ML061870256
| ML061870256 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/31/2004 |
| From: | Howell A T NRC/RGN-IV/DRP |
| To: | Edington R K Nebraska Public Power District (NPPD) |
| References | |
| EA-04-131, FOIA/PA-2006-0007 IR-04-014 | |
| Download: ML061870256 (24) | |
See also: IR 05000298/2004014
Text
4ý A ~UNITED STATES v SNUCLEAR REGULATORY
COMMISSION
REGION IV 4*! :";: O il RYAN PLAZA DRIVE, SUITE 400 A3- 5 ARLINGTON.
TEXAS 76011-4005
Ai'Uf'August XX, 2004 EA-04-131 Randall K. Edington, Vice President-Nuclear
and CNO Nebraska Public Power District P.O. Box 98 Brownville, NE 68321 SUBJECT: COOPER NUCLEAR STATION -NRC INSPECTION
REPORT 05000298/2004014;
PRELIMINARY
GREATER THAN GREEN FINDING Dear Mr. Edington: On July 15, 2004, the U. S. Nuclear Regulatory
Commission (NRC) completed
an inspection
at your Cooper Nuclear Station. The purpose of the inspection
was to followup on the misalignment
of the service water system that rendered one train of service water inoperable
for a period of 21 days. The enclosed inspection
report documents
an inspection
finding which was discussed
on July 22, 2004, with Mr. J. Roberts, Director of Nuclear Safety Assurance, and other members of your staff.The report discusses
a finding that appears to have Greater than Green safety significance.
As described
in Section 1 R04 of this report, this issue involved the failure to restore the Division 2 service water gland water supply to a normal alignment
on January 21, 2004, following maintenance
on the Division 2 service water discharge
strainer.
This error went undetected
until February 11, 2004, when a low pressure alarm prompted operators
to perform a confirmatory
valve alignment
during which it was discovered
that the Division 2 gland water supply was cross-connected
with the Division 1 supply. This resulted in Division 2 of the service water system and Emergency
Diesel Generator
2 being inoperable
for 21 days. This finding was assessed based on the best available
information, including
influential
assumptions, using the applicable
Significance
Determination
Process and was preliminarily
determined
to be a Greater than Green Finding. Because the preliminary
safety significance
is Greater than Green, the NRC requests that additional
information
be provided regarding
the nonrecovery
probability
for Division 2 of the service water system and any other considerations
you have identified
as impacting
the safety significance
determination.
This finding does not present a current safety concern because the valve lineup was restored to the normal configuration
per the system operating
procedure
and the affected equipment
was returned to an operable condition This finding is also an apparent violation
of NRC requirements
and is being considered
for I ao=0rft=VaM
1FWW= dkftM85 c IA-0=0=o6-
escalated
enforcement
action in accordance
with the "General Statement
of Policy and Procedure
for NRC Enforcement
Actions" (Enforcement
Policy), NUREG-1 600. The current enforcement
policy is included on the NRC's website at http://www.nrc.gov/what-we-do/regulatory/enforcement.html.
Before the NRC makes a final decision on this matter, we are providing
you an opportunity
(1) to present to the NRC your perspectives
on the facts and assumptions, used by the NRC to arrive at the finding and its significance, at a Regulatory
Conference
or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory
Conference, it should be held within 30 days of the receipt of this letter and we encourage
you to submit supporting
documentation
at least one week prior to the conference
in an effort to make the conference
more efficient
and effective.
If a Regulatory
Conference
is held, it will be open for public observation.
If you decide to submit only a written response, such submittal
should be sent to the NRC within 30 days of the receipt of this letter.Please contact Mr. Kriss Kennedy at (817) 860-8144 within 10 days of the date of this letter to notify the NRC of your intentions.
If we have not heard from you within 10 days, we will continue with our significance
determination
and enforcement
decision and you will be advised by separate correspondence
of the results of our deliberations
on this matter.Since the NRC has not made a final determination
in this matter, no Notice of Violation
is being issued for the inspection
finding at this time. In addition, please be advised that the characterization
of the apparent violation
described
in the enclosed inspection
report may change as a result of further NRC review.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 will be made available
electronically
for public inspection
in the NRC Public Document Room or from the Publicly Available
Records (PARS) component
of NRC's document system (ADAMS). ADAMS is accessible
from the NRC Web site at http:llwww.nrc.qov/reading-rm/adams.html (the Public Electronic
Reading Room).Should you have any questions
concerning
this inspection, we will be pleased to discuss them with you.Sincerely, Arthur T. Howell III, Director Division of Reactor Projects Docket: 50-298 Ucense: DPR-46 Enclosure:
Inspection
Report 05000298/2004014
w/attachment:
Supplemental
Information
cc w/enclosure:
Clay C. Warren, Vice President
of Strategic
Programs Nebraska Public Power District 1414 15W Street, Columbus, NE 68601 John R. McPhail, General Counsel Nebraska Public Power District P.O. Box 499 Columbus, NE 68602-0499
P. V. Fleming, 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 Sue Semerena, Section Administrator
Nebraska Health and Human Services System Division of Public Health Assurance Consumer Services Section 301 Centennial
Mall, South P.O. Box 95007 Lincoln, NE 68509-5007
Ronald A. Kucera, Deputy Director for Public Policy Department
of Natural Resources P.O. Box 176 Jefferson
City, MO 65101 Jerry Uhlmann, Director State Emergency
Management
Agency P.O. Box 116 Jefferson
City, MO 65102-0116
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
Daniel K. McGhee Bureau of Radiological
Health Iowa Department
of Public Health 401 SW 7th Street, Suite D Des Moines, IA 50309 William J. Fehrman, President.
