ML081650090

IR 05000298-08-008, on 03/19/2008 - 06/13/2008, for Cooper, Triennial Fire Protection Follow-up Inspection

ML081650090
Person / Time
Site:	Cooper
Issue date:	06/13/2008
From:	Caniano R Division of Reactor Safety IV
To:	Minahan S Nebraska Public Power District (NPPD)
References
EA-07-204 IR-08-008
Download: ML081650090 (29)

See also: IR 05000298/2008008

Text

June 13, 2008

EA 07-204

Stewart B. Minahan

Vice President-Nuclear and CNO

Nebraska Public Power District

P.O. Box 98

Brownville, NE 68321

SUBJECT:

FINAL SIGNIFICANCE DETERMINATION FOR A WHITE FINDING AND

NOTICE OF VIOLATION, NRC INSPECTION REPORT 05000298/2008008,

COOPER NUCLEAR STATION

Dear Mr. Minahan:

The purpose of this letter is to provide you the final results of our significance determination of

the preliminary Greater than Green finding identified in the Nuclear Regulatory Commission

(NRC) Inspection Report 05000298/2008007. The inspection finding was assessed using the

significance determination process and was preliminarily characterized as a finding of greater

than very low safety significance resulting in the need for further evaluation to determine the

significance and, therefore, the need for additional NRC action.

Our preliminary finding was discussed with your staff during an exit meeting on March 18, 2008.

The finding involved two procedures used by operators to bring the plant to a safe shutdown

condition in the event of certain postulated fire scenarios. The procedures could not be

performed as written. This performance deficiency involved the failure to properly verify and

validate these infrequently used procedures.

The NRCs preliminary assessment of the safety significance of this inspection finding was a

modified bounding analysis based upon the best available information. This simplified analysis

demonstrated that this finding did not have high importance to safety, but that additional

information and analyses would be needed to determine the final significance. Therefore, the

finding was issued with a preliminary safety significance of Greater than Green.

At the request of Nebraska Public Power District, a regulatory conference was held on May 13,

2008, to further discuss your views on this issue. A copy of the handout you provided is

attached to the regulatory conference meeting summary (ML081550102). During the regulatory

conference, your staff described your assessment of the significance of the finding and your

views on the applicability of the Interim Enforcement Discretion Policy.

UNITED STATES

NUCLEAR REGULATORY COMMISSION

R E GI ON I V

612 EAST LAMAR BLVD, SUITE 400

ARLINGTON, TEXAS 76011-4125

Nebraska Public Power District

- 2 -

After considering the information developed during this inspection, the additional information

you provided in your letter dated May 8, 2008 (ML081540362), and the information your staff

provided at the regulatory conference, the NRC has concluded that the inspection finding is

appropriately characterized as White, an issue with low to moderate increased importance to

safety, which may require additional NRC inspections.

The final significance determination, described in Enclosure 2, was based on the significance

determination process Phase 3 analysis performed by the NRC staff using multiple risk tools

including, a standardized plant analysis risk model simulation of the potential fires that would

impact this finding, hand calculations, and a linked event tree model of the Cooper Nuclear

Station's remote shutdown capabilities developed by NRC analysts. This evaluation considered

insights and values provided by your staff. The results of your analyses and fire modeling

provided important information needed for our staff to complete our significance determination

process evaluation. Our final assessment of the change in risk due to this performance

deficiency has dropped an order of magnitude. For fire areas that would not have the potential

to cause a control room evacuation, the NRC results closely match your results. However, for

cases with the potential to cause control room evacuation, which dominated the safety impact,

our results indicated greater safety significance than your results. The areas where the two

analyses differed significantly included the frequency with which operators would abandon the

main control room, and the assessment of the human reliability associated with the expected

recovery actions. Your analysis did not adequately model the impact of spurious operations due

to fire damage in alternate shutdown fire areas or treat them consistent with the plant operating

procedure, which would be expected to result in a higher evacuation frequency. In addition,

your evaluation did not include core damage sequences that involved the failure of the high

pressure coolant injection system early in the event. These sequences represented about

one fourth of the risk in our evaluation. We estimated the change in core damage frequency

associated with this finding to be 8.1 x 10-6, as discussed in Enclosure 2 to this letter, compared

to your final significance of 8.6 x 10-8.

You have 30 calendar days from the date of this letter to appeal the staffs determination of

significance for the identified White finding. Such appeals will be considered to have merit only

if they meet the criteria given in NRC Inspection Manual Chapter 0609, Significance

Determination Process, Attachment 2, Process for Appealing NRC Characterization of

Inspection Findings (Significance Determination Process Appeal Process).

The NRC has also determined that the two examples of inadequate fire response operating

procedures involved a violation of NRC requirements as cited in the enclosed Notice of

Violation (Notice). The circumstances surrounding the violation are described in detail in NRC

Inspection Report 05000298/2008007. This violation of 10 CFR Part 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings involved steps contained in Emergency

Procedures 5.4POST-FIRE, Post-Fire Operational Information, and 5.4FIRE-S/D, Fire

Induced Shutdown From Outside Control Room. Certain steps in the procedures intended to

reposition motor-operated valves locally, would not have worked as written because the steps

were not appropriate for the configuration of the motor-starter circuits. As a consequence of this

violation, these quality-related procedures would have challenged the operators ability to bring

the plant to a safe shutdown condition in the event of certain fires. In accordance with the NRC

Enforcement Policy, the Notice is considered escalated enforcement action because it is

associated with a White finding.

Nebraska Public Power District

- 3 -

Because plant performance for this issue has been determined to be in the regulatory response

band, we will use the NRC Action Matrix, as described in NRC Inspection Manual Chapter 0305,

Operating Reactor Assessment Program, to determine the most appropriate NRC response

and any increase in NRC oversight. We will notify you by separate correspondence of that

determination.

The staff has reviewed the position provided in your March 10, 2008, letter (ML080740507)

concerning the circumstances surrounding this violation and how the Interim Enforcement Policy

Regarding Enforcement Discretion for Certain Fire Protection Issues related to this violation.

During the regulatory conference, your presentation reiterated the position stated in your letter.

Our review has concluded that your letter and regulatory conference presentation provided no

new information. Therefore, we maintain that all of the requirements of the Interim Enforcement

Policy Regarding Enforcement Discretion for Certain Fire Protection Issues were not satisfied

and enforcement discretion will not be granted for this violation.

