ML062860241

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Analysis: Brief Description of Issue
ML062860241
Person / Time
Site: Cooper Entergy icon.png
Issue date: 10/11/2006
From:
- No Known Affiliation
To:
Office of Nuclear Reactor Regulation
References
FOIA/PA-2006-0007
Download: ML062860241 (16)
v • d • e


Text

v' P-11 b On January 21, 2004, the Division II service water discharge strainer was bypassed for routine maintenance (cleaning). In accordance with operating procedures, the gland water supply for the Division II pumps was cross-connected with the Division I pumps.

This is performed to prevent the introduction of large debris into the Division II pump glands. At that time, licensed operators declared the Division II service water '

subsystem to be inoperable because it was no longer independent from the other I wn ane-t ne the disdli&rgV stfiiiirwa~s retrned to-"

service, and the Division II service water subsystem was declared operable. However, operators restoring the system, failed to realign the gland water supply to the Division II pumps. Therefore, the interdependence between the two divisions remained.

On February 11, licensed operators were conducting a valve alignment verification because several spurious gland water low pressure annunciators had alarmed for Division II pumps. The incorrect alignment was discovered as a result. Licensed operators appropriately declared Division II inoperable. The valves were realigned and the system was restored to an operable status.

B. Statement of Performance Deficiency Operators failed to restore the normal valve alignment for the Division II service water pump gland water supply following maintenance and prior to returning the system to service. This configuration resulted in the Division II service water gland sealing system being provided by the Division I service water pumps. In this configuration, a failure of he Division I pumps would result in loss of gland water to the Division II pumps.

C. Significance Determination Basis

1. Phase 1 Screening Logic, Results and Assumptions In accordance with NRC Inspection Manual Chapter 0612, Appendix B, "Issue Screening," the inspectors determined that the failure to properly realign the system was a licensee performance deficiency because the system was returned to service in a condition that failed to meet the operability requirements of

.Technical Specification 3.7.2. This specification requires that both divisions of service water be operable. Additionally the failure to properly align the gland water system was fully within the licensee's abilities to control. The issue was more than minor because it was similar to Example 4.e in Manual Chapter 0612, Appendix E, "Examples of Minor Issues," and it met the "not minor if" criteria, in

  • that the error resulted in improper valve manipulation (alignment).

The inspectors evaluated the issue using the SDP Phase 1 Screening Worksheet for the Initiating Events, Mitigating Systems, and Barriers Cornerstones provided in Manual Chapter 0609, Appendix A, "Significance Determination of Reactor Inspection Findings for At-Power Situations." This issue caused an increase in the likelihood of an initiating event, namely loss of service water, as well as increasing the probability that the service water system available to perform Information in this record was.yt*dnot be sURsed its mitigating systems function. Therefore, the is to Phase 2 in accordance with tJpe Freedom 01f4tF e t Act, exemption *"i rnki A -20 ULCPS UR I4JTOUTA4PPROi 19aNTFR iI )FbHEPJýRE _0R,- 000

3

2. Phase 2 Estimation for Internal Events In accordance with Manual Chapter 0609, Appendix A, Attachment 1, ",User Guidance for Significance Determination of Reactor Inspection Findings for At-Power Situations,"

the inspectors evaluated the subject finding using the Risk-Informed Inspection Notebook for Cooper Nuclear Station, Revision 1. The following assumptions were made:

The failure of gland water cooling to a service water pump will result in the failure of the pump to meet its risk-significant function.

The configuration of the service water system increased the likelihood that all service water would be lost.

The condition existed for 21 days. Therefore, the exposure time window used was 3 - 30 days.

The initiating event likelihood credit for loss of service water system was increased from five to four by the senior reactor analyst in accordance with Usage Rule 1.2 in Manual Chapter 0609, Appendix A, Attachment 2, "Site Specific Risk-Informed Inspection Notebook Usage Rules." This change reflects the fact that the finding increased the likelihood of a loss of service water, a normally cross-tied support system.

The configuration of the service water system did not increase the probability that the system function would be lost by an order of magnitude because both pumps in Division I would have to be lost before the condition would affect Division II. Therefore, the order of magnitude assumption was that the service water system would continue to be a multi-train system.

Because both divisions of service water continued to run and would have been available without an independent loss of Division I, this condition decreased the reliability of the system, but not the function. Therefore, sequences with loss of the service water mitigating function were not included in the analysis.

