ML16148A837
| ML16148A837 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 10/18/1993 |
| From: | Harmon P, Keller L, Lesser M, Miller W, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A836 | List: |
| References | |
| 50-269-93-24, 50-270-93-24, 50-287-93-24, NUDOCS 9311080250 | |
| Download: ML16148A837 (20) | |
See also: IR 05000269/1993024
Text
gA RE(;,,
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
0 8101
MARIETTA STREET, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.: 50-269/93-24, 50-270/93-24 and 50-287/93-24
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC 28242-0001
Docket Nos.:
50-269, 50-270, 50-287, 72-4
License Nos.: DPR-38, DPR-47, DPR-55, SNM-2503
Facility Name:
Oconee Nuclear Station
Inspection Conducte
August 29 -
September 25, 1993
Inspector:
'15b-
____/
PE.mon,
Senior Resident Inspector
Date Signed
6 (2-/
W. K.
tner, Resident Inspector
Date Signed
er, Resident Inspector
Date Signed
W. H. Mller, Jr., Project Engineer
Date Signed
Approved by:?V
M. S. Lesser, Setion Chief,
Date Signed
Reactor Projects Section 3A
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
Keowee issues, review of licensee event reports and review of
licensee's employee concerns program (Attachment 1).
Results:
Two violations were identified. The first violation involved
inadequacies in the licensee's test program which resulted in a
Unit 3 load shed channel being inoperable for approximately six
years (paragraph 2.h).
The second violation involved a failure to
implement the fire protection plan testing requirements contained
in the Selected Licensee Commitments Manual (paragraph 6).
9311080250 931019
PDR ADOCK 05000269
a
t
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- H. Barron, Station Manager
S. Benesole, Safety Review Manager
D. Coyle, Systems Engineering Manager
- J. Davis, Safety Assurance Manager
T. Coutu, Operations Support Manager
B. Dolan, Manager, Mechanical/Nuclear Engineering
W. Foster, Superintendent, Mechanical Maintenance
- J. Hampton, Vice President, Oconee Site
D. Hubbard, Component Engineering Manager
C. Little, Superintendent, Instrument and Electrical (I&E)
- M. Patrick, Regulatory Compliance Manager
- B. Peele, Engineering Manager
- S Perry, 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.
NRC Resident Inspectors
P. Harmon
- W Poertner
- L. Keller
- 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
0.Hro
2
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 alarms and were cognizant of plant
conditions.
Plant tours were taken throughout the reporting period on a
routine basis. The areas toured included the following:
Turbine Building
Auxiliary Building
CCW Intake Structure
Independent Spent Fuel Storage Facility
Units 1, 2 and 3 Electrical Equipment Rooms
Units 1, 2 and 3 Cable Spreading Rooms
Units 1, 2 and 3 Penetration Rooms
Units 1, 2 and 3 Spent fuel Pool Rooms
Station Yard Within the Protected Area
Standby Shutdown Facility
Keowee Hydro Station
During the plant tours, ongoing activities, housekeeping,
security, equipment status, and radiation control practices were
observed.
b.
Plant Status
Units 1, 2, and 3 operated at power the entire reporting period.
c.
LPSW Valve Failure
At 1:10 p.m. on September 1, valve 2LPSW-51 failed close while in
the automatic mode of operation. Valve 2LPSW-51 is the Unit 2
main turbine oil cooler temperature control valve and throttles
low pressure service water (LPSW) flow to the main turbine oil
tank to maintain oil temperature at setpoint. When 2LPSW-51
failed close, oil temperatures increased until a main turbine oil
cooler outlet temperature alarm (117 degrees) was received in the
control room. Temperature alarms were also received on turbine
bearings 4 and 5. The operators immediately diagnosed the cause
of the temperature alarms and placed the 2LPSW-51 controller in
manual and opened the valve to reestablish LPSW flow to the oil
cooler. The licensee determined that the oil temperature detector
had failed low resulting in a close signal being applied to the
valve controller. The licensee repaired the temperature detector
and returned the valve to automatic control.
d.
Mispositioned Containment Isolation Valve
On September 2, the licensee found valve 2CF-41 approximately 7
turns open. Valve 2CF-41 is a normally closed 3/4 inch instrument
3
root valve on the Core Flood Tank 2B fill line and is a
containment isolation valve. The mispositioned valve was
identified by a non-licensed operator during makeup to Core Flood
Tank 2B when 600 psig was indicated on the local gage downstream
of valve 2CF-41. The non-licensed operator notified the control
room and the valve was determined to be approximately 7 turns
open. Valve 2CF-41 was closed and the operators verified that the
root valve on the Core Flood Tank 2A fill line was closed and that
the corresponding valves on Units 1 and 3 were also in their
required positions. Subsequent to finding valve 2CF-41 open, the
licensee reperformed the Outside Reactor Building Manual Isolation
Valve Checklist, PT/2/A/115/08, Enclosure 13.3. No other
containment isolation valves were found mispositioned.