In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter, its

enclosure(s), and your response, if you choose to provide one, will be made available

electronically for public inspection in the NRC Public Document Room or from the NRCs

document system (ADAMS), accessible from the NRC website at www.nrc.gov/reading-

rm/pdr.html or www.nrc.gov/reading-rm/adams.html. To the extent possible, your response

should not include any personal privacy, proprietary, or safeguards information so that it can be

made available to the Public without redaction.

Sincerely,

/RA/

Roy J. Caniano, Director

Division of Reactor Safety

Docket: 50-298

License: DPR-46

Enclosures:

1. Notice of Violation

2. Final Significance Determination

3. Supplemental Information

cc w/enclosures:

Gene Mace

Nuclear Asset Manager

Nebraska Public Power District

P.O. Box 98

Brownville, NE 68321

Nebraska Public Power District

- 4 -

John C. McClure, Vice President

and General Counsel

Nebraska Public Power District

P.O. Box 499

Columbus, NE 68602-0499

David Van Der Kamp

Licensing Manager

Nebraska Public Power District

P.O. Box 98

Brownville, NE 68321

Michael J. Linder, Director

Nebraska Department of

Environmental Quality

P.O. Box 98922

Lincoln, NE 68509-8922

Chairman

Nemaha County Board of Commissioners

Nemaha County Courthouse

1824 N Street

Auburn, NE 68305

Julia Schmitt, Manager

Radiation Control Program

Nebraska Health & Human Services

Dept. of Regulation & Licensing

Division of Public Health Assurance

301 Centennial Mall, South

P.O. Box 95007

Lincoln, NE 68509-5007

H. Floyd Gilzow

Deputy Director for Policy

Missouri Department of Natural Resources

P. O. Box 176

Jefferson City, MO 65102-0176

Director, Missouri State Emergency

Management Agency

P.O. Box 116

Jefferson City, MO 65102-0116

Nebraska Public Power District

- 5 -

Chief, Radiation and Asbestos

Control Section

Kansas Department of Health

and Environment

Bureau of Air and Radiation

1000 SW Jackson, Suite 310

Topeka, KS 66612-1366

Melanie Rasmussen, State Liaison Officer/

Radiation Control Program Director

Bureau of Radiological Health

Iowa Department of Public Health

Lucas State Office Building, 5th Floor

321 East 12th Street

Des Moines, IA 50319

John F. McCann, Director, Licensing

Entergy Nuclear Northeast

Entergy Nuclear Operations, Inc.

440 Hamilton Avenue

White Plains, NY 10601-1813

Keith G. Henke, Planner

Division of Community and Public Health

Office of Emergency Coordination

930 Wildwood, P.O. Box 570

Jefferson City, MO 65102

Ronald L. McCabe, Chief

Technological Hazards Branch

National Preparedness Division

DHS/FEMA

9221 Ward Parkway

Suite 300

Kansas City, MO 64114-3372

Daniel K. McGhee, State Liaison Officer

Bureau of Radiological Health

Iowa Department of Public Health

Lucas State Office Building, 5th Floor

321 East 12th Street

Des Moines, IA 50319

Ronald D. Asche, President

and Chief Executive Officer

Nebraska Public Power District

1414 15th Street

Columbus, NE 68601

Nebraska Public Power District

- 6 -

Electronic distribution by RIV:

Regional Administrator (Elmo.Collins@nrc.gov)

DRP Director (Dwight.Chamberlain@nrc.gov

DRS Director (Roy.Caniano@nrc.gov )

DRS Deputy Director (Troy.Pruett@nrc.gov)

Senior Resident Inspector (Nick.Taylor@nrc.gov)

Branch Chief, DRP/C (Rick.Deese@nrc.gov)

Senior Project Engineer, DRP/C (Wayne.Walker@nrc.gov )

Team Leader, DRP/TSS (Chuck.Paulk@nrc.gov )

RITS Coordinator (Marisa.Herrera@nrc.gov )

DRS STA (Dale.Powers@nrc.gov )

J. Adams, OEDO RIV Coordinator (John.Adams@nrc.gov)

P. Lougheed, OEDO RIV Coordinator (Patricia.Lougheed@nrc.gov )

ROPreports

CNS Site Secretary (Sue.Farmer@nrc.gov)

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Linda.Smith@nrc.gov

Neil.OKeefe@nrc.gov

John.Mateychick@nrc.gov

Karla.Fuller@nrc.gov

Nick.Taylor@nrc.gov

Michael.Cheok@nrc.gov

John.Grobe@nrc.gov

Mark.Cunningham@nrc.gov

Alexander.Klein@nrc.gov

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Jeff.Circle@nrc.gov

Joseph.Anderson@nrc.gov

Tim.Kobetz@nrc.gov

Thomas.Hiltz@nrc.gov

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SUNSI Review Completed: LJS ADAMS:

Yes

No Initials: __________

Publicly Available Non-Publicly Available Sensitive

Non-Sensitive

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OFFICIAL RECORD COPY

T=Telephone

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F=Fax

E1-1

Enclosure 1

NOTICE OF VIOLATION

Nebraska Public Power District

Docket No. 50-298

Cooper Nuclear Station

License No. DPR-46

EA-07-204

During an NRC inspection completed on March 18, 2008, a violation of NRC requirements was

identified. In accordance with the NRC Enforcement policy, the violation is listed below:

Appendix B to 10 CFR Part 50, Criterion V, Instructions, Procedures, and Drawings,

requires, in part, 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.

Procedure 0.4A, Procedure Change Process Supplement, Revision 0, implements

measures to ensure the procedure quality required by Criterion V for procedures

designated as quality-related. Attachment 2 to this procedure requires verification and

validation to be performed periodically, when writing a new procedure, when significant

changes are made to sequencing of complex steps in existing procedures, and when

infrequently used procedures are written or changed. Verification and validation efforts

are defined in this procedure as actions to confirm that the procedure steps: (1) are

usable; (2) are accurate; (3) contain the appropriate level of detail; (3) use equipment

nomenclature that corresponds to the actual hardware; and (4) satisfy plant design and

licensing basis. Procedure 0.4A applies to changes to Emergency Procedures

5.4POST-FIRE and 5.4FIRE-S/D.

Contrary to the above, between 1997 and June, 2007, the licensee failed to ensure that

two emergency operating procedures which controlled activities affecting quality were

appropriate to the circumstances. Specifically, the licensee changed Emergency

Procedures 5.4POST-FIRE and 5.4FIRE-S/D in 1997 to add steps that were

inappropriate to the circumstances because they would not work as written. Additionally,

the licensee failed to properly verify and validate procedure steps to ensure that they

would work to accomplish the necessary actions.

