ML021960501
| ML021960501 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 07/15/2002 |
| From: | Clark J NRC/RGN-IV/DRP |
| To: | Denise Wilson Nebraska Public Power District (NPPD) |
| References | |
| IR-02-008 | |
| Download: ML021960501 (22) | |
See also: IR 05000298/2002008
Text
July 15, 2002
David L. Wilson, Vice President of
Nuclear Energy
Nebraska Public Power District
P.O. Box 98
Brownville, Nebraska 68321
SUBJECT:
COOPER NUCLEAR STATION - NRC INSPECTION REPORT 50-298/02-08
AND APPARENT VIOLATION
Dear Mr. Wilson:
This refers to the special inspection conducted from May 18-24, 2002, at the Cooper Nuclear
Station. The purpose of the inspection was to evaluate multiple degraded conditions which
were experienced during startup from a forced outage on May 14, 2002. The enclosed report
presents the results of the inspection which were discussed on June 20, 2002, with Mr. Coyle
and other members of your staff.
This inspection was an examination of 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. Within these areas, the inspection covered examination of selected procedures
and representative records, observations of activities, and interviews with personnel.
This report discusses one issue that appears to have greater than very low safety significance.
As described in Section 2.03 of this report, this issue involved the failure to take adequate
corrective actions regarding instrument line snubber clogging, which resulted in a failure of the
reactor core isolation cooling system on May 14. The issue was assessed, using the applicable
significance determination process, as potentially being safety significant and, therefore, has
been preliminarily determined to be greater than Green. Risk significant issues represent an
increased importance to safety, which may require additional NRC inspection and potentially
other NRC action.
The issue also appears to be an apparent violation of NRC requirements of 10 CFR Part 50,
Appendix B, Criterion XVI. Title 10 of CFR Part 50, Appendix B, Criterion XVI, requires that a
licensee establish measures to assure that conditions adverse to quality are promptly identified
and corrected. The issue 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.
Before the NRC makes a final decision on this matter, we are providing you an opportunity to
request a Regulatory Conference where you would be able to provide your perspectives on the
significance of the finding, the bases for your position, and whether you agree with the apparent
violation. If you choose to request a Regulatory Conference, we encourage you to submit your
Nebraska Public Power District
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evaluation and any differences with the NRC evaluation 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. The NRC will also issue a press
release to announce the Regulatory Conference.
Please contact Jeff Clark at (817) 860-8166 within 7 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 this inspection finding at this time. In addition, please be advised that the number
and characterization of apparent violations described in the enclosed inspection report may
change as a result of further NRC review.
Based on the results of this inspection, the NRC also identified a finding of very low safety
significance (Green). This finding was determined to involve a violation of NRC requirements.
Because the violation was of very low safety significance, and because it was entered into your
corrective action program, the NRC is treating the finding as a noncited violation, in accordance
with Section VI.A of the NRC's Enforcement Policy. If you contest this violation, you should
provide a response with the basis for your denial within 30 days of the date of this inspection
report, 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;
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 NRCs Rules of Practice, a copy of this letter and its
enclosures will be 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/NRC/ADAMS/index.html (the Public Electronic Reading Room).
