ML040280110
| ML040280110 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 01/27/2004 |
| From: | Kennedy K NRC/RGN-IV/DRP/RPB-C |
| To: | Edington R Nebraska Public Power District (NPPD) |
| References | |
| IR-03-007 | |
| Download: ML040280110 (28) | |
See also: IR 05000298/2003007
Text
January 27, 2004
Randall K. Edington, Vice
President-Nuclear and CNO
Nebraska Public Power District
P.O. Box 98
Brownville, Nebraska 68321
SUBJECT: COOPER NUCLEAR STATION - NRC INTEGRATED INSPECTION
REPORT 50-298/03-07
Dear Mr. Edington:
On December 31, 2003, the U. S. Nuclear Regulatory Commission (NRC) completed an
inspection at your Cooper Nuclear Station. The enclosed integrated inspection report
documents the inspection findings which were discussed on January 8, 2004, with
Mr. S. Minahan, Acting Site Vice President, and other members of your staff.
This inspection examined activities conducted under your license as they relate to safety and
compliance with the Commissions rules and regulations and with the conditions of your license.
The inspectors reviewed selected procedures and records, observed activities, and interviewed
personnel.
Based on the results of this inspection, the NRC identified five findings that were evaluated
under the risk significance determination process as having very low safety significance
(Green). The NRC also determined that there were three violations associated with these
findings. These violations are being treated as noncited violations (NCVs), consistent with
Section VI.A of the Enforcement Policy. These NCVs are described in the subject inspection
report. If you contest the violation or significance of these NCVs, you should provide a
response within 30 days of the date of this inspection report, with the basis for your denial, to
the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC
20555-0001, with copies to the Regional Administrator, U.S. Nuclear Regulatory Commission,
Region IV, 611 Ryan Plaza Drive, Suite 400, Arlington, Texas 76011-4005; the Director, Office
of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the
NRC Resident Inspector at the Cooper Nuclear Station facility.
In accordance with 10 CFR 2.790 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).
Nebraska Public Power District -2-
Should you have any questions concerning this inspection, we will be pleased to discuss them
with you.
Sincerely,
/RA/
Kriss M. Kennedy, Chief
Project Branch C
Division of Reactor Projects
Docket: 50-298
License: DPR-46
Enclosure:
NRC Inspection Report 05000298/2003007
w/attachment: Supplemental Information
cc w/enclosure:
Randall K. Edington, Vice President-Nuclear
Nebraska Public Power District
P.O. Box 98
Brownville, Nebraska 68321
John R. McPhail, General Counsel
Nebraska Public Power District
P.O. Box 499
Columbus, Nebraska 68602-0499
P. V. Fleming, Licensing and
Regulatory Affairs Manager
Nebraska Public Power District
P.O. Box 98
Brownville, Nebraska 68321
Michael J. Linder, Director
Nebraska Department of
Environmental Quality
P.O. Box 98922
Lincoln, Nebraska 68509-8922
Chairman
Nemaha County Board of Commissioners
Nemaha County Courthouse
1824 N Street
Auburn, Nebraska 68305
Nebraska Public Power District -3-
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, Nebraska 68509-5007
Ronald A. Kucera, Deputy Director
for Public Policy
Department of Natural Resources
205 Jefferson Street
Jefferson City, Missouri 65101
Jerry Uhlmann, Director
State Emergency Management Agency
P.O. Box 116
Jefferson City, Missouri 65101
Chief, Radiation and Asbestos
Control Section
Kansas Department of Health
and Environment
Bureau of Air and Radiation
1000 SW Jackson, Suite 310
Topeka, Kansas 66612-1366
Daniel K. McGhee
Bureau of Radiological Health
Iowa Department of Public Health
401 SW 7th Street, Suite D
Des Moines, Iowa 50309
William J. Fehrman, President
and Chief Executive Officer
Nebraska Public Power District
1414 15th Street
Columbus, Nebraska 68601
Chief Technological Services Branch
National Preparedness Division
Department of Homeland Security
Emergency Preparedness & Response Directorate
FEMA Region VII
2323 Grand Blvd., Suite 900
Kansas City, Missouri 64108-2670
Nebraska Public Power District -4-
Electronic distribution by RIV:
Regional Administrator (BSM1)
DRP Director (ATH)
Acting 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 (NBH)
Jim Isom, Pilot Plant Program (JAI)
RidsNrrDipmLipb
Anne Boland, OEDO RIV Coordinator (ATB)
CNS Site Secretary (SLN)
Dale Thatcher (DFT)
W. A. Maier, RSLO (WAM)
R:\_CNS\2003\CN2003-07RP-SCS.wpd
RIV:RI:DRP/C SRI:DRP/C C:DRS/PSB C:DRS/OB C:DRP/C
SDCochrum SCSchwind TWPruett ATGody KMKennedy
E - KMKennedy E - KMKennedy MPShnnon for GWJohnston for /RA/
1/27/04 1/27/04 1/21/04 1/21/04 1/27/04
OFFICIAL RECORD COPY T=Telephone E=E-mail F=Fax
ENCLOSURE
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Docket.: 50-298
License: DPR 46
Report No.: 05000298/2003007
Licensee: Nebraska Public Power District
Facility: Cooper Nuclear Station
Location: P.O. Box 98
Brownville, Nebraska
Dates: September 28 through December 31, 2003
Inspectors: S. Schwind, Senior Resident Inspector
S. Cochrum, Resident Inspector
P. Elkmann, Emergency Preparedness Inspector
P. Gage, Senior Operations Engineer
Approved By: K. Kennedy, Chief, Project Branch C, Division of Reactor Projects
Enclosure
SUMMARY OF FINDINGS
IR05000298/2003007; 09/28/03 - 12/31/03; Cooper Nuclear Station: Personnel Performance
During Nonroutine Evolutions, Operability Evaluations, Postmaintenance Testing, Refueling and
Outage Activities, Identification and Resolution of Problems.
