ML061870254
| ML061870254 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/31/2004 |
| From: | Howell A NRC/RGN-IV/DRP |
| To: | Edington R Nebraska Public Power District (NPPD) |
| References | |
| EA-04-131, FOIA/PA-2006-0007 IR-04-014 | |
| Download: ML061870254 (25) | |
See also: IR 05000298/2004014
Text
5
REQ1,
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UNITED STATES Dr 4A
I.? NUCLEAR REGULATORY COMMISSION C
REGION IV I V
611 RYAN PLAZA DRIVE, SUITE 400 " ) m I T
. -
4, 4LN
ARLINGTON, TEXAS 760114005
August XX, 2004
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 1R04 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
kIMOWnty infts recd was cdetw
in=t %h*~ekdfm~
4 -bo,
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.qov/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.gov/reading-rmladams.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 Ill, 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 15d 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 (KMIK)
Senior Project Engineer, DRP/C (WCW)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (KEG)
Dan Merzke, Pilot Plant Program (DXM2)
RidsNrrDlpmLIpb
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:\_CNS\2004\CN2004-14RP-SCS.wpd
SDCochrurn SCSchwind DPLoveless KMKennedy DDChamberlain ATHowell
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 1R04).
Attachment
REPORT DETAILS
1. REACTOR SAFETY
Cornerstones: Mitigating Systems
1R04 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.
Descridption. 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
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
Zum 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 Division 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.
.1 Significance Determination
The analysts reviewed the performance deficiency to determine the appropriate risk
characterization. In summary, the performance deficiency was determined to be a
finding that was more than minor and required a Phase 2 estimation. The Phase 2
Attachment
process estimated the color of the finding as YELLOW and finding specific data
indicated the necessity for a Phase 3 evaluation. The analyst developed the preliminary
Phase 3 results as presented in Table 3.a. The total change in core damage frequency
was estimated to be 1.0 x 10s and the total change in large early release frequency was
estimated to be 9.5 x 10-6. The assumptions and considerations used in the evaluation
are presented below.
Phase 1 Screening Logic, Results and Assumptions
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 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:
a 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 No credit for recovery was given since there was insufficient time to implement
recovery actions and there was no procedural guidance requiring operators to
verify the valve lineup upon receipt of a service water gland water trouble alarm.
- 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 Inspection Manual Chapter 0609, Appendix A, Attachment 2,
"Site Specific Risk-Informed Inspection Notebook Usage Rules." This change
reflects the fact that the finding increased the likelihood of a loss of service
water, a normally cross-tied support system.
The configuration of the service water system did not increase the probability
that the system function would be lost by an order of magnitude because both
pumps in Division I would have to be lost before the condition would affect
4
Division II. Therefore, the order of magnitude assumption was that the service
water system would continue to be a multi-train system.
Because both divisions of service water continued to run and would have been
available without an independent loss of Division I, this condition decreased the
reliability of the system, but not the function. Therefore, sequences with loss of
the service water mitigating function were not included in the analysis.
The last two assumptions are a deviation from the risk-informed notebook that was
recommended by the Senior Reactor Analyst. This deviation represents a Phase 3
analysis in accordance with Inspection Manual Chapter 0609, Appendix A, Attachment
1, in the section entitled: "Phase 3 - Risk Significance Estimation Using Any Risk Basis
That Departs from the Phase 1 or 2 Process."
Table 2 of the risk-informed notebook requires that all initiating event scenarios be
evaluated when a performance deficiency affects the service water system. However,
given the assumption that the service water system function was not degraded, only the
sequences with the special initiator for Loss of Service Water (TSW) and the sequences
related to a Loss of A/C are applicable to this evaluation. The sequences from the
notebook are presented in Table 1, as follows:
Table 1: Phase 2 Sequences
Initiating Event Sequence Mitigating Results
Functions
Loss of Service Water 1 RECSW24-LI 6
Loss of Service Water 2 RCIC-LI 6
Loss of Service Water 3 RCIC-HPCI 6
Loss of Critical 4160V Bus F 1 NONE 6
Loss of Critical 4160V Bus F 2 HPI 8
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 and/or did not represent the actual configuration of the system, a Phase 3
evaluation Is required.
Phase 3 Analysis
Internal Initiating Events
Assumptions:
The results from the risk-informed notebook estimation were compared with an
5
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 25 through February 11, 2004
representing the exposure time.
e. The nominal likelihood for a loss of service water, IEL(rsIw. 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 10- per critical year.
f. The nominal likelihood for a partial loss of service water, IELPMsW), at the Cooper
Nuclear Station is as stated in NUREG/CR-5750, "Rates of Initiating Events at
Nuclear Power Plants: 1987 - 1995," Section 4.4.8, "Loss of Safety-Related
Cooling Water System." This reference documents a partial loss of service
water frequency (loss of single division) at 8.92 x 10-3 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-H method used by Idaho National Engineering and Environmental
Laboratories (INEEL) 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.
