ML16154A761
| ML16154A761 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/25/1995 |
| From: | Crlenjak R, Harmon P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16154A760 | List: |
| References | |
| 50-269-94-38, 50-270-94-38, 50-287-94-38, NUDOCS 9502030122 | |
| Download: ML16154A761 (15) | |
See also: IR 05000269/1994038
Text
Epk REGo
UNITED STATES
.o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/94-38, 50-270/94-38 and 50-287/94-38
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC
28242-0001
Docket Nos.: 50-269, 50-270 and 50-287
License Nos.: DPR-38, DPR-47 and DPR-55
Facility Name:
Oconee Units 1, 2 and 3
Inspection Conducted: November 27 - December 31, 1994
Inspector:
>1(siv.t4-t"
,)'s 1'/5
P. E. Harmon, Senior Pogidei
Inspector
Date Signed
W. K. Poertner, Resident Inspector
L. A. Keller, Resident Inspector
P. G. Hum rey, Resident Inspector
Approved by:
R.'V. Crlenj , Chief, Brdnch 3
ate
igned
Division of Reactor Projects
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
onsite engineering and technical assistance.
Results:
One violation was identified for failure to follow procedures when
transferring operation of the Keowee Hydro Unit from Remote to
Local, paragraph 2.e.
The licensee's practices for performing on-line maintenance
revealed that while no formal assessment is performed, on-line
maintenance involving taking multiple components out-of-service is
not routine at Oconee, paragraph 6.
A reactor trip of Unit 2 from 100 percent power occurred on
December 8,.1994. The cause of the trip was a loss of power to
the Integrated Control System (ICS) due to a loose lug on the
power supply breaker. The unit was returned to power the
following day, paragraph 2.c.
ENCLOSURE 2
9502030122 950125
PDR ADOCK 05000269
0-
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- B. Peele, Station Manager
- E. Burchfield, Regulatory Compliance Manager
- D. Coyle, Systems Engineering Manager
J. Davis, Engineering Manager
T. Coutu, Operations Support Manager
- W. Foster, Safety Assurance Manager
- J. Hampton, Vice President, Oconee Site
0. Hubbard, Superintendent, Instrument and Electrical (I&E)
C. Little, Electrical Systems/Equipment Manager
- J Smith, Regulatory Compliance
- G. Rothenberger, Operations Superintendent
R. Sweigart, Work Control Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
- Attended exit interview.
2.
Plant Operations (71707)
- a.
General
The inspectors reviewed plant operations throughout the reporting
period to verify conformance with regulatory requirements,
Technical Specifications (TS), and administrative controls.
Control room logs, shift turnover records, temporary modification
log, and equipment removal and restoration records were reviewed
routinely. Discussions were conducted with plant operations,
maintenance, chemistry,,health physics, instrument & electrical
(I&E), and engineering personnel.
Activities within the control rooms were monitored on an almost
daily basis.
Inspections were conducted on day and night shifts,
during weekdays and on weekends.
Inspectors attended some shift
changes to evaluate shift turnover performance. Actions observed
were conducted as required by the licensee's Administrative
Procedures. The complement of licensed personnel on each shift
inspected met or exceeded the requirements of TS. Operators were
responsive to plant annunciator alarmsand were cognizant of plant
conditions..
Plant tours were taken throughout the reporting period on A
routine basis.
During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
practices were observed.
2
b.
Plant Status
Unit 1 essentially operated at 100 percent power the entire
reporting.period.
Unit 2 experienced a reactor trip on December 8, 1994, due to a
loss of control power to the ICS. The unit was restarted and was
back on line December 9, 1994, and operated at essentially 100
percent power for the remainder of the reporting period.
Unit 3 essentially operated at 100 percent power the entire
reporting period.
C.
Unit 2 Reactor Trip
Responding to the Unit 2 reactor trip which occurred on December
8, 1994, at 2:24 p.m., the- inspectors monitored control room
operations during trip recovery. The trip resulted from a loss of
power to the ICS which was caused by a breaker tripping in the
circuit. A loose connection on the load side of the breaker
terminal was determined to have caused the breaker to trip. The
loss of power to the ICS generated a false "high steam generator
level" signal which tripped the main feedwater pumps. Loss of
both feedwater pumps in turn generated a signal that tripped the
reactor. All systems responded appropriately and the reactor was
shut down without adverse conditions noted.