The report covered a 3-month period of inspection by resident inspectors and announced
inspections by a Region IV emergency preparedness inspector and a senior operations
engineer. Three Green noncited violations and two Green findings were identified. 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: Initiating Events
- Green. A noncited violation of Technical Specification 5.4.1(a) was identified for a
failure to establish an adequate system operating procedure for the turbine oil
purification and transfer system during main turbine lube oil reservoir vapor extractor
maintenance. This caused an oil leak resulting in a fire.
This finding was greater than minor since inadequate system operating procedures
could be reasonably viewed a precursor to a significant event and, if left
uncorrected, could become a more significant safety concern. The finding was
determined have a very low safety significance (Green), since it did not affect the fire
mitigation defense in depth elements in Figure 4-1 of Inspection Manual 0609,
Significance Determination Process, Appendix F. In addition, it had crosscutting
aspects associated with problem identification and resolution, since a number of
opportunities were missed to identify the procedure error and prevent the
subsequent fire (Section 1R14).
- Green. The failure to correctly rack in a breaker and to establish an adequate
postmaintenance test following corrective maintenance on Station Air Compressor B
was determined to be a self-revealing finding. The air compressor was rendered
inoperable following maintenance as a result of its breaker not being fully racked in,
and this condition was not discovered for 35 days.
This finding was more than minor since it was associated with the increased
likelihood of a loss of instrument air, which is an initiating event, but was determined
to have very low safety significance (Green), since it did not increase the likelihood
of a LOCA, did not contribute to both the likelihood of a reactor trip and the likelihood
that mitigation equipment or functions would not be available, and did not increase
the likelihood of a fire or internal flooding. In addition, this finding had crosscutting
aspects associated with human performance because personnel failed to specify a
postmaintenance test per station procedures and incorrectly racked in the breaker
(Section 1R19).
Enclosure
-2-
- Green. A self-revealing finding was identified associated with the failure to evaluate
and take corrective actions for a fire on the Booneville 345 kV transmission line in
1997. This led to a similar fire on a transmission tower between the main
transformers and the main generator disconnect switches which induced a plant
transient in October 2003.
This finding was more than minor since it induced a plant transient. Given the
configuration of the switchyard, the fire did not pose a challenge to offsite power. It
was determined to have a very low safety significance (Green) since it did not affect
the fire mitigation defense in depth elements in Figure 4-1 of Inspection
Manual 0609, Significance Determination Process, Appendix F. In addition, it had
crosscutting aspects associated with problem identification and resolution since the
October 2003 fire and transient could have been avoided had the 1997 fire been
more thoroughly evaluated (Section 4AO2).
Cornerstone: Mitigating Systems
- Green. A noncited violation of 10 CFR Part 50, Appendix B, Criterion XVI, was
identified regarding the failure to take adequate corrective actions for degraded
conditions on the diesel fuel oil transfer system. In February 2003, corrosion
products from the fuel oil storage tank clogged the fuel oil strainer supplying
Emergency Diesel Generator 1. Corrective actions for that event failed to preclude
recurrence of the condition in November 2003.
This finding was more than minor since it was associated with the operability,
availability, and reliability of a mitigating system but was of very low safety
significance (Green), since it did not represent the actual loss of a safety function.
In addition, it had crosscutting aspects associated with problem identification and
resolution since the corrective action only addressed symptoms of the problem and
not the root cause, which was corrosion of the fuel oil storage tank (Section 1R15).
Cornerstone: Barrier Integrity
- Green. A noncited violation of Technical Specification 5.4.1(a) was identified
regarding the failure to establish an adequate procedure for operation of the residual
heat removal system. Within the guidance of the existing procedure, operators
inadvertently established a flow path between the reactor vessel and the condensate
storage tank which resulted in draining 300 gallons of reactor coolant to the
condensate storage tank.
This finding was more than minor, since it was associated with the cornerstone
attribute of procedure quality, but was determined to have very low safety
significance (Green), since the draindown was small and decay heat removal
capabilities were not challenged (Section 1R20).
Enclosure
-3-
B. Licensee-Identified Violation
A violation of very low safety significance, which was identified by the licensee, was
reviewed by the inspectors. Corrective actions taken or planned by the licensee have
been entered into the licensees corrective action program. This violation and corrective
action tracking numbers are listed in Section 4OA7 of this report.
Enclosure
REPORT DETAILS
The plant was operating at full power at the beginning of this inspection period. On
September 28, reactor power was reduced to approximately 25 percent as required by
Technical Specifications (TS) due to failure of a turbine trip device during testing. Full power
operations were resumed on October 1. On October 16, reactor power was reduced to
approximately 65 percent in response to a fire reported underneath a main turbine bearing. Full
power operations were resumed on October 17 following completion of firefighting activities and
a damage assessment. On October 28 the reactor was manually scrammed due to a fire
reported on a tower adjacent to the 345 kV switchyard. Full power operations resumed on
November 3 following completion of repairs. One November 28 the reactor automatically
scrammed on low reactor pressure vessel (RPV) level due to an unexpected decrease in
reactor feed pump speed. Full power operation resumed on December 13 following
troubleshooting on the reactor feed pump.
1. REACTOR SAFETY
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency
Preparedness
1R01 Adverse Weather Protection
a. Inspection Scope
The inspectors selected four samples representing the review of preparations/protection
for cold weather conditions on two risk significant systems. The four samples included:
- A review of maintenance work orders completed in order to prepare the systems
for possible freezing temperatures
- A review of deficiency tags and condition reports associated with heat tracing
and other cold weather protection measures to determine their impact on the
systems
- A walkdown of the 250 vdc station batteries to determine if room temperatures
were being maintained above 70EF
- A walkdown of the environmental controls in the intake structure to verify that the
licensee had completed the required actions identified in the work orders
The two systems chosen for this inspection included:
- Portions of the 250 vdc system including the 250 vdc station batteries.