6
i. The probability of operators failing to properly diagnose the need to restore
Division II service water gland water upon a loss of Division I service water is 0.4.
This assumed the nominal diagnosis failure rate of 0.01 multiplied by the
following performance shaping factors:
- Available Time: 10
The available time was barely adequate to complete the diagnosis. The
analyst assumed that the diagnosis portion of this condition included all
activities to identify the mispositioned valves. A licensee operator took 21
minutes to complete the steps during a simulation of the operator
response to a failure of Division I service water. The analyst noted that
this walk through did not require operators to prioritize many different
annunciators. Additionally, operations personnel had been briefed on the
finding at a time prior to the walk through, so they were more
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 I service water and the
loss of gland water to Division I1. Additionally, the operators would
understand that the consequences of their actions would represent a
threat to plant safety.
0 Complexity: 2
The complexity of the tasks necessary to properly diagnose this condition
was determined to be moderately complex. The analyst determined that
all indications for proper diagnosis would be available; however, there
was some ambiguity in the diagnosis of this condition. The following
factors were considered:
- Division I would be lost and may be prioritized above Division I1.
- 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 II given problems with Division I.
- Previous heat exchanger clogging events may mislead the
operators during their diagnosis.
Initiating Event Calculation: The analyst used Assumptions e, f, and g, calculated the
new initiating event likelihood, IELTrsw.,), as follows:
IELUrSW-cSB) =' IELYsw) + [ %* IEL(pTsW)]
7
9.72 x 104 + [ 0.5 * 8.92 x 103] =
5.43 x 10-3/ yr - 8760 hrs/yr
6.20 x 10"7/hr.
Evaluation of Change in Risk: Using Assumptions a and b, the analyst modified
Revision 3.03 of the SPAR model to include updated loss of offsite power curves as
published in NUREG CR-5496. The changes to the loss of offsite power recovery
actions, change in diesel generator mission time 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 modified SPAR model the
baseline for this evaluation. The resulting baseline core damage frequency, CDFbs,,
was 4.82 x 10" /hr.
The analyst changed this modified model to reflect that the failure of the Division I
service water system would cause the failure of the gland water to Division I1. Division II
was then modeled to fail either from independent divisional equipment failures, or from
the failure of Division I. The analyst determined that the failure of Division II could be
prevented by operator recovery action. As stated in Assumption i, the analyst assumed
that this recovery action would fail 40 percent of the time. The model was requantified
with the resulting current case conditional core damage frequency, CDFC,, of 1.74 x 10
8 /hr.
The change in core damage frequency (ACDF) from the model was:
ACDF CDFr - CDFb...
= 1.74x10"-4.82x10 9 = 1.26x 104 /hr.
Therefore, the total ACDF from internal initiators 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" 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 .22 5.14 x 10-
Recover AC Power in 30
Minutes
8
ACP-XHE-NOREC-4H Operator Fails to .023 6.8 x 10-2
Recover AC Power in 4
Hours
ACP-XHE-NOREC-90 Operator Fails to .061 2.35 x 101
Recover AC Power in 90
Minutes
Operator Fails to .023 6.8 x 10'2
ACP-XHE-NOREC-BD
Recover ACP before
Battery Depletion
IE-LOOP Loss of Offsite Power 5.20 x 10O/hr 5.32 x 10"i/hr
Initiator
EPS-DGN-FR-FTRE Diesel Generator Fails to 0.5 hrs. 0.5 hrs.
Run - Early Time Frame
EPS-DGN-FR-FTRM Diesel Generator Fails to 2.5 hrs. 13.5 hrs.
Run - Middle Time
Frame*
OEP-XHE-NOREC- Operator Fails to 2.9 x 10-2 5.6 x 10'2
10H Recover AC Power in 10
Hours
OEP-XHE-NOREC-1 H Operator Fails to 1.2 x 10-1 3.93 x 10"!
