ML062860099

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E-Mail from Franovich to Doe Et Al., Agenda - July 15 Region Iv SERPs and Enforcement Panels Ex. 2,4,5, Outside Scope
ML062860099
Person / Time
Site: Cooper Entergy icon.png
Issue date: 07/08/2004
From: Franovich R L
NRC/NRR/DIPM
To: Caruso M A, Coe D H, Franovich M X, Gibbs R A, Honcharik M C, Perch R L, Richards S A, Tschiltz M D, Wilson P R
Office of Nuclear Reactor Regulation
References
FOIA/PA-2006-0007 IR-04-014
Download: ML062860099 (22)
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Text

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Subject:

Rani Franovich W"-wA Doug Coe; Mark Caruso; Michael Tschiltz; Michelle Honcharik; Mike Franovich; Robert Perch; Russell Gibbs; Stuart Richards Thu, Jul 8, 2004 6:01 PM Re: Agenda -July 15 Region IV SERPs and Enforcement Panels SERP will be in 0-1 4F3.Thanks, Rani k xk\/>>> Gary Sanborn 07/08/04 05:50PM >>>NOT FOR PUBLIC RELEASE WITHOUT APPROVAL OF THE DIRECTOR, OE REGION IV ENFORCEMENT PANEL & SERP AGENDA Thursday, July 15, 2004 Bridge No 4l Case 1 -- 12:30 Central /1:30 Eastern Cooper Nuclear Station, EA No. TBD This is an initial SERP to discuss a service water system performance deficiency that has preliminarily been determined to be greater than green. A worksheet and system drawing are attached.Case 2 -- 1:15 Central /2:15 Eastern (estimated)

Attachments:

As stated CC:'.Gary Sanborn v~,I Information In this record was deleted in accordance with the Freedom of Infornation Act, exemptions 9? "_ ., FOIA- -0 6 -O C227

.. 4 SERP Worksheet for SDP-Related Finding -at Cooper Nuclear Station Service Water Gland Seal Water Configuration Deficiency SERP Date: Cornerstones Affected: Proposed Preliminary Results: Licensee:

Net Facility/Location:

Coc Docket No: 50-License No: DPI Inspection Report No: Date of Exit Meeting: July Inspectors:

Sco Branch Chief: Kris Meeting Members: Issue Sponsor: Technical Spokesperson:

Program Spokesperson:

OE Representative:

7/15/04 Initiating Events and Mitigating Systems Greater than Green -Violation of 10 CFR 50, Appendix B, Criterion V, failure to prescribe appropriate instructions for the restoration service water following maintenance ,raska Public Power District per Nuclear Station / Brownville, NE 298 R 46 298/2004-014 Special'22,2004 itt Schwind; Steve Cochrum;s Kennedy Arthur T. Howell Michael D. Tschiltz Stuart A. Richards James G. Luehman CONTENTS A. Brief Description of Issue ................

.........................

2 B. Statement of Performance Deficiency

......................................

2 C. Significance Determination Basis .........................................

2 1. Reactor Inspection for IE, MS, B Cornerstones

.........................

2 a. Phase 1 Screening Logic, Results and Assumptions

...............

2 b. Phase 2 Risk Evaluation

.....................................

3 c. Phase 3 Analysis ..........................................

4 Internal Initiating Events .............

e .......................

4 External Initiating Events ................................

9 Potential Risk Contribution due to Large Early Release Frequency

.12 Licensee's Risk Assessment

................................

14 Sensitivity Studies ........................................

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

..............

15 D. Proposed Enforcement

................................................

15 E. Determination of Follow-up Review .......................................

16 SERP Disposition Record ....................................................

17 SDP Phase 2 W orksheets

...................................................

18 Counting Rule W orksheet ....................................................

21 NOTICE OF VIOLATION

....................................................

22 o0 ON -F Q18LICbSISpSJR WtTH0UTr 4PPRO VAo6TH ORrOE6&i,-E

/

2 A. Brief Description of Issue 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 I1 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 division as required.

