ML042250525
| ML042250525 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 08/12/2004 |
| 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: ML042250525 (25) | |
See also: IR 05000298/2004014
Text
August 12, 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 follow up 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, such as those documented in
Section 1R04.b in the enclosed report.
This finding does not present a current safety concern because the valve lineup was restored to
the normal configuration. Also, the affected equipment was returned to an operable condition.
Nebraska Public Power District -2-
This finding is also an apparent violation of NRC requirements and is being considered for
escalated enforcement action in accordance with the General Statement of Policy and
Procedure for NRC Enforcement Actions (Enforcement Policy), NUREG-1600. The
current enforcement policy is included on the NRCs 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. We note that in a letter to the NRC dated August 9, 2004,
NPPD submitted information related to the safety significance of this issue. The NRC will
consider this information prior to making a final decision on this matter. 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 any additional 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 business 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, 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
NRCs document system (ADAMS). ADAMS is accessible from the NRC Web site at
http://www.nrc.gov/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,
/RA/
Arthur T. Howell III, Director
Division of Reactor Projects
Docket: 50-298
License: DPR-46
Nebraska Public Power District -3-
Enclosure:
NRC Inspection Report 05000298/2004014
w/attachment: Supplemental Information
cc w/enclosure:
Clay C. Warren, Vice President of
Strategic Programs
Nebraska Public Power District
1414 15th 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
Nebraska Public Power District -4-
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
Jerry C. Roberts, Director of
Nuclear Safety Assurance
Nebraska Public Power District
P.O. Box 98
Brownville, NE 68321
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
Nebraska Public Power District -5-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
DRS Director (DDC)
Senior Resident Inspector (SCS)
Branch Chief, DRP/C (KMK)
Senior Project Engineer, DRP/C (WCW)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (KEG)
RidsNrrDipmLipb
Jennifer Dixon-Herrity, OEDO RIV Coordinator (JLD)
CNS Site Secretary (SLN)
Dale Thatcher (DFT)
W. A. Maier, RSLO (WAM)
G. F. Sanborn, D:ACES (GFS)
K. D. Smith, RC (KDS1)
F. J. Congel, OE (FJC)
OE:EA File (RidsOeMailCenter)
Dave Nelson, OE (DJN)
ADAMS: W Yes * No Initials: __kmk___
W Publicly Available * Non-Publicly Available * Sensitive W Non-Sensitive
R:\_CNS\2004\CN2004-14RP-SCS.wpd
SRI:DRP/C SRA:DRS C:DRP/C D:DRS D:DRP
SCSchwind DPLoveless KMKennedy DDChamberlain ATHowell
E - KMKennedy /RA/ /RA/ /RA/ CSMarschall for
8/11/04 8/11/04 8/11/04 8/11/04 8/12/04
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket.: 50-298
License: DPR 46
Report: 05000298/2004014
Licensee: Nebraska Public Power District
Facility: Cooper Nuclear Station
Location: P.O. Box 98
Brownville, Nebraska
Dates: March 25 through July 15, 2004
Inspectors: S. Schwind, Senior Resident Inspector
S. Cochrum, Resident Inspector
D. Loveless, Senior Reactor Analyst
Approved By: A. Howell III, Director, Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR05000298/2004014; 03/25/04 - 07/15/04; Cooper Nuclear Station; Equipment Alignment.
The report documents the NRCs 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-1649, 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 Part 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
through 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.
The finding was greater than minor because it affected the reliability of the service
water system, which is relied upon to mitigate the effects of an accident. The
finding was determined to have a potential safety significance greater than very
low significance (i.e., Greater than Green) 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).
Enclosure
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
(1) Introduction. A self-revealing apparent violation of 10 CFR Part 50, Appendix B,
Criterion V, was identified for the failure to provide adequate instructions for restoring
the SW system to an operable configuration following the completion of maintenance
activities on January 21, 2004. This resulted in Division 2 of the SW system being
inoperable from January 21 through February 11, 2004.
(2) Description. Cooper Nuclear Station is equipped with two divisions of SW, Divisions 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
through the system. 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 Divisions 1 and 2 gland water supplies which is only used during
maintenance activities. By procedure, if the Divisions 1 and 2 gland water supplies are
cross-connected, the division of SW that is not supplying its own gland water must be
declared inoperable.
