ML16148A828
| ML16148A828 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 09/16/1993 |
| From: | Harmon P, Keller L, Lesser M, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A827 | List: |
| References | |
| 50-269-93-22, 50-270-93-22, 50-287-93-22, NUDOCS 9309280251 | |
| Download: ML16148A828 (11) | |
See also: IR 05000269/1993022
Text
GRE
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
s ~101
MARIETTA STREqT, N.W., SUITE 2900
ATLANTA, GEORGIA 30323-0199
Report Nos.:
50-269/93-22, 50-270/93-22 and 50-287/93-22
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 Condu
d: July 25 - August 28, 1993
Inspect r-
A
cHarmon,
Senior Resident Inspector
Date Signed
L.
Keller, Resident Inspector
Date Signed
K. Poertner, Resident Inspector
Date Signed
Approved by:
?
L/
3
M. S. Lesser, Section Chief
Date Signed
Projects Section 3A
Division of Reactor Projects
SUMMARY
Scope:
This routine, resident inspection was conducted in the areas of
plant operations, surveillance testing, maintenance activities,
Keowee issues, inspection of open items and review of licensee
event reports.
Results:
One Deviation from commitments was identified. The Deviation
involved a failure to calibrate the Unit 1, 125 VDC ground detec
tor circuitry annually as committed in response to a previous
violation (paragraph 2.d).
One Unresolved Item (URI) was identified. The URI involved the
past operability of load shed channel 1 when powered from a 120
VAC power supply instead of 125 VDC control power (paragraph 2.c).
9309280251 930917
PDR ADOCK 05000269
0
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, Work Control Superintendent
- R. Sweigart, Operations Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
NRC Resident Inspectors
P. Harmon
- W. Poertner
- L. Keller
NRC Personnel
- 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. Some inspections were made
during shift change in order to evaluate shift turnover
performance. Actions observed were conducted as required by the
2
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. During the plant tours, ongoing activities,
housekeeping, security, equipment status, and radiation control
practices were observed.
b.
Plant Status
Unit 1 operated at power for most of the reporting period. On
August 23, the Unit experienced a turbine/reactor trip from full
power on loss of DC power to a panelboard during testing
activities. The loss of power occurred due to an improperly wired
circuit breaker. Refer to paragraph 2.e for details. The Unit
was returned to power operation on August 26.
Unit 2 operated at power for most of the reporting period. On
August 25, the Unit experienced a reactor trip from full power
when an operator inadvertently pulled a Unit 2 "Z" phase relaying
potential drawer during Unit I tagging activities. Refer to
paragraph 2.f for details. The Unit was returned to power
operation on August 26.
Unit 3 operated at power the entire reporting period.
C.
Unit 3 Load Shed Channel 1
On August 3, the Licensee determined that Unit 3 load shed relay
374LSDI, located in switchgear 3TD, was fed from 120 volt AC power
instead of 125 volt DC control power as required by the wiring
diagrams. The licensee discovered this error as the result of an
ongoing wiring verification program. The licensee declared load
shed channel 1.inoperable at 4:00 p.m. and initiated a work
request to correct the wiring deficiency. The licensee also
initiated the problem investigation process (PIP) to determine how
the wiring error had occurred. The wiring was returned to normal
and load shed channel 1 was declared operable at 7:40 p.m. on
August 3.
Subsequent to this event, the licensee determined that a
modification had been performed in 1987 to provide a dedicated
fuse block for the load shed initiate coils contained in the
associated 4160 volt switchgear on all three units. During the
implementation of this modification the channel 1 load shed relay
for switchgear 3TD was connected to a 120 volt AC fuse block
located in the same breaker cubicle as the 125 volt DC fuse block
which was identified in the modification package as the proper
termination point.
3
The 120 volt AC power that was connected to the load shed relay is
supplied from a 4160V/120V transformer connected to switchgear 3TD
and used for indication and relaying on the 3TD switchgear. The
effect of supplying the 374LSD1 relay from its associated 4160
volt switchgear would be that the channel 1 load shed signal for
switchgear 3TD would not occur until after power was restored to
the switchgear following a loss of offsite power event.