- The intake structure, including the sluice gates on the ice control tunnel, the ice
deflector, and environmental controls in the service water pump room
Enclosure
-2-
b. Findings
No findings of significance were identified.
1R04 Equipment Alignment
a. Inspection Scope
Partial Equipment Alignment Inspections
The inspectors performed one partial equipment alignment inspection. The walkdown
verified that the critical portions of the selected systems were correctly aligned per the
system operating procedures (SOPs). The following system was included in the scope
of this inspection:
- Emergency Diesel Generator (EDG) 1 while EDG 2 was inoperable for planned
maintenance on October 27. The walkdown included portions of the system in the
diesel building, the Division I critical switchgear room, and the control room.
Complete Equipment Alignment Inspections
On October 24, the inspectors performed one complete system alignment inspection of
the standby liquid control (SLC) system. The inspectors verified that the system was in
the appropriate configuration per the SOP and that it was installed and capable of
performing its design functions as described in the Updated Final Safety Analysis
Report (USAR). A review of maintenance work orders and corrective actions
documents for the past 12 months was also performed. A walkdown of the system was
performed to assess material condition such as system leaks and housekeeping issues
that could adversely affect system operability.
b. Findings
No findings of significance were identified.
1R11 Licensed Operator Requalification
a. Inspection Scope
The inspector conducted an in-office review of the annual operating examination test
results for 2002. Since this was the first half of the biennial requalification testing cycle,
the licensee had not yet administered the written examination. These results were
assessed to determine if they were consistent with NUREG 1021 guidance and Manual
Chapter 0609, Appendix I, Operator Requalification Human Performance Significance
Determination Process, requirements. This review included examination test results for
7 crews, which included 42 licensed individuals.
Enclosure
-3-
b. Findings
No findings of significance were identified.
1R12 Maintenance Rule Implementation
a. Inspection Scope
The inspectors reviewed two equipment performance issues to assess the licensees
implementation of their maintenance rule program. The inspectors verified that
components that experienced performance problems were properly included in the
scope of the licensees maintenance rule program, and the appropriate performance
criteria were established. Maintenance rule implementation was determined to be
adequate if it met the requirements outlined in 10 CFR 50.65 and Administrative
Procedure 0.27, Maintenance Rule Program, Revision 15. The inspectors reviewed
the following equipment performance problems:
- Failure of Steam Tunnel Fan Cooling Unit CNS-9-HV-FCU-FC-R-1KA on October 17
(Notification 10276549)
- Failure of Supply Fan HV-DG-1D to automatically start during testing of EDG 2 on
October 29 (Notification 10278560)
b. Findings
No findings of significance were identified.
1R13 Maintenance Risk Assessments and Emergent Work Evaluation
a. Inspection Scope
The inspectors reviewed four risk assessments for planned or emergent maintenance
activities to determine if the licensee met the requirements of 10 CFR 50.65(a)(4) for
assessing and managing any increase in risk from these activities. Evaluations for the
following maintenance activities were included in the scope of this inspection:
- Emergency Station Service Transformer outage due to maintenance on the 69 kV
transmission line by Omaha Public Power District on October 15
- EDG 2 outage for planned maintenance on October 29 (Work Order 4248388)
- EDG 2 fuel oil strainer planned maintenance on November 24 (Work
Order 4346703)
Enclosure
-4-
- Station Service Air Compressor (SAC) B 480 V breaker found not fully racked in,
which rendered the compressor inoperable from November 10 through December 15
(Notification 10285815)
b. Findings
No findings of significance were identified.
1R14 Personnel Performance During Nonroutine Evolutions
a. Inspection Scope
For the nonroutine events described below, the inspectors reviewed operator logs, plant
computer data, and strip charts to determine what occurred, how the operators
responded, and if the response was in accordance with plant procedures:
- On October 16, the inspectors responded to the control room shortly after a fire was
reported in the turbine building. The inspectors observed and evaluated the actions
by the control room, actions required by procedures, and monitoring of plant
conditions during this event.
- On October 28, the inspectors responded to the control room shortly after operators
manually scrammed the reactor in response to a fire on a transmission tower
between the main transformers and the main generator disconnect switches. The
inspectors observed and evaluated the followup actions by the operators, action
required by procedures, and monitoring of plant conditions during this event. This
event is discussed in Sections 4OA2 and 4OA7 of this report.
b. Findings
Fire in Turbine Building
Introduction. A Green noncited violation (NCV) of TS 5.4.1(a) was identified for a failure
to establish an adequate SOP for the turbine oil purification and transfer system during
main turbine lube oil reservoir vapor extractor maintenance, which caused an oil leak
resulting in a fire.
Description. On October 16 at 12:19 p.m., a station operator discovered a small fire
located beneath Main Turbine Bearing 1. The operator had been sent inside the main
turbine shield wall to evaluate earlier reports of smoke observed by a remote camera in
the turbine building. Control room operators immediately entered Emergency Procedure
5.4FIRE, General Fire Procedure, Revision 5. The fire brigade responded, but their
initial attempts to extinguish the fire with portable CO2 and dry chemical extinguishers
were unsuccessful. At 12:30 p.m., a Notice of Unusual Event was declared, since the
duration of the fire had exceeded 10 minutes. The fire was extinguished using water
and foam at 1:36 p.m. No offsite assistance was requested. Due to elevated dose
Enclosure
-5-
rates in the fire affected area and the extended time required to fight the fire, reactor
power was reduced to 65 percent to maintain the fire brigades dose as low as is
reasonably achievable. Damage was limited to discoloration of piping underneath the
affected area. There were no injuries and the Notice of Unusual Event was terminated at
3:41 p.m. after the licensee determined that the fire was completely extinguished and
there was no risk of re-ignition.