This violation is associated with a White significance determination process finding.

The NRC has concluded that information regarding the reason for the violation, the corrective

actions taken and planned to correct the violation and prevent recurrence and the date when full

compliance was achieved is already adequately addressed on the docket in NRC Inspection

Reports 05000298/2007008, 05000298/2008007, and Licensee Event Report 05000298/2007005-00. However, you are required to submit a written statement or explanation

pursuant to 10 CFR 2.201 if the description therein does not accurately reflect your corrective

actions or your position. In that case, or if you choose to respond, clearly mark your response

as a "Reply to a Notice of Violation," include the EA number, and send it to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001 with a

copy to the Regional Administrator, Region IV, 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).

E1-2

Enclosure 1

If you choose to respond, your response will be made available electronically for public

inspection in the NRC Public Document Room or from the NRCs document system (ADAMS),

accessible from the NRC website at www.nrc.gov/reading-rm/pdr.html or www.nrc.gov/reading-

rm/adams.html. Therefore, to the extent possible, the response should not include any personal

privacy, proprietary, or safeguards information so that it can be made available to the Public

without redaction.

If you contest this enforcement action, you should also provide a copy of your response, with

the basis of your denial, to the Director, Office of Enforcement, United States Nuclear

Regulatory Commission, Washington, DC 20555-0001.

Dated this 13th day of June 2008

E2-1

Enclosure 2

FINAL SIGNIFICANCE DETERMINATION SUMMARY

Significance Determination Basis

a.

Phase 1 Screening Logic, Results, and Assumptions

In accordance with NRC Inspection Manual Chapter 0612, Appendix B, "Issue

Screening," the issue was determined to be more than minor because it was associated

with the equipment performance attribute and affected the mitigating systems

cornerstone objective to ensure the availability, reliability, or function of a system or train

in a mitigating system in that 10 motor-operated valves would not have functioned

following a postulated fire in multiple fire zones. The following summarizes the valves

and fire areas affected:

Valves Affected

HPCI-MO-14

Steam Supply to High Pressure Coolant Injection (HPCI)

Turbine Valve

HPCI-MO-16

Steam Supply to HPCI Turbine Outboard Isolation Valve

RHR-MO-17

Shutdown Cooling Suction Valve

RHR-MO-25A

Residual Heat Removal (RHR) A Inboard Injection Valve

RHR-MO-25B

RHR B Inboard Injection Valve

RHR-MO-67

RHR Discharge to Radwaste Inboard Valve

RHR-MO-921

Augmented Offgas Steam Supply Valve

RWCU-MO-18

Outboard Reactor Water Cleanup Isolation Valve

MS-MO-77

Outboard Main Steam Drain Line Isolation Valve

RR-MO-53A

Reactor Recirculation Pump A Discharge Valve

Fire Areas Affected

CB-A

Control Building Reactor Protection System Room 1A, Seal Water

Pump Area, and Hallway

CB-A-1

Control Building Division 1 Switchgear Room and Battery Room

CB-B

Control Building Division 2 Switchgear Room and Battery Room

CB-C

Control Building Reactor Protection System Room 1B

CB-D

Control Room, Cable Spreading Room, Cable Expansion Room,

and Auxiliary Relay Room

RB-CF

Reactor Building North/Northwest 903, Northwest Quad 889 and

859, and RHR Heat Exchanger Room A

RB-DI (SW)

Reactor Building South/Southwest 903, Southwest Quad 889 and

859, and RHR Heat Exchanger Room B

RB-DI (SE)

Reactor Building RHR Pump B/HPCI Pump Room

RB-J

Reactor Building Critical Switchgear Room 1F

RB-K

Reactor Building Critical Switchgear Room 1G

RB-M

Reactor Building North/Northwest 931 and RHR Heat Exchanger

Room A

E2-2

Enclosure 2

RB-N

Reactor Building South/Southwest 931 and RHR Heat Exchanger

Room B

RB-FN

Reactor Building 903, Northeast Corner

TB-A

Turbine Building (multiple areas)

The significance determination process (SDP) Phase 1 Screening Worksheet (Manual

Chapter 0609, Attachment 4), Table 3b directs the user to Manual Chapter 0609,

Appendix F, Fire Protection Significance Determination Process, because it affected

fire protection defense-in-depth strategies involving post fire safe shutdown systems.

However, Manual Chapter 0308, Attachment 3, Appendix F, Technical Basis for Fire

Protection Significance Determination Process for at Power Operations, states that

Manual Chapter 0609, Appendix F, does not include explicit treatment of fires in the

main control room. The Phase 2 process can be utilized in the treatment of main control

room fires, but it is recommended that additional guidance be sought in the conduct of

such an analysis.

b.

Phase 2 Risk Estimation

Based on the complexity and scope of the subject finding and the significance of the

finding to main control room fires, the analyst determined that a Phase 2 estimation was

not appropriate.

c.

Phase 3 Analysis

In accordance with Manual Chapter 0609, Appendix A, the analyst performed a Phase 3

analysis using input from the Nebraska Public Power District, Individual Plant

Examination for External Events (IPEEE) Report - 10 CFR 50.54(f) Cooper Nuclear

Station, NRC Docket No. 50-298, License No. DPR-46, dated October 30, 1996, the

Standardized Plant Analysis Risk (SPAR) Model for Cooper, Revision 3.31, dated

September 2007, licensee input (see documents reviewed list in Enclosure 3), a

probabilistic risk assessment using a linked event tree model created by the analyst for

evaluating main control room evacuation scenarios, and appropriate hand calculations.

Assumptions:

Following the regulatory conference, the analysts revised the Phase 3 analysis. To

evaluate the change in risk caused by this performance deficiency, the analyst made the

following assumptions:

1. For fire zones that do not have the possibility for a fire to require the main

control room to be abandoned, the ignition frequency identified in the IPEEE

is an appropriate value.

2. The fire ignition frequency for the main control room (PFIF) is best quantified

by the licensees revised value of 6.88 x 10-3/yr.

3. Of the original 64 fire scenarios evaluated, 18 were determined to be

redundant and were eliminated, 41 of the remaining (documented in Table 1)

E2-3

Enclosure 2

were identified as the predominant sequences associated with fires that did

not result in control room abandonment.