PT/2/A/115/08, Enclosure 13.3, had last been completed on June 18.
The licensee did not identify any evolutions since the last
completion date of the procedure that would have opened valve 2CF
41. The licensee will issue a Licensee Event Report (LER) as
required by 10 CFR 50.73. The inspectors will follow this item by
review of the licensee LER.
e.
Inoperable Reactor Building Radiation Monitors.
At 10:10 p.m. on September 3, the licensee declared the Unit 3
reactor building radiation monitors 3RIA-47,48,49 and 49A
inoperable due to water intrusion in the sample lines. The sample
lines were drained, however, subsequent monitoring determined that
water accumulation continued to occur in the sample lines. A
reactor building entry was made at 2:15 a.m. on September 5 and
the licensee determined that valve 3FDW-253 had a bonnet to body
leak and that steam was being entrained in the monitor sample
piping inlets. Valve 3FDW-253 is a 1 inch vent valve located on
the 3B steam generator feedwater line inside the reactor building.
The licensee redirected the steam leak by draping the valve with
welding cloth and securing it to the piping.
The licensee
returned the instruments to service and monitored for water
intrusion. The instruments were declared operable at 3:00 p.m. on
September 5 after the instruments exhibited expected radiation
values and trends. The licensee performed an online leak repair
of valve 3FDW-253 on September 8 to stop the body to bonnet leak
and prevent further steam cutting of the valve.
f.
C LPSW Pump Motor Replacement
At 2:32 p.m. on September 15, the licensee removed Units 1 and 2,
C LPSW pump from service to replace the pump motor due to elevated
motor winding temperatures. The licensee had previously replaced
the B LPSW pump motor for Units 1 and 2 on April 29, 1993, due to
elevated stator temperatures and had replaced the 3A LPSW pump
motor on June 30, 1993, due to a motor failure caused by
insulation breakdown on the X phase motor winding. The C LPSW
pump motor was replaced and the pump returned to service at
4
6:03 a.m. on September 16. The pump motor replacement went
smoothly and the pump was returned to service within the TS
required time frame.
g.
Independent Spent Fuel Storage Installation (ISFSI) Cask
Mispositioned in the Unit 3 Spent Fuel Pool.
At approximately 8:00 a.m. on September 20, the ISFSI storage cask
was misaligned in the Unit 3 Spent Fuel Pool.
The licensee was
placing the empty cask on the cask pit stand located in the north
east corner of the spent fuel pool when the cask was mispositioned
on the stand, resulting in the cask leaning against the north end
of the spent fuel pool.
The maintenance personnel involved in
moving the cask attempted to lift the storage cask to realign the
cask to the stand, at which time the lifting hook on the cask
trunion located opposite of the spent fuel pool wall shifted, the
trunion end cap was knocked off and the lifting hook slipped
partially off the trunion. The trunion end cap is not designed to
withstand the lifting forces involved in moving the cask but
provides guidance for the lifting hook until the hook is fully
engaged and supporting the load. With the cask cocked on the
stand the trunions were not horizontal and the one lifting hook
engaged its respective trunion, lifting the cask and allowing the
other lifting hook to shift and engage against the trunion end
cap. The licensee stopped movement of the cask with one corner of
the cask resting on the stand guide and the other corner
approximately 3 inches above the stand with both lifting hooks
partially supporting the load. The licensee secured the cask in
its present position by opening the supply breaker to the crane
and commenced to determine corrective actions to retrieve the cask
from the spent fuel pool.
The licensee initially decided to
remove the spent fuel from the fuel racks adjacent to the cask to
establish a safe radius and to ensure that fuel assemblies would
not be damaged if the cask toppled over during recovery efforts.
The licensee determined that 136 fuel assemblies had to be moved
from the adjacent fuel racks and commenced fuel movement to
relocate the assemblies in the spent fuel pool.
Fuel movement was
completed on September 22.
In conjunction with the fuel movement activities, the licensee
developed a plan and procedure to retrieve the cask from the spent
fuel pool.