The licensee determined that the fire was caused by an oil leak from the seals of the
Main Turbine 1 bearing, which came into contact with hot piping in the area. Securing
both turbine lube oil vapor extractors allowed oil to leak out of the journal bearing seals.
The vapor extractors are designed to maintain a slightly negative pressure on the
turbine bearing oil return system, which prevents oil from leaking out of the bearing
seals. Both vapor extractors were secured for planned maintenance per SOP 2.2.81,
Turbine Oil Purification and Transfer System, Revision 29, and were out of service for
approximately 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. They had been restored to service 45 minutes prior to the fire.
Multiple reports were made to the control room of an oil mist on the turbine deck prior to
restoring the vapor extractors to service.
In 1986, a design modification added a redundant vapor extractor as recommended by
Westinghouse Bulletin 8504. This bulletin also recommended that the main turbine be
shutdown if both vapor extractors were out of service. The Westinghouse vendor
manual recommended limiting the time both vapor extractors are out of service to the
time necessary to transfer operation from one to the other. The recommendations of
the bulletin were translated into Design Change 86-84, Installation of Redundant Vapor
Extractor, which stated that a failure of the vapor extractors would require shutdown of
the turbine generator;, however, SOP 2.2.81 was changed in July 2002 to allow
operation of the main turbine with both vapor extractors secured. This condition was
allowed for an unspecified period of time.
Analysis. This finding had crosscutting aspects associated with problem identification
and resolution. This assessment was based on industry operating experience that was
provided to the work planner and discussed at the plan-of-the-day meeting on
October 15, indicating that fire events had occurred at other nuclear power stations
when both lube oil vapor extractors were secured during turbine operation. Also, there
were several opportunities to address the oil leak prior to the fire based on multiple
reports made to the control room of an oil mist on the turbine deck. This assessment
was also based on the licensees root cause investigation, which determined that a
number of opportunities were missed to identify the error in SOP 2.2.81 during the
procedure change review.
This finding was more than minor, since it affected the Initiating Events Cornerstone, the
inadequate SOPs could be reasonably viewed as a precursor to a significant event and,
if left uncorrected, it could become a more significant safety concern. Inspection
Manual Chapter 0609, Significance Determination Process, Appendix F, was used to
assess the safety significance of this finding. Phase 1 of the significance determination
Enclosure
-6-
process (SDP) concluded that the finding was of very low safety significance (Green),
since it did not affect the fire mitigation defense in depth elements in Figure 4-1.
Enforcement. TS 5.4.1(a) requires that licensees establish, implement, and maintain
written procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Appendix A recommends operating procedures for the turbine-
generator system. Contrary to the above, adequate operating procedures were not
established for the turbine-generator system, since the licensees procedures for the
operation of the lube oil vapor extractors did not minimize the time that both vapor
extractors could be secured and allowed turbine-generator operation with both vapor
extractors secured for an unspecified period of time. This finding is being treated as an
NCV (50-298/0307-01) consistent with Section VI.A of the NRC Enforcement Policy.
The licensee entered this issue into their corrective action program (CAP) as significant
condition report (SCR) 2003-1808. Procedure 2.2.81 was revised to correct the
procedural inadequacy.
1R15 Operability Evaluations
a. Inspection Scope
The inspectors reviewed four operability determinations regarding mitigating system
capabilities to ensure that the licensee properly justified operability and that the
component or system remained available so that no unrecognized increase in risk
occurred. These reviews considered the technical adequacy of the licensees evaluation
and verified that the licensee considered other degraded conditions and their impact on
compensatory measures for the condition being evaluated. The inspectors referenced
the USAR, TS, and the associated system design criteria documents to determine if
operability was justified. The inspectors reviewed the following equipment conditions
and associated operability evaluations:
- Inservice Test (IST) failure of Diesel Fuel Oil Transfer Pump A due to debris buildup
on the inlet strainer for Fuel Oil Day Tank 2 (Notification 10279881)
- Missed surveillance test on SLC pump discharge relief valves (Notification
10277107)
- Inadvertent removal of riprap during dredging operations adjacent to the intake
structure (Notification 10280113)
- Failure of the main turbine mechanical trip device on high reactor vessel level during
testing (Notification 10272894)
b. Findings
Introduction: A Green NCV was identified regarding the failure to take adequate
corrective actions for degraded conditions on the diesel fuel oil transfer system.
Enclosure
-7-
Description: On November 5, Fuel Oil Transfer Pump A failed to develop the required
flowrate during Surveillance Procedure 6.1DG.401, Diesel Generator Fuel Oil Transfer
Pump IST Flow Test (Div 1), Revision 13. Troubleshooting indicated that the fuel oil
strainer on the inlet float valve for Fuel Oil Day Tank 1 had accumulated sufficient
corrosion product debris from the fuel stream as to restrict flow. The licensee cleaned
the strainer, and the transfer pump subsequently passed the surveillance test. In
addition, an operability determination was performed which concluded that the corrosion
products were being transported from the fuel oil storage tank, which was a slow
process that could be managed through the preventive maintenance (PM) program.
The operability determination also stated that, if the strainer became clogged during
diesel operation, there would be a sufficient volume of fuel in the day tank to allow for
cleaning or replacement of the strainer without interruption of engine operation.
The diesel fuel oil system at Cooper Nuclear Station consists of two underground
storage tanks, two transfer pumps, and a day tank for each EDG. Each transfer pump
takes a suction approximately 3 inches from the bottom of its respective storage tank,
and the pump discharge headers are normally cross-connected. Although either
transfer pump can supply fuel to either day tank, a single transfer pump does not have
sufficient capacity to supply fuel to two fully loaded EDGs. Therefore, each transfer
pump is required to support operability of its respective EDG.