Sincerely,
/RA/
Jeffrey A. Clark, Chief
Project Branch F
Division of Reactor Projects
Docket: 50-298
License: DPR-46
Enclosure:
NRC Inspection Report
50-298/02-08
Nebraska Public Power District
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cc w/enclosure:
Michael T. Coyle
Site Vice President
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
D. F. Kunsemiller, Risk and
Regulatory Affairs Manager
Nebraska Public Power District
P.O. Box 98
Brownville, Nebraska 68321
Dr. William D. Leech
Manager - Nuclear
MidAmerican Energy
907 Walnut Street
P.O. Box 657
Des Moines, Iowa 50303-0657
Ron Stoddard
Lincoln Electric System
1040 O Street
P.O. Box 80869
Lincoln, Nebraska 68501-0869
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
-4-
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
Vick L. Cooper, Chief
Radiation Control Program, RCP
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 R. Mayben, President
and Chief Executive Officer
Nebraska Public Power District
1414 15th Street
Columbus, Nebraska 68601
Nebraska Public Power District
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Electronic distribution by RIV:
Regional Administrator (EWM)
DRP Director (KEB)
DRS Director (EEC)
Senior Resident Inspector (SCS)
Branch Chief, DRP/F (KMK)
Senior Project Engineer, DRP/F (JAC)
Staff Chief, DRP/TSS (PHH)
RITS Coordinator (NBH)
Jim Isom, Pilot Plant Program (JAI)
RidsNrrDipmLipb
Scott Morris (SAM1)
CNS Site Secretary (SLN)
Dale Thatcher (DFT)
R:\\_CNS\\2002\\CN2002-08RP-SCS.wpd
RIV:RI:DRS/EMB
TL:SRI:DRP/F
C:DRP/F
JFMelfi
SCSchwind
JAClark
E - JAClark
E - JAClark
/RA/
7/12/02
7/12/02
7/15/02
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:
50-298/02-08
Licensee:
Nebraska Public Power District
Facility:
Cooper Nuclear Station
Location:
P.O. Box 98
Brownville, Nebraska
Dates:
May 18-24, 2002
Team Leader:
Inspector:
Scott Schwind, Senior Resident Inspector
J. Melfi, Reactor Inspector, Engineering Maintenance Branch
Approved By:
Jeffrey A. Clark, Chief, Project Branch F
SUMMARY OF FINDINGS
Cooper Nuclear Station
NRC Inspection Report 50-298/02-08
IR 05000298/02-08; on 5/18-24/2002; Nebraska Public Power District; Cooper Nuclear Station;
Special Team Inspection Report. Corrective actions, event response.
The inspection was conducted by two team members consisting of one resident inspector and a
region-based engineering and maintenance inspector. The inspection identified one Green
issue. The significance of the issue is indicated by its color (Green, White, Yellow, Red) using
IMC 0609, "Significance Determination Process."
Cornerstone: Mitigating Systems
TBD. The licensee failed to take corrective actions to prevent clogging of instrument
line snubbers which resulted in the inadvertent isolation of the reactor core isolation
cooling system on May 14, 2002. This was an apparent violation of 10 CFR Part 50,
Appendix B, Criterion XVI.
This finding was evaluated using the significance determination process. The clogging
of instrument snubbers affected the ability of the reactor core isolation cooling system to
perform its safety function. Instrument line snubbers were also installed in
instrumentation for the main steam system, the high pressure coolant injection system,
and the reactor recirculation system which could have affected the ability of those
systems to perform their safety functions. Manual Chapter 0609 requires a Phase 3
determination whenever multiple equipment may be affected by a common cause.
Therefore, further analysis of the safety significance is being performed (Section 2.03).
Green. Technical Specification 5.4.1(a) requires that the licensee establish, implement,
and maintain written procedures recommended in Regulatory Guide 1.33, Revision 2,
Appendix A, February 1978. Appendix A recommends procedures for abnormal, off
normal, or alarm conditions. The inspectors concluded that the guidance contained in
the alarm response procedure for a diesel generator fuel oil day tank low level alarm
was inadequate. Specifically, the procedure directed operators to perform incorrect
actions under a postulated condition that could have resulted in both diesel generators
being inoperable. This was determined to be a violation of Technical Specification 5.4.1(a). This violation is being treated as a noncited violation consistent
with Section VI.A of the NRC Enforcement Policy. This issue was entered into the
licensees corrective action program as Notification 10163642.
This finding was considered to have a potential impact on safety since the inadequate
procedure could result in the failure of both diesel generators following a loss of one
diesel fuel oil transfer pump. This finding was characterized by the significance
determination process as having very low safety significance since credit for recovery
was given, based on fuel consumption rates and adequate procedures to monitor fuel
consumption if both diesels were running (Section 2.04).
Report Details
SPECIAL INSPECTION ACTIVITIES
01
Inspection Scope
On May 14, 2002, Nebraska Public Power District shut down Cooper Nuclear Station
due to problems associated with the digital electrohydraulic (DEH) control system.
Several other degraded conditions were experienced during the plant shutdown and the
following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. These included an inadvertent isolation of the reactor core isolation
cooling (RCIC) system and the failure of a diesel generator (DG) fuel oil transfer pump.