Recover AC Power in 1
Hours
OEP-XHE-NOREC-2H Operator Fails to 6.4 x 10-2 2.49 x 10a
Recover AC Power in 2
Hours
OEP-XHE-NOREC-4H Operator Fails to 4.5 x 10-2 1.36 x 10-'
Recover AC Power in 4
Hours
- Diesel Mission Time was increased from 2.5 to 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br /> in accordance with
9
Table 3.a: Phase 3 Analysis Results
Model Result Core Damage LERF
Frequency
SPAR 3.03, Baseline: Internal Risk 4.8 x 10-9/hr 4.4 x 10 9/hr
Revised Internal Events Risk 1.7 x 10 8/hr 1.7 x 108/hr
TOTAL Internal Risk (ACDF) 6.4 x 10- 6.3 x 10-6
Baseline: External Risk 7.9 x 10 11/hr 17.2 x 10-11/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"6 9.5 x 10.6
Change I I
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: ToD 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
163-05 PCS-SRVP1 -SPC-CSS-VA1 2.9 x 10-10
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__ I_VAl I _I
External Initiatina Events:
In accordance with Manual Chapter 0609, Appendix A, Attachment 1, Step 2.5,
- Screening for the Potential Risk Contribution Due to External Initiating Events,* the
analyst assessed the impact of external initiators because the Phase 2 SDP result
provided a Risk Significance Estimation of 7 or greater.
Seismic. High Winds, Floods, and Other External Events:
The analyst determined, through plant walkdown, that the major divisional equipment
associated with the service water system were on the same physical elevation as its
redundant equipment In the alternate division. All four service water pumps are located
in the same room at the same elevation. Both primary switchgear are at the same
elevation and in adjacent rooms. Therefore, the likelihood that internal or external
flooding and/or seismic events would affect one division without affecting the other was
considered to be extremely low. Likewise, high wind events and transportation events
were assumed to affect both divisions equally.
Fire:
The analyst evaluated the list of fire areas documented in the licensee's fire plan, and
concluded that the Division I service water system could fail in internal fires that did not
directly affect Division II equipment. These fires would constitute a change In risk
associated with the finding. As presented in Table 4, the analyst identified two fire areas
of concern: Pump room fires and a fire in Switchgear 1F. Given that all four service
water pumps are located in one room, three different fire sizes were evaluated, namely:
one pump fires, three pump fires, and four pump fires.
In the Individual Plant Examination for External Events Report - Cooper Nuclear Station
(IPEEE), 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:
Table 4.a: Internal Fire Probabilities
Parameter IVariable I Probability
11
Fire Ignition Frequency L.- 6.55 x 103 /yr
Conditional Probability of a Large Oil Spill Puro spl 0.18
Conditional Probability of Fire less than PShort Fka 0.10
3 minutes
Conditional Probability of Unsuccessful Halon PHab 0.05
Probability of Losing One Division I Pump in a P1.1 0.5
One Pump Fire
Probability of Losing Both Division I Pumps in a P2-3 0.5
Three Pump Fire
Probability of Losing One Division I Pump in a P1-. 0.5
Three Pump Fire
Conditional Probability of Losing the Running P.n 1 0.5
Division I Pump Given a Fire Damaging a
Single Pump
Failure to Run Likelihood for a Service Water L,* 3.0 x 10-"/hr
Pump
Failure to Start Probability per Demand for a PrFS 3.0 x 10-3
Service Water Pump
As described in the IPEEE, the licensee determined that there were three different
potential fire scenarios in the service water pump room, namely: a fire damaging one
pump, caused by a small oil fire, a fire that results from the spill of all the oil from a
single pump that damages three pumps; and fires that affect all four pumps. The
licensee had determined that fires affecting only two pumps were not likely. The analyst
determined that a four-pump fire was part of the baseline risk, therefore, it would not be
evaluated. A one-pump fire would not automatically result In a plant transient.
However, the analyst assumed that a three-pump fire affecting both of the Division I
pumps, would result in a loss of service water system initiating event.