The inspectors reviewed modification procedure, TN/3/A/1426/00/0,
that implemented the design change to install the dedicated fuse
block, and determined that the procedure had required that the
wiring be verified by two electricians and a QC inspector during
the installation process. The inspectors also identified that the
post modification testing performed after the modification had
been completed had not identified that the modification was wired
incorrectly and that subsequent load shed testing had also not
identified the incorrect wiring.
The inspectors held discussions with the licensee throughout the
inspection period concerning the past operability of load shed
channel 1. The licensee had not completed the past operability
evaluation by the end of the inspection period but stated that the
preliminary review indicated that the channel was operable when
connected to the 120 volt AC power supply. The inspectors
expressed concern about the operability of relay 374LSD1 when
powered from the 120 volt AC supply and requested that the
operability evaluation be provided for review when completed.
This item is identified as Unresolved Item 287/93-22-01: Load Shed
Channel 1 Operability, pending completion of the licensee's past
operability determination and review by the inspectors.
d.
DC Ground on Switchgear 1TA
On August 9, the inspector noted that the "DC System Trouble"
annunciators were in alarm for both trains of all three units.
The licensee indicated that the cause of the annunciator alarm was
a low resistance or "hard" ground (approximately 180 ohms) on the
positive leg from panelboard DIA, located downstream of breaker 31
(OEE-117-31) which is the feeder breaker for control power to
reactor coolant pump (RCP) 1B1. This portion of the DC control
system is non-safety related, but is directly tied to the safety
related 125 volt DC panelboard. At Oconee, numerous non-safety
loads are powered from the safety-related DC bus. The ground had
.been present since July 17, 1993. On July 22, I&E technicians
were able to trace the ground to the 181 RCP switchgear. After
narrowing the general location of the ground to the feeder for the
IBI RCP switchgear, the licensee deferred further work on
correcting or isolating the ground due to the perceived risk of
tripping the RCP. The licensee indicated that it was consistent
with the design of the vital DC system for a single ground to show
up on all three units due to all the units' DC systems being
interconnected through the auctioneering diode assemblies. The
4
inspector noted that these alarms would not reflash if another
positive ground occurred anywhere in the DC distribution systems
for all three units. The inspector was also concerned that there
were no compensatory actions to monitor for further positive
grounds.
The inspector noted that the control room annunciators that were
locked into alarm were shared annunciators which also provided
alarms for other conditions such as battery charger trouble,
charger output breaker tripped, and DC bus voltage low. These
other potential alarm conditions would have been masked in the
control room due to the continued presence of the ground. There
were no compensatory measures established to check for these
conditions other than normal operator rounds once a shift to check
local alarm panels.
The inspector reviewed open work requests for the vital DC system
and found that for all three units there were ten (10) open work
requests dealing with grounds (both positive and negative) and/or
the inability to calibrate ground detectors. The ground detectors
cannot be calibrated while grounds exist in the circuit. With the
exception of the hard ground discussed above, the grounds were
intermittent in nature and therefore the licensee was unable to
identify the location of the grounds. Some of the open work
requests dated back to November 1992.
A conference call between the licensee, Region II, and NRR on
Wednesday, August 12, 1993 discussed potential DC system
vulnerabilities due to the prolonged presence of the hard positive
ground and the unresolved intermittent grounds (both positive and
negative), and the licensee's schedule for corrective action. It
was the licensee's position that the ground did not present an
immediate operability concern, and that any subsequent single
failures were bounded by the single failure analysis outlined in
the FSAR. That is, the plant was designed to withstand the total
failure of a single 125 volt DC control bus. Therefore, even if a
second ground developed, causing the loss of the DC bus, that
event was bounded by the design.