The licensee's retrieval plan involved securing the
lifting hooks with a temporary collar, placing shims under the
cask to prevent excessive tilting, lowering the cask to allow the
temporary collar to be tightened to ensure full engagement of the
lifting hook on the trunions, lifting the cask and placing it
securely on the stand, removing the lifting rig for inspection,
reattachment of the lifting rig to the cask, and removal of the
cask from the spent fuel pool into the cask storage pit located
adjacent to the spent fuel pool.
5
The licensee commenced cask retrieval efforts on September 25 and
completed the transfer of the cask to the storage pit on
September 27.
The inspectors monitored the licensee;s activities
in the spent fuel pool .and witnessed cask retrieval evolutions in
progress. The licensee's efforts were deliberate and accomplished
in a controlled manner. Preliminary inspections of the cask did
not identify any damage. The licensee does not plan to
reintroduce the cask into the spent fuel pool until a root cause
evaluation is completed and corrective actions implemented to
prevent recurrence. The inspectors will follow the licensee's
actions in this area.
h.
Load Shed Channel 1
During the previous inspection period (NRC Inspection Report
269,270,287/93-22) the inspectors identified an Unresolved Item
concerning the past operability of Unit 3 Load Shed Channel 1.
The past operability concern resulted from the fact that the load
shed channel 1 slave relay in switchgear 3TD had been incorrectly
wired to a 120 VAC power supply in 1987, during implementation of
a modification package. The item was identified as an unresolved
item because the licensee had not completed the past operability
evaluation but had stated that the preliminary review indicated
that the channel had been operable.
The licensee completed the past operability evaluation during this
inspection period and provided the evaluation to the inspectors
for review. The licensee justification for operability was based
on the operability of the other load shed channel and non-safety
related undervoltage relays that would accomplish the load shed
function independently of the load shed channels. Technical
Specification 3.7.1.c requires that the emergency power switching
logic circuitry be operable as specified by the conditions of
Table 3.7-1.
Table 3.7-1 requires that two circuits/channels of
load shed and transfer to standby circuits (Channels A and B) be
operable during normal operation. The undervoltage relays are not
considered a portion of the emergency power switching logic
circuitry, are not considered technical specification required
components, are not safety related, and are not controlled as part
of the licensee's quality assurance program.
The inspectors discussed the issue with Region II,
review the licensee position with respect to the past operability
of load shed channel 1 and the incorrect wiring of the switchgear
3TD channel 1 load shed slave relay. It was concluded that the
post modification testing performed after implementation of
modification TN/3/A/1426/00/0 had been inadequate and that the
load shed channel had been inoperable since 1987 when the
modification was implemented. The failure to establish an
adequate post modification test program on the Unit 3 Load Shed
Channel 1 circuity following the performance of Modification
Package TN/3/A/1426/00/0, resulting in the incorrect wiring of the
6
load shed channel 1 slave relay in switchgear 3TD going undetected
and the channel being inoperable from March 1987 to August 1993 is
identified as Violation 287/93-24-01: Inadequate Post Modification
test Program.
Within the areas reviewed, one violation was identified.
3.
Surveillance Testing (61726)
Surveillance tests were reviewed by the inspectors to verify procedural
and performance adequacy. The completed tests reviewed were examined
for necessary test prerequisites, instructions, acceptance criteria,
technical content, authorization to begin work, data collection,
independent verification where required, handling of deficiencies noted,
and review of completed work. The inspectors witnessed the tests, in
whole or in part, to verify that approved procedures were available,
test equipment was calibrated, prerequisites were met, tests were
conducted according to procedure, test results were acceptable and
systems restoration was completed.
Surveillances reviewed and witnessed in whole or in part:
-
TI/2/A/3001/12A, Functional Test for 2RC-4 Indication Lights.
This special test procedure verified proper operation of the open
and closed indicating lights for valve 2RC-4, Pressurizer PORV
Block Valve, in the Safe Shutdown Facility (SSF) control room.
The inspectors reviewed the special test procedure, witnessed the
performance of the test from the SSF control room, and verified
that the acceptance criteria was met.
-
PT/0/A/0620/16, Keowee Hydro Emergency Start Test. The inspectors
observed the performance of this technical specification required
surveillance procedure on September 16 and September 20. On
September 16 the Keowee Unit 1 generator breaker failed to close.
On September 20, Keowee Unit 1 started but did not obtain expected
voltage of 13.8 KV. The voltage regulator was adjusted and the
test reperformed satisfactorily. This item is discussed in more
detail in paragraph 5.
Within the areas reviewed, licensee activities were satisfactory.
No violations or deviations were identified.
4.