A preliminary risk evaluation, performed in accordance with NRC Management
Directive 8.3, concluded that these concurrent conditions presented more than very low
risk. Therefore, a special inspection was performed at Cooper Nuclear Station to
evaluate the degraded conditions and immediate corrective actions and to determine
whether any potential generic safety implications existed. Specifically, this inspection
was conducted to:
1. Develop a sequence of events for the degradation/failure of each of the affected
systems.
2. Determine the adequacy of the licensee's maintenance on the affected systems
between the last outage and the current time.
3. Evaluate the effectiveness of the licensees efforts in identifying and preventing the
failures in these systems, including a review of recent corrective action program
notifications.
4. Identify the extent of effects of the degraded systems, including similar equipment in
redundant trains.
5. Identify system operability concerns that may be related to restart of the facility.
6. Assess whether the licensee's event reporting activities were in compliance with
10 CFR requirements.
7. Determine whether the conditions which existed on or about May 14, 2002, were
linked to a common performance deficiency.
02
Special Inspection Areas
02.01 Overview and Sequence of Events
On May 14, 2002, Cooper Nuclear Station was operating at approximately 20 percent
reactor power and was preparing to synchronize the main generator to the offsite
transmission grid. DEH fluid Pumps A and B were running to support startup of the
main turbine. The following sequence of events then occurred:
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5/14/2002
08:24 p.m.
Control room operators latched the main turbine.
5/14/2002
09:05 p.m.
The control room received an annunciator alarm: TURB
EH FLUID HIGH TEMP.
An operator was dispatched to investigate and found the
local temperature indication to be reading normal (155oF).
5/14/2002
09:10 p.m.
The control room received an annunciator alarm: TURB
EH FLUID SUPPLY FILTER A HIGH D/P.
An operator and engineering personnel responded to the
turbine building and reported that the differential pressure
on the DEH Pump A discharge filter was pegged high and
the differential pressure on the DEH Pump B discharge
filter was starting to increase.
5/14/2002
09:41 p.m.
The control room received an annunciator alarm: TURB
EH FLUID SUPPLY FILTER B HIGH D/P.
Electrohydraulic (EH) pressure was observed lowering
below 1800 psig and stabilized at 1550 psig.
Engineering recommended tripping the main turbine.
5/14/2002
09:44 p.m.
The control room tripped the main turbine.
5/14/2002
09:48 p.m.
The control room entered Abnormal Procedure 2.4DEH,
DEH Abnormal
5/14/2002
09:52 p.m.
Both DEH pump discharge filter differential pressure
gages were observed to be pegged high.
5/14/2002
10:24 p.m.
An EH fluid leak was reported from Intercept Valve 1.
An operator entered the area and isolated the leak by
closing Valve TGF-V-54.
5/14/2002
10:41 pm.
DEH Pumps A and B discharge filter differential pressures
were observed to have lowered to 100 psid.
5/14/2002
10:43 p.m.
The shift manager made the decision to perform a plant
scram based on DEH system parameters.
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5/14/2002
10:51 p.m.
A manual reactor scram was inserted by control room
operators. The plant entered Mode 3.
Main turbine bypass valves responded as required to
control reactor pressure.
5/14/2002
11:10 p.m.
The control room received an annunciator alarm: RCIC
STEAM LINE HIGH FLOW CHANNEL A.
RCIC-MO-16 isolated on a 1/2 Group V isolation signal.
RCIC was declared inoperable.
5/14/2002
11:20 p.m.
An operator was dispatched to the Reactor Building to
check for evidence of an RCIC steam line break. No
evidence of a break was found.
5/15/2002
03:47 a.m.
Control room operators reset the 1/2 Group V isolation
signal.
5/15/2002
04:47 a.m.
The control room declared the main steam bypass valves
inoperable due to degraded conditions on the DEH
system.
5/15/2002
08:05 a.m.
The control room established shutdown cooling using
residual heat removal Loop B.
5/15/2002
11:00 a.m.
Reactor temperature was reduced below 212o F and Mode
4 was declared.
5/15/2002
04:10 p.m.
The control room issued Surveillance Procedure
6.2DG.101, Diesel Generator 31 Day Operability Test
(IST)(DIV 2).