As the loose lug could not be tightened, and the affected breaker
(number 25 on the 2KI load center) could not be removed without
de-energizing the entire load center, the breaker's outputs were
swapped to an installed spare breaker (number 26).
Oconee has not
developed load lists for power supply breakers, so the
consequences of de-energizing the entire 2KI load center could not
be determined. The plant was restarted the following day and the
turbine generator was on-line at 1:57 p.m.
The inspectors witnessed the operator's response to the reactor
trip and reviewed the licensee's post trip report. The operators
responded in a very professional manner and conducted the post
trip actions in a very calm, organized fashion. The post trip
review placed particular emphasis on the turbine by-pass valves'
response to the trip. This was prompted by past problems when
these valves repositioned to a random setting and failed to
maintain proper steam generator inventory. Since that time, the
licensee modified the control system, and the post trip review
confirmed that the valves operated properly. The inspector
determined that a thorough post trip review had been conducted,
and that the operators had performed well in their response to the
trip.
3
d.
Unit 2 Control Room Instrumentation
The inspector noted that a total of 51 Unit 2 control instruments
(including computer indications and alarms) were out-of-service or
were not indicating correctly prior to the Unit 2 refueling outage
which began on October 6, 1994. Since the outage has been
completed, the inspectors have been monitoring the status of
control room instrumentation. On December 30, 1994, a total of 37
instruments and computer points were listed as out-of-service or
not indicating properly.
Based on the significant number of instruments with noted
problems, it appears that more emphasis is needed to maintain
control room instrumentation and assure that the operators have
sufficient indications for operating the plant. At the end of the
inspection period, the licensee had formed a task force to
aggressively pursue restoration of out-of-service control room
instruments. The inspectors will monitor the results of this
team's efforts in future inspection reports.
e.
Keowee Unit 1 Loss of Excitation
On December 11, 1994, Keowee Unit 1 tripped while connected to the
grid at no-load conditions. The unit had been operability tested
from the Oconee control room and the Local/Remote switch had been
placed in Remote to perform the operability test. The dispatcher
requested that control of the Keowee unit be transferred back to
Keowee as soon as possible because of lake level letdown
requirements. To accomplish this, Procedure OP/O/A/1106/019,
Keowee Hydro at Oconee, requires shutting down the hydro unit
prior to transferring control of the unit to Keowee. Recalling
past hydro practices where the transfer was done with the unit on
line, the Keowee operator, with concurrence from the Oconee
control room, attempted to transfer control from Oconee to Keowee
by depressing the Manual to Auto Control Transfer push button and
taking the Local/Remote switch from Remote to Local.
When the Keowee operator attempted to transfer control of the
Keowee unit from Remote to Local, the generator output breaker
opened, the generator field breaker and field supply breakers
opened and the voltage regulator transferred to manual.
The
Keowee Unit 1 turbine continued to operate, so the Keowee operator
secured the Keowee unit by pressing the stop button.
Subsequent to securing the unit, the Keowee operator smelled
smoke.
Investigating, the operator found the closing coil on the
generator field breaker smoking and racked out the breaker to
deenergize the closing coil.
The generator field breaker closing
coil was replaced with a spare closing coil and the breaker was
returned to service. The subsequent operability testing was
satisfactory.
4
The loss of excitation resulted from momentary dropouts of the
master run relays with the unit at speed-no-load conditions. The
transfer could have possibly been accomplished if the Keowee unit
had been loaded prior to the transfer from remote to local.
The
coil failure resulted from concurrent close and trip signals being
applied to the generator field breaker and the breaker mechanism
operating to the trip free condition prior to the closing coil
being deenergized, resulting in the coil overheating.
The failure to operate the Keowee hydro station in accordance with
approved procedures is identified as Violation 50-269,270,287/94
38-01:
Failure to Follow Keowee Transfer Procedures.
f.
