ML16161A983
| ML16161A983 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 06/01/1988 |
| From: | Peebles T, Skinner P, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16161A984 | List: |
| References | |
| 50-269-88-12, 50-270-88-12, 50-287-88-12, NUDOCS 8806200208 | |
| Download: ML16161A983 (13) | |
See also: IR 05000269/1988012
Text
R REG
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.V.
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/88-12, 50-270/88-12, 50-287/88-12
Licensee:
Duke Power Company
422 South Church Street
Charlotte, NC
28242
Docket Nos.:
50-269, 50-270, 50-287
License Nos.:
Facility Name:
Oconee Nuclear Station
Inspection Conducted:
April 19 - May 16, 1988
Inspectors: _
_
_
__(_
_
)/__/_f
P. H.-Skinne , genior Resident Inspector
Date Signed
L. D. Wert, Resident Inspector
Date Signed
Approved by:__
__
__
__
__
__
_
/
T. A. Peebles,'Section Chief
Date Signed
Division of Reactor Projects
SUMMARY
Scope:
This routine inspection involved resident inspection on-site in the
areas of operations, surveillance, maintenance,
physical security, radiation
protection, engineered safeguards features lineups, nonroutine reporting, and
B&W Owners Group Plant Reassessment Program.
Results:
Of the eight areas inspected,
no violations or deviations were
identified.
8806200208 SS0602
ADOCK 05000269
Q
REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- M. Tuckman, Station Manager
J. Davis, Technical Services Superintendent
W. Foster, Maintenance Superintendent
T. Glenn, Instrument and Electrical Support Engineer
- C. Harlin, Compliance Engineer
D. Hubbard, Performance Engineer
J. McIntosh, Administrative Services Superintendent
- B. Millsaps, Maintenance Service Engineer
- F. Owens, Assistant Engineer, Compliance
P. Street, Mechanical Technical Support Engineer
- R. Sweigart, Operations Superintendent
L. Wilkie, Integrated Scheduling Superintendent
Other licensee employees contacted included technicians, operators,
mechanics, security force members, and staff engineers.
NRC Resident Inspectors
- P. H. Skinner
L. D. Wert
- Attended exit interview.
2.
Exit Interview
The inspection scope and findings were summarized on May 16,
1988, with
those persons indicated in paragraph 1 above.
The inspectors described the areas inspected and discussed in detail the
inspection findings listed below. Dissenting comments were not received
from the licensee.
Proprietary information is not contained in this
report.
Item Number
Status
Description/Reference Paragraph
269/85-21-01
Closed
Violation for Failure to Follow
Procedure
269,270,287/85-21-03
Closed
Violation for Failure to Provide
an Adequate Procedure
2
269,270,287/88-12-01
Closed
Licensee
Identified
Violation
Potential Loss of All AC Power Due
to Switchyard Modification
269,270,287/88-12-02
Open
Inspector
Followup
Item:
Corrective Actions to
Preclude
Late Submittal of Reports
270/88-12-03
Open
Inspector
Followup
Item:
Management
review
of
Communications
Interface Between
Performance and Operations During
Testing
Closed
Appendix R Review With Respect to
Valve Operability
Closed
Stuck Suction Relief Valve on Main
Pump After a Reactor
Trip
Closed
Violation
Due
to
Management Deficiency
3.
Licensee Action on Previous Enforcement Matters
a.
(Closed) Violation (50-269/85-21-01):
Failure to Follow Procedure on
Classification of Work Requests.
The licensee responded to this
violation in correspondence dated October 11,
1985.
The inspector
has reviewed this information and the corrective actions addressed
and based on this review, this item is closed.
b.
(Closed) Violation
(50-269,270,287/85-21-03):
Inadequacies
in
Development
and
Implementation
of
Procedure
MP/O/A/2001/4,
Breaker Inspection and Maintenance.
The licensee addressed this
violation in correspondence dated October 11,
1985.
Based on this
action, this item is closed.
4.
Plant Operations (71707)
a.
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, Unitf2 refueling 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 during the day,
night shifts,
and on
weekends.
Some
inspections were made during
shift
3
change in order 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
Units 1, 2, and 3 Electrical Equipment Rooms
Units 1, 2, and 3 Cable Spreading Rooms
Station Yard Zone within the Protected Area
Standby Shutdown Facility
Units 1, 2, and 3 Penetration Rooms
Unit 2 Containment
Condenser Circulating Water Intake Structure
During the plant tours,
ongoing activities, housekeeping, security,
equipment status, and radiation control practices were observed.