A similar event occurred in February 2003, when Fuel Oil Transfer Pump A failed a
surveillance test due to corrosion products in the strainer. The licensees response to
that event was similar; the strainer was cleaned and an operability determination was
performed which concluded that the debris buildup could be managed by the PM
program. The PM to clean and inspect the strainer was increased from a 72-week
frequency to a 24-week frequency and the contents of both fuel oil storage tanks were
filtered in May 2003 in an attempt to reduce the amount of sediment in the tanks. Based
on trend data from past engine runs and the current condition of the fuel oil storage
tanks, the licensee concluded that the fuel strainer would become blocked by debris
after approximately 30 to 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br /> of run time. The 24-week PM frequency was
considered adequate to prevent this. At the time of the failure in November, EDG 1 had
approximately 40 hours4.62963e-4 days <br />0.0111 hours <br />6.613757e-5 weeks <br />1.522e-5 months <br /> of run time and the strainer clogged prior to the end of the
24-week maintenance interval.
Analysis: This finding had crosscutting aspects associated with problem identification
and resolution. This assessment was based on the fact that the licensee had performed
an analysis that indicated the failure would repeat itself at approximately 30 to 35 hours4.050926e-4 days <br />0.00972 hours <br />5.787037e-5 weeks <br />1.33175e-5 months <br />
of engine run time, yet the corrective action for the February 2003 failure was to change
the PM frequency based on calendar time rather than engine run time. In addition, the
corrective actions primarily dealt with the symptoms caused by increased fuel storage
tank corrosion, not the root causes. This approach also created an operator
workaround, since manual action would be required to maintain an EDG operable during
its 7-day mission time.
Enclosure
-8-
This finding affected the Mitigating Systems Cornerstone and was considered more than
minor, since it was associated with the operability, availability, and reliability of a
mitigating system. Based on the results of an SDP Phase 1 evaluation, this finding was
determined to have very low safety significance, since it did not represent the actual loss
of a safety function.
Enforcement: Appendix B, Criterion XVI, of 10 CFR Part 50 states that measures shall
be established to assure that conditions adverse to quality are promptly identified and
corrected. In the case of significant conditions adverse to quality, the measures shall
assure that the cause of the condition is determined and corrective actions taken to
preclude repetition. Failure of Fuel Oil Transfer Pump A was considered a significant
condition adverse to quality, since it adversely impacted the ability of a risk significant
safety system to perform as designed. Corrective actions for the transfer pump failure
in February 2003 failed to preclude an additional failure in November 2003. This
violation of 10 CFR Part 50, Appendix B, Criterion XVI, is being treated as an NCV,
consistent with Section VI.A of the NRC Enforcement Policy (50-298/0307-02). The
licensee entered this issue into their CAP as SCR 2003-1876.
1R16 Operator Workarounds
a. Inspection Scope
The inspectors reviewed eight operator workaround items to evaluate their cumulative
affect on mitigating systems and the operators ability to implement abnormal or
emergency procedures. In addition, open operability determinations and selected
condition reports were reviewed and operators were interviewed to determine if there
were additional degraded or nonconforming conditions that could complicate the
operation of plant equipment.
b. Findings
No findings of significance were identified.
1R19 Postmaintenance Testing
a. Inspection Scope
The inspectors reviewed or observed seven selected postmaintenance tests to verify
that the procedures adequately tested the safety function(s) that were affected by
maintenance activities on the associated systems. The inspectors also verified that the
acceptance criteria were consistent with information in the applicable licensing basis and
design basis documents and that the procedures were properly reviewed and approved.
Postmaintenance tests for the following maintenance activities were included in the
scope of this inspection:
Enclosure
-9-
- Replacement of scram solenoid pilot valves from September 12 to October 28 (Work
Order 432210)
- EDG 2 piston replacement on October 29 (Work Order 4248388)
- Leak repair on moisture separator for Station Air Compressor (SAC) B on
November 10 (Work Order 4338511)
- Cleaning and inspection of Diesel Fuel Oil Strainer DGDO-STRN-FLTV11 on
November 24 (Work Order 4343940)
- Control panel switch replacement for Reactor Coolant Sample Valve RR-AOV-
741AV on December 11 (Work Order 4172876)
- Cleaning and inspection of Service Water Strainer A on December 16 (Work
Order 4323349)
- Control board replacement in 250 vDC Battery Charger A on December 17 (Work
Order 4314331)
b. Findings
Introduction: A Green finding was identified regarding the failure to correctly rack in a
breaker and to specify an adequate postmaintenance test following corrective
maintenance on SAC B.
Details: On November 10, SAC B was removed from service to repair a leak on the
moisture separator. The tagging order specified that the breaker for the compressor
(EE-CB-480G) be racked to the test position and specified the restoration configuration
as racked in. The corrective maintenance on the moisture separator was completed,
the tags were cleared, and the system was restored to a standby configuration. Work
Order 4338511 did not specify any postmaintenance test following this job.
SAC B remained in standby until December 15 when operators attempted to start it as
part of their normal equipment rotation routine. The compressor failed to start and,
upon further investigation, it was determined that Breaker EE-CB-480G was not fully
racked in. Once the breaker had been fully racked in, operators were successful in
starting SAC B.
Analysis: This finding had crosscutting aspects associated with human performance.
This assessment was based on the fact that personnel failed to follow station
procedures regarding work planning and control. Administrative Procedure 0.40, "Work
Control Program," Revision 39, Section 6.7.1, requires that postmaintenance testing be
specified to demonstrate satisfactory completion of work and verify that no new
deficiencies have been created. This was not done. In addition, station personnel failed
to correctly restore the breaker for SAC B following maintenance.