The last two assumptions are a deviation from the risk-informed notebook that was recommended by the Senior Reactor Analyst. This deviation represents a Phase 3 analysis in accordance with Manual Chapter 0609, Appendix A, Attachment 1, in the section entitled: "Phase 3 - Risk Significance Estimation Using Any Risk Basis That Departs from the Phase 1 or 2 Process."

Table 2 of the risk-informed notebook requires that all initiating event scenarios be evaluated when a performance deficiency affects the service water system. However, given the assumption that the service water system function was not degraded, only the sequences with the special initiator for Loss of Service Water (TSW) and the sequences related to a Loss of A/C are applicable to this evaluation. The sequences from the notebook are as follows:

OONT1"

4 Initiating Event Sequence Mitigating Results Functions Loss of Service Water 1 RECSW24-LI 6 Loss of Service Water 2 RCIC-LI 6

.L o ss of S e rv ice W a te r .......1.. . .3 < R C IC -HP CI .. .. 6 . . . .

-Th ijg the counting rule worksheet; this finding was estimated to be YELLOW.

o~ever, because several assumptions made during the Phase 2 process were overly cons qtive, a Phase 3 evaluation is required.

Phase 3 Analysis Internal Initiating Events Assumptions:

As stated above, the analyst modified the Phase 2 estimation by not including the sequences from initiating events other than a loss of service water. This change alone represents a Phase 3 analysis.

However, the results from the modified notebook estimation were compared with an K evaluation developed using a Standardized Plant Analysis Risk (SPAR) model simulation of the cross tied service water divisions, as well as an assessment of the licensee's evaluation provided by the licensee's probabilistic risk assessment sta A - See m.an T.... e S PAR ru n s w e r e b a s e d o n t " " "Ain The Cooper SPAR mo,,,l wasrevised to better reflect the lure logic for t e service maintenance system water basic .

events, -This iodel, including

~epresents the com ponen an appropriate tool forttest and f evaluation of the

_ suect finding.*'

b. NUREG/CR-5496, "Evaluation of Loss of Offsite Power Events at Nuclear Pow Plants: 1980 - 1996," contains the NRC's current best estimate of both the likelihood of each of the loss of offsite power (LOOP.) classes (i.e., plant-centered, grid related, and severe weather) and their recovery probabilities.

The service water pumps at Cooper will fail to run if gland water is lost for 30

-minutes or more. If gland water is recovered within 30 minutes of loss, the pumps will continue to run for their mission time, given their nominal failure rates.

d. The condition existed for 21 days from January 25 through February 11, 2004 representing the exposure time.

The nominal likelihood for a loss of service water, IELrrSW), at the Cooper Nuclear .

Station is as stated in NUREG/CR-5750, "Rates of Initiating Events at Nuclear 000N F-OR PU LI.1~OUEWITHO PPARO0VAL OF THE D1RECTON'F OE000_-'

5

  • Powver Plants: -1987 -.1900=,"1. CZt+rnA.A. N "'o r~e.~f ~-i.r Water System." This reference documents a total loss of service water

' frequency at 9.72 x 101 per critical year.

10 f. Th6 nominal likelihood for a partial loss of service water, IEL(PTSW), at the Cooper v Nuclear Station is as stated in NUREG/CR-5750, "Rates of Initiating Events at Nuclear Power Plants: 1987 - 1995," Section 4.4.8, "Loss of Safety-Related Cooling Water System." This reference documents a partial loss of service

.............. water frequency (iossof single division)at 8.92 xfO0per~criticaiyear.-------

g. The configuration of the service water system increased the likelihood that all service water would be lost. The increase in loss of service water initiating event likelihood best representing the change caused by this finding is one half the nominal likelihood for the loss of a single division. The analyst noted that the nominal value represents the likelihood that either division of service water is lost. However, for this finding, only losses of Division I equipment result in the loss of the other division.
h. The SPAR HRA method used by Idaho National Engineering and Environmental Laboratories during the development of the SPAR models and published in Draft NUREG/CR-xxxxx, INEELJEXT-02-10307, "SPAR-H Method," is an appropriate tool for evaluating the probability of operators recovering from a loss of Division I service water.
i. The probability of operators failing to properly diagnose the need to restore Division II service water gland water upon a loss oq-DiVIS I service water is 0.

This assumed the nominal dia nosis failure rate *f 0.01 rr* tiplied by the following performance hapi factors:

" Available Tim 1 .