Unit 1 -
Unit 1 has continuously operated during this reporting
period at 100% power. As of May 16, the unit has operated
continuously for 185 days without a shutdown.
Unit 2 -
Unit 2 commenced this reporting period at approximately 30%
power recovering from a generator runback caused
by
a
faulty temperature sensing device. The device was repaired
and the unit reached 100% on April 19 and has remained
there except for a 5 hour5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> period on April 26 to correct a
feedwater heater tube leak on 2A2 heater, for the remainder
of the reporting period.
Unit 3 -
Unit 3 commenced the report period in an outage caused by a
steam generator tube leak. Steam generator tube leakage
repairs were completed May 2 and return to power operations
commenced. On May 4, a primary leak occurred which forced
the plant to return to a cold condition to make repairs
(see
paragraph 4.c.).
The plant returned to normal
operating
pressure
and
temperature
on
May 8, but
experienced problems with the electrical system on the main
generator. On May 10, the plant had been returned to 100%
power.
b.
Unusual Event On Unit 3 Due To SG Tube Leak
On April 17,
1988,
at approximately 3:15 p.m.,
the condenser air
ejector exhaust radiation monitor (RIA-40)
began increasing steadily
from about 280,000 cpm. Investigation identified that a primary to
4
secondary leak of approximately 1.3 gpm in the steam generators had
developed. By 10:00 p.m.,
RIA-40 had increased to 900,000 cpm and
operators began shutting down the unit. At 1:15 a.m. on April 18, an
Unusual
Event was declared and a cooldown of the unit to cold
shutdown conditions was commenced to isolate the leak and perform
effective repairs. The leak was localized to the 'A' steam generator
and the cooldown was conducted using the 'B' steam generator.
Upon
obtaining cold shutdown conditions at 4:40 p.m. the Unusual Event was
terminated. The licensee performed an extensive inspection of the
steam generator tubes in both steam generators as discussed in TS 4.17.4.d. A total of 3974 tubes were inspected in the 'A'
SG and
3740 tubes inspected in the
'B'
SG.
Two
leaking tubes
were
identified in the 'A' SG and none in the 'B' SG. As a result of the
eddy current testing, a total of 27 tubes in the 'A' steam generator
were plugged and 23 tubes plugged in the 'B'
generator.
Steam
generator work was completed on May 2 and the unit commenced recovery
from the outage.
c.
Unusual Event On Unit 3 Due To Seal Injection Leak
On May 4, with the plant at 2200 psig and 480 degrees F, the licensee
was conducting PT/0/A/200/46,
Leak Test.
During the visual inspection a leak was reported on
the
seal
injection piping to the mechanical seal on reactor coolant pump 3B1.
After further investigation, the leak appeared to be on the seal 'C'
(1st stage) which is in an unisolable section of piping.
Based on
this observation an Unusual Event was declared on May 5 at 0008 and
the required notifications were made.
Rough calculations performed
during the cooldown to cold conditions indicated a leak on the order
of 0.1 gpm. The licensee decided to attempt to stop the leak using
the weld overlay method developed by NUTECH and used in early 1987 on
Units 2 and 3 to repair leaks in the reactor vessel level indicating
system. This method was attempted but did not work due to the
pressure build up in the system piping in the area of the weld
repair. When the personnel went into the area to make the repair,
they identified that the leak was actually on the line associated
with the 2nd stage seal.
The initial investigation had identified
the incorrect pipe due to the large quantity of pipes in this area.
Had the location initially been correctly identified, the plant would
probably not have declared a Unusual
Event.
As a result of the
inability to stop the leak using the overlay method with pressure in
the piping, the unit was cooled down,
depressurized and placed in
decay heat removal cooling mode. The Unusual Event was terminated on
May 6 at 0745. The leak was repaired on May 6 at 0300 and the unit
returned to critical operation on May.8 at 3:20 p.m.
d.
A recent review by the licensee identified that 10 of the last 17
reports required by TS 4.17.6.a and 4.17.6.b were not submitted
within the time requirements specified by TS. In addition the report
required by TS 4.4.2 concerning tendon surveillance dated March 29,
1988, was also submitted after the required due date specified. The
licensee has
identified both of these problems in problem
investigation reports 4-088-0009 and 3-088-0083 respectively.
The
licensee has investigated this area and developed corrective action
to correct this problem.
The inspector is identifying this as an
Inspector Followup Item 269,270,287/88-12-02: Corrective Actions to
Preclude
Late
Submittal
of
Required
TS
Reports,
pending
implementation and subsequent review of future submittals.