On February 8, control room operators received trouble alarms on both the Divisions 1
and 2 SW gland water supplies. In accordance with the alarm response procedure, an
operator was dispatched to the SW 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-1479 & SW-
1480) were open. This configuration was not in accordance with System Operating
Enclosure
-2-
Procedure (SOP) 2.2.71, Service Water System, Revision 69. In response, the
licensee immediately declared Division 2 of the SW system inoperable and entered
Technical Specification 3.7.2, which required operators to restore the inoperable division
of SW 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 SW 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 2004-0077. The subsequent investigation
determined that the valve misalignment had existed since routine preventive
maintenance had been performed on the Division 2 SW discharge strainer on
January 21, 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 IAW [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 Division 2 of
SW operable, unaware that the gland water systems remained cross-connected.
(3) Analysis. The failure to establish appropriate procedural guidance for the restoration of
the Division 2 SW 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 SW pump gland water being provided by the Division 1 SW
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 SW. This finding
affected both the Initiating Events Cornerstone and the Mitigating Systems Cornerstone
and was more than minor since it affected the reliability of the SW system, which
provides the ultimate heat sink for the reactor during accident conditions.
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
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
Enclosure
-3-
Phase 3 results as presented in Table 3.a. The total change in core damage
frequency (CDF) was estimated to be 1.0 x 10-5 and the total change in large early
release frequency (LERF) was estimated to be 9.5 x 10-6. The assumptions and
considerations used in the evaluation are presented below.
(a) 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
SW (TSW), as well as increasing the probability that the SW system would not
be available to perform its mitigating systems function. Therefore, a Phase 2
analysis was performed.
(b) 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 an SW pump will result in the failure
of the pump to meet its risk-significant function.
would be lost.
- The condition existed for 21 days. Therefore, the exposure time window
used was 3 - 30 days.
- 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 an SW gland
water trouble alarm.
- The initiating event likelihood credit for TSW 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
TSW, a normally cross-tied support system.
Enclosure
-4-
- The configuration of the SW system did not increase the probability that
the system function would be lost by an order of magnitude because both
pumps in Division I would have to be lost before the condition would
affect Division II. Therefore, the order of magnitude assumption was that
the SW system would continue to be a multitrain system.
- Because both divisions of SW 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 SW mitigating function were not included in
the analysis.
The last two assumptions are a deviation from the risk-informed
notebook. 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 SW
system. However, given the assumption that the SW system function
was not degraded, only the sequences with the special initiator for 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 SW 1 RECSW24-LI 6
Loss of SW 2 RCIC-LI 6
Loss of SW 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 either overly conservative or did not represent the
actual configuration of the system, a Phase 3 evaluation was required.
Enclosure
-5-
(c) Phase 3 Analysis
1) Internal Initiating Events
Assumptions:
The results from the risk-informed notebook estimation were compared with an
evaluation developed using a Standardized Plant Analysis Risk (SPAR) model
simulation of the cross-tied SW divisions, as well as an assessment of the
licensees evaluation provided by the licensee's probabilistic risk assessment
staff. The SPAR runs were developed on the basis of the following analyst
assumptions:
a) The Cooper SPAR model was revised to better reflect the failure logic for
the SW 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 NRCs 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 SW 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 SW, IEL(TSW), 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 SW frequency at 9.72 x 10-4 per critical year.
f) The nominal likelihood for a partial loss of SW, 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 SW frequency (loss of single division) at 8.92 x 10-3 per
critical year.
Enclosure
-6-
g) The configuration of the SW system increased the likelihood that all SW
would be lost. The increase in TSW 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 SW 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 SW.
i) The probability of operators failing to properly diagnose the need to
restore Division II SW gland water upon a loss of Division I SW 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 SW.
The analyst noted that this walkthrough did not require operators
to prioritize many different annunciators that would be evident
during the postulated plant conditions of interest. Additionally,
operations personnel had been briefed on the finding at a time
prior to the walkthrough, 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 SW
and the loss of gland water to Division II. Additionally, the
operators would understand that the consequences of their
actions would represent a threat to plant safety.
- Complexity: 2
The complexity of the tasks necessary to properly diagnose this
condition was determined to be moderately complex. The analyst
Enclosure
-7-
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 II.
- The diagnosis takes place at both the main control room and
the auxiliary panel in the SW 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.
2) Initiating Event Calculation: The analyst used Assumptions e, f, and g calculated
the new initiating event likelihood, IEL(TSW-case), as follows:
IEL(TSW-case) = IEL(TSW) + [ 1/2 * IEL(PTSW) ] =
9.72 x 10-4 + [ 0.5 * 8.92 x 10-3 ] =
5.43 x 10-3/ yr ÷ 8760 hrs/yr
6.20 x 10-7/hr.