5/15/2002
10:44 p.m.
While performing Procedure 6.2DG.101, the DG 2 fuel oil
transfer pump failed to start as required by step 4.86. The
thermal overloads for the pump motor were found to be
tripped.
5/16/2002
01:17 a.m.
Condition Report 10163513, DGDO XFER P B Overloads
Tripped, was initiated.
5/16/2002
02:27 a.m.
The thermal overloads were reset and the fuel oil transfer
pump restored level to the day tank. The overloads
tripped a second time during this evolution.
5/16/2002
02:59 a.m.
SP 6.2DG.101 was logged as complete.
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5/16/2002
10:10 a.m.
The control room issued a Caution Order for DGDO-2-
XFER PUMP A, to place the switch in the AUTO position
to ensure that the Division 1 had an adequate fuel oil
supply if needed.
5/16/2002
05:07 p.m.
The control room issued Caution Order for DGDO-12-
DGDO-V-19 to close the valve to ensure that the
Division 1 DG has adequate fuel oil supplied, if needed.
5/16/2002
09:34 a.m.
Condition Report 10163642 was written on the DG fuel oil
transfer pump capacity, questioning if one pump could
supply both diesels.
5/17/2002
07:00 a.m.
A modification package was initiated to replace the
1.5 horsepower motor on Transfer Pump 2 with a
3.0 horsepower motor, due to difficulties in procuring
1.5 horsepower motor.
5/18/2002
12:00 p.m.
The new pump motor was tested satisfactorily and the
Division 2 DG was declared operable.
2.02
Digital Electrohydraulic Control System failure
a.
Inspection Scope
The inspectors reviewed operator logs and interviewed station personnel to develop a
sequence of events for the DEH Pump A failure and subsequent system degradation.
Maintenance work orders generated since the last refueling outage and corrective action
program notifications for the past 12 months were reviewed to assess the effectiveness
of the licensees maintenance and corrective action program in identifying and
preventing failures in this system. In addition, the inspectors reviewed the licensees
apparent cause determination and immediate corrective actions for the pump failure.
b.
Findings
No findings of significance were identified.
2.03
RCIC System Isolation
a.
Inspection Scope
The inspectors reviewed operator logs and interviewed station personnel to develop a
sequence of events for the isolation of the RCIC system. Maintenance work orders
generated since the last refueling outage, corrective action program notifications for the
past 12 months, and industry operating experience related to this failure were reviewed
to assess the effectiveness of the licensees maintenance and corrective action program
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in identifying and preventing failures in this system. In addition, the inspectors reviewed
the licensees apparent cause determination and immediate corrective actions for this
failure.
b.
Findings
Description of the Event
On May 14, 2002, the licensee performed a reactor scram and plant cooldown following
a failure in the DEH system. During cooldown and depressurization of the reactor
coolant system, a containment isolation signal was received which caused the RCIC
steam supply line to isolate. There was no demand for RCIC at that time. The isolation
signal was generated by an RCIC high steam flow signal from Differential Pressure
Switch RCIC-DPIS-83. The high steam flow signal cleared in approximately 6 seconds.
The control room dispatched an operator to the reactor building to check for indications
of a steam line break and none were found. Control room operators reset the RCIC
isolation signal approximately 4.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> after the high steam flow signal cleared.
Apparent Cause and Corrective Actions
The licensee concluded that the apparent cause for the spurious isolation signal was a
clogged snubber in the instrument line for Differential Pressure Switch RCIC-DPIS-83.
The licensee determined that these snubbers (small, flow restricting orifices) were
installed in both instrument lines for Switch RCIC-DPIS-83 in order to dampen pressure
perturbations during RCIC turbine starts. One of these snubbers had apparently
become clogged with debris which trapped high pressure fluid in one side of the
pressure switch. Thus, during the plant cooldown and depressurization, the switch
erroneously indicated a differential pressure, indicative of a steam line break.
As an immediate corrective action, the instrument lines for RCIC-DPIS-83 were flushed
and the water was collected for analysis. It contained approximately 19.3 mg of debris
which was determined to be typical carbon steel corrosion products ranging in size up to
0.05 inches. The orifice diameter of the snubbers is only .002 inches. Therefore,
clogging of the snubber by corrosion products was likely the cause of the invalid
isolation signal. In addition, all other safety-related instrument lines containing snubbers
were flushed.
