ML16161A818
| ML16161A818 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 05/27/1987 |
| From: | Bryant J, Peebles T, Wert L NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16161A820 | List: |
| References | |
| 50-269-87-13, 50-270-87-13, 50-287-87-13, NUDOCS 8706020237 | |
| Download: ML16161A818 (12) | |
See also: IR 05000269/1987013
Text
SREG(
UNITED STATES
0
NUCLEAR REGULATORY COMMISSION
REGION II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos: 50-269/87-13, 50-270/87-13, and 50-287/87-13
Licensee:
Duke Power Company
422 South Church Street
Charlotte, N.C. 28242
Facility Name:
Oconee Nuclear Station
Docket Nos.:
50-269, 50-270, and 50-287
License Nos.:
Inspection Conducted: March 10 -
May 11, 1987
I n s p e c t o r s :
.
r
An
e
L
Br-
Date Signed
.
Approved by:
A,/
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T.rPeebr/
Sectiog
leif
Date Signed
Dvision o Reactor rojects
SUMMARY
Scope:
This routine, unannounced inspection involved on-site resident
inspection in the areas of operations, surveillance, lineups, followup of events,
cleaning and testing of reactor building cooling units and decay heat removal
coolers, and shutdown work in progress. Additional areas examined during the
report period are described in Report No. 50-269,270,287/87-16.
Results: No violations or deviations were identified in the areas covered in
this report.
8706020237 870522
ADOCK 05000269
G
REPORT DETAILS
1.
Licensee Employees Contacted
- M.S. Tuckman, Station Manager
T.B. Owen, Maintenance Superintendent
R.L. Sweigart, Operations Superintendent
J.M. Davis, Technical Services Superintendent
- C.L. Harlin, Compliance Engineer
- F.E. Owens, Assistant Engineer, Compliance
L.V. Wilkie, Superintendent of Integrated Scheduling
Other licensee employees
contacted
included technicians,
operators,
mechanics, security force members, and staff engineers.
Resident Inspectors:
- J.C. Bryant
L.D. Wert
.
- Attended exit interview.
2.
Exit Interview
The inspection scope and findings were summarized on May 12,
1987, with
those persons indicated in paragraph 1 above.
The licensee did not identify as proprietary any of the materials provided
to or reviewed by the inspectors during this inspection.
3.
Licensee Action on Previous Enforcement Matters
(Closed) Violation 50-269,270,287/86-33-02:
Inadequate Testing of ECCW
System.
This item was discussed in Report No. 87-10.
Corrective action
and response have been completed.
4.
Unresolved Items
No unresolved items were identified during this inspection.
5.
Plant Operations
The inspectors reviewed plant operations throughout the reporting period
to verify conformance with regulatory requirements, technical specifica
tions (TS),
and administrative controls.
Control
room logs,
shift
turnover records,
and equipment removal
and restoration records were
reviewed routinely.
Interviews were conducted with plant operations,
maintenance, chemistry, health physics and performance personnel.
2
Activities within the control rooms were monitored on an almost daily basis.
Inspections were conducted on day and on night shifts, during week days and on
weekends. Some inspections were made during shift change in order to evaluate
shift turnover performance.
Actions observed were conducted as required by
Operations Management Procedure 2-1.
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
Unit 3 Containment Building
During
the plant tours,
ongoing activities, housekeeping,
security,
equipment status, and radiation control practices were observed.
Unit 1 ran at 88% power throughout the report period, limited by the
temporary main stepup transformer installed in early March.
Unit 2 began the report period at 96% power, as limited by steam generator
level, and continued at that level until March 26 when it tripped on RCS
high pressure as a result of a feedwater transient.
Reactor trips are
discussed in paragraph 8 of this report.
The unit was returned to 96%
power on March 28 and continued at that power until April 7, when power
was reduced due to degraded heat transfer in reactor building cooling
units (RBCU's)
(DHR)
coolers
(See paragraph 12).
The reactor was returned to 88% power (as limited by high steam generator
level) on April 12,
where it
remained until April 20, when it tripped on
high steam generator level. Unit 2 reached 88% power again on April 21,
and continued at that power until the end of the report period.
Unit 3 began the report period in refueling shutdown. The unit was placed
on line at 15-20% power on March 31, for a brief period to test the main
generator which had been rebuilt during the refueling shutdown.
The
reactor was then taken to hot shutdown for testing of RBCU's
and DHR
coolers (Paragraph 12) and then to cold shutdown to repair a leak on the
RVLIS system. Subsequent to repairs, as Unit 3 was being heated for RBCU
testing and startup, procedures were violated concerning the HPI system
and RBCU's. Theses events are discussed in detail in Report No.
50-269,
270,287/87-16, and will not be discussed in this report. After startup on
April 14, the unit was taken off line on April 15, to replace a bad phase
pot fuse and to balance turbine bearings,
then reached 60% power on
3
April 16 and 100% power on the 17th.
The unit was taken off line on
April 23,
to repair a steam generator tube leak and was again taken
critical on May 2 (Paragraph 13). Unit 3 operated at 100% power for the
remainder of the report period.
No violations or deviations were identified.