and Chief Executive
Officer Nebraska Public Power District 1414 15th Street Columbus, NE 68601 Chief Technological
Services Branch National Preparedness
Division Department
of Homeland Security Emergency
Preparedness
& Response Directorate
FEMA Region VII 2323 Grand Boulevard, Suite 900 Kansas City, MO 64108-2670
Jerry C. Roberts, Director of Nuclear Safety Assurance Nebraska Public Power District P.O. Box 98 Brownville, NE 68321 Electronic
distribution
by RIV: Regional Administrator (BSM1)DRP Director (ATH)DRS Director (DDC)Senior Resident Inspector (SCS)Branch Chief, DRP/C (KM K)Senior Project Engineer, DRP/C (WCW)Staff Chief, DRP/TSS (PHH)RITS Coordinator (KEG)Dan Merzke, Pilot Plant Program (DXM2)RidsNrrDipmUpb
Jennifer Dixon-Herrity, OEDO RIV Coordinator (JLD)CNS Site Secretary (SLN)Dale Thatcher (DFT)W. A. Maier, RSLO (WAM)
ADAMS: X Yes 0 No Initials:__
X Publicly Available
0 Non-Publicly
Available
0 Sensitive
X Non-Sensitive
R:VCNS\2004\CN2004-14RP-SCS.wpd
!~VRW ;DRPJI3,C-'
1,1:D31P10,., ISRA;DRS [C_ RP/ 0~ A:E~ 77 jD: SDCoch rum j SCSchw~ind
j DPLoveless
JKMVKennedy
IDDChamberlain
jATHowe~l I I I________________
I _____________
_____________
A. _________________
I __________________
I ______________
OFFICIAL RECORD COPY T=Telephone
E=E-mail F=Fax
SUMMARY OF FINDINGS IR05000298/2004014;
02/11/04 -07/15/04;
Cooper Nuclear Station; Equipment
Alignment.
The report documents
the NRC's inspection
of the misalignment
of the service water system that existed for 21 days. The inspection
identified
one finding whose safety significance
has preliminarily
been determined
to be Greater than Green. The significance
of most findings is indicated
by their color (Green, White, Yellow, Red) using Inspection
Manual Chapter 0609,"Significance
Determination
Process." The NRC's program for overseeing
the safe operation
of commercial
nuclear power reactors is described
in NUREG-1 649, "Reactor Oversight
Process," Revision 3, dated July 2000.A. NRC-Identified
and Self-Revealing
Findings Cornerstone:
Mitigating
Systems TBD. A self-revealing
apparent violation
of 10 CFR 50, Appendix B, Criterion
V was identified
for the failure to provide adequate instructions
for restoring
the service water system to an operable configuration
following
the completion
of maintenance
activities.
This condition
existed from January 21, 2004, to February 11, 2004, and resulted in Division 2 of the service water system as well as Emergency
Diesel Generator
2 being inoperable
for 21 days.This finding is unresolved
pending completion
of a significance
determination.
The finding was greater than minor because it affected the reliability
of the service water system which is relied upon to mitigate the affects of an accident.The finding was determined
to have a potential
safety significance
greater than very low significance
because it caused an increase in the likelihood
of an initiating
event, namely, a loss of service water, as well as increasing
the probability
that the service water system would not be available
to perform its mitigating
systems function (Section 1 R04).Attachment
REPORT DETAILS 1. REACTOR SAFETY Cornerstones:
Mitigating
Systems 1 R04 Equipment
Alignment a. Inspection
Scope The inspectors
reviewed the root cause analysis and corrective
actions regarding
the failure to restore Division 2 of the service water (SW) system to normal alignment following
maintenance
on January 21, 2004.b. Findings Introduction.
A self-revealing
apparent violation
of 10 CFR 50, Appendix B, Criterion
V was identified
for the failure to provide adequate instructions
for restoring
the service water system to an operable configuration
following
the completion
of maintenance
activities
on January 21, 2004. This resulted in Division 2 of the service water system being inoperable
from January 21 through February 11, 2004.Description.
Cooper Nuclear Station is equipped with two divisions
of Service water, Division 1 and 2, each containing
two pumps. The two pumps in each division discharge
to a common header. Service water passes through a discharge
strainer and continues
to the plant. Gland water is supplied to each pump from a connection
downstream
of the discharge
strainer in the respective
divisions.
The gland water in each division supplies cooling and lubricating
water to the pump shaft bearings.
Gland water is required to support the operability
of the service water pumps. A cross-connect
line exists between the Division 1 and Division 2 gland water supplies which is only used during maintenance
activities.
By procedure, if the Division 1 and Division 2 gland water supplies are cross-connected, the division of Service water that is not supplying
its own gland water must be declared inoperable.
On February 8, control room operators
received trouble alarms on both the Division 1 and 2 service water gland water supplies.
In accordance
with the alarm response procedure, an operator was dispatched
to the service water pump room where it was determined
that the alarm was caused by low pressure on each of the gland water systems. There are no operability
limits associated
with gland water pressure, only gland water flow, which was verified to be acceptable.