Reactor Building Spray Inoperability Due to Inadequate Procedure
On December 27, 1994, the licensee performed a review of the
abnormal procedure for loss of low pressure injection. For a
postulated loss of coolant accident in which a single failure
disables 1 of the 2 reactor building emergency sump lines, the
abnormal procedure directs the operators to secure both reactor
building spray pumps. The licensee determined that this condition
was beyond the design basis assumptions contained in the maximum
hypothetical accident safety evaluation report. The licensee
declared both trains of reactor building spray inoperable on all
three units and entered TS 3.0 at 4:45 p.m. TS 3.0 requires that
the unit be placed in a hot shutdown condition within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
To correct the procedural inadequacy the licensee initiated a
procedure change to require that one train of reactor building
spray be maintained operable assuming a postulated single failure
of a reactor building emergency sump line. The procedure changes
were completed and TS 3.0 was exited at 10:25 p.m. on December 27,
1994. The licensee was reviewing this item further to determine
if the reactor building spray systems were actually inoperable as
a result of the procedural inadequacy. The inspectors considered
the licensee's action with regard to declaring the reactor
building spray systems inoperable appropriately conservative and
reviewed the proposed procedure changes. The inspectors will
continue to review this item further.
Within the areas reviewed, one Violation was identified.
3.
Maintenance and Surveillance Testing (62703 and 61726)
a.
Maintenance activities were observed and/or reviewed during the
reporting period to verify that work was performed by qualified
personnel and that approved procedures adequately described work
that was not within the skill of the craft. Activities,
procedures and work orders (WO) were examined to verify that
5
proper authorization and clearance to begin work were given,
cleanliness was maintained, exposure was controlled, equipment was
properly returned to service, and limiting conditions for
operation were met. The following maintenance activities were
observed or reviewed in whole or part:
(1) Reactor Protection System (RPS) Channel 'D'
Main Feedwater
Pumps and Main Turbine Trips Calibration, IP/0/A/0305/012
The inspector reviewed activities in progress during the
calibration of pressure switch 2PS-419 on December 27, 1994.
The work effort was being performed in accordance with
calibration procedure IP/O/A/0305/012. RPS Channel 'D,' had
been removed from service as specified in IP/O/A/0305/015,
Nuclear Instrumentation RPS Removal From and Return to
Service for Channels A,B,C and D for the switch calibration.
The activity had been authorized per Work Order 94093207,
Task 01.
The inspector determined that the activity was performed to
acceptable standards, and no discrepancies were noted.
(2) Work Order 94093081, Task 01, Check/Calibrate Emergency
Feedwater Pressure Switches
The inspectors observed activities in progress to calibrate
the Unit 1 emergency feedwater pressure switches using
procedure IP/O/A/0275/005I, Motor Driven Emergency Feedwater
Pump Safety-Related Instrumentation Calibration and System
Functional Check. The work activity was verified performed
in accordance with the procedure and no maintenance
discrepancies were noted during the performance of the work
activity. Numerous pressure switches did not meet the
calibration tolerance band stipulated in the procedure.
This issue is discussed further in paragraph 4.
b.
The inspectors observed surveillance activities to ensure they
were conducted with approved procedures and in accordance with
site directives. The inspectors reviewed surveillance
performance, as well as system alignments and restorations. The
inspectors assessed the licensee's disposition of any
discrepancies which were identified during the surveillance. The
following surveillance activities were observed or reviewed:
(1) Stroke Test of 3BS-1, IP/0/A/3001/016
Valve 3BS-1 is the 3A Reactor Building Spray Pump's
discharge isolation valve. On October 16, 1994, Valve 3BS-1
exceeded the performance stroke testing requirements by one
second. As discussed in Inspection Report 94-32, the
6
Slicensee's evaluation concluded that maintenance performed
during January 1994 altered the baseline for this valve and
that this accounted for the slower stroke time. The
licensee has instituted a weekly stroke test of Valve 3BS-1
to verify that the stroke time is not degrading. On
November 30, 1994, the inspector observed one of these
weekly stroke tests. The stroke time was 13.96 seconds,
which was consistent with the previous stroke times. All
activities observed were satisfactory.
(2) Standby Shutdown Facility (SSF) Instrument Surveillance,
PT/O/A/600/20
This monthly surveillance verifies that the SSF control room
instrumentation is operable and that it agrees with the
corresponding instrumentation in the main control rooms.
The inspector observed the surveillance check of the SSF
Unit 1 RCS temperature instruments on December 19, 1994.