Following maintenance, the discharge strainer was returned 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 The licensee failed to provide appropriate procedural guidance for the restoration of 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 the 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 affected the reliability of the service water system which provides the ultimate heat sink for the reactor during accident conditions.

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 would not be available to perform its mitigating systems function.

Therefore, the issue was passed to Phase 2.000NOT FOR'`-_ SUT OVA .HDIRECTOR,--OE-00 I i 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: ooONo OR P skE41 sc osORE Da uC SPRov L-eFi-IE-rw REc.Ton ,O-Eoioo, 4 Initiating Event Sequence Mitigating Results Functions Loss of Service Water 1 RECSW24-LI 6 Loss of Service Water 2 RCIC-LI 6 Loss of Service Water 3 RCIC-HPCI 6 Using the counting rule worksheet, this finding was estimated to be YELLOW.However, because several assumptions made during the Phase 2 process were overly conservative, a Phase 3 evaluation is required.3. 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 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 staff (Glen A. Seeman). The SPAR runs were based on the following analyst assumptions:

a. The Cooper SPAR model was revised to better reflect the failure logic for the service water system. This model, including the component test and maintenance basic events, represents an appropriate tool for evaluation of the subject finding.b. NUREG/CR-5496, "Evaluation of Loss of Offsite Power Events at Nuclear Power 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.
c. 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.e. The nominal likelihood for a loss of service water, IEL(TSW) at the Cooper Nuclear Station is as stated in NUREG/CR-5750, "Rates of Initiating Events at Nuclear 00y FRPBj~~&LOSUIM--OITAPOVLFVE6iETR."

5 Power Plants: 1987 -1995," Section 4.4.8, "Loss of Safety-Related Cooling Water System.".

This reference documents a total loss of service water frequency at 9.72 x 1 0- per critical year.f. The nominal likelihood for a partial loss of service water, IEL(PTSW), at the Cooper 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 (loss of single division) at 8.92 x 10*1 per critical year.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, INEEL/EXT-02-10307, "SPAR-H Method," is an appropriate tool for evaluating the probability of operators recovering from a loss of Division I service water.The probability of operators failing to properly diagnose the need to restore Division II service water gland water upon a loss of Division I service water is 0.4.This assumed the nominal diagnosis failure rate of 0.01 multiplied by the following performance shaping factors:* Available Time: 10 The available time was barely adequate to complete the diagnosis.

The analyst assumed that the diagnosis portion of this condition included all activities to identify the mispositioned valves. A licensee operator took 21 minutes to complete the steps. The analyst noted that this walk through was conducted in a vacuum. During 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 through, so they were more knowledgable of the potential problem than they would have been prior to the identification of the finding.+ 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 II. 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/ooo F ULI IC R II-OTP VLO TEDRCOoEo/

6 The complexity of the tasks necessary to properly diagnose this condition 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:

0 Division I would be lost and may be prioritized above Division II.K The diagnosis takes place at both the main control room and the auxiliary panel in the service water structure and requires interaction between at least two operators.

M 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.M Previous heat exchanger clogging events may mislead the operators during their diagnosis.

Analysis: Initiating Event Calc: The analyst calculated the new initiating event likelihood, IEL(rWs.cse), as follows: IEL(rSW.-se)

= IEL irsw) + [ 2

  • IELPTs] =9.72 x 10- + [ 0.5
  • 8.92 x 10, 3 =5.43 x 10"3/ yr -8760 hrs/yr 6.20 x 1 0'7/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, CDFbase, 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 II. 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= CDFcae -CDFbase= 1.74x10.8-4.82x10.9=1.26x 10 8/hr.000 0 BLIC RE WI UTA OVAL OF E DIR OR, OE000 7 Therefore, the total change in core damage frequency over the exposure time that was related to this finding was calculated as: ACDF = 1.26 x 10.8 /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'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 10"6/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-1 H Operator Fails to Recover AC 1.2 x 10"1 3.93 x 101 Power in 1 Hours OEP-XHE-NOREC-2H Operator Fails to Recover AC 6.4 x 10.2 2.49 x 10"'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 OON OO 8 Table 3.a: Evaluation Model Results Model Result Core Damage LERF Frequency SPAR 3.03, Baseline:

Internal Risk 4.8 x 10 9/hr 4.4 x 109/hr Revised Internal Events Risk 1.7 x 10 8/hr 1.7 x 1 0'8/hr TOTAL Internal Risk (ACDF) 6.4 x 10.6 6.3 x 10.6 Baseline:

External Risk 7.9 x 10"/hr '7.2 x 10 1 1/hr External Events Risk 7.1 x 10*9/hr 16.5 x 10-9/hr TOTAL External Risk (ACDF) 3.6 x 10.6 3.2 x 10.6 TOTAL Internal and External 1.0 x 10.5 9.5 x 10.1 Change NOTE 1: The analyst assumed that the ratio of high and low pressure sequences were the same as for internal events baseline.Table 3.b: Top Risk Cutsets Initiating Event Sequence Sequence Importance Number Loss of Offsite Power 39-04 EPS-VA3-AC4H 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"'6 SPC-SDC-CSS-VA1 4.6 x 10"11 39-23 EPS-SRVP1-RCI-HCI 2.7 x 10" 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 9 63-06 PCS-SRVP1-SPC-CSS-CVS 2.9 x 10.11 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 10-1'VA1 I External Initiatina Events: 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 1 F. 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 LFire 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 Fire 0.10 Conditional Probability of Unsuccessful Halon PHalon 0.05 Probability of Losing One Division I Pump in a One P 1-1 0.5 Pump Fire O00ONEFOR T PBL c-I 06URE-WITHOUrT PROVA F THE Dl -GR"Ooo I 10 Probability of Losing Both Division I Pumps in a Three P 2-3 0.5 Pump Fire Probability of Losing One Division I Pump in a Three P 1-3 0.5 Pump Fire Conditional Probability of Losing the Running Division I Pun.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 PFTS 3.0 x 10-3 Water Pump I 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)J + [LFire PLarge Spill (1 -PShort Fire)]= [6.55 x 1 0 3/yr + 8760 hrs/yr
  • 0.18
  • 0.10 * (1 -0.05)]+ [6.55 x 10 3/yr + 8760 hrs/yr
  • 0.18 * (1 -0.10)]= 1.34 x 10 7/hr 00TO0OEO 11 The likelihood of a single pump in Division 1 being damaged because of a fire, LDo,1 Pump was calculated as follows: LDl Pump = (Lone Pump
  • P 1-1) + (LThree Pumps
  • PI-3)= (6.78 x 1 0" 7/hr
  • 0.5) + (1.34 x 1 0*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, PAftFail, was calculated as follows: PAX Fails = PFTrs
  • Prun-1 + LFTR= (3.0 x 10-3
  • 0.5) + (3.0 x 1 08/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, Lpump LOSWS, is then calculated as follows: Lpump LOSWS = LDiI Pump
  • PAft 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, LDiI Pumps was calculated as follows: LDNiv Pumps = LThree Pumps
  • P 2.3= 1.34 x 10" 7/hr
  • 0.5= 6.7 x 10" 8/hr Given that a fire-induced loss of both Division I pumps 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, LDil 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 108. The current case probability was 6.63 x 104 .Therefore, the ACDP was 6.63 x 10-4.000 oTFORýo oSCLOýSURE W AR, OE0 12 The analyst also assessed the affect of this finding on a postulated fire 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 (Lswftchgea,), as the frequency for loss of Switchgear 1 F and a transient.

The analyst used the revised baseline and current case SPAR models to quantify the conditional core damage probabilities for a fire in Switchgear 1 F. The resulting CCDPs were 1.88 x 10.4 (CCDPbase) for the baseline and 1.70 x 10.2 (CCDPcur,,t).