Maintenance Activities (62703)
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 trade. Activities, procedures, and work
requests were examined to verify that proper authorization to begin work
was given, provisions for fire were made, cleanliness was maintained,
7
exposure was controlled, equipment was properly returned to service, and
limiting conditions for operation were met.
Maintenance activities reviewed and witnessed in whole or in part:
-
WR 93030743, Install Wiring and Test 2RC-4. This maintenance
activity installed a jumper in the control circuitry for valve
2RC-4, pressurizer PORV block valve, to provide power to the open
indicating light in the SSF control room during an SSF event.
This jumper had been inadvertently deleted during a previous
modification package and was identified as Violation 270/93-21-01
in NRC Inspection Report No. 269,270,287/93-21. The inspectors
reviewed the work package and observed the installation of the
jumper.
Within the areas reviewed, licensee activities were satisfactory.
No violations or deviations were identified.
5.
Keowee Issues
a.
Both Keowee Units out of Service for Modification
At 7:34 a.m. on September 7, both Keowee units were removed from
service to allow implementation of modification 52930, Replacement
of Keowee Transfer Circuitry for Switchgear 1X and 2X., Technical
Specification 3.7.6 allows both Keowee units to be removed from
service for 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> provided the outage is scheduled and the 4160
volt standby busses are energized by a Lee Gas Turbine through a
dedicated transmission line. The purpose of the modification
package was to modify the Keowee auxiliary transfer logic scheme
to allow the Keowee unit aligned to the underground path to be
powered from the underground path and the Keowee unit aligned to
the overhead path to be powered from the overhead path. The
modification also modified the transfer to backup power supply
scheme to allow power to be restored to the preferred power supply
before transfer to the backup power supply occurred. The
modification was implemented and the Keowee units were returned to
service at 12:51 a.m. on September 8.
b.
Keowee Unit 1 Failure to Start
On September 16, the inspectors witnessed the licensee's
performance of surveillance PT/0/A/0620/16, Keowee Hydro Emergency
Start Test. This test demonstrates the following: 1) operability
of each Keowee Hydro units' emergency start circuitry from the
Oconee Control Rooms; 2) the ability of the Keowee units to reach
rated speed and voltage within 23 seconds; 3) the ability of the
Keowee units to supply 25 MW or greater to the system grid; and 4)
verification of the setpoints for time-delay relays 52-1TD and 52
2TD for the close permissive signal to the generator output
breakers ACB-1 and ACB-2. Both of the Keowee units received a
8
start signal and Unit 2 reached rated speed and voltage
satisfactorily. However, the Unit 1 generator supply breaker
(Device No. 41-52) did not close and the unit did not develop an
output voltage. The breaker closing coil energized but the
breaker did not fully actuate and the closing coil overheated.
This placed Keowee Unit 1 out of service and put the Oconee site
in a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> LCO per TS Section 3.7.2. The licensee promptly
realigned Keowee Unit 2 from the overhead path to the underground
path and verified that the unit was operable. Subsequent
evaluation by the licensee determined that the breaker failure was
internal to the breaker itself. The licensee initially indicated
that the breaker failure was caused by high resistance in the
closing coil contacts. The theory developed was that the high
resistance value reduced the current to the closing coil to a
value that would not close the breaker and that the closing coil
remained energized and eventually overheated. The licensee
replaced the generator breaker and performed the monthly
performance test to verify operability of Keowee Unit 1. The
monthly test starts the unit from the Oconee control room. The
inspectors questioned the decision not to perform the emergency
start test to verify operability. The licensee indicated that
personnel considerations precluded the test from continuing in
that personnel availability would be impacted since the test had
been performed just prior to the end of the scheduled workweek.
The licensee justified that performance of the monthly test would
verify operability of the generator supply breaker. The licensee
completed the Keowee emergency start test on Monday September 20.
Subsequent to replacing the generator supply breaker, the licensee
performed testing on the failed breaker. The licensee determined
that with 8 amps supplied to the closing coil, the breaker.closed
as designed. The normal current at full voltage is approximately
22 amps. The licensee also determined that current value too low
to prevent the breaker from operating did not overheat the closing
coil enough to cause damage. The licensee determined that full
voltage and current were required to overheat the closing coil to
the point of damage.. The licensee also determined that the high
resistance measured during the initial troubleshooting was most
likely caused by the overheating of the closing coil.
The coil
resistance increases significantly as the coil temperature
increases. The licensee believes that the resistance values
measured initially were influenced by the elevated coil
temperature. After further review the licensee identified that a
missing cotter pin in the latching mechanism may have caused
mechanical binding and prevented a previous trip signal from fully
resetting. The inspectors will continue to follow the licensee's
investigation.
c.