The licensee indicated that
troubleshooting efforts to eliminate the ground would resume on
Monday, August 16, 1993. Subsequent to the conference call, the
inspector learned that the delay in resolving the ground was due
to high load demand on the utility grid, and technicians being on
vacation. Several members of the licensee's staff had expressed
concerns with technicians going into the RCP breaker cubicles in
search of the ground. The concern was that work in a RCP breaker
cubicle was high risk and could cause a plant trip. The
inspectors asked the licensee why power reductions during off-peak
periods were not considered which would have allowed the 1B1 RCP
to be taken off line. The licensee conceded that miscommunication
among the staff had occurred, and a power reduction to aid the
ground hunt was not fully explored. The inspectors were not able
to find evidence of any licensee planned action to resolve the
5
existing ground from July 22, when the IBI RCP breaker was
identified as the ground location, until the August 12 conference
call, initiated by the NRC. The licensee was apparently willing
to allow the ground to exist until an indeterm'inant point at which
a perceived lower risk existed. The inspectors remained concerned
with the presence of prolonged grounds in the DC system in that
the system's importance to safety requires a high degree of
reliability.
On Monday, August 16, I&E crews resumed the ground hunt. On
August 17, one full month after the ground first appeared, I&E
technicians found a short length of multi-strand copper wire in
the IBI RCP pump breaker cubicle. The wire had fallen into a
position which shorted a DC connection block to the cubicle frame.
The wire was removed and the ground alarm cleared. This evolution
did not challenge the RCP.
The inspector noted that the Unit 1 ground detectors were outside
their grace period for recalibration required by Procedure
IP/0/B/3000/024. The surveillance is scheduled on an annual
basis, with the last scheduled date being September, 1992. The
grace period for calibrating the Unit 1 ground detectors ended May
21, 1993. This procedure was originally written in response to
NRC Violation 269, 270,287/88-17-01, Maintenance Procedure
Deficiencies. In the response to this violation the licensee
committed to perform an annual recalibration of the ground
detectors. The technicians responsible for this surveillance were
not able to calibrate the detectors due to the presence of small,
high resistance grounds on the bus. The technicians requested a
deferral or hold of the surveillance. The surveillance was placed
on hold until conditions allowed the calibration. In accordance
with the licensee's policy, a surveillance can be placed on hold
(except for TS required surveillances) by the responsible
technical group. Commitment mandated surveillances are not
controlled as carefully. There was no recognition that the ground
detector calibration was a NRC commitment item. This demonstrated
a lack of controls to ensure compliance with NRC commitments.
The failure to perform an annual recalibration of the Unit 1
ground detectors is identified as Deviation 269/93-22-02: Failure
to calibrate Unit 1 ground detectors annually. The licensee
indicated that they had been unable to calibrate the ground
detectors due to the continued existence of grounds on the vital
DC system.
Following removal of the ground, technicians were able to
successfully calibrate the Unit 1 ground detectors.
e.
Unit 1 Reactor Trip
At 11:17 a.m. on August 23, Unit 1 tripped from approximately 100
percent power during performance of a peak inverse voltage test on
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the 1ADA isolating diodes for DC panelboard 1DIA. During
performance of the peak inverse voltage test, power was lost to DC
panelboard IDIA resulting in a main turbine trip and a reactor
trip. The loss of power to panelboard 1DIA resulted from reversed
leads (reversed polarity) in the 2DCA supply breaker to isolating
transfer diode cabinet 1ADA that prevented DC power from passing
through the transfer diodes when the power supply from 1DCA was
isolated.
During the transient, the main feedwater (MFW) pumps continued to
run but adequate pump discharge pressure could not be maintained
to actually feed the steam generators. The motor driven emergency
feedwater pumps started on a steam generator dryout protection
signal when steam generator levels dropped below 21 inches for
greater than 30 seconds. Approximately 7.5 minutes after the
reactor trip, power was restored to DC panelboard 1DIA. When
power was restored to the panelboard the 1Al and 1BI reactor
coolant pumps attempted to restart. The 1Al and IBI reactor
coolant pumps had not automatically transferred to the startup
transformer due to loss of control power to the supply breaker
feeding the reactor coolant pump bus from the startup transformer.