The change in core damage frequency was calculated as follows: " ACDF= Lswftchgear

  • (CCDPcurrent -CCDPbhs)= 3.70 x- 0" 3/yr +8760 hrs/yr * (1.70 x 10.2 -1.88 x 10-4)= 7.10 x 10" 9/hr Table 4: Internal Fire Risk Fire Areas: Fire Type Fire Ignition ACDP ACDF Frequency Switchgear 1 F Shorts Bus 4.22 x 10 7/hr 1.68 x 10.2 7.10 x 10 9/hr Service Water Pump One Pump 9.38 x 10 9/hr 6.63 x 10'4 6.22 x 10" 1 2/hr RoomI Room Both Pumps 6.7 x 10 8/hr 6.63 x 10-4 4.44 x 10'"/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.000 FOR0UBLIC CLOSUýRE APPRO OFTHED ECTO N9E00 13 In accordance with Manual Chapter 0609, Appendix H, "Containment Integrity SDP," the analyst determind that this was a Type A finding, because the finding affected the plant core damage frequjency.

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 T A Find ins at Full Power.1 Following each model run, the analyst segregated the core damage sequences as follows: Loss of coolant accidents were assumed to result in a wet drywell floor. The analyst assumed that during all station blackout initiating events the drywell floor remained dry. The 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-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.OOONOTFO LICDISCL OUTAPPRO DIRECTOR, OE0 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 analystreviewed 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.900-NT POPUB LBL--C1 iOSUR -IT-HO UT-APPRO VTEL'-ODFIWTXRjaEC

,..OEO -OF--

15 The analyst determined that this assumption was responsible for about 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 1 0 6/hr.The analyst determined that this assumption was responsible for the vast majority of the difference in the final results. The analyst noted that the majority of risk was from core damage sequences that were initiated by a 2. All Other Inspection Findings (Not IE, MS, B Cornerstones)

Not Applicable.

D. Proposed Enforcement

1. Regulatory Requirement Not Met 10 CFR 50, Appendix B, Criterion V requires that activities affecting quality to be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances.
2. Proposed Citation Criterion V of 10 CFR 50, Apendix B requires that activities affecting quality shall be prescribed by documented instructions, procedures or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.O0 I OSU RE-WJI-T.BQLAP-PRVAt--OE THE DIRECTOR, OEO0O 16 Contrary to the above, on January 21, 2004, Division 2 of the service water system was declared operable following routine maintenance using instructions contained in Clearance Order SWB-1 -43241 47 SW-STNR-B to restore the system to its normal configuration.

These instructions did not direct restoration of the Division 2 gland water supply to a normal alignment which remained cross-connected with the Division 1 gland water supply for approximately 21 days. On February 11, 2004, the misalignment was discovered while investigating the cause of a low pressure alarm on the gland water system. This misalignment resulted in the loss of redundancy in the service water system..3. Historical Precedent E. Determination of Follow-up Review OE should review final determination letter before issuance.OONý" ýCýE ýTAP ýFTEý Attachment 1 SERP Disposition Record Licensee/Facility:

Nebraska Public Power District / Cooper Nuclear Generating Station EA No: Panel Date: f/04 Issue: Failure to Properly Align Service Water System Gland Water Supply ATTENDEES:

Chair: Branch Chief: Enf. Reps.: 01 Rep.: Counsel: Others: HQ Reps: Required Actions (Preliminary Proposed Actions -See OE Strategy Form for official record of panel decision.)

1. Issue choice letter to the licensee for a preliminary Yellow finding Responsible Person: ECD: 2. Schedule regulatory conference if requested.