Keowee Unit 1 Voltage Regulator Set Less Than Rated Voltage
During the performance of PT/0/A/0620/16, Keowee Hydro Emergency
Start Test, on September 20, Keowee Unit 1 started and established
9
rated speed but did not established rated voltage of 13.8 KV. The
machine developed 13.3 KV. The procedure acceptance criteria
required that the machine develop approximately 13.8 KV. The
performance technicians initially discussed signing the step off
as complete based on the 13.3 KV value obtained. Subsequent
discussions determined that the test would be continued and a test
discrepancy initiated to resolve the low voltage concern. Design
engineering was contacted and preliminary discussions determined
that 13.3 KV was acceptable but that the voltage regulator should
be adjusted to 13.8 KV. After completing PT/0/A/0620/16, the
licensee removed Keowee Unit 1 from service to adjust the voltage
regulator. The voltage regulator was adjusted and PT/0/A/0620/16
was reperformed to verify proper operation of the voltage
regulator. The unit was returned to service at approximately 7:08
p.m. later that same day. The licensee determined that the
voltage regulator had been set at 13.3 KV during previous
maintenance activities based on information from design
engineering that the minimum acceptable voltage was 13.2 KV. The
licensee plans to revise the performance test to establish an
acceptable voltage band based on the no-load value of 13.8 KV and
is reviewing the program to ensure that the voltage regulator is
required to be set at 13.8 KV for no-load conditions.
No violations or deviations were identified.
6. 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 reviewed:
a.
(Closed) LER 269/92-11, Potential Single Failure During A
LOCA/LOOP Event May Result in the Loss of Emergency Power Due to
Design Deficiency.
During an engineering review, the licensee identified that a
postulated failure of the Keowee Hydro underground feeder air
circuit breaker could cause closure of the air circuit breaker to
the overhead path on the unit aligned to the underground path.
This could tie both Keowee units together through the main step up
transformer, possibly out of phase, rendering both units
To correct this problem, the control circuitry to the air circuit
breakers were modified by the installation of normally closed
contacts ("B" fingers) to prevent the two Keowee units from
connecting to the overhead path at the same time. Also, Timer 52
1TD was replaced with a timer that has a longer range of
10
adjustment. The new timer is set at 6 seconds instead of 4
seconds. These modifications should prevent both units from
connecting to the overhead line at the same time during emergency
starts when there is a failure of the 13.8 KV underground path to
Oconee. The inspector reviewed Work Request No. 9272588 01, ACB 1
and ACB 2 Interface Modification, and Procedure TN/2/A/0E4673/001,
Install Interlock from ACB 1 to ACB 2 and from ACB 2 to ACB 1
Replace Timer 52-1TD, and verified that this modification was
complete.
In addition, the licensee conducted a single failure analysis of
the Keowee power system. This analysis, Calculation OSC-5096,
Keowee Single Failure Analysis, identified four postulated single
failure problems. As of this inspection the potential single
failures had either been corrected by station modifications or
temporary measures had been implemented to eliminate any single
failure that could render both units inoperable and prevent the
Emergency Power System from performing its intended safety
function. The inspectors reviewed this analysis. The licensee
has completed the corrective actions for this LER.
b.
(Open) LER 269/92-14, Equipment Failure Results in the
Inoperability of Keowee Unit 2 Overhead Emergency Power Path and a
Technical Specification Violation.
While performing post-modification testing, the licensee
identified a failed relay which resulted in the inoperability of
the Keowee Unit 2 overhead emergency power path. The failed relay
was repaired by replacing a plastic stop nut, adjusting the
contact gap according to the manufacturer's instructions and
retesting the relay to ensure operability. To prevent recurrence,
the licensee initiated the following corrective action:
-
Inspect and repair other MG-6 type relays at Oconee and
Keowee.
-
Develop and implement an appropriate Preventive Maintenance
program for the MG-6 type relays.
-
Perform tests per the Keowee Design Basis Document.
The inspectors reviewed the licensee's corrective action and noted
the following status:
MG-6 RELAYS
The MG-6 relay inspection program has been completed for Keowee
(July 1993), Oconee Unit 1 (February 1993) and Oconee Unit 2 (June
1993).
The inspection of the Oconee Unit 3 MG-6 relays is
scheduled to be completed during the next scheduled refueling
outage in early 1994. Presently only four MG-6 relays have been
replaced. Four of the six MG-6 relays installed at Keowee have
11
been replaced with new ITE solid state type relays (Relay Nos.
