ML16148A535
| ML16148A535 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 08/08/1991 |
| From: | Cline W NRC Office of Inspection & Enforcement (IE Region II) |
| To: | Tuckman M Duke Power Co |
| Shared Package | |
| ML16148A536 | List: |
| References | |
| NUDOCS 9109100028 | |
| Download: ML16148A535 (7) | |
See also: IR 05000269/1991015
Text
UNITED STATES
o
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/91-16, 50-270/91-16 and 50-287/91-16
Licensee:
Duke Power Company
P. 0. Box 1007
Charlotte, NC 28201-1007
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 Conducted: June 30 - July 27, 1991
Inspector:
P. E. Harmon, Senior
s'de
spector
Date Signed
B. B Desi, Rsldent
e~qyDate
Signed
W. K. Poertner Re ' en Is
or
Date Signed
Approved by:
'? 1-g
G. A. tb-sle5=
tion Chief-Dt
i'e
Da e Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine resident inspection was conducted in the areas of
operations, surveillance testing, maintenance activities, and review
of open items.
Results:
No violations or deviations were identified.
9109160028 910829
PDR ADOCK 05000269
I
REPORT DETAILS
1. Persons Contacted
Licensee Employees
- H. Barron, Station Manager
D. Couch, Keowee Hydrostation Manager
- T. Curtis, Compliance Manager
- J. Davis, Technical Services Superintendent
D. Deatherage, Operations Support Manager
B. Dolan, Design Engineering Manager, Oconee Site Office
W. Foster, Maintenance Superintendent
T. Glenn, Engineering Supervisor
- 0. Kohler, Compliance Engineer
C. Little, Instrument and Electrical Manager
H. Lowery, Chairman, Oconee Safety Review Group
B. Millsap, Maintenance Engineer
M. Patrick, Performance Engineer
D. Powell, Station Services Superintendent
- G. Rothenberger, Integrated Scheduling 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
- B. Desai
- 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 performance personnel.
Activities within the control rooms were monitored on an almost daily
basis. Inspections were conducted on day and on night shifts, during
weekdays and on weekends.
Some inspections were made during shift
change in order to evaluate shift turnover performance.
Actions
- I
2
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 Zone 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.
Within the areas inspected, licensee activities were satisfactory.
b. Plant Status
Unit 1 operated at power for the entire reporting period.
At
10:30 a.m., on July 28, a milestone was reached by Unit 1. This Unit
became the first nuclear unit in the country to reach the 100 million
megawatt-hours of electricity.
Reactor coolant pump 1A1 was secured on July 14,
due to a low oil
level alarm. Power level was reduced to approximately 40 percent to
allow maintenance personnel to enter the reactor building and add oil
to the pump motor.
Oil was added to the pump motor, the pump was
restarted and the unit returned to 100 percent power.
During the
building entry a small fire occurred when a plastic container melted
and approximately 2 tablespoons of oil dropped onto the pressurizer
support stand and flashed. The licensee initiated a task force to
review this event and determine corrective actions to prevent
reoccurrence.
Unit 2 operated at power for the entire reporting period.
Unit 3 operated at power until July 3, when it automatically tripped
on loss of both main feedwater pumps due to low suction pressure.
The unit was returned to service on July 4.
On July 15, the unit
experienced a runback from 100 percent power due to loss of control
rod group 3 out-limit.
Control
Rod Drive
(CRD)
breaker 11
3
replacement was in progress.
The licensee postulated that when the
breaker was opened, the D.C.
hold power to one of the two phases was
isolated which caused the rods to align to the single phase D.C. hold
power supply.
This realignment caused the control rod group 3
out-limit to be lost resulting in the runback.
The runback was
stopped at 71 percent power by taking the Integrated Control System
(ICS) to manual.
The runback was determined to be invalid since the
100 percent lights were on, indicating that the rods had not moved
significantly.
CRD breaker replacement was suspended and the Unit
was returned to 100 percent power.
c. Unit 3 Reactor Trip.
On July 3, Unit 3 tripped from 100 percent power due to the loss of
both Main Feedwater Pumps (MFPs).
The MFPs tripped due to low
suction pressure caused by a failure in the Powdex Master controller
while controlling in automatic that resulted in the powdex outlet
valves closing. During the failure of the Powdex Master controller
the powdex bypass valve controller was in manual and the bypass
valves remained shut. This resulted in the condensate booster pumps
and the MFPs tripping on low suction pressure followed by a reactor
trip signal due to the loss of both MFPs.
The licensee determined that the failure of the Powdex Master
controller was caused by a failed gasket that blocked the outlet port
to the valve relay.
This was perceived as a loss of instrument air
by the controller and the powdex valves closed.
Following the reactor trip and Emergency Feedwater (EFW)
initiation
on loss of both MFPs, the EFW flow control valve (EFDW-315) to the 3A
steam generator failed to control steam generator water level.
The
control room operator took manual control of the valve to maintain
level in the 3A steam generator. The solenoid valve controlling the
automatic function of the flow control valve had not operated
properly.
The solenoid valve was agitated and the controller was
returned to automatic and operated properly. The solenoid valve was
replaced prior to returning the unit to power operation and the
licensee is investigating to determine if more frequent cycling of
the solenoid is appropriate to prevent reoccurrence.
During recovery two main steam relief valves did not reseat within
the guidelines of the post trip review procedure.