The available time was barely adequate to complete the diagnosis. The analyst assumed that the diagnosis portion of this condition included aj "--6)4r activities toidentify-the-mispositioned valves. A licensee operator took321

...- minutes to complete the s-teps..The analyst noted that this walk through was conducted in a vacuum. Durirg a real incident, operators would have to prioritize many different annunciators. Additionally, operations personnel had been briefed on the finding at a time prior to the walk

.though, so they were more knowledgable of the potential problem than they would have been prior to the identification of the finding.

4 Stress: 2 Stress under the conditions postulated would be high. Multiple alarms would be initiated including a loss of the Division I service water and the loss of gland water to Division I1. Additionally, assuming that indications of gland water failure were believed, the operators would understand that the consequences of their actions would represent a threat to plant safety.

+ Complexity: 2 00 NOT UB SURE WIT, APPROV L-OF",~EPJBFC_7"ORIOE-QQ

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,,,,;,a,.,,,,*,x,,,,y ,.,,th,,--,,so*.o ,,n,.e II~~y oa-,y toproperly U1JU1TIIy. -'"

....... *1"....c"n "--1tto UcyIul~gtlI1"lgI~LjIILU was determined to be moderately complex. The analyst determined that there was some ambiguity in the diagnosis of this condition. The following factors were considered:

,, Division I would be lost and may be prioritized above Division II.

  • The diagnosis takes place at both the main control room and the auxiliary panel in the service water structure and requires

. . .. inrt~iction-b~tw--hnat l*ast t-woopera'tor;"r - ..

  • There have previously been alarms on gland water annunciators when swapping Divisions. Therefore, operators may hesitate to take action on Division II given problems with Division I.
  • Previous heat exchanger clogging events may mislead the operators during their diagnosis,,-..
  • * .÷ ., *7**.*-.*"

iain E~vent(' I}c:'"

ihe analyst calculated the new initiating event likelihood, IELrSW.case), as follows:

IELrSW.case) = IELrrsw) + [ 2

3 9.72x104+[0.5*8.92x10. ]

5.43 x 10O3/ yr 760 hrs/yr 6.2 x c0"/hr.

Evaluation of Change in Risk The SPAR Revision 3.03 model was modified to include updated loss of offsite power curves as published in NUREG CR-5496, as stated in Assumption b. The changes to the loss of offsite power recovery actions and other modifications to the SPAR model were documented in Table 2. In addition, the failure logic for the service water system was significantly changed as documented in Assumption a. These revisions were incorporated into a base case update, making the revised model the baseline for this evaluation. The resulting baseline core damage frequency, CDFbas,, was 4.82 x 10"9 /hr.

The analyst changed this modified model to reflect that the failure of the Division I service water system would cause the failure of the gland water to Division I1. Division II was then modeled to fail either from independent divisional equipment failures, or from the failure of Division I. The analyst determined that the failure of Division II could be prevented by operator recovery action. As stated in Assumption **,the analyst assumed that this recovery action would fail 40 percent of the time. The model was requantified with the resulting current case conditional core damage frequency, CDFcas, of 1.74 x 10"8/hr.

The change in core damage frequency (ACDF) from the model was:

ACDF CDFcs - CDFba,*

1.74 x 10"8 - 4.82 x 10"9 = 1.26 x 10"8 /hr.

000 TFOR P CDISCLOSUR THOUTAPP L**T, ,. -..

A 7 i rlsnr the nvvnr%,i t;ri 4

____. Therefore,A,"h- toftal change in -rnr, dlmrnan-- fr*,nn i inn +ek.n -

related to this finding was calculated as:

ACDF = 1.26 x 108 /hr

  • 24 hr/day
  • 21 days = 6.35 x 10.6 for 21 days The risk significance of this finding is presented in Table 3.a. The dominant cutsets from the internal risk model are shown in Table 3.b.

Table 2: Baseline Revisions to SPAR Model Basic Event Title Original Revised ACP-XHE-NOREC-30 Operator Fails to Recover AC .22 5.14 x 10' Power in 30 Minutes ACP-XHE-NOREC-4H Operator Fails to Recover AC .023 6.8 x 10.2 Power in 4 Hours ACP-XHE-NOREC-90 Operator Fails to Recover AC .061 2.35 x 10-1 Power in 90 Minutes ACP-XHE-NOREC-BD Operator Fails to Recover ACP .023 6.8 x 10.2 before Battery Depletion IE-LOOP Loss of Offsite Power Initiator. 5.20 x 10-6/hr 5.32 x 106/hr EPS-DGN-FR-FTRE Diesel Generator Fails to Run - 0.5 hrs. 0.5 hrs.