During this check, the operators experienced-great
difficulty in getting all six RCS temperature gauges to go
to mid scale as required. Eventually, the operators were
able to complete the step as required. The inspector
confirmed that operators properly filled out a test
deficiency form for this problem. All activities observed
were satisfactory.
(3) Keowee Hydro Operation, PT/O/A/620/09
On December 21, 1994, the inspector observed the performance
of the monthly Keowee hydro test. Both hydro units started
and supplied the Main Feeder Buses as required. All
parameters were verified by the inspector to be within
specifications. All activities observed were satisfactory.
(4) Reactor Protection System Control Rod Drive Breaker Trip and
Timing Test, IP/O/A/305/14
Procedure IP/O/A/305/14 implements the requirements of
Technical Specification (TS) 4.1.1, Table 4.1-1, Instrument
Surveillance Requirements. This surveillance requires a
monthly test of the control rod drive trip breakers. The
inspectors monitored the performance of the procedure and
verified that the acceptance criteria were met. No
deficiencies were noted.
(5) High Pressure Service Water Pump and Power Supply,
PT/0/A/250/05
Procedure PT/O/A/250/05 implements the requirements of TS 4.1.2, Table 4.1-2, Minimum Equipment Test Frequency. This
surveillance requires a monthly functional test of the High
Pressure Service Water pumps and power supplies. The
7
inspectors reviewed the completed performance test conducted
on December 31, 1994. No discrepancies were noted.
No violations or deviations were identified.
4.
Onsite Engineering (71707)
During the inspection period, the inspectors assessed the effectiveness
of the onsite design and engineering processes by reviewing engineering
evaluations, operability determinations, modification packages and other
areas involving the Engineering Department.
On December 7, 1994, during the performance of a routine calibration of
the Unit 1 RPS feedwater pressure switches, four of the eight pressure
switches were found out of calibration. These pressure switches, which
are set at 770 psig, provide an anticipatory reactor trip signal on a
loss of main feedwater. The as found setpoints for the out of
calibration instruments ranged from 735 psig to 750 psig. These values
exceeded the 15.5 psig maximum setpoint drift assumed in the uncertainty
calculation assumptions. The pressure switches in question are Static
0-Ring model 9N6-W5-U8-C1A-JJTTNQ pressure switches. They had been
installed during the previous refueling outage. These new pressure
switches had also been installed in the emergency feedwater (EFW)
initiation circuitry.
Based on the data obtained from the Unit 1 RPS switches, the licensee
initiated a program to calibrate all the Static-0-Ring EFW and RPS
pressure switches on all three units. The calibration of the switches
was completed on December 14, 1994.
Five of the six EFW pressure
switches on Unit 1 were out of calibration. Eleven of the fourteen
total feedwater pressure switches on Unit 2 were found out of
calibration and twelve of the fourteen pressure switches on Unit 3 were
found out of calibration.
The pressure switches were reset to the proper setpoint and a
conditional operability evaluation was performed for all three units.
The conditional operability evaluation concluded that the pressure
switches could be considered operable if the calibration frequency was
increased to weekly for Unit 3 and every two weeks for Units 1 and 2.
Having reviewed the conditional operability determination and the
calibration data collected since the problem was first identified, the
inspectors concur with the licensee's conditional operability
evaluation.
The licensee was still reviewing this issue at the end of the inspection
period, but had already determined that portions of the Unit 1 and Unit
3 initiation circuitry were inoperable due to the excessive instrument
calibration drift. The inspectors will continue to review this item in
the future via the Licensee Event Report required to be submitted to the
NRC per 10 CFR 50.73.
8
Within the areas reviewed, licensee activities were satisfactory and no
violations or deviations were identified.
5.
Cold Weather Preparations (71714)
The inspector reviewed the licensee's program to protect equipment and
systems against extreme cold weather conditions. The program is
outlined in Enclosure 5.12, Cold Weather Checklist of Operations
Procedure, OP/1/A/1102/20, Shift Turnover, and is initiated via a
computer alarm when the outside temperature reaches a low of 35 degrees
F. The procedure checklist specifies various preventive measures to be
implemented such as building doors closed, dampers closed, heaters
turned on and operating properly, outside equipment cooling water at
rated flows, trench covers in place, heat tracing operating properly and
building heating systems in service.