3) Evaluation of Change in Risk: Using Assumptions a) and b), the analyst
modified Revision 3.03 of the SPAR model to include updated LOOP curves as
published in NUREG CR-5496. The changes to the LOOP 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 SW
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 CDF, CDFbase, was
4.82 x 10-9 /hr.
The analyst changed this modified model to reflect that the failure of the
Division I SW system would cause the failure of the gland water to Division II.
Division II was then modeled to fail either from independent divisional equipment
failures or from the failure of Division I. The analyst determined that the failure
of Division II could be prevented by operator recovery action. As stated in
Enclosure
-8-
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 CDF, CDFcase, of 1.74 x 10-8 /hr.
The change in CDF from the model was:
CDF = CDFcase - CDFbase
= 1.74 x 10-8 - 4.82 x 10-9 = 1.26 x 10-8 /hr.
Therefore, the total CDF from internal initiators over the exposure time that was
related to this finding was calculated as:
CDF = 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 Power .22 5.14 x 10-1
in 30 Minutes
ACP-XHE-NOREC-4H Operator Fails to Recover ac Power .023 6.8 x 10-2
in 4 Hours
ACP-XHE-NOREC-90 Operator Fails to Recover ac Power .061 2.35 x 10-1
in 90 Minutes
ACP-XHE-NOREC-BD Operator Fails to Recover ac Power .023 6.8 x 10-2
before Battery Depletion
IE-LOOP Loss of Offsite Power Initiator 5.20 x 10-6/hr 5.32 x 10-6/hr
EPS-DGN-FR-FTRE Diesel Generator Fails to Run - Early 0.5 hrs. 0.5 hrs.
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 Power 2.9 x 10-2 5.6 x 10-2
in 10 Hours
OEP-XHE-NOREC-1H Operator Fails to Recover ac Power 1.2 x 10-1 3.93 x 10-1
in 1 Hour
Enclosure
-9-
(continued)
Basic Event Title Original Revised
OEP-XHE-NOREC-2H Operator Fails to Recover ac Power 6.4 x 10-2 2.49 x 10-1
in 2 Hours
OEP-XHE-NOREC-4H Operator Fails to Recover ac Power 4.5 x 10-2 1.36 x 10-1
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 /> to account for the increased time expected
to recover offsite power derived from data analysis published in NUREG/CR-5496.
Table 3.a: Phase 3 Analysis Results
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 10-8/hr
TOTAL Internal Risk ( CDF) 6.4 x 10-6 6.3 x 10-6
Baseline: External Risk 7.9 x 10-11/hr 1
7.2 x 10-11/hr
External Events Risk 7.1 x 10-9/hr 1
6.5 x 10-9/hr
TOTAL External Risk ( CDF) 3.6 x 10-6 3.2 x 10-6
TOTAL Internal and External Change 1.0 x 10-5 9.5 x 10-6
NOTE 1: To simplify the data analysis, the analyst assumed that the ratio of high and low pressure
sequences were the same as for internal events baseline. This has been accepted practice for
achieving a reasonable approximation for LERF.
Table 3.b: Top Risk Cutsets
Initiating Event Sequence Number Sequence Importance
LOOP 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-AC90MIN 8.4 x 10-11
Enclosure
-10-
(continued)
Initiating Event Sequence Number Sequence Importance
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-LCS 6.0 x 10-10
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-VA1 3.7 x 10-11
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 SW System 9 PC1-SPC-SDC-CSS-CR1-VA1 2.2 x 10-11
2) 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.
a) Seismic, High Winds, Floods, and Other External Events:
The analyst determined, through plant walkdown, that the major divisional
equipment associated with the SW system were on the same physical
elevation as its redundant equipment in the alternate division. All four
SW 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.