27X/1X, 27X/2X, 27X/CX1 and 27X/CX2). The inspector reviewed
Procedure TN/5/A/2930/00, Replacement of Keowee Transfer Circuitry
for Switchgear 1X and 2X, which provided instruction and
documentation for the replacement of these four relays. No
discrepancies were noted. The annual performance of
PT/O/A/0620/16, Keowee Hydro Emergency Start Test, verifies the
operability of the new relays. An evaluation by the licensee is
in progress on the remaining two MG-6 relays installed at Keowee
(Relay Nos. 27T/1X and 27T/2X) to determine if these relays should
also be replaced. These relays perform a safety related function
during emergency start of Keowee by providing a time delay to
assure that the Oconee switchyard is isolated prior to Keowee
being aligned to the overhead path. The two remaining MG-6 relays
are verified operable by performance of PT/O/A/0610/22, Degraded
Grid Switchyard Isolation Functional Test, which is presently
proposed to be performed every 18 months. The licensee had not
identified any required modifications, repairs or replacements to
any of the MG-6 relays installed at the Oconee facility. The NRC
will continue to monitor the licensee's actions in this area.
PREVENTIVE MAINTENANCE PROGRAM FOR MG-6 RELAYS
An evaluation is in progress by the licensee to determine the
appropriate items to be included in a preventive maintenance
program for the MG-6 type relays. The results of this evaluation
will be reviewed during a subsequent NRC inspection.
TESTING REQUIREMENT OF KEOWEE DESIGN BASIS DOCUMENT
The LER states that additional tests will be performed on the
systems and components at Keowee as required by the Keowee Design
Basis Document (DBD).
The inspectors reviewed the DBD for Keowee,
OSS-0254.00-00-1031, Design Basis Specification for the Keowee
Systems and OSS-0254.00-00-2005, Keowee Emergency Power Design
Basis Document. The DBD specifies the following tests be
performed to verify that the system or component meet the DBD
requirements. The inspectors verified that an appropriate
procedure had been prepared and implemented to perform the
required test.
TEST/MEASUREMENT
TEST PROCEDURE/(FREQUENCY)
Emergency start Keowee and
PT/O/A/0620/16, Keowee Hydro
accelerate to rated speed within 23
Emergency Start Test. (Annually)
seconds.
12
TEST/MEASUREMENT
TEST PROCEDURE/(FREQUENCY)
Verify emergency start signal to
PT/O/A/0620/16, Keowee Hydro
close permissive signal for ACB-1
Emergency Start Test. (Annually)
and ACB-2 after a 4 second (+1 or -1
second).
Verify operability of overhead
PT/O/A/0610/22, Degraded Grid System
electrical path from Keowee to
Isolation Functional Test. (proposed
Oconee.
for 18 months. First and only test
performed since plant startup was
conducted May 22, 1993.)
Verify operability of underground
PT/0/A/0610/1J, Emergency Power
electrical path from Keowee to
Switching Logic Functional Test.
Oconee.
(Annually)
Verify each Keowee unit transfers
PT/O/A/0620/17, Keowee Manual
from normal power source to standby
Synchronization Test. (Annually)
power source.
Verify each Keowee unit ability to
PT/O/A/0620/16, Keowee Hydro
supply load equivalent to Oconee
Emergency Start Test. (Annually)
emergency load demand.
Verify Keowee transformer fire
MP/O/A/2000/032, Mulsifyre System
protection system will discharge
Semi-Annual Check. (Annual
1060 gpm at 54 psig.
functional test in summer and annual
dry inspection test in winter)
Specification OSS-0254.00-00-1031, Design Basis Specification for
the Keowee Systems, identifies the Keowee Hydro Station's
mechanical systems and components that support the Keowee
emergency power system. The following systems are identified as
having a safety related function:
-
Turbine Generator Cooling Water System
-
Turbine Guide Bearing Oil System
-
Turbine Sump Pump System
-
Generator High Pressure Oil Lift System
-
Governor Air System
-
Governor Oil System
Although the DBD identifies the safety related systems at Keowee,
no tests and measurement requirements Were specified to verify the
operability of these systems. There are a number of pumps,
valves, and instrumentation and control devices which are not
13
periodically tested to verify operability. This issue was
addressed by the NRC Electrical Distribution System Factional
Inspection, NRC Inspection Report 50-269,270,287/93-02, which was
conducted January 25 - March 5, 1993. The licensee, by letter
dated July 6, 1993, committed to develop testing procedures for
these components by December 31, 1993. The preparation of these
procedures was in progress during this inspection period. First
priority had been given to the preparation of test procedures for
active components such as pumps and valves and for instrumentation
and control devices which activate components such as pumps or
valves. Procedures for testing and verification of
instrumentation and control devices which provides a visual
indication, or provides an audible alarm or activates an
annunciator panel will be developed at a later date. The licensee
has not provided a commitment date to the NRC as to when the
operability of all of these components will be verified.