The alarm cleared and no further actions were taken. The occurrence
was documented
in the corrective
action program as Notification
1029449.On February 11, an additional
trouble alarm was received on the Division 2 service water gland water supply. The gland water flow was found to be acceptable
and the alarm cleared, however, the licensee performed
the additional
action of verifying
the gland water valve lineup. As a result, operators
discovered
that the Division 2 gland water supply valve (SW-28) was shut and the cross-connect
valves (SW-1 479 & SW-1480) were open. This configuration
was not in accordance
with System Operating Attachment
-2-Procedure (SOP) 2.2.71, "Service Water System," Revision 69. In response, the licensee immediately
declared Division 2 of the service water system inoperable
and entered Technical.
Specification
3.7.2 which required operators
to restore the inoperable
division of service water to an operable status within 30 days or place the plant in a hot shutdown condition
within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. Emergency
Diesel Generator
2, Division 2 of the residual heat removal system, and Division 2 of the reactor equipment
cooling system were declared inoperable
as well since service water is required to support operability
of these systems. The licensee immediately
restored the valve lineup per SOP 2.2.71 and the affected equipment
was declared operable.The licensee documented
this valve misalignment
issue in their corrective
action program as Significant
Condition
Report 2004-0163.
The subsequent
investigation
determined
that the valve misalignment
had existed since routine preventive
maintenance
had been performed
on the Division 2 service water discharge
strainer on January 21, or approximately
21 days. Clearance
Order SWB-1-4324147
SW-STNR-B was issued in support of this maintenance
which required the strainer to be removed from service in accordance
with SOP 2.2.71. SOP 2.2.71, Section 13, "Securing
SW Zurn Strainer," directed operators
to open the gland water cross-connect
valves and shut the Division 2 supply valve (SW-28). The clearance
order was released later the same day following
completion
of the maintenance.
The instructions (release notes) on the clearance
order directed operators
to "release tags and restart [the] strainer lAW [in accordance
with SOP] 2.2.71." Operators
utilized SOP 2.2.71, Section 12, "Starting
SW Zurn Strainer," to restart the strainer.
However, Section 12 to did not contain instructions
to restore the gland water supply to its normal configuration.
Those instructions
were located in Section 10, "SW Gland Water Subsystem
B Operation" which was not referenced
by the tagout and was not used by personnel
during system restoration.
As a result, upon completion
of the activity, operators
declared DMsion 2 of service water operable unaware that the gland water systems remained cross-connected.
Analysis.
The failure to establish
appropriate
procedural
guidance for the restoration
of the Division 2 service water pump gland water supply following
maintenance
and prior to returning
the system to service was considered
to be a performance
deficiency.
This deficiency
resulted in the Division 2 service water pump gland water being provided by the Division 1 service water pumps. In this configuration, a failure of the Division 1 pumps would have resulted In loss of gland water to the Division 2 pumps, and the potential
loss of all service water. This finding affected both the Initiating
Events Cornerstone
and the Mitigating
Systems Comerstone
and was more than minor since it affected the reliability
of the service water system which provides the ultimate heat sink for the reactor during accident conditions.
The inspectors
evaluated
the issue using the SDP Phase 1 Screening
Worksheet
for the Initiating
Events, Mitigating
Systems, and Barriers Cornerstones
provided in Manual Chapter 0609, Appendix A, "Significance
Determination
of Reactor Inspection
Findings for At-Power Situations." This issue caused an increase in the likelihood
of an initiating
event, namely, a loss of.service
water, as well as increasing
the probability
that the service water system would not be available
to perform its mitigating
systems function.
Therefore, a Phase 2 analysis was Attachment
-3-performed.
Phase 2 Estimation
for Internal Events In accordance
with Manual Chapter 0609, Appendix A, Attachment
1, "User Guidance for Significance
Determination
of Reactor Inspection
Findings for At-Power Situations," the inspectors
evaluated
the subject finding using the Risk-Informed
Inspection
Notebook for Cooper Nuclear Station, Revision 1. The following
assumptions
were made:* The failure of gland water cooling to a service water pump will result in the failure of the pump to meet its risk-significant
function.a The configuration
of the service water system increased
the likelihood
that all service water would be lost.a The condition
existed for 21 days. Therefore, the exposure time window used was 3 -30 days.a The initiating
event likelihood
credit for loss of service water system was increased
from five to four by the senior reactor analyst in accordance
with Usage Rule 1.2 in Manual Chapter 0609, Appendix A, Attachment
2, "Site Specific Risk-Informed
Inspection
Notebook Usage Rules.* This change reflects the fact that the finding increased
the likelihood
of a loss of service water, a normally cross-tied
support system.The configuration
of the service water system did not increase the probability
that the system function would be lost by an order of magnitude
because both pumps in Division 1 would have to be lost before the condition
would affect Division 2. Therefore, the order of magnitude
assumption
was that the service water system would continue, to be a multi-train
system.Because both divisions
of service water continued
to run and would have been available
without an independent
loss of Division 1, this condition
decreased
the reliability
of the system, but not the function.