Early Time Frame EPS-DGN-FR-FTRM Diesel Generator Fails to Run - 2.5 hrs. 13.5 hrs.

Middle Time .Frame*

OEP-XHE-NOREC-10H Operator Fails to Recover AC 2.9 x 10"2 5.6 x 10"2 Power in 10 Hours OEP-XHE-NOREC-1H Operator Fails to Recover AC 1.2 x 10.' 3.93 x 10' Power in 1 Hours OEP-XHE-NOREC-2H Operator Fails to Recover AC 6.4 x 10.2 2.49 x 10.1 Power in 2 Hours OEP-XHE-NOREC-4H Operator Fails to Recover AC 4.5 x 10.2 1.36 x 10.1 Power in 4 Hours

  • Diesel Mission Time was increased from 2.5 to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> in accordance with NUREG/CR-5496 0 0 oF-TýlEFOýR PEWIT -APPROVAL DIRBC7

8

.Table 3.a: 'Evaluation ModeI Riesul ts 1 Model jResult SPAR 3.03, Baseline: Internal Risk Revised Internal Events Risk TOTAL Internal Risk (ACDF)

Baseline: External Risk External Events Risk TOTAL External Risk (ACDF)

TOTAL Internal and External J

Change-NOTE 1: The analyst assumed that the ratio of high and low pressure spque same as for internal events baseline.

Table 3.b: Top Risk Cutsets Initiating Event

  • 1~

Sequence Number ) I mýpo Loss of Offsite Power 39-04 EPS-VA3-AC4H ý 1.4 x 10"8 39-10 EPS-RCI-VA3-AC4H 7.6 x 10.10 39-14 EPS-RCI-HCI-AC30MIN 5.2 x 10.10 39-24 EPS-SRVP2 3.2 x 10.10 39-22 EPS-SRVP1-RCI-VA3- 8.4 x 10.11 AC90MIN 7 SPC-SDC-CSS-CVS 5.4 x 10"11 36 RCI-HCI-DEP 4.7 x 10`1 6 SPC-SDC-CSS-VA1 4.6 x 10".

39-23 EPS-SRVP1-RCI-HCI 2.7 x 10"11 Transient 62 SRV-P1-PCS-MFW-CDS- 6.0 x 10.10 LCS 63-05 PCS-SRVP1-SPC-CSS-VA1 2.9 x 10-10 64-11 PCS-SRVP2-LCS-LCI 1.0 x 10"10 9 PCS-SPC-SDC-CSS-CR1- 3.7 x 10"11 VA1 000 NOTF LP

ŽDISC -UgE~WZH$9yT P-PRO VtQTEIQRO0

9

.. 3-6.........PCS-SRVP1:-s 63.0t -------

PC-C*Ss-CVS ... 2.9-x-10 1 63-32 PCS-SRVP1-RCI-HCI-DE2 2.6 x 10"11 Loss of Service Water System 9 PC1-SPC-SDC-CSS-CR1- 2.2 x 10" VA1 In accordance with Manual Chapter 0609, Appendix A, Attachment 1, Step 2.5, "Screening for the Potential Risk Contribution Due to External Initiating Events," the analyst assessed the impact of external initiators because the Phase 2 SDP result provided a Risk Significance Estimation of 7 or greater.

Seismic, High Winds, Floods, and Other External Events:

The analyst determined, through plant walkdown, that the major divisional equipment associated with the service water system were on the same physical elevation as its redundant equipment in the alternate division. All four service water pumps are located in the same room at the same elevation. Both primary switchgear are at the same elevation and in adjacent rooms. Therefore, the likelihood that internal or external flooding and/or seismic events would affect one division without affecting the other was considered to be extremely low. Likewise, high wind events and transportation events were assumed to affect both divisions equally.

Fire:

The analyst evaluated the list of fire areas documented in the IPEEE, and concluded that the Division I service water system could fail in internal fires that did not directly affect Division II equipment. These fires would constitute a change in risk associated with the finding. As presented in Table 4, the analyst identified two fire areas of concern: Pump room fires and a fire in Switchgear 1F. Given that all four service water pumps are located in one room, three different fire sizes were evaluated, namely: one pump fires, three pump fires, and four pump fires.

