reviewed current revisions of the critical procedures which establish requirements and timing for operator recovery actions. No model changes were required as a result of this review.
- 2. U dates o the PRA since the last reviekv cl includin corrections o kveaknessesidenti ked b ast reviekvs.
~Res onse: The PLA submittal (Reference ti provided a summary of the model updates. This includes several items previously considered to be weaknesses. The information from Reference 1 (pages 7 and 8 of ) is repeated below for convenience.
The most significant change included with each model update is the creation of a "one-top" model which is constructed &om the original model's individual top events for various initiators, e.g., small LOCA, large LOCA, SGTR, reactor trips, etc. The one-top model allows rapid quantification, and each case for this re-evaluation of LPSI was individually quantified. The truncation used for quantification was 2E-10 or lower.
This replaces the use of one master cutset file (per unit) in the original (1995) CEOG evaluation.
I L-99-215 ENCLOSURE PAGE3 of22 The model update process included a review of all plant design changes that were implemented since creation of the original models. Due to the maturity of the St. Lucie units, only one plant design change was implemented (Unit 2) that resulted in a notable impact on the analysis results, and is discussed in the following summary of significant changes. For the reliability/unavailability database update, FPL was able to use the last three years of data gathered pursuant to the Maintenance Rule (10 CFR 50.65) which provided concise, high-quality unavailability and reliability data for the risk-significant systems. Outside peer review was not performed for the update because creating a one-top model essentially involved combining the existing tops for the various scenarios, and other model changes that were implemented were not extensive. A summary of significant model changes relevant to the LPSI AOT extension follows:
Test & Maintenance (T&M) events for selected equipment were added to better support Maintenance Rule implementation and related risk evaluations. Minor improvements were made in the modeling of instrument air systems and in the handling of common cause events.
New initiating event (IE) frequencies were calculated for all LOCAs. This was done in accordance with CEOG Probabilistic Safety Assessment Working Group (PSAWG) Technical Position Paper, "I<valuation of the Initiating I<vent I<requency for the Loss ofCoolant Accident", CEOG Task 941, January 1997. Although the IE frequency for two LOCA sizes (large and small) decreased, the net impact was an increase in the total LOCA IE frequency of nearly 48%, i.e., &om 2.09E-3 to 3.09E-3 per year.
The process of adding recoveries is now automated using a recovery "rule file". The rule file utilizes a manual recovery action process in that recovery actions are added to each cutset rather than being generated &om the model, but the process is automated such that all the similar cutset scenarios are recovered automatically. This automatic feature ensures uniform and complete inclusion of recovery actions throughout all of the generated cutsets, and yields more realistic and consistent results.
FPL reevaluated all offsite power recovery cases for both St. Lucie units. One case was added to the Unit 1 analysis for recovery of offsite power in 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> (approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> before the Unit 1 CST would deplete without condensate replenishment). The non-recovery probability for one case was increased for both units due to an incorrect assumption that was used in the original analysis. In addition, the related recovery for getting power &om the alternate unit was increased due to timing considerations. Although 60 minutes total is available (as assumed in the original evaluation), only 45 minutes remains for power recovery afier diagnosis of the event per the plant Emergency Procedures. This factor was combined with hardware-related failures to calculate the total non-recoveiy probability of 0.1 for the crosstie recovery event.
For Unit 2, a plant design change was made that requires the SDC suction cross-connect valve to be locked open. The valve was normally closed during power operations, and this action was taken in response to concerns raised by GL 95-07, "Pressttre Locking and Thermal Binding of Safety-Related Power Operated Gate Valves". The modification also included a requirement to remove electrical power from each of the SDC suction isolation valve actuators by locking open their associated motor control circuit breakers. The intersystem-LOCA (ISLOCA) calculations were revised to include the plant design change. This resulted in an increase in the ISLOCA frequency. However, the plant design change prevents inadvertent opening of the SDC suction valves during power operations and iinproves the ability to initiate shutdown cooling operations for events involving loss of one train of electrical power. These factors werc judged to offse the calculated risk increase such that the net change to ISLOCA is at least risk neutral.
The net effect of the modeling changes caused a slight increase in the calculated core damage frequency (CDF). However, when the data update was completed, including all other initiating events, the final result was a decrease in the calculated CDF for both units.
L-99-215 ENCLOSURE PAGE 4 of 22
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Additional Information not in the PLA:
An issue addressed in the NRC SER for the IPE regarded the IE frequency used for loss of a DC bus. The IE frequency used in the IPE was based on the generic bus failure probability over a year. As part of the PSA update, a fault tree was used to assess anew IE frequency for loss of a DC bus. The revised loss of DC bus IE &equency was incorporated in the previous PSA update and is, therefore, refiected in the LPSI AOT extension evaluation. The new Loss of DC Bus IE frequency is 1.07E-03/yr compared to the IPE value of 3.94E-04/yr. It is judged that this re-assessment corrects the perceived deficiency identified by the NRC and thus no further action is required.
A sensitivity study has been performed covering selected operator actions. The actions chosen were either related to LPSI system operation or were questioned by the NRC in the SER for the St. Lucie IPE. The operator actions modified are listed in the following table.
0 erator Actions Reviewed for LPSI Sensitivit Stud Operator Action Description New Value for Old Value Sensitivit Stud Failure to initiate shutdown RTOP1[2]RLTC 7.5E44 1.0E42 coolin for SGTR RTOP1TLTC Failure to initiate shutdown
/A ON UN1T 2 coolin for transients 1.22E42 1.22E42 Failure to initiate shutdown RTOP1[2] S1LTC 7.5E44 1.0E42 coolin for S1LOCA Failure to initiate once- through RTOP1 2 ROTC coolin for SGTR 7.5E43 5.0E42 Failure to initiate once- tlimugh RTOP1[2]TOTC 7.5E43 5.0E42 coolin - transients Failuie to initiate once- tluough RTOP1[2]S1OTC 7.5E43 5.0E42 coolin -S1LOCA Failure to manually operate steam R¹CAFWMAN 7.88E42 2.0E41 driven AFW um Failure to manually operate AFW R¹AFXVLVS 3.68E42 1.0E41 cfosswonncct valves Failure to manually actuate AFW R¹AFWCMP components (Control Room 3.0E43 3.0E42 action Failure to stop RCPs on loss of RTOP1[2]S 1RCP 3.0E-4 1.0E42 scalin water U2 SDC Failure on LOG, no CST U2XTSDC 5.58E42 2.43E41 water for Ul LTC For this operator action sensitivity study, three operator actions directly related to shutdown cooling (SDC) were evaluated. These are the first three in the table of Operator Actions Reviewed for LPSI Sensitivity Study above (RTOP1[2]RLTC, RTOP1TLTC, and RTOPl[2]S1LTC, where [2] indicates Unit 2). New values for these actions were chosen to give a significant increase (approximately'wo orders of magnitude) to the failure probabilities for initiating SDC for SGTR and Sl (small small LOCA). It should be noted that RTOP1TLTC (not used for Unit 2) was originally quantified as a time dependent action whereas the other two were initially considered as time independent, causing the original values to be smaller. Using a time-dependent approach brings those two in line with the failure probability for SDC initiation following transients (RTOP 1TLTC).