No violations or deviations were identified.
5.
Surveillance Testing (61726)
a.
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/or witnessed in whole or in part:
PT/3/A/0600/12
Turbine Driven Emergency
Feedwater Pump
Performance Test
PT/0/A/0400/11
Safe
Shutdown
Facility
(SSF)
Diesel
Generator Performance Test
PT/0/A/600/23
SSF Fuel Oil Inventory
b.
Condenser Discharge Valve (2CCW-21)
During the most recent refueling outage on Unit 2, the inspectors
observed portions of PT/2/A/0261/006
(Condenser
Circulating Water
(CCW) System Gravity and Recirculation Flow Test).
During the test
one of the condenser discharge valves (2CCW-21)
failed to
shut
automatically as required by the test. Additionally, an operator was
unable to shut the valve from a remote station above the valve.
Testing was stopped, a work request written (WR 14246C) and the valve
was repaired.
Subsequently
the CCW gravity
flow test was
satisfactorily completed and
functioned
as required.
A
review of the completed work request indicated that components were
replaced only in the "open" circuit of the valve and these components
would have no effect on the valves ability to shut. 2CCW-21 is a air
operated,
78 inch diameter butterfly valve located in the condenser
discharge piping between the condenser outlet and the concrete floor
of the turbine building. At certain lake elevations (greater than
approximately 791 feet) the failure of this valve to shut on a CCW
piping rupture could cause flooding of the turbine building through
backflow of the lakewater. Although various modifications have been
6
completed to lessen the severity of this casualty should it
occur,
(for example;
a drain out of the turbine building basement
and
watertight doors between the auxiliary building and the basement) the
Oconee Probabilistic Risk Assessment still considers flooding of the
turbine building from CCW system a very significant contribution to
core melt frequency.
After the inspector discussed his finding an initial investigation by
Instrument and Electrical (I&E)
Engineers supported the inspectors
concerns that the maintenance performed on the valve as detailed in
the work request would not address the valve's failure to
automatically shut. Automatic and remote cycling of the valve is
accomplished by operation of dual solenoid valves which act to port
air to/from the piston of the valve.
At the CCW valve itself, the
air system can be manually operated to shut the valve but in the case
of a ruptured
CCW pipe this option may
not be available.
The
inspectors requested that the licensee look into the repairs of
and also examine
the history of all of the condenser
discharge valves for other instances of failure to automatically
shut.
Additional investigation by I&E personnel identified that the limit
switch replaced was the "open" limit switch which is in the close
circuit rather than the limit switch in the open circuit.
Further
review by I&E indicated no history of failure of this valve and other
condenser discharge valves.
Operator and Performance Engineer Interface During Conduct of Test
During observation of portions of PT/3/A/0600/12 (Turbine Driven
Emergency Feedwater Pump (TDEFWP)
Performance Testing) the inspector
observed that the testing was not completed with strict adherence to
the procedure.
Specifically, a precaution which stated that a
Nuclear Equipment Operator (NEO)
should be stationed at the pump to
"continuously monitor the TDEFWP while it
is running and ensure
adequate suction pressure is maintained to the pump at all times" was
not followed.
While the NEO did continuously monitor the TDEFWP
while it
was operating,
he was not aware of the requirement to
monitor suction pressure.
He did not know the location of the
suction pressure gage and was unsure what suction pressure values
were "adequate". The NED stated he had not reviewed the performance
procedure. There is no indication of pump suction pressure in the
control room. The inspector informed the NEO of the suction pressure
gage location and the requirement to monitor suction pressure.
A
specific requirement for a minimum suction pressure is provided in
the procedure.
A performance engineer, responsible for the test
coordination,
was
aware of the gage location and the pressure
specified in the procedure since he maintained the controlled copy of
the test. However, the engineer was not in the immediate vicinity of
the pump as it
was operated.
The operating requirements of the
performance test was not communicated to the NED by the performance
7
engineer nor by the onshift reactor operator.
The unit supervisor
was made aware of this problem and also this problem was discussed
with other licensee management. The licensee is going to review this
interface area to determine if a communication problem exists and if
NEO's are being provided adequate guidance when performing equipment
operation in support of the performance engineering effort.
Pending
completion of this review and action taken, if required, this item is
identified as an Inspector Followup Item (IFI) 269,270,287/88-12-03:
Management
Review of Communications Interface Between Performance
Engineering and Operation During Performance of Testing.
No violations or deviations were identified.