In the Individual Plant Examination for External Events Report - Cooper Nuclear Station, the licensee calculated the risk associated with fires in the service water pump room (Fire Area 20A). The related probabilities for these fires were as follows:

Parameter Variable Probability Fire Ignition Frequency LFie 6.55 x 10"3/yr Conditional Probability of a Large Oil Spill PLarge Spill 0.18 Conditional Probability of Fire less than 3 minutes PShort Fie 0.10 Conditional Probability of Unsuccessful Halon PHalon 0.05 Probability of Losing One Division I Pump in a One P1.1 0.5 Pump Fire OO0N*PKFORcB StSaEW 7HOUTAPPROVAL OF TiRE L/IHECTOR, OEOOO

10

'Pr6b5bility of Losinrg B6thDiVisioiI PimpsS ifri a-Three" . 23 60.5 Pump Fire Probability of Losing One Division I Pump in a Three P1.3 0.5 Pump Fire Conditional Probability of Losing the Running Division I P,,,.1 0.5 Pump Given a Fire Damaging a Single -Pump Failure to Run Likelihood for a Service Water Pump LFTR 3.0 x 10"5/hr Failure to Start Probability per Demand for a Service PFs 3.0 x 10*3 Water Pump As described in the IPEEE, the licensee determined that there were three different potential fire scenarios in the service water pump room, namely: a fire damaging one pump, caused by a small oil fire, a fire that results from the spill of all the oil from a single pump that damages three pumps; and fires that affect all four pumps. The licensee had determined that fires affecting only two pumps were not likely. The analyst determined that a four-pump fire was part of the baseline risk, therefore, it would not be evaluated. A one-pump fire would not automatically result in a plant transient.

However, the analyst assumed that a three-pump fire affecting both of the Division I pumps, would result in a loss of service water system initiating event.

The IPEEE stated that a single pump would be damaged in an oil fire that resulted from a small spill of oil, Lone Pump* The analyst, therefore, calculated the likelihood that a fire would damage a single pump as follows:

Lone Pump = LFIre * (1 PLarge Spill)

= 6.55 x 10 3/yr + 8760 hrs/yr * (1 - 0.18)

= 6.78 x 10 7/hr As in the IPEEE, the analyst assumed that all pumps would be damaged in an oil fire that resulted from a large spill of oil, that lasted for less than 3 minutes, if the halon system failed to actuate. It should be noted that the intensity of an oil fire is based on the availability of oxygen, and the fire is assumed to continue until all oil is consumed or it is extinguished. Therefore, the shorter the duration of the fire, the higher its intensity and the more likely it is to damage equipment in the pump room. Should the fire last for less than 3 minutes and the halon system successfully actuate, or if the fire lasted for longer than 3 minutes, the licensee determined that a single pump would survive the fire, LThree Pumps, The analyst, therefore, calculated the likelihood that a fire would damage three pumps as follows:

LThree Pumps = [LFire

  • PLarge Spill PShort Fire * (1 - PHalon)] + [LFire
  • PLarge Spill * (1 - PShort Fire)]

= [6.55 x 10O3/yr +8760 hrs/yr

  • 0.18
  • 0.10 * (1 - 0.05)]

+ [6.55 x 10O3/yr + 8760 hrs/yr

  • 0.18 * (1 - 0.10)]

= 1.34 x 107/hr 000 NGT-F-T DIREC__MD G O-

11

..... The li-llhr *f a a n l reý'VI nhm ll§U n i ICAl r l*. .lI*I -i W* , dam.d b, cause of a -fir ;

I KAU . .......

DlO.Odl ... ..

was calculated as follows:

LDIV1 Pump = (Lone Pump

  • P1 -1) + (Lree Pumps
  • P 1-3)

= (6.78 x 10"7/hr '* 0.5) + (1.34 x 10'7/hr

  • 0.5)

= 4.06 x 10"7/hr The analyst assumed that a fire damaged pump would remain inoperable for the 30-day allowed-outage time. Therefore, the probability that the redundant Division I pump would start and run for 30 days, PAR Fail, was calculated as follows:

P,, Fails = PFrs

  • P.,n.. + LFTR

= (3.0 x 103

  • 0.5) + (3.0 x 10"S/hr
  • 24 hrs/day *30 days)