Responsible Person: ECD: 3. Prepare and issue final significance determination letter Responsible Person: ECD: 4.Responsible Person: ECD: OOONOTFOý BLIC CLOSUR HOU 0 IREC R, OEOOO 19 , ONOT rFTU-BLIC-DISCLOS EWITH T4AJ 'OS-THE'-DIRECTQIOEO0O 21 Counting Rule Worksheet Step 11 Instructions (1) Enter the number of sequences with a risk significance equal to 9. (1) 0 (2) Divide the result of Step'(1) by 3 and round down. (2) 0 (3) Enter the number of sequences with a risk significance equal to 8. (3) 0 (4) Add the result of Step (3) to the result of Step (2). (4) 0 (5) Divide the result'of Step '(4) by 3 and round down. (5) __0-(6) Enter the number of sequences with a risk significance equal to 7. (6) -0 (7) Add the result of Step (6) to the result of Step (5). (7)' 0 (8) Divide the result of Step (7) by 3 and round down. (8) 0 (9) Enter the number of sequences with a* risk significance equal to 6. (9) -3 (10) Add the result of Step (9) to the result of Step (8). (10)- ý3 (11) Divide theresult of Step (10) by 3 and round down. (11) .1 -(12) Enter the number of sequiences with a risk significance equal to 5. (12) 0 (13) Add the result of Step (12) to the result of Step (11). (13)': 1 (14) Divide the result of Step (13) by 3 and round down6. (14) 0: (15) Enter the number of sequences with a risk significance equal to 4. (15) 0 (16) Add the result of Step (15) to the result of Step (14). (16) 0* If the result of Step 16 is greater than zero, then the risk significance of the inspection finding is of high safety significance (RED).* If the result of Step 13 is greater than zero, then the risk significance of the inspection finding is at least of substantial safety significance (YELLOW).* If the result of Step 10 is greater than zero, then the risk significance of the Inspection finding is at least of low to moderate safety significance (WHITE).* If the result of Steps 10, 13, and 16 are zero, then the risk significance of the inspection finding is of very low safety significance (GREEN).Phase 2 Result: EJ GREEN tr WHITE 0 YELLOW 0 RED Table 6 -Counting Rule Worksheet"Issue Date: 03/18/02 A2-21 0609, App A, Att 2 DRAFT NOTICE OF VIOLATION Nebraska Public Power District Docket No. 50-298 Cooper Nuclear Station License No. DPR-46 EA-04-XXX During an NRC inspection conducted on March 25 through July 10, 2004 a violation of NRC requirements was identified.

In accordance with the "General Statement of Policy and Procedure for NRC Enforcement Actions," NUREG-1 600, the violation is listed below: Pursuant to the provisions of 10 CFR 2.201, Nebraska Public Power District is hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555 with a copy to the Regional Administrator, Region 4, and a copy to the NRC Resident Inspector at the facility that is the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of Violation (Notice).

This reply should be clearly marked as a "Reply to a Notice of Violation; EA-04-XXX" and should include for each violation:

(1) the reason for the violation, or, if contested, the basis for disputing the violation or severity level, (2) the corrective steps that have been taken and the results achieved, (3) the corrective steps that will be taken to avoid further violations, and (4)the date when full compliance will be achieved.

Your response may reference or include previous docketed correspondence, if the correspondence adequately addresses the required response.

If an adequate reply is not received within the time specified in this Notice, an order or a Demand for Information may be issued as to why the license should not be modified, suspended, or revoked, or why such other action as may be proper should not be taken.Where good cause is shown, consideration Will be given to extending the response time.If you contest this enforcement action, you should also provide a copy of your response, with the basis for your denial, to the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001.

Because your response will be made available electronically for public inspection in the NRC Public Document Room or from the NRC's document system (ADAMS), accessible from the NRC Web site at http://www.nrc.Qov/reading-rm/adams.html, to the extent possible, it should not include any personal privacy, proprietary, or safeguards information so that it can be made available to the public without redaction.

If personal privacy or proprietary information is necessary to provide an acceptable response, then please provide a bracketed copy of your response that identifies the information that should be protected and a redacted copy of your response that deletes such information.

If you request withholding of such material, you must specifically identify the portions of your response that you seek to have withheld and provide in detail the bases for your claim of withholding (e.g., explain why the disclosure of information will create an unwarranted invasion of personal privacy or provide the information required by 10 CFR 2.390(b) to support a request for withholding confidential commercial or financial information).

If safeguards information is necessary to provide an acceptable response, please provide the level of protection described in 10 CFR 73.21.Dated this -day of -2004

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