6.
Maintenance Activities (62703)
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 in use adequately described
work that was not within the skill of the trade.
Activities,
procedures
and
work
requests 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.
Maintenance reviewed and/or witnessed in whole or in part:
WR 15094C
Investigate Torque Switch Setting LP-20
WR 51629G 2CF-1 Limitorque Repairs
b.
Emergency Power Switching Logic Malfunctions
In late 1987,
Duke Power Company decided that due to increases in
present generation capacity and for future increases due to projects
in progress, modifications to the 230kv switchyard were required.
Nuclear Station Modification (NSM) ON-22637, 230kv Switchyard Circuit
Breaker Replacement,
was developed to replace the power circuit
breakers (PCB)
and various associated relaying with larger capacity
PCB's. This NSM is in the process of being performed at this time.
Since the PCB's
have a higher interrupting capability,
larger
capacitance is provided to suppress the voltage gradient across the
contacts during breaker operation.
On March 28, 1988, while
performing a surveillance test on the Keowee Emergency Start System
per
PT/2/A/0610/01J,
the
unit
experienced
a CT-2
(Startup
Transformer)
lock-out from a transformer differential phase relay.
The cause of the lockout could not be determined and an investigation
was performed with the assistance of the design engineering group.
On April 4, the design engineering group met with the operations
staff and identified that due to the higher value of capacitance on
the new PCBs an induced resonance circuit had developed on the CT-2
circuit which under certain breaker alignments.could result in a CT-2
8
lockout condition.
The
design personnel also provided recommen
dations for operations under these specific circumstances if
they
occurred. Design was requested at this time to do further studies on
this problem.
On April
26, design engineering as a result of
additional studies, identified that Unit 2 could experience a failure
where emergency power would not be automatically provided to the Unit
2 loads as described in the
FSAR.
The licensee immediately took
action to place Unit 2 on Unit 3's startup transformer since Unit 3
was already shut down to cold conditions, and placed Unit 3 power on
the Lee Station 100kv power source.
The licensee also made notifi
cations as required by 10 CFR 50.72. At approximately 1:30 p.m.
on
April 27,
a conference call was held between
NRR (Helen Pastis,
Carl Shulton, Dave Matthews), Region II (Brian Bonser), DPC Corporate
Engineering (Bob Dobson, Jim Stoner, Paul Guill),
Oconee station
Management and the resident inspector to discuss facts associated
with this event.
Duke provided NRC a draft memo detailing the
information discussed in this conference call dated April 28,
1988.
The licensee identified that as a result of the resonance problem the
voltage induced on the low voltage side of the startup transformer is
of a sufficient magnitude to exceed the pickup setting of the
Emergency Power Switching Logic (EPSL)
voltage sensing relay.
This
would result in the EPSL system falsely sensing that the transformer
is available for use and would prevent the automatic transfer to the
standby power source which would be available for use if an emergency
were to occur. The only situations in which this condition would
exist would be if
the PCB's are open and all disconnect switches
associated with the startup transformer and the PCB's are closed or
when
a transformer differential
lockout existed that was not a
sustained fault to ground or was spurious in nature coincident with a
loss of off-site power to that unit. This item is being identified
as a Licensee Identified Violation (LIV)
270/88-12-01:
Potential
Complete Loss of All AC Power Due to 230kv Switchyard Modifications.
This is identified as a LIV as discussed in 10 CFR 2, Appendix C due
to the facts that it meets all the following criteria:
(1) it was identified by the licensee
(2) it
fits a Severity Level
IV or V violation category because
of
the
low
probability
of
all
conditions
occurring
simultaneously
(3) it was reported, as required
(4) it
has been corrected and measures to prevent recurrence are
being taken
(5) it
was not a violation that could reasonably be expected to
have
been
prevented by the licensee's corrective action to
a previous violation.
No violations or deviations were identified.
9
7.
Resident Inspector Safeguards Inspection (71881)
In the course of the monthly activities, the Resident Inspectors included
review of portions of the licensee's physical security activities.
The
performance of various shifts of the security force was observed in the
conduct of daily activities which included; protected and vital areas
access controls, searching of personnel,
packages and vehicles, badge
issuance and retrieval, escorting of visitors, patrols and compensatory
posts.
In addition, the inspectors observed protected area lighting and
protected
and vital areas barrier integrity,
and verified interfaces
between the security organization and operations or maintenance.
No violations or deviations were identified.
8.