The potential for instrument line snubbers to become clogged and affect instrument
response was communicated to licensees in NRC Information Notice 92-33, Increased
Instrument Response Time When Pressure Dampening Devices Are Installed. This
Information Notice was reviewed by the licensee in 1993 and determined to be
applicable at Cooper Nuclear Station since multiple safety-related pressure instruments,
including instruments in the main steam system, reactor recirculation system, high
pressure coolant injection (HPCI) system, and RCIC system have snubbers installed in
them. This condition was never entered into the corrective action program. Rather, an
action item was generated in the Nuclear Action Item Tracking System (NAITS 92-
0430). As a result, a maintenance work request (MWR 93-1993) was generated to flush
all the affected instrument lines and record as-found conditions. The as-found
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conditions were evaluated qualitatively rather than quantitatively, so the exact amount
and size of the debris particles was unknown. However, of the 26 instruments that were
flushed in 1993, 12 were reported to have had debris in them similar to that which was
flushed from RCIC-DPIS-83 in 2002. The licensee concluded that there were no
immediate operability concerns based on these as-found conditions but determined that
a preventive maintenance procedure should be developed to periodically flush these
instruments. Over the course of the next 4 years, this action item was granted multiple
extensions to its due date and responsibility was transferred between multiple
departments until it was finally closed in 1997 with no further actions taken.
Title 10 of CFR Part 50, Appendix B, Criterion XVI, states that measures shall be
established to assure that conditions adverse to quality are promptly identified and
corrected. The failure to complete corrective actions identified through the review of
Information Notice 92-33 led to the isolation of the RCIC system which was considered a
condition adverse to quality. This is an apparent violation of 10 CFR Part 50,
Appendix B, Criterion XVI (50-298/0208-01). This issue was entered into the licensees
corrective action program as Resolved Condition Report 2002-0895.
Potential for Common Mode Failure
The same instrument line snubbers found in the RCIC differential pressure switches
were also installed in other safety-related instrument lines. Other safety functions
potentially affected by snubber clogging included: main steam line isolation on high
differential pressure or low steam line pressure, HPCI pump trip on low suction
pressure, HPCI turbine lube oil cooler flow, and the flow biased scram setpoints.
Therefore, this issue presented a potential common mode failure for several other
systems. The instruments providing input into the above list of safety functions have
varying instrument line configurations and operating conditions and may not be as
susceptible to clogging by corrosion products as the RCIC instruments. However, the
as-found conditions from the instrument flushes conducted in 1993 noted that corrosion
products were flushed from several of these instruments.
Significance Determination Process
This finding had an actual impact on safety because it rendered the RCIC system
inoperable. RCIC is considered a mitigation system; therefore, the finding was more
than minor and the safety significance was evaluated using Manual Chapter (MC) 0609,
Significance Determination Process. MC 0609, Appendix A, requires a Phase 3
determination whenever multiple equipment may be affected by a common cause.
Therefore, further analysis of the safety significance is being performed. Nevertheless,
an analysis using the Phase 1 and 2 worksheets was performed to preliminarily
characterize the safety significance. This analysis assumed that there were no common
cause affects on other systems and that the condition of the clogged snubber developed
sometime between the last successful surveillance test and May 14, 2002. The last
surveillance was performed 34 days prior to the event; therefore, t/2 (or 17 days) was
used as the exposure time. No credit was given for recovery of RCIC since recovery
from and erroneous isolation signal would involve lifting leads in a panel located outside
of the control room. There was no specific procedure to identify the leads to be lifted
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nor would there be sufficient personnel onsite at all times to complete this task in a
timely manner. This resulted in greater than very low safety significance with the
dominant sequence being high pressure injection during a loss of service water event.
2.04
Emergency DG Fuel Oil Transfer Pump Failure
a.