In addition, alarm 1SA9B3, Reactor Building Ventilation Purge Inlet Temp
Low, annunciates when the outside temperature reaches a low temperature
of 40 degrees F. The response requires that various heater alarms be
reviewed for malfunctions and steam supplies be readied for use per
procedure OP/0/A/1106/22, Auxiliary Steam System.
The cold weather program was based on an evaluation of equipment where
freeze protection was required and a compiled list of areas that have
experienced problems with freezing. The inspector witnessed
implementation of the procedure on December 1, 1994, when the outside
temperature dropped to 35 degrees F. No discrepancies were identified
during the inspector's review of the completed checklist, and the
program was considered to be adequate.
6.
Evaluation of On-Line Maintenance (TI 2515/126)
The objective of this inspection was to evaluate the impact on safety of
the licensee's practices regarding the removal of equipment from service
for on-line scheduled maintenance. The licensee indicated that it was
their policy to limit the scope of maintenance activities being
conducted simultaneously, and the scope of maintenance activities
conducted on-line that could be accomplished during an outage. However,
the licensee had no formalized process or procedures for assessing the
risk associated with.taking multiple components out of service at the
same time for maintenance, or for doing maintenance on-line rather than
during an outage. The inspector noted that the only formal mechanism
for restricting maintenance activities were the requirements of TS. The
inspector conducted a review of the maintenance history from January
1993 until December 1994 to determine the amount and frequency of
maintenance performed during power operation. The inspector noted that
it was rare for there to be multiple entries into Limiting Conditions
for Operations (LCOs) for maintenance or testing. However, several
specific examples when this occurred included:
9
On January 12, 1993, the 3B Reactor Building Cooling Unit (RBCU),
3A Low Pressure Injection (LPI) pump, and Keowee Unit I were all
out of service at the same time.
On March 8, 1993, the Unit 1 Turbine Driven Emergency Feedwater
(TDEFW) pump and lB LPI train were both taken out of service for
maintenance/testing simultaneously.
On May 19, 1993, the IC Low Pressure Service Water pump,
containment isolation valve 1RC-7, and switchyard battery charger
SY-2 were taken out of service at the same time.
-
On October 4, 1993, the SSF, Unit 1 Emergency Condenser
Circulating Water (ECCW), and the Unit 1 TDEFW pump were all taken
out of service simultaneously.
Additionally, the inspector noted that following the most recent Unit 2
refueling outage the licensee entered the LCO for the Unit 2 RBCUs on
three separate occasions to perform maintenance on cooler outlet valves
(under the LCO for 9 days over a 15 day period). This maintenance was
originally slated for completion during the outage, but was purposely
deferred to on-line maintenance in order to prevent extending the outage
duration.
The inspector concluded that in general the licensee limits on-line
maintenance. However, there were no requirements, other than TS, to
limit either the scope or frequency of maintenance conducted while at
power. Additionally, there was no formal mechanism to assess the
potential risks of conducting multiple maintenance/testing activities at
the same time. The licensee indicated that as part of their planned
implementation of the Maintenance Rule, they were preparing a matrix
that would administratively prohibit certain combinations of maintenance
activities based on insights gained from Probabilistic Risk Assessment
(PRA).
The inspectors noted that the licensee did perform a PRA as part
of their planning for an extended outage of the Keowee overhead path.
This outage activity, which lasted 14 days while all three Oconee units
were on-line, consisted of reblocking the Keowee main transformer. The
PRA concluded that the attendant work should be performed during periods
of Oconee unit "innages."
No violations or deviations were identified.
7.
Inspection of Open Items (92902 and 92903)
The following open items were reviewed using licensee reports,
inspection record review, and discussions with licensee personnel, as
appropriate:
a.
(Closed) Unresolved Item 50-269,270,287/90-30-02: Clarification
of TS 3.4.1.
10
As a result of this item the licensee submitted a TS change
request to clarify the operability requirements of the emergency
feedwater automatic initiation circuitry. This change was
approved and incorporated into the TS by amendment 207 for Units 1
and 2, and amendment 204 for Unit 3. Based on the TS change, this
item is closed.
b.
(Closed) Unresolved Item 50-269,270,287/94-36-01: Failure To Meet
SSF Activation Time Requirement
This.URI was identified concerning the ability of Oconee operators
to place the SSF into operation within 10 minutes. The licensee
had determined that the SSF must be activated within 10 minutes of
the onset of an SSF required event in order to prevent Reactor
Coolant Pump (RCP) seal damage/failure and/or loss of natural
circulation due to steam void formation.