Enclosure
-11-
b) Fire:
The analyst evaluated the list of fire areas documented in the licensees
fire plan and concluded that the Division I SW 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 SW 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 SW pump room (Fire Area 20A). The related probabilities for
these fires were as follows:
Table 4.a: Internal Fire Probabilities
Parameter Variable Probability
Fire Ignition Frequency LFire 6.55 x 10-3/yr
Conditional Probability of a Large Oil Spill PLarge Spill 0.18
Conditional Probability of Fire less than 3 minutes PShort Fire 0.10
Conditional Probability of Unsuccessful Halon PHalon 0.05
Probability of Losing One Division I Pump in a One Pump Fire P1-1 0.5
Probability of Losing Both Division I Pumps in a Three Pump Fire P2-3 0.5
Probability of Losing One Division I Pump in a Three Pump Fire P1-3 0.5
Conditional Probability of Losing the Running Division I Pump Prun-1 0.5
Given a Fire Damaging a Single Pump
Failure to Run Likelihood for a SW Pump LFTR 3.0 x 10-5/hr
Failure to Start Probability per Demand for an SW Pump PFTS 3.0 x 10-3
As described in the IPEEE, the licensee determined that there were three
different potential fire scenarios in the SW pump room, namely: a fire
damaging one pump, caused by a small oil-spill fire limited to a 2-quart
spill from the lower bearing reservoir associated with that pump; a fire
that results from the spill of all the oil from a single pump (28 quarts),
spreading rapidly, and damaging three pumps; and fires that affect all
four pumps. The licensee had determined that fires affecting only two
Enclosure
-12-
pumps were not likely, because of the nature of oil spills and spreading
calculations. 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 TSW system initiating event.
The IPEEE stated that a single pump would be damaged in an oil fire that
resulted from a small spill of oil, LOne Pump. The analyst, therefore,
calculated the likelihood that a fire would damage a single pump as
follows:
LOne Pump = LFire * (1 - PLarge Spill)
= 6.55 x 10-3/yr ÷ 8760 hrs/yr * (1 - 0.18)
= 6.78 x 10-7/hr
As in the IPEEE, the analyst assumed that all pumps would be damaged
in an oil fire that resulted from a large spill of oil, that lasted for less than
3 minutes, if the Halon system failed to actuate. The intensity of an oil
fire is dependent on the availability of oxygen, and the fire is assumed to
continue until all oil is consumed or 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 actuates, or if the fire lasts
longer than 3 minutes, the licensee determined that a single pump would
survive the fire, LThree Pumps. The analyst, therefore, calculated the
likelihood that a fire would damage three pumps as follows:
LThree Pumps = [LFire * PLarge Spill * PShort Fire * (1 - PHalon)] + [LFire * PLarge Spill * (1 -
PShort Fire)]
= [6.55 x 10-3/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, LDiv1 Pump was calculated as follows:
LDiv1 Pump = (LOne Pump * P1-1) + (LThree Pumps * P1-3)
= (6.78 x 10-7/hr * 0.5) + (1.34 x 10-7/hr * 0.5)
= 4.06 x 10-7/hr
Enclosure
-13-
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, PAlt Fails, was
calculated as follows:
PAlt Fails = PFTS * Prun-1 + LFTR
= (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 SW as a result of a one-pump fire,
Lpump LOSWS, is then calculated as follows:
Lpump LOSWS = LDiv1 Pump * PAlt Fails
= 4.06 x 10-7/hr * 2.31 x 10-2
= 9.38 x 10-9/hr
The likelihood of both pumps in Division 1 being damaged because of a
fire (LDiv1 Pumps) was calculated as follows:
LDiv1 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 TSW
system gland water and the assumption was made that the gland water
was unrecoverable during large fire scenarios, LDiv1 Pumps is equal to the
likelihood of a TSW system initiating event.
The analyst used the revised baseline and current case SPAR models to
quantify the conditional core damage probability (CCDP) 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 TSW initiating event. The baseline CCDP
was determined to be 1.99 x 10-8. The current case probability was 6.63
x 10-4. Therefore, the CDP was 6.63 x 10-4.
The analyst also assessed the effect of this finding on a postulated fire in
Switchgear 1F. The analyst walked down the switchgear rooms and
Enclosure
-14-
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 10-3/yr (Lswitchgear), as the frequency for loss of Switchgear 1F and a
The analyst used the revised baseline and current case SPAR models to
quantify the CCDPs for a fire in Switchgear 1F. The resulting CCDPs
were 1.88 x 10-4 (CCDPbase) for the baseline and 1.70 x 10-2 (CCDPcurrent)
for the current case. The change in CDF was calculated as follows:
CDF = Lswitchgear * (CCDPcurrent - CCDPbase)
= 3.70 x 10-3/yr ÷ 8760 hrs/yr * (1.70 x 10-2 - 1.88 x 10-4)
= 7.10 x 10-9/hr
Table 4.b: Internal Fire Risk
Fire Areas: Fire Type Fire Ignition CDP CDF
Frequency
Switchgear 1F Shorts Bus 4.22 x 10-7/hr 1.68 x 10-2 7.10 x 10-9/hr
Service Water Pump Room One Pump 9.38 x 10-9/hr 6.63 x 10-4 6.22 x 10-12/hr
Both Pumps 6.7 x 10-8/hr 6.63 x 10-4 4.44 x 10-11/hr
Total CDF 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 CDF: 3.60 x 10-6
3) Potential Risk Contribution from 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
significance determination process result provided a risk significance estimation
of 7.