DBD Specification OSS-0254.00-00-2005, Keowee Emergency Power
Design Basis Document, describes the operability requirements for
the Keowee Main Transformer Fire Protection System. These
requirements are verified by performance of surveillance procedure
MP/0/A/2200/032, Mulsifyre System Semi-annual Check. This
procedure requires two tests to be performed each year. One test
is a "dry test" or visual inspection to be performed during the
winter. The other test is a "wet test" or functional test to be
performed during the summer. *The wet test verifies operability of
all components of the fire protection system. The inspectors
reviewed the most recent test performed on April 30, 1992, by
procedure MP/O/A/2200/032 and noted that the Keowee fire pump had
not been tested. Sections 9.5, 11.3.25 and 11.3.26 of the
procedure specifically require the Keowee fire pump to be tested
for operability and to verify that the pump will deliver at least
1060 gpm at a pressure of 54 psi which is adjusted if lake level
is greater than 787.9 feet. Three test points are required to be
obtained and plotted on the Keowee Fire Protection Pump
Performance Curve, Enclosure 13.5 of the procedure. These
procedure steps had been deleted from the 1992 test procedure by
the "N/A" notation. The pump was not tested and verified operable
by measuring.discharge flow and pressure due to problems with a
portable flow test meter.
Upon further investigation, the inspectors determined that the
last operability test of the Keowee fire pump was performed on
October 31, 1990. Using this date as the base for establishing
the annual functional test schedule, the next test date would have
been required October 31, 1991.
However, a date of May 1, 1992,
would fall within the six month grace period permitted by TS
required surveillances. The 1991 annual test was performed on
April 30, 1992, but this test did not perform an operability test
and evaluation of the fire pump.
14
Selected Licensee Commitment Manual, Section 16.9.2, Sprinkler and
Spray Systems, Surveillance Item a.i, requires that the Keowee
Main Transformer Fire Protection System be functionally tested
annually. The failure to perform an annual functional test of the
fire pump, which is a component of the Main Transformer Fire
Protection System, is identified as Violation 269,270,287/93-24
02: Failure to Perform Functional Test of Keowee Main Transformer
Fire Protection System.
The pump was subsequently tested using a special test procedure.
This test indicated that with a Keowee Lake level above 795.5
feet, the pump would deliver the required flow of 1060 gpm at a
discharge pressure of 54 psi.
However, the difference between the
pump discharge pressure and suction pressure did not meet the past
operability requirements for the pump with a lower lake level.
Selected Licensee Commitment Manual Section 16.9.7, Keowee Lake
Level, required lake level be maintained at a level of 787.9 feet
or greater in order for the Keowee Main Transformer Fire
Protection System to be operable. Presently, the pump will not
meet the operability requirements with lake level below 795.5,
therefore the licensee has revised Selected Licensee Commitment
16.9.7 to require lake level be maintained above 795.5 for Keowee
Main Transformer Fire Protection System operability and is
evaluating corrective actions to return the system to its original
design capabilities. The licensee reviewed Keowee Lake levels to
verify that lake level had not dropped below 795.5 since the last
time the pump was verified operable.
Within the areas reviewed, one violation was identified.
7.
Employee Concerns Program (TI 2500/028)
The inspectors reviewed the licensee's employee concerns program to
determine if the the licensee had implemented a program to provide
employees, who wish to raise safety issues, an alternate path from their
normal line management to express these concerns and to encourage people
to come forward with their concerns without fear of retribution. The
results of this review are documented on the attached form.
8.
Exit Interview
The inspection scope and findings were summarized on September 28, with
those persons indicated in paragraph I above. The inspectors described
the areas inspected and discussed in detail the inspection findings.
No dissenting comments were received from the licensee. The licensee
did not identify as proprietary any of the material provided to or
reviewed by the inspectors during this inspection.
15
Item Number
Description/Reference Paragraph
VIO 50-287/93-24-01
Inadequate Post Modification Test Program
(paragraph 2.h).
VIO 50-269,270,287/93-24-02
Failure to Perform Functional Test of
Keowee Main Transformer Fire Protection
System (paragraph 6)
Attachment
EMPLOYEE CONCERNS PROGRAMS
PLANT NAME: OCONEE
LICENSEE: Duke Power
DOCKET #: 50-269, 270. 287
NOTE: Please circle yes or no if applicable and add comments in the space
provided.