Inspection of Open Items (92701)
The following open items are being closed based on review of licensee
reports,
inspection,
record review, and discussions with licensee
personnel, as appropriate:
(Closed)
LER 269/87-02:
Appendix R Review With Respect to Valve
Operability.
The
licensee has completed all corrective actions
specified in this report.
The inspector verified the action to be
complete and that it
met the commitment identified in the report.
Based on this review, this item is closed.
(Closed) LER 270/82-10: Stuck Suction Valve On The 2B MFP After A
Reactor Trip. Nuclear Station Modification 1584 has been completed
on all Units. Based on this action, this item is closed.
(Closed)
LER 270/87-06:
TS 3.3.6 Violation
Due To A Management
Deficiency. The licensee's program in response to IE Bulletin (IEB)
85-03 covers the problem areas addressed in this LER.
The program
for IEB 85-03 is implemented and has not identified similar problems
of this nature.
Based on this review this item is closed.
9.
Babcock and Wilcox Owners Group Plant Reassessment Program
In January 1986, NRR requested the Babcock and Wilcox Owners Group (BWOG)
to assume a leadership role in accomplishing key aspects of the overall
effort required for the reassessment of all
plants.
The BWOG
committed to take the lead in a planned effort to define concerns relative
to reducing the frequency of reactor trips and the complexity of post-trip
response in B&W plants.
The BWOG issued BAW-1919,
"Trip Reduction and
Transient Response Improvements Program" including 5 revisions as of July
1987.
The NRC has reviewed BAW-1919 and its revisions and has issued a
Safety Evaluation Report (SER) (NUREG-1231) and
Supplement 1 to
NUREG-1231. Table 12.1 of the NUREG list 207 recommendations that were
developed by the BWOG for implementation considerations at each of the B&W
10
utilities. These recommendations comprise the BWOG Safety and Performance
Improvement Program (SPIP)
which has goals by the end of 1990,
to reduce
the average trip frequency per plant to less than two per year ,and also
that the number of complex transients will be reduced to 0.1 per plant per
year based on a moving 3-year average. Attachment 1 to this report shows
the actions taken on various of these recommendations.
See inspection
report 269,270,287/87-55 for additional actions taken to date.
Attachment:
Safety and Performance Improvement
Program Recommendations
ATTACHMENT
SAFETY AND PERFORMANCE IMPROVEMENT PROGRAM RECOMMENDATIONS
Recommendation
Number
Subject
Remarks
TR-009-ICS
Improvements in ICS tune
Complete
control circuit
TR-040-ADM
Use the TA Committee's Trip
Complete
Investigation Root Cause
Determination Program
TR-112-PES
Review Switchyard maintenance
Complete
procedures to ensure there is no
mechanism for loss of offsite power
TR-113-PES
Review breaker control power
Complete
distribution to determine effects
of a loss of battery bus
TR-116-PES
Review DC charging system and
Complete
ensure the charging voltage does
not exceed plant equipment
voltage ratings
TR-117-PES
Modify inverter overcurrent
Complete
protection to ensure the
breakers/fuses open on
overcurrent before inverter fail
TR-118-PES
Evaluate loadings on AC and DC
Complete
.vital buses to ensure adequate
margins exist without trip of
equipment
TR-184-ICS
Provide separate fuses for hand
- Not
stations that use AC power
Applicable
TR-185-ICS
Power feedwater flow recorders
- Not
directly from NNI
Applicable
TR-188-ICS
Maintain DC power supply current
- Not
balance and perform a periodic
Applicable
full load test for each power
supply
TR-189-ICS
Set selector switches to select
- Not
maximum NNI dependence
Applicable
Attachment
2
TR-190-ICS
Develop backup controls for
- Not
pressurizer level and pressure
Applicable
control
TR-193-ICS
Review/test pressurizer heater
- Not
low -
low level interlock logic
Applicable
TR-194-ICS
Buffer hand powered indicators
Rejected
and recorder inputs from
automatic power signals
TR-195-ICS
Supply hand and automatic
Rejected
powered circuit from separate
panels
TR-196-ICS
Set pressurizer level signal
Rejected
select relays to automatic
powered transmitters
TR-197-ICS
Provide automatic power transfer
Rejected
for the modulating pressurizer
heater converters
TR-198-ICS
Automatic selection of auto
Rejected
powered sensor on loss of
hand power
TR-203-PES
Establish preventive maintenance
Complete
to increase reliability of
inverters
TR-204-ICS
Eliminate or reduce automatic
Rejected
ICS runback rate on asymmetric
rod conditions
- per DPC analysis