Inspection Scope
The inspectors reviewed operator logs and interviewed station personnel to develop a
sequence of events for the failure of the Division II emergency DG fuel oil transfer
pump. Maintenance work orders generated since the last refueling outage, corrective
action program notifications for the past 12 months, and industry operating experience
potentially related to this failure were reviewed to assess the effectiveness of the
licensees maintenance and corrective action program in identifying and preventing
failures in this system. In addition, the inspectors reviewed the licensees apparent
cause determination and immediate corrective actions for this failure.
b.
Findings
Diesel Fuel Oil Transfer System General System Description
The diesel fuel oil system is a required subsystem for the DG that provides for the
storage and transfer of clean fuel oil to be used by the DG. For each DG, the system
has a storage tank, transfer pump, day tank, engine-driven fuel oil pump, electric-driven
fuel oil booster pump, injection pumps, and fuel injection nozzles. The fuel oil transfer
pumps move oil from the storage tanks to the day tanks. The diesel fuel oil transfer
system has a normally open crosstie valve (DGDO 19), enabling either fuel oil transfer
pump to supply either day tank. Level switches in the day tanks control the start and
stop of each pump. A float admission valve on the day tank inlet prevents the overfilling
of the day tanks. The licensing and design basis for the DG fuel oil system is to provide
one diesel fuel for 7 days operation under postulated accident loads.
Description of the Event
On May 15, 2002, the licensee was performing a routine monthly surveillance test on the
Division II emergency DG. Following completion of the test, operators attempted to start
the Division II fuel oil transfer pump in order to completely fill the Division II day tank, but
the pump failed to start. The thermal overloads in the supply breaker for the pump
motor were found to be tripped. The thermal overloads were reset and the pump was
started; however, the motor tripped again due to a thermal overload condition. The
Division II emergency DG was declared inoperable but was considered available for use.
Therefore, during a loss of offsite power, it would have started and loaded as designed.
Apparent Cause and Corrective Actions
The licensee concluded that motor winding degradation was the most likely cause for
the Division II fuel oil transfer pump motor failure. This conclusion was supported by
-8-
troubleshooting which identified a measured current imbalance, loss of motor efficiency,
and the lack of a motor bearing degradation. This was a reasonable explanation and
was supported by a sufficient level of detail.
The inspectors reviewed industry operating experience, preventive maintenance
records, and vendor recommended maintenance for this pump and found no previous
opportunities to identify degraded conditions on the pump motor. The only routine
predictive maintenance item performed on the motor was vibration monitoring per the
licensees in-service testing (IST) program. A review of the IST results for the transfer
pump did not reveal any adverse trends in performance. There were no previous
corrective maintenance items or problem identification reports which would indicate
electrical problems with the motor.
As an immediate corrective action, the licensee replaced the Division II fuel oil transfer
pump motor with a new motor and restored the DG to operability within the allowed
outage time required by the Technical Specification (TS). The licensee performed an
extent of condition inspection on the Division I fuel oil transfer pump motor on May 19,
2002 (Notification 1014224), and found a slight phase imbalance. The licensee found
that Phase B was approximately 2.2 amps, while Phases A and C were 2.5 to 2.6 amps.
After running several minutes, all phases of the motor equalized at approximately 2.3 to
2.4 amps. This was lower than the thermal overload setting of 2.95 amps. As a
preventive maintenance item, the licensee scheduled replacement of the Division I
motor in mid-June. The inspectors concluded that these corrective actions were
reasonable.
Potential for Common Mode Failure
The Divisions I & II diesel fuel oil transfer subsystems are cross-connected through a
normally opened valve (DGDO-19) that allows for the filling of either day tank from either
fuel oil transfer pump. This valve remained open with no administrative controls
following the failure of the Division II fuel oil transfer pump. Therefore, if a low level in
the Division I tank occurred, the Division I pump would have started and supplied both
day tanks.
Prior to replacement of the Division II pump motor, the inspectors questioned control
room operators as to whether one transfer pump was sufficient to supply two fully
loaded DGs. The operators were unsure. Upon further questioning by the inspectors,
the licensee acknowledged that one transfer pump would not be sufficient to supply two
fully loaded emergency DGs. As a result, Valve DGDO-19 was caution tagged closed to
assure that the operable diesel would receive enough fuel.