L-99-215 ENCLOSURE PAGE 5 of 22 The next three operator actions (RTOP1[2]ROTC, RTOP1[2]TOTC, and RTOP1[2]S1OTC) are not directly related to SDC. However, once-through cooling (OTC) is one means of cooling down to SDC conditions. The above actions were quantified as "slips" (i.e., time-independent actions) for the St. Lucie IPE. The NRC concluded in the St. Lucie IPE SER that treating post-initiator human actions with a time-independent approach is "troublesome" since the approach does not model diagnosis and decision-making and has the potential to over-estimate the likelihood of success. 'Another observation made by the NRC was that the quantification of the above actions was not sequence-specific, i.e., the same probability was used for all sequences thus not considering potential difFerences in time for diagnosis and the available time to complete the action. Although these actions are not specifically related to a LPSI pump/system being OOS in most cases, they could have an impact on the overall PSA results and are thus included in this study.
For once-through-cooling (OTC) initiation, FPL agrees with the NRC conclusion that the timing is scenario-specific. The most limiting case would be a total loss of main feedhvater resulting in a unit trip on low SG level. OTC must be initiated before SG dryout (approximately 19-20 minutes). The only initiating events (IEs) that would result in this scenario are related to loss of MFW. For all other IEs, the reactor trip would occur with at least normal operating SG level, and thus the available time to initiate OTC would be lengthened. For some scenarios, the initiation of OTC may be several hours aAer shutdown, when the decay heat is substantially lower than immediately after the trip. Since analysis of multiple OTC recovery actions based on various OTC timing assumptions will not be completed in time to support this PLA, a representative and conservative timing assumption will be used for this sensitivity study. Applying the time-dependent technique used for the PSL IPE and assuming 20 min to SG dryout, a conservative 15-minute diagnosis time (thus 5 minutes available for performing the action), and a 2-minute response time, the estimated non-recovery probability would be approximately 2E-02. This timing would actually only apply to the t=0 loss of all feedwater events (i.e., reactor trip on low SG level). For longer-term loss of feedwater scenarios, the available time would be longer. For this operator action sensitivity study, a conservative value of 5E-02 for all OTC recovery events was used. The benefit of performing sequence-specific quantification of OTC recovery events willbe evaluated as part of a future PSA update.
The next three selected operator actions (R¹CAFMAN, R¹AFXVLVS, and R¹AFWCMP) are for the Auxiliary Feedwater (AFW) system. The non-recovery probability for these events was increased to address NRC concerns expressed in the IPE SER regarding timing. R¹CAFWMAN involves manual local operation of the turbine driven ("C") AFW pump. The action is primarily associated with loss of DC control power to the pump. The dominant method of losing power would be battery depletion following loss of AC power to the battery chargers or charger failure. Battery depletion would be at least 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> aAer loss of the chargers.
Decay heat level would be less than that immediately afier a unit trip. The available time to recovery feedwater would thus be greater than the 60 minutes assumed for a t=0 loss of all feedwater. This basic event was originally quantified as an ex-control room action with a 10-minute diagnosis time, a 13-minute response time, and 50 minutes available time (assuming 60 minutes to recover feedwater). Ifit is assumed for this study that an additional 10 minutes is required for diagnosis (20 minutes total), 40 minutes would then be available to complete the action. This results in a revised probability of 0.12. A conservative value of 0.2 was used for this study. R¹AFXVLVS involves opening (locally) AFW cross connect valves after failure of a motor-driven AFW pump on one train and the failure of the AFW flow path to the SG on the other train. This action was quantified assuming a 10-minute response time and 55-minute available time.
For this study, the response time was increased to 15 minutes and the available time was reduced to 50 minutes (i.e., 5 additional minutes assumed for diagnosis and 5 fewer minutes assumed for response). This results in a non-recovery probability of approximately 0.1 (baseline is 3.68E-02). R¹AFWCMP involves the operator manually activating AFW components from the control room in the event of an automatic actuation failure. Since this action is well covered by procedures and training, it is judged that a one decade increase, from 3E-03 to 3E-02, is conservative and is adequate for this study.
L-99-215 ENCLOSURE PAGE 6 of 22 Action RTOP ISIRCP (RTOP2S1RCP) involves the operator securing the RCPs aAer loss of Component Cooling Water (CCW) cooling to the pumps. It is assumed that the pumps must be secured within 10 minutes to prevent a seal LOCA, although industry events have shown, that the pumps could operate longer than 10 minutes without catastrophic seal damage. Since this is an in-control room action clearly addressed by procedures, the operator action was assumed to be time-independent ("slip") for the PSL IPE. For this study, it was assumed that this is a time-dependent in-control room response action requiring 3 minutes to diagnose (thus a 7-minute available time) and a 1-minute response time. The resulting non-recovery probability would be approximately 7E-03. For this study, a conservative value of 1E-02 was used.
The last event is U2XTSDC. IMs represents the probability of Unit 2 failing to reach shutdown cooling on a Loss of Grid thereby being unable to supply water &om the Unit 2 CST to the Unit 1 AFW pump suction for long-term cooling (beyond about 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />). This was recalculated assuming Unit 2 had one LPSI (SDC) pump out for maintenance. The new value for this basic event would become 2.43E-01 using this assumption.
Although this is not an operator action, it is directly related to LPSI (SDC) operation and is appropriate for inclusion in this sensitivity study.
The sensitivity study results are shown in the following tables. All table numbers used correspond to the equivalent tables in the PLA submittal with the addition of an "S" (for sensitivity), except Tables 1 and 2 are combined for this study.