Therefore, sequences
with loss of the service water mitigating
function were not included in the analysis.The last two assumptions
are a deviation
from the Cooper Risk-informed
Notebook that was recommended
by the Senior Reactor Analyst. This deviation
represents
a Phase 3 analysis in accordance
with Manual Chapter 0609, Appendix A, Attachment
1, in the section entitled: "Phase 3 -Risk Significance
Estimation
Using Any Risk Basis That Departs from the Phase I or 2 Process.*Table 2 of the risk-informed
notebook requires that all initiating
event scenarios
be evaluated
when a performance
deficiency
affects the service water system. However, given the assumption
that the service water system function was not degraded, only the Attachment
-4-sequences
with the special initiator
for Loss of Service Water (TSW) and the sequences related to a Loss of NC are applicable
to this evaluation.
Using the counting rule worksheet, this finding was estimated
to be YELLOW.However, because several assumptions
made during the Phase 2 process were overly conservative, a Phase 3 evaluation
is required.Phase 3 Analysis Internal Initiating
Events Assumptions:
As stated above, the analyst modified the Phase 2 estimation
by not including
the sequences
from initiating
events other than a loss of service water. This change alone represents
a Phase 3 analysis.However, the results from the modified notebook estimation
were compared with an evaluation
developed
using a Standardized
Plant Analysis Risk (SPAR) model simulation
of the cross tied service water divisions, as well as an assessment
of the licensee's
evaluation
provided by the licensee's
probabilistic
risk assessment
staff. The SPAR runs were based on the following
analyst assumptions:
a. The Cooper SPAR model was revised to better reflect the failure logic for the service water system. This model, including
the component
test and maintenance
basic events, represents
an appropriate
tool for evaluation
of the subject finding.b. NUREG/CR-5496, "Evaluation
of Loss of Offsite Power Events at Nuclear Power Plants: 1980 -1996," contains the NRC's current best estimate of both the likelihood
of each of the loss of offsite power (LOOP) classes (i.e., plant-centered, grid related, and severe weather) and their recovery probabilities.
c. The service water pumps at Cooper will fail to run if gland water is lost for 30 minutes or more. If gland water is recovered
within 30 minutes of loss, the pumps will continue to run for their mission time, given their nominal failure rates.d. The condition
existed for 21 days from January 21 through February 11, 2004 representing
the exposure time.e. The nominal likelihood
for a loss of service water, IELCTSw), at the Cooper Nuclear Station is as stated in NUREG/CR-5750, "Rates of Initiating
Events at Nuclear Power Plants: 1987 -1995," Section 4.4.8, "Loss of Safety-Related
Cooling Water System." This reference
documents
a total loss of service water frequency
at 9.72 x 1 V" per critical year.Attachment
-5-f. The nominal likelihood
for a partial loss of service water, IEL~pTsw), at the Cooper Nuclear Station is as stated in NUREG/CR-5750, "Rates of Initiating
Events at Nuclear Power Plants: 1987 -1995," Section 4.4.8, "Loss of Safety-Related
Cooling Water System." This reference
documents
a partial loss of service water frequency (loss of single division)
at 8.92 x IV0 per critical year.g. The configuration
of the service water system increased
the likelihood
that all service water would be lost. The increase in loss of service water initiating
event likelihood
best representing
the change caused by this finding is one half the nominal likelihood
for the loss of a single division.
The analyst noted that the nominal value represents
the likelihood
that either division of service water is lost. However, for this finding, only losses of Division I equipment
result in the loss of the other division.h. The SPAR HRA method used by Idaho National Engineering
and Environmental
Laboratories
during the development
of the SPAR models and published
in Draft NUREG/CR-xxxxx, INEEL/EXT-02-10307, "SPAR-H Method," is an appropriate
tool for evaluating
the probability
of operators
recovering
from a loss of Division I service water.The probability
of operators
failing to properly diagnose the need to restore Division 2 service water gland water upon a loss of Division 1 service water is 0.4. This assumed the nominal diagnosis
failure rate of 0.01 multiplied
by the following
performance
shaping factors: 4 Available
Time: 10 The available
time was barely adequate to complete the diagnosis.
The analyst assumed that the diagnosis
portion of this condition
included all activities
to identify the mispositioned
valves. A licensee operator took 21 minutes to complete the steps. The analyst noted that this walk through was conducted
in a vacuum. During a real incident, operators
would have to prioritize
many different
Additionally, operations
personnel
had been briefed on the finding at a time prior to the walk through, so they were more knowledgeable
of the potential
problem than they would have been prior to the identification
of the finding.+ Stress: 2 Stress under the conditions
postulated
would be high. Multiple alarms would be initiated
including
a loss of the Division 1 service water and the loss of gland water to DMsion 2. Additionally, assuming that indications
of gland water failure were believed, the operators
would understand
that the consequences
of their actions would represent
a threat to plant safety.Attachment
-6-* Complexity:
2 The complexity
of the tasks necessary
to properly diagnose this condition was determined
to be moderately
complex. The analyst determined
that there was some ambiguity
in the diagnosis
of this condition.
The following
factors were considered:
,, Division 1 would be lost and may be prioritized
above Division 2.* The diagnosis
takes place at both the main control room and the auxiliary
panel in the service water structure
and requires interaction
between at least two operators.
There have previously
been alarms on gland water annunciators
when swapping Divisions.
Therefore, operators
may hesitate to take action on Division 2 given problems with Division 1.Previous small bore piping clogging events may mislead the operators
during their diagnosis.