Enclosure
-10-
This finding affected the Initiating Events Cornerstone and was considered more than
minor, since it was associated with the increased likelihood of a loss of instrument air,
which is an initiating event. Based on the results of an SDP Phase 1 evaluation, this
finding was determined to have very low safety significance, since it did not increase the
likelihood of a LOCA, a fire, or internal flooding and did not contribute to either the
likelihood of a reactor trip or that mitigation equipment or functions would not be
available.
Enforcement: Although SAC B is a risk significant component, it is not considered
safety related. Therefore, no violation of NRC requirements was identified. The
licensee entered this issue into their CAP as Notification 10285815.
1R20 Refueling and Outage Activities
a. Inspection Scope
The inspectors observed outage-related activities during Forced Outage 03-05.
Activities included the scram recovery actions following a manual reactor scram on
October 28, plant cooldown, placing the residual heat removal (RHR) system in the
shutdown cooling mode of operation, and startup activities.
b. Findings
Introduction: An inadequate procedure, which led to an RPV draindown event while
placing RHR in shutdown cooling, was considered to be a self-revealing, Green NCV.
Description: On October 29, operators were in the process of flushing Division 1 of the
RHR system in preparation for placing it in shutdown cooling. During the flushing and
venting process, SOP 2.2.69.2, RHR System Shutdown Operations, Revision 42,
directed operators to open the RHR shutdown cooling condensate supply valves, RHR-
96 and RHR-97, and then to open the inboard and outboard shutdown cooling isolation
valves, RHR-MO-17 and RHR-MO-18. This established a drain path from the RPV to
the condensate system and, subsequently, to the condensate storage tank (CST).
Control room operators noted that RPV level decreased by 1.5 inches during this
evolution and that RHR-96 and RHR-97 were hot, which indicated they were passing
reactor coolant. At this point, the drain path was isolated. It was estimated that 300
gallons were inadvertently transferred from the reactor coolant system to the CST at a
flow rate of approximately 60 gallons per minute.
Analysis: This finding affected the Barrier Integrity Cornerstone since it represented the
unintentional bypass of two fission product barriers (reactor coolant system and
containment system) and was more than minor, since it was associated with the
cornerstone attribute of procedure quality. This finding degraded the safety of a
shutdown reactor; therefore, MC 0609, Appendix G, "Shutdown Operations Significance
Determination Process," was used to assess its signficance. A quantitative assessment
was not performed since an RPV level change of 1.5 inches does not represent a loss of
Enclosure
-11-
control. Pages T-14 through T-16 of Appendix G were used to assess the significance
since the reactor was in hot shutdown, time to boil was less than 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, and initial
conditions for RHR operations had been met. The guidelines for core heat removal,
inventory control, and power availability were met. In addition, the containment
guidelines were met, since the automatic containment isolation function for RHR on low
RPV level (7.81 inches on the wide-range instrument) was operable. Although this
finding did increase the likelihood of a loss of reactor coolant inventory, a Phase 2
analysis was unnecessary because level instrumentation was unaffected and this was
not considered rapid loss of inventory. Based on these results, this finding was
determined to have very low safety significance.
Enforcement: TS 5.4.1(a) requires written procedures to be established, implemented,
and maintained as recommended by Regulatory Guide 1.33, Revision 2, Appendix A,
February 1978. Appendix A recommends operating procedures for the shutdown
cooling system. SOP 2.2.69.2, RHR System Shutdown Operations, Revision 42, did
not meet this requirement in that it directed operators to align the system in a manner
which established a drain path from the RPV to the CST. This violation is being treated
as an NCV (50-298/0307-03) consistent with Section VI.A of the NRC Enforcement
Policy. The licensee entered these issues into their CAP as Notifications 10249930 and
10249920.
1R22 Surveillance Testing
a. Inspection Scope
The inspectors observed or reviewed the following three surveillance tests to ensure that
the systems were capable of performing their safety function and to assess their
operational readiness. Specifically, the inspectors verified that the following surveillance
tests met TS requirements, the USAR, and licensee procedural requirements:
- 15.TG.302, Main Turbine Trip Functional Test, Revision 5, performed on
September 29
- 6.2ADS.303, ADS [alternate depressurization system] Logic System Functional
Test (Div 2), Revision 7, performed on October 17
- SLC pump discharge relief valve testing under Work Orders 4285654 and 4338440.
b. Findings
No findings of significance were identified.
Enclosure
-12-
1R23 Temporary Plant Modifications
a. Inspection Scope
The inspectors reviewed Temporary Configuration Change 4347948, dated
December 2, 2003, which installed temporary diagnostic equipment in the controller
cabinet for Reactor Feed Pump B and installed an additional supervisory alarm for the
feed pump turbine in the control room. The inspectors verified that the change did not
require NRC approval prior to implementation and that adequate controls on the
installation existed.
b. Findings
No findings of significance were identified.
1EP4 Emergency Action Level and Emergency Plan Changes
a. Inspection Scope
The inspector performed an in-office review of Revision 44 to the Cooper Nuclear
Station Emergency Plan, submitted September 17, 2003. This revision:
- Clarified responsibility for on-shift dose assessment
- Revised documentation requirements for Letters of Agreement
- Updated the description of tone alert radios
- Revised the description of the conduct of emergency response organization training
- Updated titles
The revision was compared to its previous version, to the criteria of NUREG-0654,
Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and
Preparedness in Support of Nuclear Power Plants, Revision 1, and to the requirements
of 10 CFR 50.47(b) and 50.54(q) to determine if the revision decreased the
effectiveness of the plan. The inspector completed the required one sample during this
inspection.
b. Findings
No findings of significance were identified.
