ML081650090
| 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
UNITED STATES
NUC LE AR RE G UL AT O RY C O M M I S S I O N
R E GI ON I V
612 EAST LAMAR BLVD , SU I TE 400
AR LI N GTON , TEXAS 76011-4125
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.
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)
OEMail.Resource@nrc.gov Michael.Franovich@nrc.gov
OEWeb.Resource@nrc.gov Jeff.Circle@nrc.gov
Doug.Starkey@nrc.gov Joseph.Anderson@nrc.gov
Maryann.Ashley@nrc.gov Tim.Kobetz@nrc.gov
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Victor.Dricks@nrc.gov Carl.Lyon@nrc.gov
Bill.Maier@nrc.gov Undine.Shoop@nrc.gov
Linda.Smith@nrc.gov Richard.borchardt@nrc.gov
Neil.OKeefe@nrc.gov Melissa.Wyatt@nrc.gov
John.Mateychick@nrc.gov Paul.Lain@nrc.gov
Karla.Fuller@nrc.gov Bruce.Boger@nrc.gov
Nick.Taylor@nrc.gov Harold.Barrett@nrc.gov
Michael.Cheok@nrc.gov Frederick.Brown@nrc.gov
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Alexander.Klein@nrc.gov
Christi.Maier@nrc.gov
SUNSI Review Completed: LJS ADAMS: Yes No Initials: __________
Publicly Available Non-Publicly Available Sensitive Non-Sensitive
S:\DRS\REPORTS\CN 2008008 Final Significance ltr - NFO
SRI/EB2 SRI/EB2 C:DRS/EB2 SRA/DRS ACES C:DRP/C D:DRS
JMMateychick NFOKeefe LJSmith DLoveless CMaier DChamberlain RJCaniano
E /RA/ /RA/ /RA/ /RA/ /RA/ /RA/ /RA/
6/7/08 6/5/08 6/5/08 6/5/08 6/5/08 6/5/08 6/13/08
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
NOTICE OF VIOLATION
Nebraska Public Power District Docket No. 50-298
Cooper Nuclear Station License No. DPR-46
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).
E1-1 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
E1-2 Enclosure 1
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
E2-1 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)
E2-2 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.
E2-3 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
E2-4 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.
E2-5 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.
E2-6 Enclosure 2
Table 1
Postulated Fires Not Involving Main Control Room Evacuation
Fire Area/ Estimated
Area/ Scenario Scenario Ignition Base Case
Shutdown delta-CDF Function Affected
Zone Number Description Frequency CCDP CCDP
Strategy Contribution
RHR A
1C 1 2.94E-03 8.82E-07 8.15E-05 2.37E-07
Pump Room
RB-CF 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 Shut HPCI-MO-14,
7 MCC Y 3.83E-03 1.12E-03 1.21E-03 3.45E-07 HPCI-MO-16,
8 Panel AA3 9.98E-04 2.76E-05 1.28E-04 1.00E-07 RHR-MO-921,
2A/2C 9 Panel BB3 9.98E-04 1.12E-03 1.21E-03 8.98E-08 RWCU-MO-18 and
RCIC Starter MS-MO-77
10 1.32E-03 5.27E-06 8.27E-05 1.02E-07
Rack
250V Div 1
11 5.10E-04 2.76E-05 1.28E-04 5.12E-08
Rack
250V Div 2
12 2.09E-04 1.12E-03 1.21E-03 1.88E-08
Rack
13 ASD Panels 3.02E-04 1.12E-03 1.21E-03 2.72E-08
7A 14 6.74E-03 7.64E-04 7.64E-04 0.00E+00
CB-A 7B 15 1.36E-03 2.61E-06 2.61E-06 0.00E+00
RPS Room
8C 16 4.15E-03 1.75E-07 1.75E-07 0.00E+00 Open RHR-MO-25B
1A
8D 17 2.42E-03 3.57E-04 3.58E-04 4.84E-10 and RHR-MO-67
Hallway
10B 18 (used CB 1.09E-02 2.05E-05 2.85E-05 8.74E-08
corridor)
E2-7 Enclosure 2
8H 19 Switchgear 4.27E-03 3.49E-04 3.49E-04 1.28E-09 Open RHR-MO-17,
CB-A-1
Room 1A RHR-MO-25B, and
RHR-MO-67
Battery
8E 20 2.25E-03 8.74E-06 1.03E-05 3.51E-09
Room 1A
CB-B 8G 21 Switchgear 4.27E-03 1.82E-03 1.83E-03 3.42E-08
Room 1B Open RHR-MO-25A
Battery
8F 22 2.25E-03 4.81E-06 5.73E-06 2.07E-09
Room 1B
CB-C 8B 23 RPS Room 4.15E-03 1.75E-07 1.77E-07 5.81E-12 Open RHR-MO-17,
1A RHR-MO-25A, and
8C 24 4.15E-03 1.75E-07 1.77E-07 5.81E-12
RHR-MO-67
RHR Heat
RB-DI (SW) Shut HPCI-MO-14
2D 25 Exchanger 6.70E-04 8.66E-05 8.68E-05 1.27E-10
and RR-MO-53A.