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L-99-215 ENCLOSURE PAGE 7 of 22 TABLE IS and 2S - CONDITIONALCDF CONTRIBUTIONS OPERATOR ACTION SENSITIVITYSTUDY CURRENT AOT AYS PROPOSED AOT AYS BASELINE 3.47E-05 2.90E-05 CM (CASE 1A) 6.13E-05 4.59E-05 (1) CCDF/YR (1 TRAIN AVAILABLE)
PM (CASE 1B) 3.92E-05 3.21E45 (2) CCDF/YR (1 TRAINNEVER OUT FOR T/M) CASE 2 3.47E45 2.89E-05 INCREASE IN CDF/YR CM 2.67E45 1.70E45
[= (I) - (2)] PM 4.52E46 3.24E-06 SINGLE AOT RISK (CURRENT AOT) CM 2.19E-07 1.40E-07 4
[= (3)/HR
[= (3)/HR ~ PROPOSED AOT HRS]
PM 8.68E-08 6.21E-08 ASSUMED DOWNTIMEFREQUENCY CM 6
(/YR/LPSI TI&IN) PM YEARLYAOT RISK (CURRENT AOT) CM 4.38E47 2.79E-07
[= (4) * (6)
[= (5) * (6) ~ 2 TIV INS] PM 5.20E-07 3.73E-07 PROPOSED TOTALDOWNTIME CM 24 (HRS/YR/TIGON) PM 208 208 ASSUMED MEANDURATION CM 24 24 (10) (HRS/DOWNTIME EVENT)
= 9/6 PM SINGLE AOT RISK FOR ASSUMED MEAN CM 7.30E-08 4.66E-08 (11) DURATION
= 3/HR* 10 PM 3.56E-08 2.55E-08 YEARLYAOT RISK FOR ASSUMED MEAN CM 1.46E-08 9.31E-8 (12) DURATION
= 11 ~ 6 *2TRAINS PM 2.13E-07 1.53E-07 RG 1.174 (Reference 3) discusses acceptance criteria for changes in CDF and LERF. RG 1.174 indicates that a change in CDF of <1E-06 with a total CDF of <IE-04 and a change in LERF of <1E-7 with a total LERF of
<IE45 is considered very small. As can be seen in Table 3S, the change in the average CDF assuming the proposed LPSI unavailability is <IE46 for the sensitivity study results. Table 4S shows that the change in the average LERF assuming. the proposed LPSI unavailability is <IE47 for the sensitivity study. The proposed change in CDF and LERF due to the proposed AOT extension is, therefore, considered very small.
I 99-215 ENCLOSURE PAGE 8 of 22 Table 3S (Operator Action Sensitivity Study) s ~ ~
PROPOSED AVERAGE CDF Pammeter St. Lucie Unit 1 St. Lucio Unit 2 LPSI System Success Criteria 1of2 1of2 Present AOT, days Proposed AOT, days Proposed Downtime, lus/train/yr. 232 232 Average CDF, base, per yr. 3.47E45 2.90E45 Proposed Average CDF, pcr yrts using LPSI T/M sct at Proposed 3.49E-05 2.91E-05 Downtime value Table 4S (Operator Action Sensitivity Study)
PROPOSED AVERAGE LERF Early Containmcnt Failure
- Early Containment Failure Probabilit = 0.01 aseline Probabili = 0.1 Parameter St. Lucie Unit 1 St. Lucie Unit 2 St. Lucie Unit 1 St. Lucie Unit 2 Avg. base LERF pcr 3.77E-06 6.18E46 6.85E46 8.76E-06 r.
Proposed LERF, per yrra using LPSI T/M 3.77E46 6.18E-06 6.86E-06 8.78E-06 set at proposed downtime value
- Sensitivity evaluation (factor of 10 increase)
RG 1.177 (Reference 4) states that the licensee must demonstmte that the proposed AOT change has only a small quantitative impact on plant risk. Per Reference 4, an ICCDP of less than 5.0E-07 is considered small for a single AOT change. As is shown in Tables 5S, the ICCDP values for the proposed AOT extension are below the RG 1.177 specified values except for the Unit 1 CM case which is only slightly above 5E47 (i.eta 5.11E-07). The ICCDP results for this study are considered small. Also pcr NRC RG 1. 177, an ICLERP of less than 5.0E-08 is considered small for a single AOT change. For ICLERP, the Unit 1 CM case is slightly above these guidelines. However, this case also includes an increased early containment failure probability of 0.1, which is ten times the baseline assumption. Additionally, this potential risk increase must be balanced against the risks inherent in maneuvering the plant for a shutdown and potentially having to enter a mode where the LPSI pump is the only means of cooling, i.e., with one pump already outwf-service. This is especially true since the only case at issue is ~un tanned corrective mainteriance, which implies a pump or train has ddled and requires repair.
It is arguable that it is safer to do so on line rather than to shutdown and be forced to rely on the only remaining pump or train. Finally, this study is intentionally quite conservative.
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L-99-215 ENCLOSURE PAGE 9 of 22 Table 5S (Operator Action Sensitivity Study)
ICCDP RESULTS Parameter St. Lucie Unit I St. Lucic Unit 2 ICCDP for Corrective Maintenance 5.11E47 3.24E47 C case ICCDP for Preventive Maintenance 8.64E48 5.95E48 case Table 6S (Operator Action Sensitivity Study)
ICLERP RESULTS Early Containment Failure *Early Containment Failure Probabilit = 0.01 aseline Probabilit = 0.1 St. Lucie Unit 1 St. Lucie Unit 2 St. Lucie Unit 1 St. Lucie Unit 2 CM 1.88E48 5.94E49 6.42E48 3.53E48 PM 2.11FA9 7.67E-10 9.78FA9 6.32FA9
- Sensitivity evaluation (factor of 10 increase)
It is judged that appropriate uncertainty issues are addressed by the combination of the sensitivity studies provided in the PLA and the additional sensitivity studies documented above.
- 3. Details o the eer review rocess a sununa o eer review indin s and a discussion o the inde endence o internal reviewslreviewers.
R~cs onse: Reference 5, section 5.2, and the response to Reference 6 question 2 provide a summary of tiie original IPE model peer review process. This information is repeated below:
Three levels of review were used for the St. Lucie PRA. The first consisted of normal engineering quality assurance carried out by the organization performing the analysis. A qualified individual with knowledge of PRA methods and plant systems performed an independent review of the results for each task. This represents a detailed check of the input to the PRA model and provides a high degree of quality assurance.
The second level of review was performed by plant personnel not directly involved with the development of the PRA model. This consisted of individuals from Operations, Technical, Training, and ISEG groups who reviewed the system description notebooks and accident sequence description. This provided diverse expertise with plant design and operations knowledge to review the system descriptions for accuracy.
The third level of review was performed by PRA experts from ERIN Engineering, FRH, Inc., NUS, and Baltimore Gas & Electric. This review provided broad insights on techniques and results based on experience from other plant PRAs. The review team concentrated on the overall PRA methodology, accident sequence analysis, system fault trees and draft quantification results. The intent was to provide early feedback to the St. Lucie staff concerning the adequacy and accuracy of the reviewed products.
It should be noted that the methodologies used for the St. Lucie Level I and Level II analyses were similar to those used for the Turkey Point PRA. The Turkey Point IPE submittal was thoroughly reviewed by the NRC stafF and NRC contractors. The NRC review concluded that the process used to develop the Turkey Point PRA was acceptable in meeting the intent of GL-88-20.
L-99-215 ENCLOSURE PAGE 10 of 22 The general areas of review were described above. The overall purpose of the review was to ensure the quality of the PRA project and to ensure that the project objectives were being met. The review team found that the project was successfully meeting those objectives with a sound methodology.