4. The baseline conditional core damage probability for a control room

evacuation at the Cooper Nuclear Station is best represented by the creation

of a new probabilistic risk assessment tool created by the analyst using a

linked event tree method. The primary event tree used in this model is

displayed as Figure 1 in the Attachment. The baseline conditional core

damage probability as calculated by the linked event tree model was

1.14 x 10-1, which is similar to the generic industry value of 0.1.

5. The analyst used an event tree, RECOVERY-PATH, shown in Figure 2 in the

Attachment, to evaluate the likelihood of operator recovery via either

restoration of HPCI or manually opening Valve RHR-MO-25B. The resulting

non-recovery probability was 7.9 x 10-2.

6. The risk related to a failure of Valve RHR-MO-25B to open following an

evacuation of the main control room was evaluated using the analysts linked

event tree model. The conditional core damage probability calculated by the

linked event tree model was 2.4 x 10-1.

7. Any fire in the main control room that is large enough to grow and that goes

unsuppressed for 20 minutes will lead to a control room evacuation.

8. Any fire that is unsuppressed by automatic or manual means in the auxiliary

relay room, the cable spreading room, the cable expansion room or

Area RB-FN will result in a main control room evacuation.

9. The Cooper SPAR model, Revision 3.31, represents an appropriate tool for

evaluation of the core damage probabilities associated with postulated fires

that do not result in main control room evacuation.

10. All postulated fires in this analysis resulted in a reactor scram. In addition,

the postulated fire in Fire Area RB-K resulted in a loss-of-offsite power.

11. Valves RHR-MO-25A and RHR-MO-25B are low pressure coolant injection

system isolation valves. These valves can prevent one method of decay heat

removal in the shutdown cooling mode of operation.

12. For Valves RHR-MO-25A and RHR-MO-25B, the subject performance

deficiency only applies to the portion of the post fire procedures that direct the

transition into shutdown cooling. Therefore, the low pressure injection

function is not affected.

13. Valve RHR-MO-25B must open from the motor-control center for operators to

initiate alternate shutdown cooling from the alternate shutdown panel

following a main control room evacuation.

E2-4

Enclosure 2

14. Valve RHR-MO-17 is one of two RHR system shutdown cooling cold-leg

suction isolation valves. These valves can prevent decay heat removal in the

shutdown cooling mode of operation.

15. Valve RWCU-MO-18 is the outboard isolation valve for the reactor water

cleanup system. The system is a closed-loop system outside containment

with piping rated at 1250 psig and 575°F. The isol ation of this system is

designed to protect the system demineralizer resins and as an isolation for a

piping break outside containment. The success or failure of the resins will not

affect the likelihood of core damage. The failure of the system piping without

isolation would contribute to an intersystem loss-of-coolant accident.

However, the likelihood that the system piping fails and an automatic isolation

is not generated would be very low.

16. Valve MS-MO-77 is a 3-inch main steam line drain. The valve isolates a high

pressure drain line heading back to the main condenser. The licensee stated

that the failure to isolate this line would not result in a high enough loss-of-

reactor coolant to affect the core damage frequency. However, the failure to

close this valve could result in a transient that would not have otherwise been

caused by the postulated fire scenario.

17. Valve RR-MO-53A is the discharge isolation valve for Reactor Recirculation

Pump 1-A. The failure to close either this valve or Valve RR-MO-43A would

result in a short circuit of the shutdown cooling flow to the reactor vessel.

The performance deficiency did not apply to Valve RR-MO-43A.

18. Valve RHR-MO-921 provides isolation of a 3-inch steam line heading to the

augmented offgas system. Just downstream of the valve the piping reduces

to a 1-inch diameter line. This line taps off the HPCI pump steam line and

terminates in the main condenser high pressure drain header. Because this

is a 1-inch line, the valve does not contribute to the large-early release

frequency except for postulated seismic events. Additionally, inventory

losses would be minimal and not affect mitigating systems necessary

following the subject fire initiation. Finally, the line would be automatically

isolated upon the isolation of the HPCI pump steam line. However, the failure

to close this valve could result in a transient that would not have otherwise

been caused by the postulated fire scenario.

19. Valve HPCI-MO-14 provides isolation of the HPCI system from the reactor

coolant system. The failure to isolate this valve, when required, would result

in reactor vessel level increasing in an uncontrolled manner, filling the steam

lines and suppressing the steam to all steam-driven equipment. This

increases the core damage probability because it results in the loss of all high

pressure systems.

20. Valve HPCI-MO-16 provides isolation of the HPCI system from the reactor

coolant system. The failure to isolate this valve, when required, would result

in reactor vessel level increasing in an uncontrolled manner, filling the steam

E2-5

Enclosure 2

lines and suppressing the steam to all steam-driven equipment. This

increases the core damage probability because it results in the loss of all high

pressure systems.

21. Valve RHR-MO-67 provides isolation of the RHR system from radwaste.

Post-fire instructions affecting this valve are to assist in placing shutdown

cooling in service. Failure of this valve would delay placing shutdown cooling

in service and act as a distraction to operators placing the plant in a safe

shutdown condition.

22. The exposure time used for evaluating this finding should be determined in

accordance with Inspection Manual Chapter 0609, Appendix A, Attachment 2,

Site Specific Risk-Informed Inspection Notebook Usage Rules. Given that

the performance deficiency was known to have existed for many years, the

analyst used the 1-year of the current assessment cycle as the exposure

period.

23. Based on fire damage and/or procedures, equipment affected by a postulated

fire in a given fire zone is unavailable for use as safe shutdown equipment.

24. The performance deficiency would have resulted in each of the demanded

valves failing to respond following a postulated fire.

25. In accordance with the requirements of Procedure 5.4POST-FIRE, operators

would perform the post-fire actions directed by the procedure following a fire

in an applicable fire zone. Therefore, the size and duration of the fire would

not be relevant to the failures caused by the performance deficiency.

26. Given Assumption 25, severity factors and probabilities of non-

suppression were not addressed for postulated fires that did not result in

main control room evacuation.

Postulated Fires Not Involving Main Control Room Evacuation:

The senior reactor analyst used the SPAR model for Cooper Nuclear Station to estimate

the change in risk, associated with fires in each of the associated fire scenarios (Table 1,

Items 1 - 41) that was caused by the finding. Average unavailability for test and

maintenance of modeled equipment was assumed, and a cutset truncation of

1.0 x 10-13 was used. For each fire zone, the analyst calculated a baseline conditional

core damage probability consistent with Assumptions 9, 10, 25 and 26.