When control power was restored, the startup transformer supply
breaker to the 1A1 and 1B1 reactor coolant pumps closed in. The
1A1 and IBI reactor coolant pump supply breaker subsequently
tripped on overcurrent.
As a result of the complications experienced during the reactor
trip, NRC Region II dispatched an electrical inspector from the
Division of Reactor Safety to assist the resident staff in
conducting a special inspection into the circumstances surrounding
the event. This reactor trip is discussed in greater detail in
NRC Inspection Report 50-269,270,287/93-23.
Unit 1 was returned to power operation on August 26, 1993.
f.
Unit 2 Reactor Trip
At 11:30 p.m. on August 25, 1993, Unit 2 tripped from
approximately 100 percent power due to a turbine trip/reactor trip
signal. The turbine generator trip resulted from a loss of load
indication and generator lockout when a non licensed operator
pulled the Z phase relaying potential drawer to the disconnect
position on the Unit 2 generator. The non licensed operator was
in the process of tagging out the Unit 1 generator for replacement
of the Unit 1 generator bus bar disconnect links and pulled the
Unit 2 drawers instead of the Unit 1 drawers.
The Senior Resident Inspector responded to the site when informed
by the licensee that Unit 2 had tripped. The trip response was
normal and the Unit stabilized in hot shutdown. The inspectors
reviewed the post trip review report prior to restart of the Unit
7
and noted no discrepancies. Unit 2 was returned to power
operation on August 26, 1993.
Within the areas reviewed, one Deviation was identified.
3.
Surveillance Testing (61726)
a.
Rod Drop Test
The following surveillance test was reviewed by the inspectors to
verify procedural and performance adequacy. The completed test
reviewed was 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.
IP/O/A/0330/003A, Control Rod Drive Rod Drop Time Test. The
purpose of this surveillance is to ensure that rod drop
times are within technical specification requirements. This
surveillance test is normally accomplished during refueling
outages but was performed on the Unit 1 Group 1 and 2
control rods prior to returning the Unit to service after
the reactor trip on August 23. Group 1 rod 8 and group 2
rod 5 had experienced slow drop times during the previous
refueling outage and an emergency technical specification
change had been issued by the NRC to allow the drop times of
these two rods to be increased to 2 seconds. The licensee
had committed to test these rods at the next Unit shutdown
to verify that the drop times were acceptable. The
inspectors witnessed the rod drop time testing conducted.
The rod drop times were less than 2 seconds but the rod drop
times were significantly slower than the other rods in the
groups and were slower than the last recorded rod drop time
tests conducted in January 1993. Group 1 rod 8 dropped in
1.876 seconds and group 2 rod 5 dropped in 1.989 seconds.
The licensee intends on replacing the drive mechanisms of
these rods at the next refueling outage.
b.
Missed Emergency Feedwater Surveillance
During the inspection period the licensee identified that the
Technical Specification required monthly safety-related functional
test of the motor driven emergency feedwater pumps initiation
pressure switches had not been performed since Unit 2 returned
from its scheduled refueling outage on June 24, 1993. The
surveillance had not been performed because the procedure had been
suspended for the duration of the refueling outage and had not
been removed from this status prior to returning the Unit to
service. The Technical Specification required surveillance was
performed successfully subsequent to identifying that the allowed
grace period had been exceeded. This item will be tracked and
8
evaluated by review of the Licensee Event Report (LER) required to
be submitted to the NRC in accordance with 10 CFR 50.73.
No violations or deviations were identified.
4.
Maintenance Activities (62703)
Maintenance activity was observed and reviewed during the reporting
period to verify that work was performed by qualified personnel and that
approved procedures in use adequately described work that was not within
the skill of the trade. Activities, procedures, and the work request
were examined to verify proper authorization to begin work, provisions
for fire, cleanliness, and exposure control, proper return of equipment
to service, and that limiting conditions for operation were met.