A summary of the peer review comment areas is as follows:
~ The overall methodology reflects the current state of the art for PRAs and will meet the requirements of GL-88-20 (confirmed by the NRC St. Lucie IPE SER).
~ The system description notebooks were very well organized and very complete.
~ The event trees and success criteria used to support the systems analysis interface are consistent with those of other similar analyses.
~ CST replenishment should be included for sequences where long-term cooling via AFW may be required (this was included for Unitl, not applicable for Unit 2).
~ Units 1 and 2 data should be combined to formulate the plant-specific history (this was incorporated).
Another level of peer review is accomplished through the CEOG joint comparison process. The intent of this process is to provide a cross comparison of CE units PSA results to validate the plant specific results and conclusions. An example of the joint comparison process related to the proposed LPSI AOT change is provided in the response to Reference 6 question 3. Additional CEOG cross comparisons have been performed since issuance of Reference 6. A sensitivity study was performed to address differences identified in these cross comparisons that are judged to have the potential to impact the conclusions of the St. Lucie LPSI AOT evaluation. See response to question 2 above for additional information regarding the St. Lucie sensitivity study performed.
FPL has updated both the models and the reliability/unavailability databases for St. Lucie Units 1 and 2. The updated models and databases were then used to re-calculate the risk numbers in support of the requested St.
Lucie LPSI AOT extension. The significant model and data changes are summarized in Section 3.2.2 of the St.
Lucie proposed license amendment (Reference 1) and in the response to question 2 above. As discussed in Reference 1, outside peer review was not performed for the update because changes that were implemented are not extensive. One or more FPL PSA engineers implemented the changes, and a FPL PSA engineer not involved with implementation ofthe changes performed an independent review.
cf. Descri tion o PRA ual'ssurance methods.
~Rcs onse: As noted in the response to question 2 above and in Reference i, the models used for this PLA were generated using the IPE models developed in response to Generic Letter (GL) 88-20, Individual Plant Examination for Severe Accident Vulnerabilities, and associated supplements. The original development work was classified and performed as "Quality Related" under the FPL 10CFR Appendix B quality assurance program. The revision and applications of the PRA models and associated databases continue to be handled as Quality Related. Since the approval of the IPE, the FPL Reliability and Risk Assessment Group (RRAG) has maintained the PSA models consistent with the current plant configuration such tliat they are considered "living"models. The PSA models are updated for different reasons, including plant changes and modifications, procedure changes, accrual of new plant data, discovery of modeling errors, advances in PSA technology, and issuance of new industry PSA standards.
The update process ensures that the applicable changes are implemented and documented timely so that risk analyses performed in support of plant operation reflect the plant configuration, operating philosophy, and transient and component failure history. The PSA maintenance and update process is described in the FPL
L-99-215 ENCLOSURE PAGE 11 of 22 RRAG standard "PSA Update and Maintenance Procedure". This standard defines two different types of
. periodic updates: 1) a data analysis update, and 2) a model update. The data analysis update is performed at least every five years. Model updates consist of either single or multiple PSA changes and are performed at a &equency dependent on the estimated impact of the accumulated changes. Guidelines to determine the need for a model update are provided in the standard. This includes written procedures, independent review of all model changes, data updates and risk assessments performed using PSA methods and models. Risk assessments are performed by one individual, independently reviewed by another and approved by the Department Head or designee. The PSA group falls under the FPL Engineering Quality Instructions with written procedures derived from those QIs. Procedures, risk assessment documentation, and associated records are controlled and retained as QA records.
All computer programs that process PSA model inputs are verified and validated as needed. The RRAG policy on verification and validation of QA controlled/procured sofbvare, as well as the verification and validation for sofbvare and computers when used for Quality Related applications are described in RRAG standard "PSA Software Control Procedure". This standard provides a list of all the sofhvare used by the RRAG and indicates whether the sofhvare is QA controlled/procured. Sofbvare verification is the process used to ensure the software meets the sofbvare requirement specifications. The PSA sofbvare that is procured with a QA option and is developed under a 10 CFR 50 Appendix B QA program does not require further software verification by the RRAG. However, the PSA sofbvare, which is not procured with a QA option can be verified by comparison of results to previously approved sofbvare. Validation of sofbvare is performed for different conditions such as: 1) a new installation of sofbvare, 2) any new database or configuration file changes issued by the RRAG, 3) unreasonable results, 4) change in computer configuration (sofbvare, hardware), and 5) use of sofhvare for Quality Related applications for the first time. Validation requirements for each Quality Related PSA computer program are documented in a Sofbvare Verification/Validation Plan (SVVP) procedure. These requirements include the method of validation, the &equency of validation, the documentation required and the acceptance criteria. A SVVP procedure is submitted for each program. Actual validation benchmark problems can exercise more tlian one program, but a separate Sofhvare Verification/ Validation Report (SVVR) must be submitted for each program. Each SVVP procedure and SVVR is independently reviewed and then approved by the RRAG supervisor. Software validation tests both the sofhvare and the hardware. Validation tests are also if performed following any significant change in the hardware, operating system, or program or the validation period established in the SVVP procedure expires. Sample formats for the SVVP and SVVR are provided in the Engineering Quality Instruction (conforming to the pertinent 10 CFR 50 Appendix B requirements) for computer sofbvare control.
- 5. Results o revinfss o ertinent accident se <<ences and cut sets or modelin ade ua and com lefeness with res ect to tlsis a lication
~Res onse; The results of the evaluations performed in support of the St. Lueie LPSi AOT extension request were reviewed by two PSA engineers (a preparer and an independent reviewer). Both concluded that the results were appropriate considering the inputs and assumptions used. It is judged, based on a review of the results, that the models are adequate for this application. The following summarizes the dominant cutsets:
Unit 1:
~ Attachment 1 lists the top 10 Unit 1 baseline cutsets. This is the value shown in the PLA Tables 1 and 2 as the "Conditional CDF, per yr., 1 LPSI train not out for T/M". The dominant accident sequence is related to a "Small-Small" (1/2" to 3") LOCA initiating event with failures related to high pressure safety injection. Other cutsets in the top 10 are related to ATWS.
L-99-215 ENCLOSURE PAGE 12 of 22
~
Attachment 2 lists the top 10 Unit 1 cutsets for the corrective maintenance (CM) case. This is the value shown in the PLA Table 1 for "Conditional; CDF, per yr., 1 LPSI train unavailable". For this case, one LPSI train is assumed out-of-service for corrective maintenance and the common cause LPSI failures are set to the beta factor. The dominant sequence is related to a "Large" (>5") LOCA with common cause failure of LPSI pumps. Additional cutsets that are now in the top 10 (i.e., not in the baseline top
- 10) are related to a "Large" LOCA, one LPSI train out-of-service, and failures in the other LPSI train.