Valve 3MS-5 did
not reseat until main steam pressure was lowered to 88 percent of
setpoint and valve 3MS-11 did not reseat until pressure was reduced
to 90 percent of setpoint. The normal value specified in the post
trip review procedure is 93 percent of setpoint. The reseat values
for relief valves 3MS-5 and 3MS-11 were reviewed by mechanical
maintenance and the vendor prior to restart of the Unit.
This issue
was also discussed with Region II personnel on July 8, 1991.
4
During review of the post trip response, the licensee determined that
MFP discharge pressure remained above 750 psig when both MFPs tripped
until the "D" heater drain pumps were secured.
The EFW system
automatically initiates only on the loss of both MFPs.
The loss of
MFPs is sensed by loss of control oil pressure or low MFP discharge
pressure.
The low discharge pressure setpoint is set at 750 psig.
The licensee determined that the discharge pressure of the "D" heater
drain pumps could maintain MFP discharge pressure above the actuation
setpoint for automatic initiation of EFW on low MFP discharge
pressure.
Review of past trips that involved loss of both MFPs
indicated that the heater drain pumps installed in Units 1 and 2
could also maintain discharge pressure above the actuation setpoint.
Based on this determination the licensee reduced power on Units 1 and
2 to approximately 70 percent power and secured the heater drain
pumps to ensure that the EFW pumps would receive an auto start signal
on low MFP discharge pressure on a loss of both MFPs. The restart of
Unit 3 was allowed based on the heater drain pumps remaining secured
or isolated from the condensate system.
The licensee generated a procedure to run the heater drain pumps with
the discharge valve closed and the recirculation valves to the heater
drain tank locked open to determine if this configuration would
preclude MFP discharge pressure from staying above the EFW automatic
initiation setpoint. The procedure was only performed on the Unit 1
heater drain pumps.
The 1D heater drain pump developed a discharge
pressure of 710 psig. The 2D heater drain pump developed a discharge
pressure of 720 psig.
Based on this information, the licensee
determined that at 100 percent power, discharge pressure could still
remain above the initiation setpoint with the recirculation flowpath
open.
The licensee performed an engineering evaluation to raise the
actuation setpoint to 800 psig.
This setpoint change also effected
the actuation setpoint for the Reactor Protection System anticipatory
trip on loss of both MFPs and the ATWS Mitigation System Actuation
Circuitry (AMSAC).
The setpoint change was in the conservative
direction.
The engineering evaluation determined that the maximum
discharge pressure available from the heater drain pumps would be 773
psig based on original manufacturers head curves and that the lowest
possible actuation pressure including instrument inaccuracies would
be 782.8 psig.
The 773 psig discharge pressure was based on pump
dead heading and the licensee agreed to operate with the valves in
the pump recirculation lines locked open.
Review of the engineering calculation determined that design
engineering reviewed five available pump curves for the "D" heater
drain pumps originally installed.
The sixth pump curve was not
available when the engineering calculation was performed.
The
inspector also determined that the pump internals for all the heater
drain pumps had been refurbished and swapped between units so that
the pump curves reviewed were not for the presently installed pump
5
configuration. Subsequent to the evaluation, a sixth pump curve was
obtained and the maximum discharge pressure was below the assumed
value in the engineering evaluation.
When questioned on the
acceptability of only reviewing five pump curves for the original
pump configurations the licensee stated that the value used in the
calculation was based on engineering judgement and conversations with
the pump manufacturer.
The inspector considers the engineering
calculation to support the operation of the heater drain pumps to
have been weak with respect to maximum discharge pressure available
from the heater drain pumps; however, the licensee agreed to operate
with the pump recirculation flowpath open to provide a greater margin
than the calculated values.
Long term corrective actions and
followup of this event will be accomplished by review of the
licensee's LER.
No violations or deviations were 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 tests witnessed, in whole or in part, were inspected
to determine 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:
IP/O/A/0275/006C Safety Related Functional Test of the MDEFWP
Initiation Pressure Switches
IP/O/A/0275/005I MDEFWP Safety Related Instrumentation
Calibration and System Functional Check
IP/O/B/0275/005B Feedwater System Feedwater Pump Suction and
Discharge Pressure Switch Calibration
PT/1/A/600/01
Periodic Instrument Surveillance
PT/2/A/600/01
Periodic Instrument Surveillance
PT/3/A/600/01
Periodic Instrument Surveillance
PT/2/A/600/12
TDEFWP Performance Test
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 in use adequately described work that was not within
'the skill of the trade.
Activities, procedures, and work requests were
6
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.
Maintenance reviewed and witnessed in whole or in part:
WR 53090 Determine valve position upon loss of air for MS-93.
WR 57385 Determine valve position upon loss of air for MS-87
WR 55168 CRD Breaker 3-DC-4 Replacement
No violations or deviations were identified.
5. Review of Licensee Event Report (LER) (92700)
The following LER was reviewed to determine if the information provided
met the NRC requirements.
(Closed)
LER 50-287/91-05: Design Deficiency and Procedure Deficiency
Cause Spurious ATWS System Actuation Resulting in Manual Reactor Trip.
This item was addressed in NRC inspection report 50-269,270,287/91-09 and
the inspectors reviewed the licensee response dated April 30, 1991.
Based
on this review, this item is closed.
6. Exit Interview (30703)
The inspection scope and findings were summarized on July 29, 1991, 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.
0II