For areas where the postulated fire resulted in a reactor scram, the frequency of the

transient initiator, IE-TRANS, was set to 1.0. All other initiators were set to the house

event FALSE, indicating that these events would not occur at the same time as a

reactor scram. Likewise, for Fire Area RB-K, the frequency of the loss-of-offsite power

initiator, IE-LOOP, was set to 1.0 while other initiators were set to the house event

FALSE.

E2-6

Enclosure 2

With input from the detailed IPEEE notebooks, maintained by the licensee, the analyst

was able to better assess the fire damage in each zone. This resulted in a more realistic

evaluation of the baseline fire risk for the zone, and lowering the change in risk for each

example.

Consistent with guidance in the Reactor Accident Sequence Precursor Handbook,

including NRC document, "Common-Cause Failure Analysis in Event Assessment,

(June 2007)," the baseline established for the fire zone, and Assumptions 22 through 26,

the analyst modeled the resulting condition following a postulated fire in each fire zone

by adjusting the appropriate basic events in the SPAR model. Both the baseline and

conditional values for each fire zone are documented in Table 1.

As shown in Table 1, the analyst calculated a change in core damage frequency (CDF)

associated with these 41 fire scenarios of 2.9 x 10-6/yr.

The analyst evaluated the licensees qualitative reviews of the 13 fire scenarios that

were impacted by the failure of the HPCI turbine to trip. In these scenarios, HPCI floods

the steam lines and prevents further injection by either HPCI or reactor core isolation

cooling system. Qualitatively, not all fires will grow to a size that causes a loss of the trip

function due to spatial separation. Additionally, not all unsuppressed fires would cause a

failure of the HPCI trip function. Finally, no operator recovery was credited in these

evaluations.

Given that these qualitative factors would all tend to decrease the significance of the

finding, the analyst believed that the total change in risk would be significantly lower than

the 2.9 x 10-6/yr documented above. Based on analyst judgment and an assessment of

the evidence provided by the licensee, an occurrence factor of 0.1 was applied to

the13 fire scenarios. This resulted in a total CDF of 7.8 x 10-7/yr. Therefore, the

analyst determined that this value was the best estimate of the safety significance for

these 41 fire scenarios.

E2-7

Enclosure 2

Table 1

Postulated Fires Not Involving Main Control Room Evacuation

Fire Area/

Shutdown

Strategy

Area/

Zone

Scenario

Number

Scenario

Description

Ignition

Frequency

Base

CCDP

Case

CCDP

Estimated

delta-CDF

Contribution

Function Affected

1C

1

RHR A

Pump Room

2.94E-03

8.82E-07

8.15E-05

2.37E-07

2

MCC K

3.02E-03

2.76E-05

1.28E-04

3.03E-07

3

MCC Q

3.93E-03

2.76E-05

1.28E-04

3.95E-07

4

MCC R

3.43E-03

2.76E-05

1.28E-04

3.44E-07

5

MCC RB

1.62E-03

1.12E-03

1.21E-03

1.46E-07

6

MCC S

2.23E-03

1.12E-03

1.21E-03

2.01E-07

7

MCC Y

3.83E-03

1.12E-03

1.21E-03

3.45E-07

8

Panel AA3

9.98E-04

2.76E-05

1.28E-04

1.00E-07

9

Panel BB3

9.98E-04

1.12E-03

1.21E-03

8.98E-08

10

RCIC Starter

Rack

1.32E-03

5.27E-06

8.27E-05

1.02E-07

11

250V Div 1

Rack

5.10E-04

2.76E-05

1.28E-04

5.12E-08

12

250V Div 2

Rack

2.09E-04

1.12E-03

1.21E-03

1.88E-08

RB-CF

2A/2C

13

ASD Panels

3.02E-04

1.12E-03

1.21E-03

2.72E-08

Shut HPCI-MO-14,

HPCI-MO-16,

RHR-MO-921,

RWCU-MO-18 and

MS-MO-77

7A

14

6.74E-03

7.64E-04

7.64E-04

0.00E+00

7B

15

1.36E-03

2.61E-06

2.61E-06

0.00E+00

8C

16

RPS Room

1A

4.15E-03

1.75E-07

1.75E-07

0.00E+00

8D

17

2.42E-03

3.57E-04

3.58E-04

4.84E-10

CB-A

10B

18

Hallway

(used CB

corridor)

1.09E-02

2.05E-05

2.85E-05

8.74E-08

Open RHR-MO-25B

and RHR-MO-67

E2-8

Enclosure 2

8H

19

DC

Switchgear

Room 1A

4.27E-03

3.49E-04

3.49E-04

1.28E-09

CB-A-1

8E

20

Battery

Room 1A

2.25E-03

8.74E-06

1.03E-05

3.51E-09

Open RHR-MO-17,

RHR-MO-25B, and

RHR-MO-67

8G

21

DC

Switchgear

Room 1B

4.27E-03

1.82E-03

1.83E-03

3.42E-08

CB-B

8F

22

Battery

Room 1B

2.25E-03

4.81E-06

5.73E-06

2.07E-09

Open RHR-MO-25A

8B

23

4.15E-03

1.75E-07

1.77E-07

5.81E-12

CB-C

8C

24

RPS Room

1A

4.15E-03

1.75E-07

1.77E-07

5.81E-12

Open RHR-MO-17,

RHR-MO-25A, and

RHR-MO-67

RB-DI (SW)

2D

25

RHR Heat

Exchanger

Room B

6.70E-04

8.66E-05

8.68E-05

1.27E-10

Shut HPCI-MO-14

and RR-MO-53A.

RB-DI (SE)

1D/1E

26

RHR B/HPCI

Pump Room

4.28E-03

6.48E-05

1.44E-04

3.37E-07

Shut HPCI-MO-14

and RR-MO-53A.