~ Attachment 3 lists the top 10 Unit 1 cutsets for the preventive maintenance (PM) case. This is the value shown in the PLA Table 2 for "Conditional; CDF, per yr., 1 LPSI train unavailable". For this case, one LPSI train is assumed out-of-service for preventive maintenance and the common cause LPSI failures are set to 0.0. The dominant sequence is the same as the baseline case. Additional cutsets that are now in the top 10 (i.e., not in the baseline top 10) are related to a "Large" LOCA, one LPSI train out-of-service, and failures in the other LPSI train.
~ Attachment 4 lists the top 10 Unit 1 cutsets for the new average CDF assuming the proposed LPSI downtime. This is the value shown in the PLA Table 3 for "Proposed Average CDF, per yr., using LPSI T/M set at proposed downtime value". For this case, the LPSI unavailability was changed based on the proposed downtime assuming an increased AOT. The dominant sequences are the same as the baseline case.
Unit 2:
~ Attachment 5 lists the top 10 Unit 2 baseline cutsets. This is the value shown in the PLA Tables 1 and 2 as the "Conditional CDF, per yr., 1 LPSI train not out for T/M". The dominant accident sequence is related to a "Small-Small" LOCA with failures related to high pressure safety injection.
~ Attachment 6 lists the top 10 Unit 2 cutsets for the CM case. The dominant sequences are the same as discussed above for the Unit 1 CM case.
~ Attachment 7 lists the top 10 Unit 2 cutsets for the PM case. The dominant sequences are the same as discussed above for the Unit 1 PM case.
~ Attachment 3 lists the top 10 Unit 2 cutsets for the new average CDF assuming the proposed LPSI downtime. The dominant sequences are the same as the baseline case.
- 6. Provide a summa o tfse lant rocedures tlsat address lant actions in res onse to external events e.
Iud rricanes tornadoes d res
~Rcs onse: The Administrative Procedure entitled "Hurricane Season Preparation" outlines the actions to be reviewed prior to the start of hurricane season, and the Administrative Procedure entitled "Severe Weather Preparations" provides instructions to be followed to prepare for severe weather (including tornadoes) or in response to a hurricane watch or warning. Actions to be taken include, but are not limited to:
~ Installing intake structure missile shielding ifremoved,
~ Topping offthe diesel oil storage tanks,
~ Removing the stoplogs from storage and prepare them for installation,
~ Surveying the plant site, removing trash and debris, and secure loose equipment,
~ Closing Reactor Auxiliary Building outside doors and roof hatches, and
L-99-215 ENCLOSURE PAGE 13 of 22 Placing station batteries on equalizing charge.
The Administrative Procedure entitled "Hurricane Staffing" provides instructions for staf6ng in preparation of a hurricane.
The Emergency Plan Implementing Procedure entitled "Duties and Responsibilities of the Emergency Coordinator" provides the criteria for unit shutdown if a hurricane warning is in effect, and either one or both Unit(s) is/are in Mode 1, 2 or 3. The shutdown criteria is as follows:
~ For storms projected to reach a Category I or 2, the unit(s) shall be placed in HOT STANDBY (Mode
- 3) or below at least two (2) hours before the projected onset of sustained hurricane force winds at the site and both units shall remain off-line for the duration of the hurricane force winds (or restoration of reliable ofBite power).
~ For storms projected to reach Category 3, 4 and 5 prior to landfall, the units shall be shut down to a temperature less than 350 degrees T ave. at least two (2) hours before the projected onset of sustained hurricane force winds at the site and both units shall remain off-line for the duration of the hurricane force winds (or restoration of reliable offsite power).
The Emergency Plan Implementing Procedure entitled "Classification of Emergencies" provides instructions on the classification of emergencies at the St. Lucie plant. The procedure includes criteria for emergency classification of events related to hurricanes, tornadoes, abnormal water level, and fires.
The Off-Normal Operating Procedure entitled "Response To Fire" provides operator actions for responding to a fire at each St. Lucie Unit. These procedures provide specific guidance to the operator for performing a safe if shutdown fire impact assessment and direction as to which mode to place the unit in the fire challenges continued unit operation or stable plant conditions. Additional procedures provide fire-fighting strategies to assist the fire brigade in combating the fire.
L-99-215 ENCLOSURE PAGE 14 of 22 REFERENCES
- 1. FPL letter L-99-079, J.A Stall (FPL) to NRC (DCD), St. Lucie Unit 1 and Unit 2, Docket Nos. 50-335 and 50-389, Proposed License Amendments, "LPSI System Risk Informed AOTQ<ctension",
June 1, 1999.
- 2. Extension",
CE NPSD-'995, "Joint Applications Report For Low Pressure Safety Injection System AOT May 1995.
- 3. Regulatory Guide 1.174, "An Approach for Using Probabilistic RiskAssessment in Decisions on Plant Specific Changes to the Licensing Basis", July 1998.
- 4. Regulatory Guide 1.177, "An Approach for Plant Specijic Risk-Informed Decisionmaking: Technical Spectftcations", August 1998.
- 5. FPL letter L-93-301, D.A. Sager (FPL) to NRC (DCD), St. Lucie Units 1 and 2, Docket Nos. 50-335 and 50-389, "Summary Report ofIndividual Plant Ecamination for Severe Accident Vulnerabilities - Generic Letter 88-20", December 9, 1993.
- 6. CEOG letter CEOG-96-254, D.F. Pilmer (CEOG) to Christopher L Grimes (NRC), "CEOG Response To Request For Additional Information (RAI) Related To The CE<OG Joint Applications Reports", June 14, 1996.
I;i 1
L-99-215 ENCLOSURE PAGE 15 of 22 ATTACHMENTI Unit I Conditional CDF w/I LPSI Train Not Out for T/M (Baseline)
Total Frequency = 1.44E45/yr.