The IPEEE stated that a single pump would be damaged in an oil fire that resulted from
a small spill of oil, L" pmp. The analyst, therefore, calculated the likelihood that a fire
would damage a single pump as follows:
Lone Pump "= L-Fi- * (1 - PL.aM spl)
= 6.55 x 10"3/yr - 8760 hrs/yr * (1 - 0.18)
= 6.78 x 10-/hr
As in the IPEEE, the analyst assumed that all pumps would be damaged in an oil fire
that resulted from a large spill of oil, that lasted for less than 3 minutes, if the Halon
12
system failed to actuate. It should be noted that the intensity of an oil fire is based on
the availability of oxygen, and the fire is assumed to continue until all oil is consumed or
it is extinguished. Therefore, the shorter the duration of the fire, the higher its intensity
and the more likely it is to damage equipment in the pump room. Should the fire last for
less than 3 minutes and the Halon system successfully actuate, or if the fire lasted for
longer than 3 minutes, the licensee determined that a single pump would survive the
fire, LThree Pumps* The analyst, therefore, calculated the likelihood that a fire would
damage three pumps as follows:
LThme Pumps = [LF. *"PLrgo SpiO " PS)o, Fir * (1 - Pi*1.i)] + [LFJ * PLargo SpM * (1 - PShot R)]
= [6.55 x l0O3/yr + 8760 hrs/yr * 0.18 " 0.10 * (1 - 0.05)]
+ [6.55 x 103/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, LDW, Pump
was calculated as follows:
LDIvl Pump = (Lone Pump * P1 -1 ) + (LThnis Pumps * Pl 3 )
= (6.78 x 10"7/hr * 0.5) + (1.34 x 10"7/hr * 0.5)
= 4.06 x 10"7/hr
The analyst assumed that a fire damaged pump would remain inoperable for the 30-day
allowed-outage time. Therefore, the probability that the redundant Division I pump
would start and run for 30 days, PA Fph, was calculated as follows:
PMt pak = PFrs * Pru,-i + LFT
= (3.0 x 10'3 * 0.5) + (3.0 x 10 5/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 * PAf eals
= 4.06 x 10 7/hr * 2.31 x 10.2
= 9.38 x 10 9/hr
The likelihood of both pumps in Division 1 being damaged because of a fire, L.D,1 Pump,
was calculated as follows:
13
~
LD 1 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 I pumps results in a loss of service water
system gland water, and the assumption was made that the gland water was
unrecoverable during large fire scenarios, LD 0 , Pumps is equal to the likelihood of a loss of
service water system initiating event.
The analyst used the revised baseline and current case SPAR models to quantify the
conditional core damage probability for a fire that takes out both Division I pumps or one
Division I pump with a failure of the second pump. A fire that affects both Division I
pumps was assumed to cause an unrecoverable loss of service water initiating event.
The baseline conditional core damage probability was determined to be 1.99 x 10". The
current case probability was 6.63 x 10-4. Therefore, the ACDP was 6.63 x 10-.
The analyst also assessed the affect of this finding on a postulated fire in
Switchgear 1F. The analyst walked down the switchgear rooms and interviewed
licensed operators. The analyst identified that, by procedure, a fire in Switchgear 1F
would require deenergization of the bus and subsequent manual scram of the plant.
Additionally, the analyst noted that no automatic fire suppression existed in the room.
Therefore, the analyst used the fire ignition frequency stated in the IPEEE, namely
3.70 x 10 /yr (Lsw*hea,), 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 (CCDPcjrrnt). The change in
core damage frequency was calculated as follows:
ACDF = Lwfthg.r * (CCDP,,n, - CCDPbsO)
= 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.b: Internal Fire Risk
Fire Areas: Fire Type Fire Ignition ACDP ACDF
Frequency
Switchgear Shorts Bus 4.22 x 10-7/hr 1.68 x 10.2 7.10 x 10O/hr
IF I I I I
14
Service One Pump 9.38 x 10 9/hr 6.63 x 104 6.22 x 10' 2/hr
Water
Pump Both Pumps 6.7 x 108/hr 6.63 x 104 4.44 x 1011/hr
Room
Total ACDF for Fires affecting the Service Water System: 7.14 x 10 9/hr
Exposure Time (21 days): 5.04 x 102 hrs
External Events Change in Core Damage Frequency: 3.60 x 106
Potential Risk Contribution from Larue Early Release Frequency (LERFR:
In accordance with Manual Chapter 0609, Appendix A, Attachment 1, Step 2.6,
- Screening for the Potential Risk Contribution Due to LERF,n 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 intersystem loss of coolant accidents (ISLOCA), anticipated transients
without scram (ATWS), station blackouts (SBO) and small-break loss of coolant
accident (SBLOCA)/Transient sequences involving high reactor coolant system
pressure. A loss of service water (TSW) 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
analysts assumed that containment flooding was successful for all high pressure
transients and those 1ow pressure transients that had the residual heat removal
system available.
6 All Event V initiators were grouped as ISLOCA
15
Transient Sequence 65, Loss of dc Sequence 62, Loss of service water system
Sequence 71, small loss of coolant accident Sequence 41, medium loss of
coolant accident Sequence 32, large loss of coolant accident Sequence 12, and
LOOP Sequence 40 cutsets were considered ATWS sequences
All loss of offsite power (LOOP) Sequence 39 cutsets were considered SBOs.