RB-J

3A

27

Switchgear

Room 1F

3.71E-03

5.28E-05

5.28E-05

0.00E+00

Open RHR-MO-17,

RHR-MO-25B, and

RHR-MO-67

RB-K

3B

28

Switchgear

Room 1G

3.71E-03

1.77E-02

1.77E-02

0.00E+00

Open RHR-MO-25A

3C/3D

/3E

29

RB Elevation

932

1.13E-02

7.06E-06

8.99E-06

2.18E-08

RB-M

2B

30

RHR Hx

Rm A

6.70E-04

7.06E-06

8.99E-06

1.29E-09

Open RHR-MO-17

and RHR-MO-25B

E2-9

Enclosure 2

3C/3D

/3E

31

Reactor

Building

Elevation

932

1.13E-02

1.22E-05

1.38E-05

1.81E-08

RB-N

2D

32

RHR Heat

Exchanger

Room B

6.70E-04

1.22E-05

1.38E-05

1.07E-09

Open RHR-MO-25A

11D

33

Condenser

Pit Area

3.10E-03

4.83E-06

6.20E-06

4.25E-09

11E

34

Reactor

Feedwater

Pump Area

6.25E-03

4.83E-06

6.20E-06

8.56E-09

11L

35

Pipe Chase

6.70E-04

4.83E-06

6.20E-06

9.18E-10

12C

36

Condenser

and Heater

Bay Area

3.27E-03

4.83E-06

6.20E-06

4.48E-09

12D

37

TB Floor 903

3.45E-03

4.83E-06

6.20E-06

4.73E-09

13A

38

Turbine

Operating

Floor

5.76E-03

4.83E-06

6.20E-06

7.89E-09

13B

39

Non-critical

Switchgear

Room

3.79E-03

4.83E-06

6.20E-06

5.19E-09

13C

40

Electric Shop

8.56E-04

4.83E-06

6.20E-06

1.17E-09

TB-A

13D

41

I&C Shop

8.90E-04

4.83E-06

6.20E-06

1.22E-09

Open RHR-MO-17,

RHR-MO-25A, and

RHR-MO-67

Total Estimated CDF for 41 Postulated Fire Scenarios:

2.91E-06

Enclosure 2

E2-10

Post-Fire Remote Shutdown Calculations:

As documented in Assumptions 4, 5, and 6, the analyst created a linked event tree

model, using the Systems Analysis Programs for Hand-on Integrated Reliability

Evaluation (SAPHIRE) software provided by the Idaho National Laboratory, to evaluate

the risks related to fire-induced main control room abandonment at the Cooper Nuclear

Station. This linked event tree was used to evaluate the increased risk from the subject

performance deficiency during the response to postulated fires in the main control room,

the auxiliary relay room, the cable spreading room, the cable expansion room or Fire

Area RB-FN. The primary event tree used in this model is displayed as Figure 1 in the

Attachment.

As documented in Assumption 5, the analyst used an event tree to evaluate the

likelihood of operator recovery via either restoration of HPCI or manually opening

Valve RHR-MO-25B. The resulting non-recovery probability was 7.9 x 10-2.

Using the linked event tree model described in Assumption 4, the analyst calculated the

CDF to be 7.3 x 10-6/yr. The dominant cutsets are shown below in Table 2.

Table 2

Main Control Room Abandonment Cutsets

Postulated Fire

Sequence

Mitigating Functions

Results

Auxiliary Relay Room

4-01-03

Failure to Reestablish HPCI

Failure to Open MO-25B

1.7 x 10-6/yr

Main Control Room

3-01-03

Failure to Reestablish HPCI

Failure to Open MO-25B

4.5 x 10-7/yr

Auxiliary Relay Room

4-01-12

Early HPCI Failure

Failure to Open MO-25B

4.1 x 10-7/yr

Auxiliary Relay Room

4-01-12

HPCI Out of Service

Failure to Open MO-25B

2.7 x 10-7/yr

Main Control Room

4-01-12

Early HPCI Failure

Failure to Open MO-25B

1.1 x 10-7/yr

Control Room Abandonment Frequency

NUREG/CR-2258, Fire Risk Analysis for Nuclear Power Plants, provides that control

room evacuation would be required because of thick smoke if a fire went unsuppressed

for 20 minutes. Given Assumption 6 and assuming that a fire takes 2 minutes to be

detected by automatic detection and/or by the operators, there are 18 minutes remaining

in which to suppress the fire prior to main control room evacuation being required. NRC

Inspection Manual Chapter 0609, Appendix F, Table 2.7.1, Non-suppression Probability

Values for Manual Fire Fighting Based on Fire Duration (Time to Damage after

Detection) and Fire Type Category, provides a manual non-suppression probability

(PNS) for the control room of 1.3 x 10-2 given 18 minutes from time of detection until time

of equipment damage. This is a reasonable approach, although fire modeling performed

by the licensee indicated that 16 minutes was the expected time to abandon the main

control room based on habitability.

Enclosure 2

E2-11

In accordance with Inspection Manual Chapter 0609, Appendix F, Task 2.3.2, the

analyst used a severity factor of 0.1 for determining the probability that a postulated fire

would be self sustaining and grow to a size that could affect plant equipment.

Given these values, the analyst calculated the main control room evacuation frequency

for fires in the main control room (FEVAC) as follows:

FEVAC = PFIF * SF * PNS

= 6.88 x 10-3/yr * 0.1 * 1.3 x 10-2

= 8.94 x 10-6/yr

In accordance with Procedure 5.4FIRE-S/D, operators are directed to evacuate the main

control room and conduct a remote shutdown, if a fire in the main control room or any of

the four areas documented in Assumption 8, if plant equipment spuriously actuates/de-

energizes equipment, or if instrumentation becomes unreliable. Therefore, for all

scenarios except a postulated fire in the main control room, the probability of non-

suppression by automatic or manual means are documented in Table 3, below.

Table 3

Control Room Abandonment Frequency

Fire Area

Ignition

Frequency

(per year)

Severity

Automatic

Suppression

Manual

Suppression

Abandonment

Frequency

(per year)

Main Control

Room

6.88 x 10-3

0.1

none

1.3 x 10-2

8.94 x 10-6

Auxiliary Relay

Room

1.42 x 10-3

0.1

none

0.24

3.41 x 10-5

Cable Expansion

Room

1.69 x 10-4

0.1

2 x 10-2

0.24

8.11 x 10-8

Cable Spreading

Room

4.27 x 10-3

0.1

5 x 10-2

0.24

5.12 x 10-6

Reactor Building

903 (RB-FN)

1.43 x 10-3

0.1

2 x 10-2

0.24

6.86 x 10-7

Total MCR Abandonment:

4.89 x 10-5

Enclosure 2

E2-12

The licensees total control room abandonment frequency was 1.75 x 10-5. For the main

control room fire, the licensees calculations were more in-depth than the analysts. The

remaining fire areas were assessed by the licensee using IPEEE data. However, the

following issues were noted with the licensees assessment:

Kitchen fires were not included in licensees evaluation

This would tend to increase the ignition frequency

This might add more heat input than the electrical cabinet fires

modeled by the licensee

Habitability Forced Abandonment

Non-suppression probability did not account for fire brigade

response time or the expected time to damage.