Cutset
~ln uts ~Dcrcri iioo Event Prob P~robobili 1 o/ZZS1U1 SMALL-SMALLLOCA 3.01EC3 1.64E-06 CMM1AVCCCF N-HEADER AIR OPERATED ISOLATION VALVES FTC DUE TO COMMON CAUSES 5.44E-04 2 o/ZZS1U1 SMALL-SMALLLOCA 3.01E-03 1.26E-06 GMM1MRMOV MINIMUMRECIRC LINE MOTOR VALVES TRANSFER CLOSED 4.19E-04 3 o/oZZS1U1 SMALI SMALLLOCA 3.01E%3 8.87E47 GMM1FTRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E-04 4 o/oZZT1U1 REACTOR TRIPS 1.90E+00 8.38E-07 NMMICEDM MECHANICALFAULTPREVENTING ROD INSERTION 2.10E46 ZZMTCUNF1 MODERATOR TEMPERATURE COEFFICIENT UNFAVORABLE(UNIT 1) 2.10E-01 5 loZZS1U1 SMALL-SMALLLOCA 3.01E-03 5.78E-07 QMM1MVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92EW4
'/oZZS IVI SMALL-SMALLLOCA 3.01E-03 4. 17E-07 GMM1MPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.38E-04 7 'loZZCCWU1 LOSS OF CCW 9.41E-04 2.82E-07 RTOP1S1RCP OPERATOR FAILS TO SECURE RCPS FOLLOWING LOSS OF SEAL COOLING 3.00E-04 8 o/oZZS1U1 SMALL-S~LLOCA "
3.01E-03 2.28E-07 GMM1HCVCCF COMMON CAUSE FAILURE OF HPSI INJECTION VALVES TO OPEN 7.58E-05 9 o/oZZT3AU1 LOSS OF MAINFEEDWATER BUT RECOVERABLE 4.34E-01 1.91E-07 NMM1CEDM MECHANICALFAULTPREVENTING ROD INSERTION 2.10E-06 ZZMTCUNF1 MODERATOR TEMPERATURE COEFFICIENT UNFAVORABLE(UNIT 1) 2.10E-01 10 loZZT1U1 REACTOR TRIPS 1.90E+00 1.38E-07 NMM1CEDM MECHANICALFAULT PREVENTING ROD INSERTION 2.10E46 ZZ1ABKSHUT 'A'LKVLVCLOSE W/POWER 4.36E-02 ZZMTCNUNF1 MTC NOT UNFAVORABLE(UNIT 1) 7.90E-01
x
.I
L-99-215 ENCLOSURE PAGE 16 of 22
~ ~
ATTACHMENT2 Unit 1 Conditional CDF w/1 LPSI Train Unavailable for CM Case Total Frequency = 3.21E-05/yr.
Cutset
~In uts D~ercri iioo Event Prob P~erobeb ili r 1 o/oZZAU1 LARGE LOCA 5.85E-05 6.44E-06 JMM1MPACFI COMMON CAUSE FAILURE OF LPSI PUMPS TO START DURING INJECTION 1.10E41 2 o/oZZAU1 LARGE LOCA 5.85E45 6.44E46 JMM1MPFCFI COMMON CAUSE FAILURE OF LPSI PUMPS TO RUN DURING INJECTION 1.10E-01 o/oZZS1U1 SMALL-SMALLLOCA 3.01E43 1.64E-06 CMM1AVCCCF N-HEADER AIR OPERATED ISOLATIONVALVES PTC DUE TO COMMON CAUSES 5.44E44 o/oZZS1U1 SMALL-SMALLLOCA 3.01E-03 1.26E46 GMMIMRMOV MINIMUMRECIRC LINE MOTOR VALVES TRANSFER CLOSED 4.19E-04 o
oZZS1U1 SMALL-SMALLLOCA 3.01E-03 8.87E-07 GMMIFIRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E44 o/oZZT1U1 REACTOR TRIPS 1.90E+00 8.38E-07 NMM1CEDM MECHANICALFAULT PREVENTING ROD INSERTION 2.10E-06 ZZMTCUNF1 MODERATOR TEMPERATURE COEFFICIENT UNFAVORABLE(UNIT I) 2.10E-01 o/oZZS1U1 SMALL-SMALLLOCA 3.01E-03 5.78E-07 QMMIMVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92E44 8 o/oZZAUI LARGE LOCA 5.85E45 5.76E47 JMVK13207S MOTOR-OPERATED VALVEV3207 TRANSFERS CLOSED DURING STANDBY 9.85E-03 JTM1PUMPA LPSI PUMP A IN TEST OR MAINTENANCE 1.00E+00 9 o/oZZAU1 LARGE LOCA 5.85E-05 5.52E-07 JMM1PBFTM FAILURE OF LPSI PUMP B TO RUN DURING INJECTION 9.44E-03 JTM1PUMPA LPSI PUMP A IN TEST OR MAINIENANCE 1.00E+00 10 o/oZZAU1 LARGE LOCA 5.85E45 5.16E-07 JMVR13-1BS MOTOR-OPERATED VALVEMV-03-1B TRANSFERS OPEN DURING STANDBY S.81E43 JTM1PUMPA LPSI PUMP A IN TEST OR MAINTENANCE 1.00E+00
L-99-215 ENCLOSURE r
~ ~
PAGE 17 of 22 ATTACHMENT3 Unit 1 Conditional CDF w/1 LPSI Train Unavailable for PM Case Total Frequency = 1.75E-05/yr.
Cutset
~In uts ~Dcscri lion Event Prob P~rrobnbibr oloZZS1UI SMALL-SMALLLOCA 3.01E-03 1.64E-06 CMMIAVCCCF N-HEADER AIR OPERATED ISOLATION VALVES FTC DUE TO COMMON CAUSES 5.44E-04 2 oloZZS IU1 SMALL-SMALLLOCA 3.01E-03 1.26E-06 GMM1MRMOV MNIMUMRECIRC LINE MOTOR VALVES TRANSFER CLOSED 4.19E-04 oloZZS1U1 SMALL-SMALLLOCA 3.01E-03 8.87E47 GMMIFIRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E-04 oloZZTIUI REACTOR TRIPS 1.90E+00 8.38E-07 NMM1CEDM MECHANICALFAULTPREVENTING ROD INSERTION 2.10E-06 ZZMTCUNF1 MODERATOR TEMPERATURE COEFFICIENT UNFAVORABLE(UNIT I) 2.10E-01 5, oloZZS IUI SMALL-SMALLLOCA 3.01E-03 5.78E-07 QMMIMVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92E-04
/oZZAU1 LARGE LOCA 5.85E-05 5.76E-07 JMVK13207S MOTOR-OPERATED VALVEV3207 TRANSFERS CLOSED DURING STANDBY 9.85E-03 JTM1PUMPA LPSI PUMP A IN TEST OR MAINTENANCE 1.00E+00 oloZZAU1 LARGE LOCA 5.85E45 5.52E47 JMM1PBFTRI FAILURE OF LPSI PUMP B TO RUN DURING INJECTION 9.44E-03 JTMIPUMPA LPSI PUMP A IN TEST OR MAINIENANCE 1.00E+00 oloZZAU1 LARGE LOCA 5.85E-05 5.16E-07 JMVR13-1BS MOTOR-OPERATED VALVEMV43-1B TRANSFERS OPEN DURING STANDBY 8.81E-03 JTM1PUMPA LPSI PUMP A IN TEST OR MAINTENANCE 1.00E+00 ioZZS1U1 SMALL-SMALLLOCA 3.01E43 4.17E-07 GMMIMPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.38E-04 10 oloZZAU1 LARGE LOCA 5.85E45 3.34E47 JMM1PBFTSI FAILURE OF LPSI PUMP B TO START DURING INJECTION 5.72E43 JTM1PUMPA LPSI PUMP A IN TEST OR MAINTENANCE 1.00E+00
L-99-215 ENCLOSURE PAGE 18 of 22
~ e ATTACHMENT4 Unit I Proposed Average CDF Using LPSI T/M Set at Proposed Downtime Value Total Frequency = 1.45E-05/yr.