Those with success of safety-relief valves to close or a single stuck-open relief
valve were considered high pressure sequences. Those with more than one
stuck-open relief valve were considered low pressure sequences.
Transients that did not result in an ATWS were assumed to be low pressure
sequences if the cutsets Included low pressure injection, core spray, or more
than one stuck-open relief valve. Otherwise, the analyst assumed that the
sequences were high pressure.
SBLOCA Sequence I ciitsets, 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 external
events contribution to LERF. As documented in Table 3.a, the external events ALER
was _calculated as .. A....
Table 5: Large Early Release Frequency
Event Drywell Current Baseline LERF ALERF
Floor Case Factor
ISLOCA 4.70e-13 4.70e-1 3 1.0 0.O0e+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
.7.
Dry 1.57e-08 3.51e-09 1.0 1.22e-08
SBO Low Wet 0.00e+00 0.00e+00 0.1 0.00e+00
Dry 3.21e-10 5.99e-11 1.0 2.61 e-1 0
Transient High Wet 1.00e-09 8.87e-1 0 0.6 6.78e-1 1
Dry 0.00e+00 0.00e+00 1.0 0.00e+00
Transient Low Wet 1.78e-1 1 1.1 6e-1 1 0.1 6.20e-1 3
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
16
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 0.00e+00 1.0 0.00e+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-"8 4.43e-09 1.25e-08
Exposure Time (21 days): 5.04e+02
Total ALERF 6.31 e-06
Licensee's Risk Assessment:
The licensee performed an assessment of the risk from this finding as documented in
Engineering Study PSA-ES062, "Risk Significance of SCR 2004-0077, Service Water
Gland Water Valve Mis-positioning Event." The licensee's result for internal risk was a
ACDF of 3.85 x 1V. The analyst reviewed the licensee's assumptions and determined
that the following differences dominated the difference between the licensee's and the
analyst's assessments (presented in order of risk significance):
The analyst used a failure probability of 0.4, derived from the INEEL's SPAR-H
method. The licensee used a Human Error Probability of 9.2 x 10.2 for the
probability that operators would fail to realign gland water prior to failure of the
Division II pumps.
The analyst determined that this assumption was responsible for about 30% of the
difference in the final results.
The licensee's model uses a Loss of Offsite power frequency of 1.74 x 10"/hr as
opposed the analyst's use of the NUREG/CR-5496 value of 5.32 x 10"/hr.
The analyst determined that this assumption was responsible for the vast majority of the
difference in the final results. The analyst noted that the majority of risk was from core
damage sequences that were initiated by a loss of offsite power.
Additionally, the following differences between the licensee's and the analysts
evaluations were identified:
The analyst utilized generic industry probabilities for emergency diesel generator
failures to start, failures to run, and the emergency diesel generator availability.
The licensee's model uses Cooper Nuclear Station specific historical probabilities
that are lower.
- The analyst utilized functional impact frequency values from NUREG/CR-5750,
17
Table D-1 1, for the likelihood of full and partial loss of service water events. The
licensee used significantly lower values derived from a plant specific system
model that was dominated by common cause failure of the pumps.
The analyst used the SPAR assumptions that core damage would occur if the
batteries depleted following an SBO. The licensee used the MAPP code to
determine the point in time that the fuel was assumed to reach a temperature of
18000 Fahrenheit.
The analyst assumed that all fires in Switchgear 1F would result in an
unrecoverable deenergization of the switchgear. The licensee stated that certain
fire scenarios would be recoverable.
The analyst used the SPAR model as modified to calculate the ACDF, while the
licensee used their plant-specific probabilistic risk assessment model.
The analyst used Inspection Manual Chapter 0609, Appendix H methodology to
estimate the ALERF. The licensee utilized their plant specific Level 2 model to
identify the LERF multipliers used.
Sensitivity Studies:
The analyst performed sensitivity studies on several major assumptions using the
internal events SPAR model. Table 6 summarizes the assumptions and the results.
The analyst determined that using the licensee's value for loss of offsite power
frequency would change the characterization of this finding significantly. However, the
agency has determined that the values In NUREG/CR-5496 are the best available data.
Additionally, large changes to the recovery of gland water value could impact the
characterization of this finding.
Table 6: Sensitivity Studies
Parameter Initial Value New Value New Result
IE-LOOP 1.74 x 10"1/hr 5.32 x 10"/hr 1.8 x 10-7
Adjusted IE-LOSWS 6.2 x 10"7/hr 6.2 x 10/hr 6.4 x 10-6
Gland Recovery 0.4 0.1 2.0 x 10-e
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.
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.
18
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.
40A6 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
1
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 1R04)
A-1