= 1.5 x 10"3 + 2.16 x 10.2

-2.31 x 10.2 The likelihood of having a loss of all service water as a result of a one-pump fire, LpumpLOSWS, is then calculated as follows:

Lpump LOSWS = LCvl Pump

  • PAf Fails

= 4.06 x 10-7/hr

  • 2.31 x 10.2

= 9.38 x 10"9/hr The likelihood of both pumps in Division 1 being damaged because of a fire, LDvI Pumps was calculated a6 follows:

LDvl Pumps = LThree Pumps

  • P2-3

= 1.34 x 107/hr* 0.5

= 6.7 x 10 8/hr Given that a fire-induced loss of both Division Ipumps results in a loss of service water system gland water, and the assumption was made that the gland water was unrecoverable during large fire scenarios, LDiv, Pumps is equal to the likelihood of a loss of service water system initiating event.

The analyst used the revised baseline and current case SPAR models to quantify the conditional core damage probability for a fire that takes out both Division I pumps or one Division I pump with a failure of the second pump. A fire that affects both Division I pumps was assumed to cause an unrecoverable loss of service water initiating event.

The baseline conditional core damage probability was determined to be 1.99 x 10.8. The current case probability was 6.63 x 10"4. Therefore, the ACDP was 6.63 x 10-4.

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12 iht~h yI -. a sseslsedao the affectf t h* f.nding o*n WI o" tiJ.

- td fiUs 1 in Switchgear 1 F. The analyst walked down the switchgear rooms and interviewed licensed operators. The analyst identified that, by procedure, a fire in Switchgear 1 F would require deenergization of the bus and subsequent manual scram of the plant.

Additionally, the analyst noted that no automatic fire suppression existed in the room.

Therefore, the analyst used the fire ignition frequency stated in the IPEEE, namely 3.70 x 10*3/yr (Lwit1hger), as the frequency for loss of Switchgear 1F and a transient.

.. The analyst used the revised bds lineiand burrent ca'seSPAR'mod1el tobq itiry thi..

conditional core damage probabilities for a fire in Switchgear 1F. The resulting CCDPs were 1.88 x 104 (CCDPbase) for the baseline and 1.70 x 10.2 (CCDPF Tcange-T Ie core damage frequency was calculated as follows:

ACDF =Lswjtchgear *(CCDPcurrent -CCDPbase

= 3.70 x 10 3/yr +8760 hrs/yr (1.70 x 10'2 - 1.88 x 1

=7.10 x 10 9/hr Table 4: Internal Fire Risk Fire Areas: Fire Type Fire Ignition C ACDF Frequency Switchgear 1F Shorts Bus 4.22 x 10 7/hr 1 x 10.2 7.10 x 109/hr Service Water Pump One Pump 9.38 x 10"9/hr 6.63 x 10"4 6.22 x 10"'2/hr Room Room Both Pumps 6.7 x 10 8/hr 6.63 x 10-4 4.44 x 1011/hr Total ACDF for Fires affecting the Service Water System: 7.14 x 10 9/hr Exposure Time (21 days): 5.04 x 102 hrs External Events Change in Core Damage Frequency: 3.60 x 10-6 Potential Risk Contribution from Large Early Release Frequency (LERF):

In accordance With Manual Chapter 0609, Appendix A, Attachment 1, Step 2.6, "Screening for the Potential Risk Contribution Due to LERF," the analyst assessed the impact of large early release frequency because the Phase 2 SDP result provided a risk significance estimation of 7.

In BWR Mark I containments, only a subset of core damage accidents can lead to large, unmitigated releases from containment that have the potential to cause prompt fatalities prior to population evacuation. Core damage sequences of particular concern for Mark I containments are ISLOCA, ATWS, and Small LOCA~/Transient sequences involving high reactor coolant system pressure. A loss of service water is a special initiator for a transient. Step 2.6 of Manual Chapter 0609 requires a LERF evaluation for all reactor types if the risk significance estimation is 7 or less and transient sequences are involved.

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analyst determined that this was a Type A finding, because the finding affected the plant core damage frequency. The analyst evaluated both the baseline model and the current case model to determine the LERF potential sequences and segregate them into the categories provided in Appendix H, Table 5.2, "Phase 2 Assessment Factors - Type A Findings at Full Power. These categorizations, the LERF factors, and an estimation of the change in LERF are documented in Table 5 of this worksheet.