The inspectors assessed the consequences of a failure of the Division II diesel fuel oil
transfer pump if both DGs were fully loaded. Due to differences in the piping
configuration between the Division I and Division II fuel oil transfer systems, the
inspectors concluded that with only one pump running the Division II day tank would fill
preferentially before the Division I day tank, and the Division I day tank low level alarm
would be received prior to the alarm on Division II. In this situation, Alarm Response
Procedure 2.3 DG-1, Panel DG-1-Annunciator DG-1, directed operators to secure the
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Division I fuel oil pump and isolate the day tank. This would have exacerbated the
situation since both DGs would have been operating with no fuel supply from the
storage tanks. The alarm response instructions were similar for the Division II pump as
well.
TS 5.4.1(a) requires that the licensee establish, implement, and maintain written
procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February
1978. Appendix A recommends procedures for abnormal, off-normal, or alarm
conditions. The failure to establish an adequate alarm response procedure for a DG
fuel oil day tank low level alarm is a violation of TS 5.4.1(a). This violation is being
treated as a noncited violation, consistent with Section VI.A of the NRC Enforcement
Policy (50-298/0208-02). The licensee issued a procedure change request for both
procedures and entered this into their corrective action system as Notification
10163642.
Significance Determination Process
This finding had a credible impact on safety since it could have led operators to perform
inappropriate actions which could have rendered both emergency DGs inoperable. The
emergency DGs are considered to be mitigation systems; therefore, the finding was
more than minor and the safety significance was evaluated using MC 0609. The
following assumptions were used during this evaluation:
The condition affecting the fuel oil transfer pump motor was assumed to have
existed for half of the time since the last successful surveillance test, or 15 days,
which exceeded the allowed outage time for the DG in TSs.
Credit was given for recovery of a failed train since calculations showed that both
DGs could operate fully loaded for approximately 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with only one diesel fuel
oil transfer pump in operation. Furthermore, Emergency Procedure 5.3EMPWR,
Emergency Power, required operators to monitor diesel fuel consumption to assure
that enough fuel is available during the 7-day period that a DG is required to
operate. Therefore, credit was given for recovery of a failed train, since it was
reasonable to assume that operators would have recognized the need to secure the
Division II diesel and would have had sufficient time to do so during an event prior to
challenging the operability of both DGs.
The emergency power system was treated as a single train system versus a multi-
train system, since it was assumed that operators would have recognized the failed
pump and secured the Division II DG.
The Phase 1 evaluation determined the need for Phase 2 since the finding represented
an actual loss of safety function of a single train for greater than its TS allowed outage
time. The Phase 2 evaluation resulted in very low safety significance (Green).
-10-
03
Meetings
03.01 Exit Meeting Summary
On June 20, 2002, the results of the inspection were discussed with Mr. M. Coyle and
other members of the licensees staff. The licensee acknowledged the inspection
results and informed the inspectors that no proprietary information was discussed during
the inspection.
ATTACHMENT
PARTIAL LIST OF PERSONS CONTACTED
Licensee
M. Bergman, Plant Engineering
J. Charterina, Plant Engineering Supervisor
M. Coyle, Site Vice President
K. Dia, Plant Engineer
F. Diya, Plant Engineering Manager
P. Fleming, Risk & Regulatory Affairs Manager/Licensing Manager
R. Gardner, Operations Manager
J. Gren, Plant engineering
M. Lingenfelter, DG System Engineer
M. Manning, Plant Engineering Supervisor
M. McKormack, Design Engineering Supervisor
M. Metzger, Plant Engineering
J. Ranalli, Senior Manager of Engineering
G. Seeman, Risk Management Engineer
D. Shrader, SRO operations specialist, OER group
K. Sutton, Risk Management Engineer
M. Tackett, Operations Supervisor
R. Wachowiak, Risk Management Supervisor
D. Wilson, Vice President - Nuclear
R. Yantz, Design Engineering
NRC
D. Loveless, Senior Reactor Analyst, Region IV
ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
50-298/0208-01
Failure to take corrective actions for instrument line snubber
clogging (Section 2.03)
Opened and Closed During this Inspection
50-298/0208-02
Inadequate procedure for response to a DG fuel oil day tank low
level alarm (Section 2.04)
Discussed
None.