Cutset
~ln uts D~ercri iioo Event Prob P~robebilir 1 D/DZZS lU1 SMALL-SMALLLOCA 3.01E-03 1.64E46 CMMlAVCCCF N-HEADER AIR OPERATED ISOLATIONVALVES FTC DUE TO COMMON CAUSES 5.44E-04 2 D/DZZS1U1 SMALL-SMALLLOCA 3.01E-03 1.26E-06 GMMIMRMOV MINIMUMRECIRC LINE MOTOR VALVES TRANSFER CLOSED 4.19E-04 3 D/DZZS IU1 SMALL-SMALLLOCA 3.01E-03 8.87E47 GMM1FTRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E-04 4 '/0ZZT1U1 REACTOR TRIPS 1.90E+00 8.38E47 NMM1CEDM MECHANICALFAULT PREVENTING ROD INSERTION 2.10E-06 ZZMTCUNF1 MODERATOR TEMPERATURE COEFFICIENT UNFAVORABLE(UNIT 1) 2.10E41 5 D/DZZS1UI SMALL-SMALLLOCA 3.01E-03 5.78E-07 QMMIMVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92E-04 D/aZZS1U1 SMALL-SMALLLOCA 3.01E-03 4.17E07 6MM1MPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.38E-04 7 D/oZZCCWUI LOSS OF CCW 9.41E-04 2.82E-07 RTOP IS1RCP OPERATOR FAILS TO SECURE RCPS FOLLOWING LOSS OF SEAL COOLING 3.00E-04 D/ZZS1U1 SMALL-SMALLLOCA 3.01E-03 2.28E-07 GMM1HCVCCF COMMON CAUSE FAILURE OF HPSI INJECTION VALVESTO OPEN 7.58E-05
'/OZZT3AU1 LOSS OF MAINFEEDWATER BUT RECOVERABLE 4.34' 1.91E-07 NMM1CEDM MECHANICALFAULTPREVENTING ROD INSERTION 2.10EW6 ZZMTCUNF1 MODERATOR TEMPERATURE COEFFICIENT UNFAVORABLE(UNIT I) 2.10E-01 10 D/ZZT1U1 REACTOR TRIPS 1.90E+00 1.38E-07 NMM1CEDM MECHANICALFAULTPREVENTING ROD INSERTION 2.10E46 ZZIABKSHUT 'A'LKVLVCLOSE W/POWER 4.36E-02 ZZMTCNUNF1 MTC NOT UNFAVORABLE(UNIT 1) 7.90E-01
1 I II
L-99-215 ENCLOSURE PAGE 19 of 22 ATTACHMENT5 Unit 2 Conditional CDF w/1 LPSI Train Not Out for T/M (Baseline)
Total Frequency = 1.25E-05/yr.
Cutset
~ln uts ~Dcocri iioo Event Prob P~robobib oloZZS1U2 SMALL-SMALLLOCA 3.01E-03 1.64E-06 CMM2AVCCCF N-HEADER AIR OPERATED ISOLATIONVALVES FAILTO CLOSE DUE TO COMMON CAUSES 5.44E-04 oloZZS1U2 SMALL-SMALLLOCA 3.01E43 9.90E-07 GMM2SMVCCF COMMON CAUSE FAILURE OF SUMP OUTLET MOTOR VALVESTO OPEN 3.29E-04 oloZZS1U2 SMALL-SMALLLOCA 3.01E-03 8.87E47 GMM2FTRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E44 loZZS1U2 SMALL-SMALLLOCA 3.01E43 5.78E-07 QMM2MVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92E-04 olo'ZZS1U2 SMALL-SMALLLOCA 3.01E-03 4.17E47 GMM2MPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.38E-04 1.38E-04 oloZZCCWU2 LOSS OF CCW 9.41E44 2.82E47 RTOP2S1RCP OPERATOR FAILS TO SECURE RCPS FOLLOWING LOSS OF SEAL COOLING 3.00E44 loZZS1U2 SMALL-SMALLLOCA 3.01E-03 2.28E-07 GMM2HCVCCF COMMON CAUSE FAILURE OF HPSI INJECTION VALVES TO OPEN 7.58E-05 oloZZS1U2 SMALL-SMALLLOCA 3.01E-03 1.56E-07 GMVR23 523 MOTOR-OPERATED VALVEV3523 TRANSFERS OPEN DURING STANDBY 1.80E+01 S.SIE43 GMVR23551 MOTOR-OPERATED VALVEV3551 TRANSFERS OPEN 6.00E+00 5.88E-03 oloZZS lU2 SMALL-SMALLLOCA 3.01E-03 1.56E-07 GMVR23 540 MOTOR-OPERATED VALVE3540 TRANSFERS OPEN DURING STANDBY 1.80E+01 8.81E-03 GMVR23550 MOTOR-OPERATED VALVEV3550 TRANSFERS OPEN 6.00E+00 5.88E43 10 oloZZDC2B LOSS OF DC BUS 2B FOR UNIT 2 1.07E-03 1.03E-07 NMM2TCBCCF COMMON CAUSE FAILURE OF THE TMP CIRCUIT BREAKERS 9.60EA5
1 I
1 a P.
L-99-215 ENCLOSURE I 1
~ ~
PAGE 20 of 22 ATTACHMENT6 Unit 2 Conditional CDF w/I LPSI Train Unavailable for CM Case Total Frequency = 2.91E-05/yr.