Enclosure
-13-
1EP6 Drill Evaluation
a. Inspection Scope
The inspectors observed the licensee perform an emergency preparedness drill on
December 17. Observations were conducted in the control room, technical support
center, and emergency operations facility. During the drill, the inspectors assessed the
licensees performance related to classification, notification, and protective action
recommendations. Following the drill, the inspectors reviewed the licensees critique to
determine if issues were appropriately identified and documented. The following
documents were reviewed during this inspection:
- Emergency Plan for Cooper Nuclear Station
- Emergency Plan Implementing Procedures for Cooper Nuclear Station
- Cooper Nuclear Station Emergency Preparedness Drill Scenario for December 17.
b. Findings
No findings of significance were identified.
4. OTHER ACTIVITIES (OA)
4OA1 Performance Indicator (PI) Verification
a. Inspection Scope
The inspectors sampled licensee PIs listed below for the period October 01, 2002,
through September 30, 2003. The definitions and guidance of NEI 99-02, Regulatory
Assessment Indicator Guideline, Revision 2, were used to verify the licensees basis for
reporting each data element in order to verify the accuracy of PI data reported during
the assessment period. Licensee PI data were reviewed against the requirements of
Procedures 0-PI-01, Performance Indicator Program, Revision 13.
Reactor Safety Cornerstone
- Reactor Coolant System (RCS) Leakage
The inspectors reviewed a selection of licensee event reports (LERs), portions of
operator log entries, monthly reports, and PI data sheets to determine whether the
licensee adequately collected, evaluated, and distributed PI data for the period
reviewed.
Enclosure
-14-
b. Findings
No findings of significance were identified.
4OA2 Identification and Resolution of Problems
.1 Reactor Scram Due to a Fire on a 345 kV Transmission Tower
a. Inspection Scope
The inspectors performed a review of SCR 2003-1844, which documented the root
cause investigation into a fire on a wooden transmission tower between the main
transformers and the main generator disconnect switches. The inspectors also
conducted interviews with selected licensee engineers and the personnel who
conducted the investigation. Other aspects of this event are discussed in Section 4OA7
of this report.
b. Findings
Introduction: A Green, self-revealing finding was identified associated with the failure to
evaluate and take corrective actions for a fire on the Booneville 345 kV transmission
line. This led to a similar fire on a transmission tower between the main transformers
and the main generator disconnect switches, which induced a plant transient.
Description: On October 28 at 1:30 a.m., control room operators were notified by
security of a fire on the crossarm of a wooden 345 kV transmission tower adjacent to
the 345 kV switchyard. The tower supported the main generator output lines and was
located between the main transformers and the main generator disconnect switches. At
1:45 a.m. operators began a rapid shutdown of the plant in anticipation of losing the
main generator output line. In addition, the Emergency Response Organization was
activated as a precautionary measure, even though no emergency declaration was
required or had been made. At 1:59 a.m., operators manually scrammed the reactor
when the crossarm of the tower failed, allowing one phase of the main generator output
lines to fall. This phase remained suspended above the ground and no generator
grounds or phase-to-ground arcing occurred. The inspectors arrived in the control room
at approximately 2:20 a.m. to observe operator response to the reactor scram. The fire
was extinguished and the plant was stable in Mode 3 by 6:47 a.m.
The licensees root cause investigation concluded that the fire on the crossarm was
caused by the lack of grounding straps on the crossarm insulators. In addition, the
crossarm showed signs of age-related deterioration due to the loss of wood
preservative. This was evidenced by moss growth on the crossarm and cracks in the
wood. These factors, combined with light rain several hours prior to the event,
established a high resistance current path across one of the insulators, through the
wooden crossarm, and across the tower poles to ground. This high resistance current
path eventually heated the wood sufficiently to ignite the crossarm.
Enclosure
-15-
The licensee evaluated the extent of this condition and determined that the Booneville
345 kV transmission line had a similar configuration as the main generator output line.
The insulators on the wooden tower supporting this line were not properly grounded;
however, the wooden crossarm was in better material condition since it had been
replaced in 1997 following a similar fire. The licensee entered that event into their CAP
as Department Disposition 2-18586; however, no root cause investigation or extent of
condition evaluation was performed and the only corrective action implemented was to
repair the damaged crossarm.
Following the more recent fire event, the licensee implemented a number of corrective
actions, including a modification to the main generator output line which removed the
wooden transmission tower and the installation of grounding straps on the wooden tower
supporting the Booneville 345 kV transmission line.
Analysis: This finding had crosscutting aspects associated with problem identification
and resolution. This assessment was based on the licensees failure to question the
causes and extent of condition regarding a similar fire event in 1997. A thorough
evaluation of that fire could have prevented the fire in 2003 and the associated plant
This finding was more than minor, since it affected an Initiating Events Cornerstone
attribute by increasing the likelihood of a transient. Although this fire induced a
transient, it did not pose a challenge to offsite power due to the configuration of the
switchyard and did not challenge mitigating equipment. Inspection Manual
Chapter 0609, Significance Determination Process, Appendix F, was used to assess
the safety significance of this finding. Phase 1 of the SDP concluded that the finding
was of very low safety significance (Green), since it did not affect the fire mitigation
defense in depth elements in Figure 4-1.
Enforcement: The portion of the electrical distribution system affected by this fire was
nonsafety-related; therefore, no violation of NRC requirements was identified. This
finding was entered into the licensees CAP as SCR 2003-1844.
.2 Cross-References to Problem Identification and Resolution Findings Documented
Elsewhere
Section 1R14 describes that the licensee missed a number of opportunities to identify
procedure errors, which resulted in a turbine lube oil leak.
Section 1R15 describes that the licensees corrective actions dealt primarily with the
symptoms rather than the root causes for a clogged diesel fuel oil strainer. This
condition repeated itself 9 months later.
Section 4OA2 describes that the licensee failed to thoroughly evaluate a fire on a
345 kV transmission line in 1997. This contributed to a similar fire in 2003, which
induced a plant transient.