-2-
DOCUMENTS REVIEWED
The following documents were selected and reviewed by the inspectors to accomplish the
objectives and scope of the inspection and to support any findings:
Procedures
Procedure
Number
Title
Revision
2.3 DG1
Panel DB-1 Annunciator DG-1, pages 16&17
1
5.3EMPWR
Emergency Procedure, Emergency Power
3C1
6.1DG.401
Diesel Generator Fuel Oil Transfer Pump IST Flow Test (DIV I)
8C1
6.1DG.401
Diesel Generator Fuel Oil Transfer Pump IST Flow Test (DIV I)
9
6.2DG.401
Diesel Generator Fuel Oil Transfer Pump IST Flow Test
(DIV II)
9
6.2DG.401
Diesel Generator Fuel Oil Transfer Pump IST Flow Test
(DIV II)
10
Drawings
Drawing
Number
Title
Revision
or Date
2011, sheet 1
Flow Diagrams, Turbine Oil Purification & Transfer Systems &
Diesel Oil System
N24
2077
Flow Diagram - Diesel Generator Buildings Service Water,
Starting Air, Fuel Oil, Sump System and Roof Drains
N48
X2825-202
Isometric - DO-1 Piping Inside DO-1 Tank Access Housing
N01
X2825-201
Isometric - DO-1 Piping Inside DO-1 Tank Access Housing
N01
-3-
X-2300-200
Isometric - DO-1 Diesel Oil
N02
28239
2"-DO-1 Discharge Yard Piping
4
3006 SH 5
Auxiliary One Line Diagram Starter Racks LZ and TZ; MCCs
K, L, LX, RA, RX, S, T, TX, X
N67
Work Orders
MWR 4242711
MWR 93-1993
Calculations
Number
Title
Revision
NEDC 97-012
Emergency Diesel Generator Fuel Oil On-Site Storage
Technical Specification Requirements
2
NEDC 02-046
Seismic Analysis of Gould Model 3171 Pump for the
Diesel Generator Fuel Oil Transfer Pumps
0
NEDC91-184
Motor Overload HeaterSizing
3
NEDC 86-105B
CNS Critical AC Bus Coordination Survey
7C2
NEDC 00-111
CNS Auxiliary Power System AC Loads
2C1
NEDC 00-004
Minimum MCC Voltage for Essential Loads
1C1
NEDC 87-047K
MCC K Load Summary
3C2
NEDC 87-047S
MCC S Load Summary
2C2
NRDC 91-146
Core Uncovery Analysis
0
Condition Reports
-4-
Number
Title
Date
10163486
Inadvertent DG Trip In Simulator I.C.20
5/15/02
10163513
DGDO XFER P B Overloads Tripped
5/16/02
10164123
1-CTP-DG-1B Inboard Seal Leaks
5/17/02
10163642
DG Fuel Oil Transfer Pump Capacity
5/16/02
10164235
On modification lessons learned for DG Fuel Oil Motor
Replacement
5/19/02
10164180
Nonconforming material conditionally released for work
on DG fuel oil motor.
5/17/02
SCR 2002-
0815
TGF Discharge DP High Alarm
5/14/02
10163182
RCIC Steam Line High Flow Isolation
5/14/02
10165870
No Long Term Action Implemented as Required by NRC
5/23/02
10163548
Evaluation for RCIC Half group 5 Isolation
5/15/02
10163182
RCIC-MO-16 Auto-Isolated on High Steam Line Flow
Channel A
5/14/02
Other Documents
Doc Number
Title
Revision
or Date
CED 6008866
DGDO-P-DOTA/B Motor Replacement
5/19/01
Maintenance history listing for DGDO-MOT-DFOTA
-5-
PRA02016
Risk Management input into 2.0.6 Evaluation for Forced
Outage 02-01
5/20/01
Work Number
90-2017
While rebuilding pump under MWR 90-1684, noticed motor
bearings were rough (canceled)
4/23/90
S2002037
SORC Meeting S2002-037
5/17/02
PSA-ES059
Risk Significance of Conditions Identified During the May 14,
2002 Forced Outage 02-01
1
Turbine High Pressure Fluid System Anomalies Result in
5/17/02