Cutsct
~ln uts D~eacrt tioa Event Prob Probability, 1 o/oZZAU2 LARGE LOCA 5.85E-05 6.44E46 J12MPACFI COMMON CAUSE FAILURE OF LPSI PUMPS TO START DURING INJECTION 1.10E41 2 o/oZZAU2 LARGE LOCA 5.85E-05 6.44E-06 JMM2MPFCFI COMMON CAUSE FAILURE OF LPSI PUMPS TO RUN DURING INJECTION 1.10E41 o/oZZS1U2 SMALL-SMALLLOCA 3.01E43 1.64E-06 CMM2AVCCCF N-HEADER AIR OPERATED ISOLATION VALVES FAILTO CLOSE DUE TO COMMON CAUSES 5.44E4 o/oZZS1U2 SMALL-SMALLLOCA 3.01E-03 9.90E47 GMM2SMVCCF COMMON CAUSE FAILURE OF SUMP OUTLET MOTOR VALVESTO OPEN 3.29E44 o/oZZS1U2 SMALL-SMALLLOCA 3.01EA3 8.87E-07 GMM2FTRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DUR1NG INJECTION 2.95E-04 o/oZZS1U2 SMALL-SMALLLOCA 3.01EW3 5.78E-07 QMM2MVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92E-04 7 o/oZZAU2 LARGE LOCA 5.85E-05 5.76E47 JMVK23306S MOTOR-OPERATED VALVEFCV-3306 TRANSFERS CLOSED DURING STANDBY 1.80E+01 9.85E-03 JTM2PUMPB 2B LPSI/SDC PUMP OUT FOR TEST OR MAINTENANCE 1.00E+00 8 o/oZZAU2 LARGE LOCA 5.85E-05 5.16EW7 JMVR23536S MOTOR-OPERATED VALVEV3536 TRANSFERS OPEN DURING STANDBY 1.80E+01 S.S1E-03 JTM2PUMPB 2B LPSVSDC PUMP OUT FOR TEST OR MAINTENANCE 1.00E+00 o/oZZS 1U2 SMALL-SMALLLOCA 3.01E-03 4. 17E-07 GMM2MPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.38E%4 10 /oZZAU2 LARGE LOCA 5.85E-05 3.34E7 JMM2PAFTSI FAILURE OF LPSI PUMP A TO START DURING INJECTION 5.72E43 JTM2PUMPB 2B LPSVSDC PUMP OUT FOR TEST OR MAINI'ENANCE 1.00E+00
L-99-215 ENCLOSURE PAGE 21 of 22 ATTACHMENT7 Unit 2 Conditional CDF w/I LPSI Train Unavailable for PM Case Total Frequency = 1.55E-05/yr.
Cutset
~In uts D~escri tioa Event Prob Probability 1 o/oZZS1U2 SMALL-SMALLLOCA 3.01E-03 1.64E-06 CMM2AVCCCF N-HEADER AIR OPERATED ISOLATION VALVES FAIL TO CLOSE DUE TO COMMON CAUSES, 5.44E-04 2 o/oZZS1U2 SMALL-SMALLLOCA 3.01E-03 9.90E-07 GMM2SMVCCF COMMON CAUSE FAILURE OF SUMP OUTLET MOTOR VALVES TO OPEN 3.29E-04 3 o/oZZS1U2 SMALL-SMALLLOCA 3.01E-03 8.87E%7 GMM2FTRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E-04 4 o/ZZS1U2 SMALL-SMALLLOCA 3.01E-03 5.78E-07 QMM2MVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92E44
/oZZAU2 LARGE LOCA 5.85E-05 5.76E-07 JMVK23306S MOTORWPERATED VALVEFCV-3306 TRANSFERS CLOSED DURING STANDBY 9.85E-03 JTM2PUMPB 2B LPSUSDC PUMP OUT FOR TEST OR MAINTENANCE 1.00E+00 o/oZZAU2 LARGE LOCA 5.85E-05 5.16E-07 JMVR23536S MOTOR-OPERATED VALVEV3536 TRANSFERS OPEN DURING STANDBY 8.81E-03 JTM2PUMPB 2B LPSUSDC PUMP OUT FOR TEST OR MAINTENANCE 1.00E+00
/oZZS1U2 SMALL-SMALLLOCA 3.01EA3 4. 17E-07 GMM2MPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.38E-04 8 o/oZZAU2 LARGE LOCA 5.85E-05 3.34E-07 JMM2PAFTSI FAILURE OF LPSI PUMP A TO START DURING INJECTION 5.72E-03 JTM2PUMPB 2B LPSVSDC PUMP OUT FOR TEST OR MAINTENANCE 1.00E+00 9 o/oZZAU2 LARGE LOCA 5.85E-05 3.16E-07 JMM2PAFTRI FAILURE OF LPSI PUMP A TO RUN DURING INJECTION 5.40E-03 JTM2PUMPB 2B LPSUSD C PUMP OUT FOR TEST OR MAINTENANCE 1.00E+00 10 o/oZZCCWU2 LOSS OF CCW 9.41E-04 2.82E47 RTOP2S 1RCP OPERATOR FAILS TO SECURE RCPS FOLLOWINGLOSS OF SEAL COOLING 3.00E44
L-99-215 ENCLOSURE PAGE 22 of 22 ATTACHMENT8 Unit 2 Proposed Average CDF Using LPSI T/M Set at Proposed Downtime Value Total Frequency = 1.26845/yr.
Cutset
~In uts D~crcri iion Event Prob P~robabilit
/oZZS1U2 SMALL-SMALLLOCA 3.01843 1.64E-06 CMM2AVCCCF N-HEADER AIR OPERATED ISOLATIONVALVESFAIL TO CLOSE DUE TO COMMON CAUSES 5.44E44 2 o/oZZS1U2 SMALL-SMALLLOCA 3.01E43 9.90E-07 GMM2SMVCCF COMMON CAUSE FAILURE OF SUMP OUTLET MOTOR VALVES TO OPEN 3.29844 3 '/~SIU2 SMALL-SMALLLOCA 3.01E43 8.87E47 GMM2FTRCFI COMMON CAUSE FAILURE OF HPSI PUMPS TO RUN DURING INJECTION 2.95E-04 4 o/oZZS 1U2 SMALL-SMALLLOCA 3.018-03 5.78E47 QMM2MVCCCF ICW MOTOR OPERATED VALVES FAILTO CLOSE DUE TO COMMON CAUSE FAILURES 1.92844 5 o/oZZS1U2 SMALL-SMALLLOCA 3.018-03 4.17E-07 GMM2MPACCF COMMON CAUSE FAILURE OF HPSI PUMPS TO START 1.388-04
/mCCWU2 LOSS OF CCW 9.41E44 2.82E-07 RTOP2S1RCP OPERATOR FAILS TO SECURE RCPS FOLLOWING LOSS OF SEAL COOLING 3.008-04 o/oZZS1U2 SMALL-SMALLLOCA 3.01E-03 2.28E47 GMM2HCVCCF COMMON CAUSE FAILURE OF HPSI INJECTION VALVES TO OPEN 7.588-05 o/oZZS1U2 SMALL-SMALLLOCA 3.018-03 1.56E47 GMVR23523 MOTOR-OPERATED VALVEV3523 TRANSFERS OPEN o DURING STANDBY 8.81E43 GMVR23 551 MOTOR-OPERATED VALVEV3551 TRANSFERS OPEN 5.88843 9 o/oZZS1U2 SMALL-SMALLLOCA 3.018-03 1.56E47 GMVR23 540 MOTOR-OPERATED VALVE3540 TRANSFERS OPEN DURING STANDBY 8.81E43 GMVR23550 MOTOR-OPERATED VALVEV3550 TRANSFERS OPEN 5.88E-03 10 o/oZZDC2B LOSS OF DC BUS 2B FOR UNIT 2 1.078-03 1.03E-07 NMM2TCBCCF COMMON CAUSE FAILURE OF THE TRIP CIRCUIT BREAKERS 9.608-05