On July 27, 1994, the licensee performed a drill that was written
with the intent of showing how plant personnel and equipment were
prepared to cope with mitigation of an Appendix "R" type event.
The drill scenario included a requirement to activate the SSF.
The SSF activation time for this drill was approximately 28
minutes. During this drill, it took approximately 8 minutes for
the personnel to acknowledge the need to activate the SSF, and 20
additional minutes before the SSF was in service. The licensee
indicated that this drill failure was an isolated instance and did
not indicate that the SSF could not be activated within 10
minutes. The licensee based this on the "numerous successful
testing of the 10 minute criterion" previously performed. The
inspector noted that the only previous documented test for SSF
activation was conducted on December 13, 1987. This was a single
unit scenario in which the total elapsed time was 9 minutes, 26
seconds.
The inspector observed a training exercise during the previous
inspection period and noted that the exercise did not account for
the time required for the necessary valve manipulations (valves
were not actually stroked during the drill, rather the valves were
assumed to go instantly open or closed). Additionally, the
inspector noted that completing the procedure as written within
ten minutes was extremely challenging. The inspector noted that
the necessary valve manipulations would add approximately one
minute to the activation time, and that this apparently had not
been accounted for in previous drills/tests. Due to the lack of
documentation, it was impossible to determine if factoring in the
valve stroke times into the previous tests would have resulted in
test failures.
The licensee agreed that valve stroke times should be included in
any future drill/test used to verify that the SSF could be placed
into operation within 10 minutes. The licensee concluded that
11
valve stroke times would add 56 seconds to the Unit 1 activation
time, 75 seconds to Unit 2, and 58 seconds to Unit 3.
On December 7, 1994, the inspectors observed a special drill which
was conducted to verify that the SSF could be placed in service
within 10 minutes with valve stroke times included. The
licensee's scenario for this drill assumed all Turbine Building
components were simultaneously destroyed by a fire. This required
full activation of the SSF in order to provide Reactor Coolant
Makeup and Auxiliary Service Water to all three Oconee units. The
results of the drill were as follows:
Unit 1:
9:46
Unit 2:
10:48
Unit 3:
10:00 (times in minutes:seconds)
A conference call was held between the licensee and NRC (Region II
and NRR) to discuss issues associated with the recent drill
failures. During the call the licensee maintained that the recent
drill failures indicated the need for additional operator training
and procedural enhancements, but did not indicate that the SSF was
inoperable. The licensee subsequently conducted additional
operator training and revised the SSF activation procedure. The
licensee then performed another three unit drill scenario on
December 20, 1994, similar to the one conducted on December 7,
1994. The results of the drill were as follows:
Unit 1:
6:17
Unit 2:
6:05
Unit 3:
6:18
(times in minutes:seconds)
The licensee indicated that they would continue to perform
periodic drills in order to test all shift personnel.
The
inspectors will continue to follow the licensee's drills. Based
on the last drill, the inspectors concluded that the licensee's
training and procedures had improved sufficiently to provide
reasonable assurance that the SSF could be manned within 10
minutes. The inspectors concluded that the failure to factor in
valve stroke times in drills conducted prior to December 7, 1994,
constituted a weakness in the licensee's test program for the SSF.
8.
Review of Licensee Event Reports (92700)
The below listed Licensee Event Reports (LER) were reviewed to determine
if the information provided met NRC requirements. The determination
included: adequacy of description, compliance with Technical
Specification and regulatory requirements, corrective actions taken,
existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of each event. The
following LERs were closed:
12
a.
(Closed) LER 269/92-09:
Unit 1 RCP Seal Leakage Exceeds 4 1/2
Gallons
The licensee made an evaluation on July 22, 1992, that the SSF
Make-up Pump (MUP) was inoperable when Unit 1 was shut down on May
24, 1992, due to a capacity restraint that was exceeded when 1A2
RCP seal leakage exceeded 4.5 gpm. During the unit shutdown, the
RCP seals were inspected. It was discovered that obsolete (black)
seals had been installed in each of the RCPs and this was the
source of the excess leakage observed from the 1A2 RCP seal.