Room B
RHR B/HPCI Shut HPCI-MO-14
RB-DI (SE) 1D/1E 26 4.28E-03 6.48E-05 1.44E-04 3.37E-07
Pump Room and RR-MO-53A.
Open RHR-MO-17,
RB-J Switchgear
3A 27 3.71E-03 5.28E-05 5.28E-05 0.00E+00 RHR-MO-25B, and
Room 1F
RHR-MO-67
RB-K Switchgear
3B 28 3.71E-03 1.77E-02 1.77E-02 0.00E+00 Open RHR-MO-25A
Room 1G
RB-M 3C/3D RB Elevation
29 1.13E-02 7.06E-06 8.99E-06 2.18E-08 Open RHR-MO-17
/3E 932
RHR Hx and RHR-MO-25B
2B 30 6.70E-04 7.06E-06 8.99E-06 1.29E-09
Rm A
E2-8 Enclosure 2
Reactor
3C/3D Building
RB-N 31 1.13E-02 1.22E-05 1.38E-05 1.81E-08
/3E Elevation
932 Open RHR-MO-25A
RHR Heat
2D 32 Exchanger 6.70E-04 1.22E-05 1.38E-05 1.07E-09
Room B
Condenser
11D 33 3.10E-03 4.83E-06 6.20E-06 4.25E-09
Pit Area
Reactor
11E 34 Feedwater 6.25E-03 4.83E-06 6.20E-06 8.56E-09
TB-A Pump Area
11L 35 Pipe Chase 6.70E-04 4.83E-06 6.20E-06 9.18E-10
Condenser
12C 36 and Heater 3.27E-03 4.83E-06 6.20E-06 4.48E-09
Open RHR-MO-17,
Bay Area
RHR-MO-25A, and
12D 37 TB Floor 903 3.45E-03 4.83E-06 6.20E-06 4.73E-09 RHR-MO-67
Turbine
13A 38 Operating 5.76E-03 4.83E-06 6.20E-06 7.89E-09
Floor
Non-critical
13B 39 Switchgear 3.79E-03 4.83E-06 6.20E-06 5.19E-09
Room
13C 40 Electric Shop 8.56E-04 4.83E-06 6.20E-06 1.17E-09
13D 41 I&C Shop 8.90E-04 4.83E-06 6.20E-06 1.22E-09
Total Estimated CDF for 41 Postulated Fire Scenarios: 2.91E-06
E2-9 Enclosure 2
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.
E2-10 Enclosure 2
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 Severity Automatic Manual Abandonment
Frequency Suppression Suppression Frequency
(per year) (per year)
Main Control
6.88 x 10-3 0.1 none 1.3 x 10-2 8.94 x 10-6
Room
Auxiliary Relay
1.42 x 10-3 0.1 none 0.24 3.41 x 10-5
Room
Cable Expansion
1.69 x 10-4 0.1 2 x 10-2 0.24 8.11 x 10-8
Room
Cable Spreading
4.27 x 10-3 0.1 5 x 10-2 0.24 5.12 x 10-6
Room
Reactor Building
1.43 x 10-3 0.1 2 x 10-2 0.24 6.86 x 10-7
903 (RB-FN)
Total MCR Abandonment: 4.89 x 10-5
E2-11 Enclosure 2
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.
E2-12 Enclosure 2
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.
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
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.
E2-13 Enclosure 2
- 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:
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.
E2-14 Enclosure 2
- 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.
E2-15 Enclosure 2
Attachment
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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.
E3-1 Enclosure 3
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
E3-2 Enclosure 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 various
Supplement
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 14 & 15
Outside Control Room
SELF-ASSESSMENTS AND AUDITS
QA Audit 07-01 Fire Protection Program 02/2007
Self-assessment Manual Action Feasibility - Review of Cooper 05/18/07
Nuclear Station Post-Fire Manual Actions With NRC
Inspection Manual Post-Fire Manual Action
Feasibility Criteria
Procedure Change Emergency Procedure 5.4 POST-FIRE, Post Fire Revision 4
Request Operational Information
Alarm Response HPCI Turbine Oil Cooler Temperature High Revision 17
Procedure 2.3_9-3-2,
Panel 9-3-2/D-1
CONDITION REPORTS
2007-04155
2004-03034
2004-03081
2003-05433
E3-3 Enclosure 3
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.
E3-4 Enclosure 3