Reduced risk based on 3 specific cabinets causing a loss of

ventilation early, when it should have increased the risk. Fire

modeling showed that fires in these cabinets could damage

nearby cables and cause ventilation damper(s) to close.

Risk Assessment Calculation ES-91 uses an abandonment value

of 9.93 x 10-7. However, the supporting calculation performed by

EPM used 3.02 x 10-6.

Equipment Failure Control Room Abandonment

Criteria for leaving the control room did not accurately reflect the

guidance that was proceduralized.

The evaluation of the Cable Expansion Room stated that the only

fire source was self-ignition of cables. This was modeled as a hot

work fire, and it included a probability that administrative controls

for hot work and fire watches would prevent such fires from getting

large enough to require control room abandonment. This is

inappropriate for self-ignition of cables, since there would not

really be any fire watch present. Adjusting for this would increase

the risk in this area by two orders of magnitude.

The licensee concluded that fires in equipment in the four

alternate shutdown fire areas outside the main control room (see

Assumption 8) would not result in control room abandonment

without providing a technical basis. The licensees Appendix R

analysis concluded that fire damage in these rooms require main

control room evacuation to prevent core damage.

Enclosure 2

E2-13

The analyst used the main control room abandonment frequencies documented in

Table 3. In addition, sensitivities were run using the licensees values.

Recovery Following Failure of Valve RHR-MO-25B

As documented in Assumption 5, the analyst calculated a combined non-recovery

probability using the event tree shown in Figure 2 in the Attachment.

Table 4 documents the final split fractions used in quantifying this event tree.

Using the event tree in Figure 2 and the split fractions in Table 4, the analyst calculated

a combined non-recovery probability of 7.9 x 10-2. The licensees combined non-

recovery probability was 4.0 x 10-3. The licensee used a similar approach to quantify this

value. However, the licensee assumed that operators would always shut the safety-

relief valves upon determining that reactor pressure vessel water level was decreasing.

The analyst assumed that some percentage of operators would continue to follow the

procedure and attempt to recover from the failed RHR valve or try alternate methods of

low-pressure injection. In addition, the analyst identified the following issues that

impacted the licensees analysis:

The inspectors determined that it would require 112 ft-lbs of force to manually

open Valve RHR-MO-25B. The analyst determined that this affected the

ergonomics of this recovery. Some operators may assume that the valve is on

the backseat when large forces are required to open it. Some operators might

be incapable of applying this force to a 2-foot diameter hand wheel.

The analyst noted that the following valves would be potential reasons for lack

of injection flow and/or may distract operators from diagnosis that

Valve RHR-MO-025B is closed:

RHR-81B, RHR Loop B Injection Shutoff Valve, could be closed.

RHR-27CV, RHR Loop B Injection Line Testable Check Valve,

could be stuck closed.

Table 4

Split Fractions for RECOVERY-PATH

Top Event

How Assessed

Failure Probability

LEVEL-DOWN

SPAR-H (Diagnosis Only)

1.0 x 10-3

SRV-STATUS

Best Estimate of Fraction

1.0 x 10-1

CLOSE-SRVS

SPAR-H (Action Only)

5.0 x 10-4

RESTORE-HPCI

SPAR-H (Combined)

5.1 x 10-3

OPEN-MO-25B-3

SPAR-H (Combined)

5.0 x 10-1

OPEN-MO-25B-5/7

SPAR-H (Combined)

5.5 x 10-2

Enclosure 2

E2-14

RHR-MO-274B, Injection Line Testable Check Valve Bypass

Valve, could be opened as an alternative.

Operators could search for an alternate flow path.

The licensees evaluation did not include sequences involving the failure of the

HPCI system shortly after main control room evacuation in their risk evaluation.

These sequences represented approximately 26 percent of the CDF as

calculated by the analyst. These sequences are important for the following

reasons:

Failure of HPCI leads to the need for operators to rapidly

depressurize the reactor to establish alternate shutdown cooling.

Decay heat will be much higher than for sequences involving early

HPCI success. Also, depressurization under high decay heat and

high temperature result in greater water mass loss. This will

significantly reduce the time available for recovery actions.

HPCI success sequences provide long time frames available with

HPCI operating. This reduces decay heat, increases time for

recovery, and permits the establishment of an emergency

response organization. Those factors are not applicable to early

HPCI failure sequences.

The basis for operating HPCI was not well documented by the licensee. During

many of the extended sequences, suppression pool temperature went well

above the operating limits for HPCI cooling and remained high for extended

periods of time. The following facts were determined through inspection:

The design temperature for operating HPCI is 140°F based on

process flow providing oil cooling.

General Electric provided a transient operating temperature of

170°F for up to 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

In the licensees best case evaluation of the performance

deficiency, the suppression pool would remain above 150°F for

10.6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />.

The licensee used a case-specific combined recovery in assessing the risk of

this performance deficiency. Most of the recoveries discussed by the licensee

would have been available with or without the performance deficiency.

Therefore, these should be in the baseline model and portions of the

sequences subtracted from the case evaluation. This is the approach used by

the analyst in the linked event trees model.

Enclosure 2

E2-15

The licensee stated during the regulatory conference that credit should

be given for diesel-driven fire water pump injection. This is one of the

licensees alternate strategies. However, the inspectors determined, and the

licensee concurred, that this alternate method of injection requires that

Valve RHR-MO-25B be open. Therefore, no credit was given for this alternate

strategy.

Conclusions:

The analyst concluded that the subject performance deficiency was of low to moderate

significance (White). As documented in Table 1, for a period of exposure of 1 year, the analyst

determined a best estimate CDF for fire scenarios that did not require evacuation of the main

control room of 7.8 x 10-7 using both quantitative and qualitative techniques. Additionally, using

the linked event tree model described in Assumption 4, for a period of exposure of 1 year, the

analyst calculated the CDF to be 7.3 x 10-6 for postulated fires leading to the abandonment of

the main control room. This resulted in a total best estimate CDF of 8.1 x 10-6.