The
obsolete seals were replaced with the proper seals (tan) and the
unit was returned to service on June 9, 1992. In addition, the
obsolete seals were removed from inventory and maintenance
procedure, MP/A/A/1310/004A, Seals RCP - Westinghouse Controlled
Leakage - Removal, Inspection, and Installation was revised to
specify the correct seals to be installed.
On December 14, 1994, the inspector reviewed the referenced
procedure change (change 22) and both the supply and seal return
flows for the Unit 1 RCPs. The corrective actions taken by the
licensee were determined to be acceptable. Accordingly, this LER
is considered closed.
b.
(Closed) LER 270/93-01:
U2 Trip/KI Loss/Loss of Main Feedwater
During a shutdown of Unit 2 for a refueling outage on April 4,
1993, alarm "MS Pressure Mismatch" annunciated. The reactor
temperature was at 536 degrees F and the turbine bypass valves
were closed. At that time, control room indicators began to
fluctuate and the operating feedwater pump tripped. The reactor
operator manually tripped the reactor.
During the event, the operators found that the 2A turbine bypass
valves were tripped to manual and throttled. The partially open
2A bypass valves had been responsible for the erratic indications
observed. The operator took manual control and closed both the 2A
and 2B bypass valves to control steam line pressure and reactor
cooldown.
The opening of the 2A bypass valves was determined to have been
caused by a momentary loss of the 2KI inverter power prior to
rapid transfer to the backup power supply. The loss of the 2KI
power was a result of a blown fuse. It was further learned that
when the 2KI was re-powered from the backup source, the Static
Analog Memory (SAM) module allowed the bypass valves to reset at a
random position. A similar event occurred in Unit 3 on August 10,
1994, following a loss of the "3KI" inverter. Again, the SAM
module allowed the turbine bypass valves to reset at random
positions. However, the 1994 event resulted in a dryout of the 3B
Once Through Steam Generator and the licensee had to enter the
Emergency Operating Procedures to recover the plant. Violation
269,270,287/94-23-94 was issued because of the licensee's failure
13
to take the necessary actions to correct the bypass valve problem
in a timely manner.
The licensee determined the inverters (i.e., KI, KU, and KX) to be
aged and no longer reliable. As.a result, the inverters on Units
1 & 2 have been replaced and those for Unit 3 have been procured
and scheduled for replacement during the next refueling outage.
The SAM modules were finally replaced after the August 10, 1994
event with modules which reset the turbine bypass valves back to
the closed position after a power loss.
Based on the licensee's evaluations and corrective actions, this
LER is closed.
c.
(Closed) LER 270-92-04: Loss of Off-site Power and Unit Trip Due
To Management Deficiency, Less Than Adequate Corrective Action
Program
On October 19, Oconee Unit 2 experienced a Loss of Off-site Power
event, a generator load rejection, and a Unit 2 trip from 100
percent power. A battery charger had been placed in service
without a connected battery. This produced excessive voltage
swings which caused a series of switchyard breaker failure relays
to actuate, locking out both the red and yellow buses in the 230
KV switchyard. These relays had previously been identified by the
licensee as susceptible to spurious operation due to excessive
voltages in 1980, but were not modified as recommended by the
manufacturer (Westinghouse). Lockout of the switchyard caused a
Unit 2 trip, a temporary loss of power, and startup of the
emergency power source (a Keowee emergency generator).
During recovery, the Keowee operator reset the emergency start
signal, which tripped the emergency generator and resulted in a
second loss of power on Oconee Unit 2.
Extensive corrective actions proposed in this event report have
been completed with the exception of an upgrade in the emergency
lighting at Keowee, which is currently scheduled for November
1995. The proposed corrective actions have been reviewed and
found acceptable.
This item is considered closed.
9.
Exit Interview
The inspection scope and findings were summarized on January 5, 1995,
with those persons indicated in paragraph 1 above. The inspectors
described the areas inspected and discussed in detail the inspection
findings in the summary and listed below. The licensee did not identify
14
as proprietary any of the material provided to or reviewed by the
inspectors during this inspection.
Item Number
Description/Reference Paragraph
50-269,270,287/94-38-01
VIOLATION: Failure to Follow Keowee
Transfer Procedure (paragraph 2e).