Analysis: Initiating
Event Calc: The analyst calculated
the new initiating
event likelihood, IEL(Tsw-..), as follows: IEL(TwSWs)
= IEL(rSW) + [ 1/2 * IEL(sw)] =9.72 x 10 4+ [0.5 * 8.92 x 10 3]=5.43 x 10"/ yr -8760 hrs/yr 6.20 x 10" 7/hr.Evaluation
of Change in Risk The SPAR Revision 3.03 model was modified to include updated loss of offsite power curves as published
in NUREG CR-5496, as stated in Assumption
b. The changes to the loss of offsite power recovery actions and other modifications
to the SPAR model were documented
in Table 2. In addition, the failure logic for the service water system was significantly
changed as documented
in Assumption
a. These revisions
were incorporated
into a base case update, making the revised model the baseline for this evaluation.
The resulting
baseline core damage frequency, CDFb,,,, was 4.82 x 109 /hr.The analyst changed this modified model to reflect that the failure of the Division 1 service water system would cause the failure of the gland water to Division 2. Division 2 was then modeled to fail either from independent
divisional
equipment
failures, or from the failure of Division 1. The analyst determined
that the failure of Division 2 could be prevented
by operator recovery action. As stated in Assumption
- , the analyst Attachment
-7-assumed that this recovery action would fail 40 percent of the time. The model was requantified
with the resulting
current case conditional
core damage frequency, CDF=, of 1.74 x 108 /hr.The change in core damage frequency (ACDF) from the model was: ACDF =CDF=,=,-
CDFI,= 1.74 x 10-8 -4.82 x 10-9 = 1.26 x 108 /hr.Therefore, the total change in core damage frequency
over the exposure time that was related to this finding was calculated
as: ACDF = 1.26 x 10-8/hr * 24 hr/day * 21 days = 6.35 x 10-6 for 21 days The risk significance
of this finding is presented
in Table 3.a. The dominant cutsets from the internal risk model are shown in Table 3.b.Table 2: Baseline Revisions
to SPAR Model Basic Event Title Original Revised ACP-XHE-NOREC-30
Operator Fails to Recover AC .22 5.14 x 10.1 Power in 30 Minutes ACP-XHE-NOREC-4H
Operator Fails to Recover AC .023 6.8 x 10.2 Power in 4 Hours ACP-XHE-NOREC-90
Operator Fails to Recover AC .061 2.35 x 10.1 Power in 90 Minutes ACP-XHE-NOREC-BD
Operator Fails to Recover ACP .023 6.8 x 10.2 before Battery Depletion IE-LOOP Loss of Offsite Power Initiator
5.20 x 0-6/hr 5.32 x 10 4/hr EPS-DGN-FR-FTRE
Diesel Generator
Fails to Run -0.5 hrs. 0.5 hrs.Early Time Frame EPS-DGN-FR-FTRM
Diesel Generator
Fails to Run -2.5 hrs. 13.5 hrs.Middle Time Frame*OEP-XHE-NOREC-10H
Operator Fails to Recover AC 2.9 x 10.2 5.6 x 10.2 Power in 10 Hours OEP-XHE-NOREC-1
H Operator Fails to Recover AC 1.2 x 10.1 3.93 x 10.1 Power in 1 Hours Attachment
-8-OEP-XHE-NOREC-2H
Operator Fails to Recover AC 6.4 x 10.2 2.49 x 10-1 Power in 2 Hours OEP-XHE-NOREC-4H
Operator Fails to Recover AC 4.5 x 10.2 1.36 x 10'1 Power in 4 Hours OEP-XHE-NOREC-8H
Operator Fails to Recover AC 3.2 x 10.2 7.0 x 10.2 Power in 8 Hours* Diesel Mission Time was increased
from 2.5 to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> in accordance
with NUREG/CR-5496
Attachment
-9-Table 3.a: Evaluation
Model Results Model Result Core Damage LERF Frequency SPAR 3.03, Baseline:
Internal Risk 4.8 x 1 0 9/hr 4.4 x 10-9/hr Revised Internal Events Risk 1.7 x 10" 8/hr 1.7 x 10"8/hr TOTAL Internal Risk (ACDF) 6.4 x 10- 6.3 x 10-6 Baseline:
External Risk 7.9 x 101 1/hr 17.2 x 10" 1 1/hr External Events Risk 7.1 x 10 9/hr 16.5 x 10-9/hr TOTAL External Risk (ACDF) 3.6 x 10-6 3.2 x 10"6 TOTAL Internal and External 1.0 x 10"5 9.5 x 10-6 Change NOTE 1: The analyst assumed that the ratio of high and low pressure sequences
were the same as for internal events baseline.Table 3.b: Top Risk Cutsets Initiating
Event Sequence Sequence Importance
Number Loss of Offsite Power 39-04 EPS-VA3-AC4H
1.4 x 10-8 39-10 EPS-RCI-VA3-AC4H
7.6 x 10.10 39-14 EPS-RCI-HCI-AC30MIN
5.2 x 10-10 39-24 EPS-SRVP2
3.2 x 10-10 39-22 EPS-SRVP1-RCI-VA3-
8.4 x 10.11 AC90MIN 7 SPC-SDC-CSS-CVS
5.4 x 10-11 36 RCI-HCI-DEP
4.7 x 10-11 6 SPC-SDC-CSS-VA1
4.6 x 10.11 39-23 EPS-SRVP1-RCI-HCI
2.7 x 10.11 Transient
62 SRV-P1-PCS-MFW-CDS-
6.0 x 10.10 I LCS Attachment
-10-63-05 PCS-SRVP1-SPC-CSS-VA1
2.9 x 10`10 64-11 PCS-SRVP2-LCS-LCI
1.0 x 10.10 9 PCS-SPC-SDC-CSS-CR1-
3.7 x 10"11 VAl 63-06 PCS-SRVP1-SPC-CSS-CVS
2.9 x 10"11 63-32 PCS-SRVP1-RCI-HCI-DE2
2.6 x 10-11 Loss of Service Water System 9 PC1-SPC-SDC-CSS-CR1-
2.2 x 10-11 I I_ VA1 External Initiating
Events: In accordance
with Manual Chapter 0609, Appendix A, Attachment
1, Step 2.5,"Screening
for the Potential
Risk Contribution
Due to External Initiating
Events," the analyst assessed the impact of external initiators
because the Phase 2 SDP result provided a Risk Significance
Estimation
of 7 or greater.Seismic, High Winds, Floods, and Other External Events: The analyst determined, through plant walkdown, that the major divisional
equipment associated
with the service water system were on the same physical elevation
as its redundant
equipment
in the altemate division.