A.
PROGRAM:
1. Does the licensee have an employee concerns program?
(Yes or No/Comments)
Yes
2. Has NRC inspected the program? Report #
No
B.
SCOPE: (Circle all that apply)
1. Is it for:
a. Technical? (Yes, No/Comments)
Yes
b. Administrative? (Yes, No/Comments)
Yes
c. Personnel issues? (Yes, No/Comments)
Yes
2. Does it cover safety as well as non-safety issues?
(Yes or No/Comments)
Yes
3. Is it designed for:
a. Nuclear safety? (Yes, No/Comments)
Yes
b. Personal safety? (Yes, No/Coments)
Yes
c. Personnel issues - including union grievances?
(Yes or No/Comments)
Yes
Issue Date:
XX/XX/XX
- 1 -
2500/XXX
4. Does the program apply to all licensee employees?
(Yes or No/Comments)
Yes
5. Contractors?
(Yes or No/Comments)
Contractor employees may raise safety concerns by contracting the
station's Safety Assurance Manager.
6. Does the licensee require its contractors and their subs to have a
similar program?
(Yes or No/Comments)
No
7. Does
the licensee conduct an exit interview upon terminating
employees asking if they have any safety concerns?
(Yes or No/Comments)
Yes
C.
INDEPENDENCE:
1. What is the title of the person in charge?
None
2. Who do they report to?
Corporate Management
3. Are they independent of line management?
Sometimes
4. Does the ECP use third party consultants?
No
5. How is a concern about a manager or vice president followed up?
By Human Resources and Executive Management
D.
RESOURCES:
1. What is the size of staff devoted to this program?
Oconee Human Resources Staff - 8, but not devoted full time.
2. What are ECP staff qualifications (technical training,
interviewing training, investigator training, other)?
Tyoically four years work experience in the Human Resource area.
2500/XXX
- 2 -
Issue Date:
XX/XX/XX
E.
REFERRALS:
1. Who has followup on concerns (ECP staff, line management,
other)?
Human Resources Staff
Safety Assurance Management
F.
CONFIDENTIALITY:
1. Are the reports confidential?
(Yes or No/Comments)
Yes
2. Who is the identity of the alleger made known to (senior management,
ECP staff, line management, other)?
(Circle, if other explain)
Human Resources staff professional working on the investigation.
3. Can employees be:
a. Anonymous? (Yes, No/Coments)
Yes
b. Report by phone? (Yes, No/Comments)
- I
Yes
G.
FEEDBACK:
1. Is feedback given to the alleger upon completion of the followup?
(Yes or No - If so, how?)
Yes
2. Does program reward good ideas?
No
3. Who, or at what level, makes the final decision of resolution?
No level defined.
4. Are the resolutions of anonymous concerns disseminated?
Changes are communicated.
5. Are resolutions of valid concerns publicized (newsletter,
bulletin board, all hands meeting, other)?
Changes are communicated.
Issue Date:
XX/XX/XX
- 3 -
2500/XXX
H.
EFFECTIVENESS:
1. How does the licensee measure the effectiveness of the program?
Employee feedback, employee opinion survey.
2. Are concerns:
a. Trended? (Yes or No/Comments)
Yes
b. Used? (Yes or No/Comments)
Yes
3. In the last three years how many concerns were raised?
Closed? ______
What percentage were substantiated?
No technical concerns were raised.
4. How are followup techniques used to measure effectiveness
(random survey, interviews, other)?
Employee opinion survey
5. How frequently are internal audits of the ECP conducted and by
whom?
No audits performed.
I.
ADMINISTRATION/TRAINING:
1. Is ECP prescribed by a procedure? (Yes or No/Comments)
Yes
2. How are employees,
as well as contractors,
made aware of this
program (training, newsletter, bulletin board, other)?
Employee Benefits material,
Company Procedure Manual, notices GET
Training and Orientation training for new employees.
ADDITIONAL COMMENTS:
(Including characteristics which make
the program
especially effective or ineffective.)
The licensee's ECP program is primarily an administrative and personnel conerns
program.
The person completing this form please provide the following information to the
Regional Office Allegations Coordinator and fax it to Richard Rosano at 301-504
3431.
NAME:
TITLE:
PHONE #:
W. K. Poertner/ Resident Inspector/(803) 882-6927 DATE COMPLETED: 9/10/93
2500/XXX
- 4 -
Issue Date:
XX/XX/XX