. Foliowing-.'each-modei runlthe-anai'ysttsegredat6dlth'eb-.*redrfi .se-q

.-.c*esas..........

follows:

/I Loss of coolant $ccidents were assumed to result in a wet drywell floor. The analyst assume that during all station blackout initiating events the drywell floor remained dry.-he Cooper Nuclear emergency operating procedures require drywell flooding if reactor vessel level can not be restored. Therefore, the analysts assumed that containment flooding was successful for all high pressure transients and those low pressure transients that had the residual heat removal system available.

- All Event V initiators were grouped as intersystem loss of coolant accidents (ISLOCA)

Transient Sequence 65, Loss of dc Sequence 62, Loss of service water system Sequence 71, small loss of coolant accident Sequence 41, medium loss of coolant accident Sequence 32, large loss of coolant accident Sequence 12, and LOOP Sequence 40 cutsets were considered anticipated transients without scram (ATWS)

All LOOP Sequence 39 cutsets were considered Station Blackouts. Those with success of safety-relief valves to close or a single stuck-open relief valve were considered high pressure sequences. Those with more than one stuck-open relief valve were considered low pressure sequences.

Transients that did not result in an ATWS were assumed to be low pressure sequences if the cutsets included low pressure injection, core spray, or more than one stuck-open relief valve. Otherwise, the analyst assumed that the sequences were high pressure.

Small break loss of coolant accident, Sequence 1 cutsets, that represent stuck- 7 open relief valves and other recoverable incidents, were assumed to result in a dry floor. All other cutsets were assumed to provide a wetted drywell floor.

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Awe' 14 Licensee's Risk Assessment:

The licensee performed an assessment of the risk from this finding as documented in Engineering Study PSA-ES062, "Risk Significance of SCR 2004-0077, Service Water Gland Water Valve Mis-positioning Event." The licensee's result for internal risk was a ACDF of 3.85 x 10-7 . The analyst reviewed the licensee's assumptions and determined that the following differences dominated the difference between the licensee's and the analyst's assessments:

1. The licensee used a Human Error Probability of 9.2 x 10.2 for the probability that operators would fail to realign gland water prior to failure of the Division II pumps.

O0*O* * 'C**LO VLO CO

15 I "y2 IAQ L~III ~ .4d LI IC. LIUI.1 L~ II1JIJ 10 111 110%.L~ Iv a o~J .~LI %J U U 30% of the difference in the final results.

2. The licensee's model uses a Loss of Offsite power frequency of 1.74 x 10"8 /hr as opposed the the NUREG/CR-5496 value of 5.32 x 10 6/hr.

The analyst determined that this assumption was responsible for the vast majority'of thedifference iht final results. The &haly~t riote tlie majority of risk was from core damage sequences that were initiated by a loss of offsite power.

~NJ~

2. All Other Inspection Findings (Not IE, MS, B Cornerstones)

Not Applicable.

D. Proposed Enforcement

1. Regulatory Requirement Not Met Technical Specification 5.4.1(a) requiring written procedures to be implemented as recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
2. Proposed Citation Technical Specification 5.4.1(a) requires written procedures to be implemented as recommended by Regulatory Guide 1.33, Revision 2, Appendix A, February 1978. Appendix A recommends procedures for equipment control.

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16

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Clearance Order SWB-1-4324147 SW-STRN-B by not restoring the system in accordance with the system operating procedure following maintenance. This performance finding, which caused the loss of redundancy in the service water system gland water supply, has been preliminarily determined to be of substantial risk significance (YELLOW) based on a Phase 3 SDP analysis.

3. Historical Precedent E. Determination of Follow-up Review OE should review final determination letter before issuance.

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Attachment 1

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Licensee/Facility: Nebraska Public Power District / Cooper Nuclear Generating Station EA No:

Panel Date: //04 Issue: Failure to Properly Align Service Water System Gland Water Supply

-. AT rEN DE E S: -... .. . . . ... . . . . .. . . . . .. . . . . .. . . . . . .. . . . . . ....

Chair: Branch Chief: Enf. Reps.: 01 Rep.:

Counsel: Others:

HO Reps:

Required Actions (Preliminary Proposed Actions - See OE Strategy Form for official record of panel decision.)

3. Issue choice letter to the licensee for a preliminary Yellow finding Responsible Person: ECD:
4. Schedule regulatory conference if requested.

Responsible Person: ECD:

5. Prepare and issue final significance determination letter Responsible Person: ECD:

6.

Responsible Person: ECD:

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