All four service water pumps are located in the same room at the same elevation.
Both primary switchgear
are at the same elevation
and in adjacent rooms. Therefore, the likelihood
that internal or external flooding and/or seismic events would affect one division without affecting
the other was considered
to be extremely
low. Likewise, high wind events and transportation
events were assumed to affect both divisions
equally.Fire: The analyst evaluated
the list of fire areas documented
in the IPEEE, and concluded that the Division 1 service water system could fail in internal fires that did not directly affect Division 2 equipment.
These fires would constitute
a change in risk associated
with the finding. As presented
in Table 4, the analyst identified
two fire areas of concern: Pump room fires and a fire in Switchgear
1 F. Given that all four service water pumps are located in one room, three different
fire sizes were evaluated, namely: one pump fires, three pump fires, and four pump fires.In the Individual
Plant Examination
for External Events Report -Cooper Nuclear Station, the licensee calculated
the risk associated
with fires in the service water pump room (Fire Area 20A). The related probabilities
for these fires were as follows: Attachment
-11-Parameter
Variable Probability
Fire Ignition Frequency
Lre 6.55 x 1 0 3/yr Conditional
Probability
of a Large Oil Spill Parge Spin 0.18 Conditional
Probability
of Fire less than 3 minutes PShor Fi, 0.10 Conditional
Probability
of Unsuccessful
Halon PHaon 0.05 Probability
of Losing One Division I Pump in a One P 1-1 0.5 Pump Fire Probability
of Losing Both Division I Pumps in a Three P 2-3 0.5 Pump Fire Probability
of Losing One Division I Pump in a Three P 1-3 0.5 Pump Fire Conditional
Probability
of Losing the Running Division I P,.un 1 0.5 Pump Given a Fire Damaging a Single Pump Failure to Run Likelihood
for a Service Water Pump LFT 3.0 x 1 0G/hr Failure to Start Probability
per Demand for a Service PM 3.0 x 10"3 Water Pump I I _I As described
in the IPEEE, the licensee determined
that there were three different potential
fire scenarios
in the service water pump room, namely: a fire damaging one pump, caused by a small oil fire, a fire that results from the spill of all the oil from a single pump that damages three pumps; and fires that affect all four pumps. The licensee had determined
that fires affecting
only two pumps were not likely. The analyst determined
that a four-pump
fire was part of the baseline risk, therefore, it would not be evaluated.
A one-pump fire would not automatically
result in a plant transient.
However, the analyst assumed that a three-pump
fire affecting
both of the Division I pumps, would result in a loss of service water system initiating
event.The IPEEE stated that a single pump would be damaged in an oil fire that resulted from a small spill of oil, Lon. Pump. The analyst, therefore, calculated
the likelihood
that a fire would damage a single pump as follows: Lone Pump = * (1 -Prge spl)= 6.55 x 10C 3/yr -8760 hrs/yr * (1 -0.18)= 6.78 x 10" 7/hr Attachment
-12-As in the IPEEE, the analyst assumed that all pumps would be damaged in an oil fire that resulted from a large spill of oil, that lasted for less than 3 minutes, if the halon system failed to actuate. It should be noted that the intensity
of an oil fire is based on the availability
of oxygen, and the fire is assumed to continue until all oil is consumed or it is extinguished.