Enclosure
-16-
4OA3 Event Followup
.1 (Closed) LER 50-298/03-001-00 Inadequate Communication Results if Both Diesel
Generators Inoperable Simultaneously
On February 28, 2003, the licensee declared EDG 2 inoperable due to a question
regarding the qualified life of an Agastat time delay relay in the diesel room ventilation
system. This ventilation system was required to support operability of EDG 2. EDG 1
had previously been declared inoperable on February 24 due to a clogged strainer in the
fuel oil system. The reactor was in cold shutdown (Mode 4) at the time both EDGs were
inoperable. During this period of time, only one EDG was required to be operable per
TS and at no time were both EDG simultaneously unable to perform their safety
function. The time delay relay was replaced on February 28 and EDG 2 was declared
operable. On March 2, maintenance on the fuel oil system was complete and EDG 1
was declared operable. The enforcement aspects associated with this event are
discussed in Section 1R15 of this report and Section 4OA2 (Example 2) of NRC
Inspection Report 05000298/2003002. This LER is closed.
.2 (Closed) LER 50-298/03-005-00 Turbine Trip Failure During Testing Due to Ester
Contamination of Turbine Lube Oil
On September 28, during turbine trip testing, the turbine trip block failed to actuate as
designed while testing the solenoid and low vacuum trip portions of the device.
Troubleshooting indicated binding in the auto stop oil dump valve which is mechanically
linked to the trip block. This rendered the high reactor water level (Level 8) turbine trip
feature inoperable, which required reactor power to be reduced below 25 percent per
TS. After the valve was exercised, the trip block operated properly and full power
operation was resumed. The probable cause of the auto stop oil dump valve binding
was the presence of trace amounts of hydrolyzed ester contaminants in the turbine lube
oil. The source of the ester could not be determined; however, compensatory
measures, such as regularly exercising the auto stop oil dump valve, were implemented
to ensure the condition did not recur. In addition, the turbine lube oil purification system
has been effective in removing the hydrolyzed ester contaminants. Since the source of
lube oil contamination could not be determined, the inspectors were unable to identify
any licensee performance deficiency and no findings of significance were identified.
This LER is closed.
4OA6 Meetings, Including Exit
On November 12, 2003, the inspector presented the results of the emergency plan
inspection to Mr. J. Bednar, Emergency Preparedness Manager, and other members of
his staff who acknowledged the findings.
On January 8, 2004, inspectors presented the results of the resident inspector activities
to Mr. S. Minahan, General Manager, Site Operations, and other members of his staff
who acknowledged the findings.
Enclosure
-17-
In all cases, the inspectors confirmed that proprietary information was not provided or
examined during the inspection.
4OA7 Licensee Identified Violations
The following violation of very low safety significance (Green) was identified by the
licensee and is a violation of NRC requirements which met the criteria of Section VI of
the NRC Enforcement Policy, NUREG-1600, for being dispositioned as an NCV.
- TS 5.4.1(a) requires that the licensee establish and implement written procedures
recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.
Appendix A recommends procedures for combating emergencies and other
significant events, such as reactor scrams. Contrary to this requirement, operators
failed to take manual control of reactor feed pumps as required by General
Operating Procedure 2.1.5, Reactor Scrams, Revision 44, during scram recovery
actions performed on October 28, 2003. This contributed to level control problems
following the scram. This finding was identified by the licensee during their
postscram review and was entered into their CAP as Resolve Condition Report
2003-1846. This finding was of very low safety significance, since it did not
represent the loss of any safety function.
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 Program Senior Manager
D. Cook, Senior Manager of Emergency Preparedness
J. Christensen, Acting Nuclear Site Vice President
T. Chard, Radiological Manager
K. Chambliss, Operations Manager
J. Edom, Risk Management
R. Estrada, Performance Analysis Department Manager
M. Faulkner, Security Manager
J. Flaherty, Site Regulatory Liaison
P. Fleming, Risk & Regulatory Affairs Manager
C. Kirkland, Nuclear Information Technology Manager
W. Macecevic, Work Control Manager
L. Schilling, Administrative Services Department Manager
R. Shaw, Shift Manager
J. Sumpter, Senior Staff Engineer, Licensing
K. Tanner, Shift Supervisor, Radiation Protection
D. Knox, Maintenance Manager
A. Williams, Manager, Engineering Support Division
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened and Closed
05000298/2003007-001 NCV Inadequate Procedure Results in Oil Fire Underneath Main
Turbine (Section 1R14)05000298/2003007-002 NCV Inadequate Corrective Actions Result in Repetitive
Degraded Condition on EDG (Section 1R15)05000298/2003007-003 NCV Inadequate Procedure Results in Inadvertent RPV
Draindown (Section 1R20)
Finding FIN Inadequate Postmaintenance Test of SAC (Section 1R19)
Finding FIN Inadequate Corrective Actions Result in Fire and Plant
Transient (Section 4OA2)
A-1 Attachment
Closed
05000298/2003-001-00 LER Inadequate Communication Results in Both Diesel
Generators Inoperable Simultaneously (Section 4OA3.1)
05000298/2003-005-00 LER Turbine Trip Failure During Testing Due to Ester
Contamination of Turbine Lube Oil (Section 4OA3.2)
LIST OF DOCUMENTS REVIEWED
Miscellaneous Documents Reviewed
Cooper Nuclear Station 2002 Operating Examination Results
LIST OF ACRONYMS
ADS alternate depressurization system
CAP Corrective Action Program
CFR Code of Federal Regulations
CST condensate storage tank
EDG emergency diesel generator
IST inservice test
LER licensee event report
NCV noncited violation
NEI Nuclear Energy Institute
PI performance indicator
PM preventive maintenance
SAC station air compressor
SCR significant condition report
SDP Significance Determination Process
SLC standby liquid control system
SOP system operating procedure
TS Technical Specification
USAR Updated Final Safety Analysis Report
A-2 Attachment