-
TN/4/A/2078/00/BK1, Keowee Generator Air Break Interlock.
This modification package provided an interlock to prevent
the air brakes from being applied manually or automatically
during unit operation or a unit start. The modification
consisted of installing a three way solenoid valve in the
air line to the air brakes to ensure that the air system was
vented during unit operation. The inspectors observed work
in progress and reviewed the work package for completeness.
No violations or deviations were identified.
5.
Keowee Issues
On August 17, 1993 Keowee Unit 2 failed to start manually from the
Oconee control room during the performance of PT/0/A/620/17,
Keowee Manual Sync Test. A second attempt was made to start the
Keowee unit manually from the Oconee control room without success.
Keowee Unit 2 was returned to its normal automatic alignment and
the surveillance test was repeated this time from the Keowee
control room. This time the Unit responded to the manual start
signal and the performance test was completed. The operators
performed an operability check of Keowee Unit 2 after the manual
sync test was completed to verify that Keowee Unit 2 would
automatically start from the Oconee control room. The licensee
does not consider that the Keowee unit is inoperable if the manual
start circuitry in the Oconee control room is inoperable. This
position is based on the fact that the emergency start circuity in
the Oconee control room is separate from the manual start
circuitry, and under normal circumstances the Keowee units can not
be manually started from the Oconee control room because control
of the Keowee Units is maintained in the Keowee control room. The
licensee initiated the problem investigation process to develop a
plan to troubleshoot and locate the problem with the manual start
circuitry.
No violations or deviations were identified.
9
V
6.
Inspection of Open Items (92701) (92702)
The following open item was reviewed using licensee reports, inspection
record review, and discussions with licensee personnel, as appropriate.
(Closed) Unresolved Item 269,270,287/92-13-01:
RCS Hot Leg Draindown
and Loop Drop Problems.
This item addressed problems experienced with
venting the reactor coolant system hot leg high point vents during
efforts to lower or drop the level in the hot legs. Procedure
OP/1A/1103/11, Enclosure 3.1 was revised to provide guidance to vent
nitrogen into the hot legs and provide a specific valve lineup to
establish nitrogen flow. The licensee also replaced the valves in the
vent header with the valves that would pass flow in both directions.
7.
Review of Licensee Event Reports (92700)
The below listed Licensee Event Report (LER) was reviewed to determine
if the information provided met NRC requirements. The determination
included: adequacy of description, verification of compliance with
Technical Specification and regulatory requirements, corrective actions
taken, existence of potential generic problems, reporting requirements
satisfied, and the relative safety significance of the event. The
following LER is closed:
-
LER 269/92-04, Reactor Trip Results from Low Main Feedwater Pump
Discharge Pressure Due to Management Deficiency. This LER
describes a reactor trip that occurred during a Unit startup when
operators attempted to decrease hotwell level due to a high
hotwell level alarm condition during the startup. This item was
discussed in NRC Inspection Report 269,270,287/92-11. As a result
of this trip the licensee revised Procedure OP/0/A/1106/02,
Condensate and Feedwater, to add Enclosure 3.22 which provides
written instructions to reduce hotwell level and revised the
annunciator response to high hotwell level to reference the
Operating Procedure for lowering hotwell level.
No violations or deviations were identified.
8.
Exit Interview
The inspection scope and findings were summarized on August 31, 1993,
with those persons indicated in paragraph 1 above. The inspectors
described the areas inspected and discussed in detail the inspection
findings. The licensee did not identify as proprietary any of the
material provided to or reviewed by the inspectors during this
inspection.
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Item Number
Description/Reference Paragraph
URI 50-287/93-22-01
Load Shed Channel 1 Operabil;ity (paragraph 2.c).
DEV 50-269/93-22-02
Failure to Calibrate Unit 1 Ground
Detectors Annually (paragraph 2.d)