Therefore, the shorter the duration of the fire, the higher its intensity and the more likely it is to damage equipment
in the pump room. Should the fire last for less than 3 minutes and the halon system successfully
actuate, or if the fire lasted for longer than 3 minutes, the licensee determined
that a single pump would survive the fire, LIres Pumps* The analyst, therefore, calculated
the likelihood
that a fire would damage three pumps as follows:Pumps = [L. * Purge SpE * Psh 8 rt, * (1 -PHalon)] + [LFj. * P,.Lg° spp * (1 -PShcit R)]= [6.55 x 1O 3/yr + 8760 hrs/yr * 0.18 * 0.10 * (1 -0.05)]+ [6.55 x 10 3/yr + 8760 hrs/yr * 0.18 * (1 -0.10)]= 1.34 x 10 7/hr The likelihood
of a single pump in Division 1 being damaged because of a fire, Lot, pump was calculated
as follows: LOW Pump = (LOne Pump * PI-.) + (Lree Pumps * P 1 4-)= (6.78 x 10 7/hr * 0.5) + (1.34 x 1 0" 7/hr * 0.5)= 4.06 x 10" 7/hr The analyst assumed that a fire damaged pump would remain inoperable
for the 30-day allowed-outage
time. Therefore, the probability
that the redundant
Division 1 pump would start and run for 30 days, PA Fak, was calculated
as follows: PtFas = Prs * P,-1 + L-T= (3.0 x 10-1 * 0.5) +(3.0 x 105/hr * 24 hrs/day *30 days)= 1.5 x 10" 3 + 2.16 x 10.2-2.31 x 10 2 The likelihood
of having a loss of all service water as a result of a one-pump fire, Lpump LOSWS, is then calculated
as follows: Lpump LOSWS = LDIvl Pump * P FalMs= 4.06 x 10 7/hr * 2.31 x 10.2 Attachment
-13-= 9.38 x 1 09/hr The likelihood
of both pumps in Division 1 being damaged because of a fire, LDI,, Pumps was calculated
as follows: LDWI Pumps = LThree Pumps * P2-3=1.34 x 10 7/hr * 0.5= 6.7 x 10 8/hr Given that a fire-induced
loss of both Division 1 pumps results in a loss of service water system gland water, and the assumption
was made that the gland water was unrecoverable
during large fire scenarios, LD, 1 Pumps is equal to the likelihood
of a loss of service water system initiating
event.The analyst used the revised baseline and current case SPAR models to quantify the conditional
core damage probability
for a fire that takes out both Division I pumps or one Division 1 pump with a failure of the second pump. A fire that affects both Division 1 pumps was assumed to cause an unrecoverable
loss of service water initiating
event.The baseline conditional
core damage probability
was determined
to be 1.99 x 10-8. The current case probability
was 6.63 x 10'. Therefore, the ACDP was 6.63 x 104.The analyst also assessed the affect of this finding on a postulated
fire in Switchgear
1 F. The analyst walked down the switchgear
rooms and interviewed
licensed operators.
The analyst identified
that, by procedure, a fire in Switchgear
1 F would require de-energization
of the bus and subsequent
manual scram of the plant.Additionally, the analyst noted that no automatic
fire suppression
existed in the room.Therefore, the analyst used the fire ignition frequency
stated in the IPEEE, namely 3.70 x 10 3/yr as the frequency
for loss of Switchgear
1 F and a transient.
The analyst used the revised baseline and current case SPAR models to quantify the conditional
core damage probabilities
for a fire in Switchgear
1 F. The resulting
CCDPs were 1.88 x 104 (CCDP,.,)
for the baseline and 1.70 x 10.2 (CCDPurrjnt.
The change in core damage frequency
was calculated
as follows: ACDF = L..cger * (CCDPc.,ent
-CCDPi..)= 3.70 x 10"3/yr + 8760 hrs/yr * (1.70 x 10.2 1.88 x 104)= 7.10 x 10 9/hr Table 4: Internal Fire Risk Attachment
-14-Fire Areas: Fire Type Fire Ignition ACDP ACDF Frequency Switchgear
1 F Shorts Bus 4.22 x 10 7/hr 1.68 x 10.2 7.10 x 10" 9/hr Service Water Pump One Pump 9.38 x 10"9/hr 6.63 x 104 6.22 x 10" 1/hr Roam Both Pumps 6.7 x 10 4/hr 6.63 x 104 4.44 x 10 1 1/hr Total ACDF for Fires affecting
the Service Water System: 7.14 x 10 9/hr Exposure Time (21 days): 5.04 x 10 Vhrs Extemal Events Change in Core Damage Frequency:
3.60 x 10"8 Potential
Risk Contribution
from Large Early Release Frequency (LERF): In accordance
with Manual Chapter 0609, Appendix A, Attachment
1, Step 2.6,'Screening
for the Potential
Risk Contribution
Due to LERF," the analyst assessed the impact of large early release frequency
because the Phase 2 SDP result provided a risk significance
estimation
of 7.In BWR Mark I containments, only a subset of core damage accidents
can lead to large, unmitigated
releases from containment
that have the potential
to cause prompt fatalities
prior to population
evacuation.
Core damage sequences
of particular
concern for Mark I containments
are ISLOCA, ATWS, and Small LOCA/Transient
sequences
involving
high reactor coolant system pressure.
A loss of service water is a special initiator
for a transient.
Step 2.6 of Manual Chapter 0609 requires a LERF evaluation
for all reactor types if the risk significance
estimation
is 7 or less and transient
sequences
are involved.In accordance
with Manual Chapter 0609, Appendix H, "Containment
Integrity
SDP," the analyst determined
that this was a Type A finding, because the finding affected the plant core damage frequency.
The analyst evaluated
both the baseline model and the current case model to determine
the LERF potential
sequences
and segregate
them Into the categories
provided in Appendix H, Table 5.2, "Phase 2 Assessment
Factors -Type A Findings at Full Power. These categorizations, the LERF factors, and an estimation
of the change in LERF are documented
in Table 5 of this worksheet.