Y

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Figure 1

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Figure 2

A-2

Attachment

Enclosure 3

E3-1

SUPPLEMENTAL INFORMATION

Summary of Findings

IR 05000298/2008008; 03/19/08 - 06/13/08; Cooper Nuclear Station: Triennial Fire Protection

Follow-up Inspection

The report covered a 3-month period of inspection follow-up and significance determination

efforts by region-based inspectors and a senior risk analyst. One finding with an associated

violation was determined to have White safety significance. The significance of most findings is

indicated by its color (Green, White, Yellow, Red) using Inspection Manual Chapter 0609,

"Significance Determination Process." Findings for which the significance determination

process does not apply may be green or be assigned a severity level after NRC management

review. The NRC's program for overseeing the safe operation of commercial nuclear power

reactors is described in NUREG-1649, "Reactor Oversight Process," Revision 3, dated July

2000.

A.

NRC-Identified and Self-Revealing Findings

White. A violation of 10 CFR Part 50, Appendix B, Criterion V, was identified for failure

to ensure that some steps contained in emergency procedures at Cooper Nuclear

Station would work as written. Inspectors identified that steps in Emergency

Procedures 5.4POST-FIRE, Post-Fire Operational Information, and 5.4FIRE-S/D, Fire

Induced Shutdown From Outside Control Room, intended to reposition motor-operated

valves locally, would not have worked as written because the steps were not appropriate

for the configuration of the motor-starter circuits. This condition existed between 2004

and June, 2007. Appendix B to 10 CRF 50, Criterion V, was not met because these

quality-related procedures would not work to allow operators to bring the plant to a safe

shutdown condition in the event of certain fires. This finding had a cross-cutting aspect

in Problem Identification and Resolution, under the Corrective Action Program attribute,

because the licensee did not thoroughly evaluate the 2004 NRC violation to address

causes and extent of condition (P.1.c -Evaluations).

This finding is of greater than minor safety significance because it impacted the

Mitigating Systems cornerstone objective to ensure the availability, reliability, and

capability of systems that respond to initiating events to prevent undesirable

consequences. This finding affected both the procedure quality and protection against

external factors (fires) attributes of this cornerstone objective. This finding was

determined to have a White safety significance during a Phase 3 evaluation. The

scenarios of concern involve larger fires in specific areas of the plant which trigger

operators to implement fire response procedures to place the plant in a safe shutdown

condition. Since some of those actions could not be completed using the procedures as

written, this would challenge the operators ability to establish adequate core cooling.

Enclosure 3

E3-2

KEY POINTS OF CONTACT

Licensee

K. Billesbach, Quality Assurance Manager

M. Colomb, General Manager of Plant Operations

J. Flaherty, Senior Staff Licensing Engineer

P. Fleming, Director of Nuclear Safety Assurance

V. Furr, Risk Management Engineer

G. Kline, Director of Engineering

G. Mace, Nuclear Assessment Manager

S. Minahan, Vice-President-Nuclear and Chief Nuclear Officer

S. Nelson, Risk Management Engineer

T. Shudak, Fire Protection Program Engineer

R. Stephan, Risk Assessment Engineer

K. Sutton, Risk Management Supervisor

D. VanDerKamp, Licensing Supervisor

NRC

J. Bongara, Senior Human Factors Specialist, Office of New Reactors

M. Chambers, Resident Inspector

J. Circle, Senior Reliability and Risk Analyst, Office of Nuclear Reactor Regulation

N. Salgado, Chief, Operator Licensing and Human Performance Branch, Office of Nuclear

Reactor Regulation

N. Taylor, Senior Resident Inspector

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Discussed 05000298/2008007-01

VIO

Two Inadequate Post-Fire Safe

Shutdown Procedures

Enclosure 3

E3-3

LIST OF DOCUMENTS REVIEWED

PROCEDURES

Number

Title

Revision

Administrative Procedure 0.1

Procedure Use and Adherence

31

Administrative Procedure 0.4A

Procedure Change Process

Supplement

various

Administrative Procedure 2.0.1.2

Operations Procedure Policy

27

Administrative Procedure 2.0.3

Conduct of Operations

58

Emergency Procedure 5.4 Fire

General Fire Procedure

14

Emergency Procedure 5.4 Post-Fire

Post-Fire Operational Information

12 & 13

Emergency Procedure 5.4 Fire-S/D

Fire Induced Shutdown From

Outside Control Room

14 & 15

SELF-ASSESSMENTS AND AUDITS

QA Audit 07-01

Fire Protection Program

02/2007

Self-assessment

Manual Action Feasibility - Review of Cooper

Nuclear Station Post-Fire Manual Actions With NRC

Inspection Manual Post-Fire Manual Action

Feasibility Criteria

05/18/07

Procedure Change

Request

Emergency Procedure 5.4 POST-FIRE, Post Fire

Operational Information

Revision 4

Alarm Response

Procedure 2.3_9-3-2,

Panel 9-3-2/D-1

HPCI Turbine Oil Cooler Temperature High

Revision 17

CONDITION REPORTS

2007-04155

2004-03034

2004-03081

2003-05433

Enclosure 3

E3-4

CALCULATIONS

Fauske Review of Cooper Nuclear Station Calculation NEDC 08-035, Suppression Pool Heat-

up Response for Appendix R Event with 24 Hour HPCI Operation.

Calculation NEDC 08-035, Suppression Pool Heat-up Response for Appendix R Event with

24 Hour HPCI Operation, Revision 0.

Calculation NEDC 08-041, Main Control Room Forced Abandonment Fire Scenario Analysis,

Revision 0.

EPM Calculation P1906-07-011b-001, Main Control Room Forced Abandonment Fire Scenario

Analysis,5/2008.

Calculation ES-091, Detailed PSA Study of Fire Protection Triennial Inspection, Revision 0.

Calculation NEDC 08-032, EPM Calculation 1906-07-06, Fire Ignition Frequencies, Revision 0.

MISCELLANEOUS

White paper discussion on SRV circuit operation from the alternate shutdown panel

dated 5/19/2008.

GE Service Information Letter 615, ADS/HPCI Functional Redundancy, dated 3/4/1998.

NUREG 2258, Fire Risk Analysis for Nuclear Power Plants.

NUREG/CR-6850, EPRI/NRC-RES Fire PRA Methodology for Nuclear Power Facilities.

NPPD Letter NLS2008044, Additional Information for Consideration in Addressing Inspection

Finding, dated 5/8/2008.

Generic Letter 82-21, Technical Specifications for Fire Protection Audits.

NRC Inspection Report 05000317/2007009 and 05000318/2007009.

NRC Inspection Report 05000282/2006009 and 05000306/2006009.

NRC Inspection Report 05000261/2007007.

Additional documents reviewed as part of inspecting this finding are documented in NRC

Inspection Report 05000298/2008007.