Enclosure
-15-
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 (ISLOCAs), 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 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 CDF. 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. The primary distinctions in
categories are based on the initiator type, the pressure of the reactor coolant
system at the time of core damage, and whether the drywell floor has been
flooded, either by the event or by operator action. The type of event is indicative
of the mode of core damage and the available systems, the coolant system
pressure indicates whether the core will melt through or be ejected from the
vessel, and in a Mark I containment, the steel line is significantly more
susceptible to melt through if there is no water on the drywell floor. The
categories, the total CDF related to each of 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 Station emergency
operating procedures require drywell flooding if reactor vessel level
cannot be restored. Therefore, the analysts assumed that containment
flooding was successful for all high pressure transients and those low
pressure transients that had the residual heat removal system available.
- All individual intersystem loss of coolant accident initiators designated in
the SPAR model were grouped in the ISLOCA category.
- Transient Sequence 65, Loss of dc Sequence 62, TSW system
Sequence 71, small loss of coolant accident Sequence 41, medium loss
Enclosure
-16-
of coolant accident Sequence 32, large loss of coolant accident
Sequence 12, and LOOP Sequence 40 cutsets were considered ATWS
sequences.
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 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 LERF for internal events was 6.31 x 10-6, 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 LERF was calculated as 3.2 x 10-6. This resulted in a total
LERF for the finding of 9.5 x 10-6.
Table 5: Large Early Release Frequency
Event Drywell Floor Current Case Baseline LERF Factor LERF
ISLOCA 4.70e-13 4.70e-13 1.0 0.00e+00
ATWS 3.26e-11 3.14e-11 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 0.00e+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-11
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
Enclosure
-17-
(continued)
Event Drywell Floor Current Case Baseline LERF Factor LERF
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 0.00e+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 CDF per hour 1.74e-08 4.82e-09 1.26e-08
Total LERF per Hour 1.70e-08 4.43e-09 1.25e-08
Exposure Time (21 days) 5.04e+02
Total LERF 6.31e-06
(d) Licensees 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 licensees
result for internal risk was a CDF of 3.85 x 10-7. The analyst reviewed the
licensees assumptions and determined that the following differences dominated
the difference between the licensees and the analysts assessments (presented
in order of risk significance):
- As stated in Assumption i) in the above analysis, the analyst used a value
of 0.4 for the probability that operators would fail to realign gland water
prior to failure of the Division II pumps. This value was derived using the
INEELs SPAR-H method. The licensee used a Human Error Probability
of 9.2 x 10-2, derived using an Electric Power Research Institute
calculator.
The analyst determined that this assumption was responsible for about
30 percent of the difference in the final results.
- The licensees model uses a LOOP frequency of 1.74 x 10-8/hr as
opposed to the analysts use of the NUREG/CR-5496 value of
5.32 x 10-6/hr.
The analyst determined that this assumption was responsible for the vast
majority of the difference in the final results. The analyst noted that the
Enclosure
-18-
majority of risk was from core damage sequences that were initiated by a
LOOP.
Additionally, the following differences between the licensees 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 licensees model uses Cooper Nuclear Station
specific historical probabilities that are lower.
- The analyst utilized functional impact frequency values from
NUREG/CR-5750, Table D-11, for the likelihood of full and partial TSW
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 1800EF.
- 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.
while the licensee used their plant-specific probabilistic risk assessment
model.
- The analyst used Inspection Manual Chapter 0609, Appendix H
methodology to estimate the LERF. The licensee utilized their plant
specific Level 2 model to identify the LERF multipliers used.
(e) 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 licensees value for LOOP
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.
Enclosure
-19-
Table 6: Sensitivity Studies
Parameter Initial Value New Value New Result
IE-LOOP 1.74 x 10-8/hr 5.32 x 10-6/hr 1.8 x 10-7
Adjusted IE-LOSWS 6.2 x 10-7/hr 6.2 x 10-8/hr 6.4 x 10-6
Gland Recovery 0.4 0.1 2.0 x 10-6
(4) 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 SW system to an operable configuration
following the completion of maintenance activities on January 21, 2004. This resulted in
Division 2 of the SW 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 findings
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
Enclosure
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 SW system
following maintenance (Section 1R04)
A-1 Attachment