Following
each model run, the analyst segregated
the core damage sequences
as follows: Loss of coolant accidents
were assumed to result in a wet drywell floor. The analyst assumed that during all station blackout initiating
events the drywell floor remained dry. The Cooper Nuclear emergency
operating
procedures
require drywell flooding if reactor vessel level can not be restored.
Therefore, the Attachment
-15-analysts assumed that containment
flooding was successful
for all high pressure transients
and those low pressure transients
that had the residual heat removal system available.
All Event V initiators
were grouped as intersystem
loss of coolant accidents (ISLOCA)Transient
Sequence 65, Loss of dc Sequence 62, Loss of service water system Sequence 71, small loss of coolant accident Sequence 41, medium loss of coolant accident Sequence 32, large loss of coolant accident Sequence 12, and LOOP Sequence 40 cutsets were copsidered
anticipated
without scram (ATWS)All LOOP Sequence 39 cutsets were considered
Station Blackouts.
Those with success of safety-relief
valves to close or a single stuck-open
relief valve were considered
high pressure sequences.
Those with more than one stuck-open
relief valve were considered
low pressure sequences.
that did not result in an ATWS were assumed to be low pressure sequences
if the cutsets included low pressure injection, core spray, or more than one stuck-open
relief valve. Otherwise, the analyst assumed that the sequences
were high pressure.Small break loss of coolant accident, Sequence 1 cutsets, that represent
stuck-open relief valves and other recoverable
incidents, were assumed to result in a dry floor. All other cutsets were assumed to provide a wetted drywell floor.The resulting
ALERF for internal events was 6.42 x 106, as documented
in Table 5.Additionally, the analyst used the Internal events LERF ratios to estimate the extemal ", events contribution
to LERF. As documented
in Table 3.a, the e xterntLevents-ALEBR
was calculated
as .2 _x I0'.L--L Attachment
-16-Table 5: Large Early Release Frequency Event Drywell Current Case Baseline LERF Factor ALERF Floor ISLOCA 4.70e-1 3 4.70e-1 3 1.0 0.00e+00 ATWS 3.26e-1 1 3.14e-1 1 0.3 3.60e-13 SBO High Wet 0.00e+00 0.00e+00 0.6 0.00e+00 Dry 1.57e-08 3.51e-09 1.0 1.22e-08 SBO Low Wet 0.00e+00 0.00e+00 0.1 0.OOe+00 Dry 3.21e-10 5.99e-11 1.0 2.61e-10 Transient
High Wet 1.00e-09 8.87e-10 0.6 6.78e-1 1 Dry 0.00e+00 0.00e+00 1.0 0.00e+00 Transient
Low Wet 1.78e-11 1.16e-11 0.1 6.20e-13 Dry 3.20e-10 3.17e-10 1.0 3.00e-12 SBLOCA Wet 1.82e-12 7.93e-13 0.6 6.16e-13 Dry 2.32e-12 1.96e-13 1.0 2.12e-12 MBLOCA Wet 1.43e-12 1.21e-12 0.1 2.17e-14 Dry 0.00e+00 0.OOe+00 1.0 0.00oe+00 LBLOCA Wet 3.74e-12 3.59e-12 0.1 1.51e-14 Dry 0.00e+00 0.00e+00 1.0 0.00e+00 Total Delta CDF per hour 1.74e-08 4.82e-09 1.26e-08 Total Delta LERF per Hour 1.70e-08 4.43e-09 1.25e-08 Exposure Time (21 days): 5.04e+02 Total ALERF 6.31 e-06 Phase 3 Conclusion
Enforcement.
10 CFR Part 50, Appendix B, Criterion
V, "Instructions, Procedures, and Drawings," states 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.Attachment
-17-Contrary to this requirement, Clearance
Order SWB-1 -4324147 SW-STNR-B
did not provide adequate instructions
to restore the service water system to an operable configuration
following
the completion
of maintenance
activities
on January 21, 2004.This resulted in Division 2 of the service water system being inoperable
from January 21 through February 11, 2004. This violation
of 10 CFR Part 50, Appendix B, Criterion
V is identified
as an Apparent Violation (AV 05000298/2004014-01)
pending determination
of the finding's
final safety significance.
4OA6 Meetings, Including
Exit On July 22, 2004, the inspectors
presented
the results of the resident inspector
activities
to J. Roberts, Director of Nuclear Safety Assurance, and other members of his staff who acknowledged
the finding.The inspectors
confirmed
that proprietary
information
was not provided by the licensee during this inspection.
ATTACHMENT:
SUPPLEMENTAL
INFORMATION
Attachment
SUPPLEMENTAL
INFORMATION
KEY POINTS OF CONTACT Licensee Personnel J. Bednar, Emergency
Preparedness
Manager C. Blair, Engineer, Licensing M. Boyce, Corrective
Action & Assessments
Manager J. Christensen, Director, Nuclear Safety Assurance S. Minahan, General Manager of Plant Operations
T. Chard, Radiological
Manager K. Chambliss, Operations
Manager K. Dalhberg, General Manager of Support J. Edom, Risk Management
R. Estrada, Performance
Analysis Department
Manager M. Faulkner, Security Manager J. Flaherty, Site Regulatory
Liaison P. Fleming, Licensing
Manager W. Macecevic, Work Control Manager D. Knox, Maintenance
Manager LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED Opened 05000298/2004014-01
AV Inadequate
instructions
for restoration
of the service water system following
maintenance (Section 1 R04)A-1 Attachment