6.
Surveillance Testing
The surveillance tests listed below were reviewed by the inspector to
verify procedural and performance adequacy.
The completed tests reviewed were
examined for necessary test pre
requisites,
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 witnessed in whole or in part:.
PT/0/A/0150/08A RB Personnel Lock Leak Rate Test
MP/0/A/1705/27
Fire Protection, Repair of Electrical Penetration
IP/1/A/305/3
Reactor Protection System, Channel D Calibration
and Functional Test.
IP/0/A/360/2
3R1A-54 Turbine Building Sump Radiation Monitor
Calibration
Completed surveillance reviewed:
W/R 05900C Unit 1 TDEFWP Bearing Oil Cooling Pump
No violations or deviations were identified.
7.
Maintenance Activities
Maintenance activities were observed throughout the report period but were
limited to spot checks of maintenane personnel, appropriate procedures and
work performance.
Some of the activities observed were rework of Unit 3
main feedwater valves, rework of Limitorque operators, auxiliary boiler
inspection, repair of a fireproof penetration, rework of RCW "B" Pump.
- k
No violations or deviations were identified.
4
8.
Unit 2 Trips
On March 26,
1987, at 11:33 p.m.,
Unit 2 tripped from 96% power on high
pressure.
Cause of the event appeared to
be an intermittent, poor connection in the Integrated Control System (ICS)
BTU limit circuitry. The specific portion of the ICS affected was the
steam generator feedwater control. As a result of the electrical failure,
feedwater (FDW) demand went to near zero on "A" steam generator (SG).
The
ICS responded by reducing flow to "A" SG,
resulting in increased RCS
temperature and pressure and the reactor trip.
Circuitry repairs were
made and the reactor started up and placed on line at 12:00 noon on
March 28.
On April 20,
1987,
at 5:33 a.m., Unit 2 tripped from 86% power when FDW
demand on the A loop went low.
The ICS responded by decreasing flow to
"A" SG and increasing flow to "B" SG. Since "B" SG level was already at
about 89%,
the level quickly reached 96%,
tripping FDW pumps and the
turbine. The reactor then tripped on the turbine anticipatory trip.
Investigation revealed that a failed multiplier module in the BTU limit
circuitry had caused the problem.
The module was replaced and the unit
taken critical at 5:15 p.m. on April 20.
There have been other trips in the past caused by failures in the BTU
limit circuitry.
The primary purpose of the BTU limit circuitry, as
stated by the licensee, is to maintain steam. quality for protection of the
turbine at low power levels.
Unit 3 was shut down at the time of the
Unit 2 trip, and prior to startup of Unit 3 a modification was installed
which will remove the BTU limit circuitry signal at power levels above
25%. This modification later was installed on Unit 2 with the unit on
line, and it will be installed on Unit 1 while it is on line.
No violations or deviations were identified.
9.
Unusual Events Due to Non-isolable Leaks, Units 2 and 3
An Unusual Event was declared at 3:31 p.m. on March 31, when an unisolable
leak of less than 1 gpm was discovered in the Unit 3 reactor coolant
system (RCS)
at a pipe to coupling weld in the RVLIS system.
At the
time, Unit 3 was at hot shutdown.
The RCS was reduced to cold shutdown
conditions under the assumption that the reactor would have to be defueled
and drained to repair the leak.
The Unusual Event was terminated when
the RCS reached cold shutdown conditions.
At this point the licensee
determined that the leak, which had been reduced to weeping,
could be
repaired "wet" by stick welding the leak closed then making a TIG overlay
on the pipe.
The weld procedures to be used were discussed with the resident inspector
and then, by telephone, with welding engineers in Region II. The pipe was
then successfully repaired and stiffeners added to the pipe to prevent
recurrence.
5
On April 8, 1987, a leak of 0.3 gpm at an almost identical location was
discovered on Unit 2 while the RCS was at 240 degrees F and 185 psig. An
Unusual
Event was declared.
The same repair methods were used as on
Unit 3 and the cause was the same. Therefore, causes of the event will be
discussed as one.
An entry was made into Unit 1 containment with the
reactor at power to search for similar leaks, but none were found.
The
instrumentation lines were attached as follows.
The low
pressure injection (LPI)
pump suction drop lines from the
RPS are
2500 psig lines.
A half couplant was welded to the drop lines and a 3/4"
schedule 160 pipe was socket welded into the half couplant.
At the end
of the 3/4" pipe was an isolation valve where the piping was reduced to
instrument tubing to a supported level transmitter. The leaks were in the
heat affected zone of the socket weld.
The crack on Unit 3 propagated
circumferentially about 180 degrees around the pipe.
The RVLIS modification was made on Unit 1 (which had no failure), during
a refueling outage which began February 13, 1986. The pipe drawings used
for fabrication of the pipe showed full pipe diameters.
It showed the
isolation valve at the end of the 3/4" pipe 12 inches from the centerline
of the 12"
LPI drop line.
The modification for Unit 1 was fabricated in
that manner.
In early 1986,
Duke Design Engineering changed the type drawings to one
line computerized isometrics showing only the centerline on the drawings.
Reportedly,
no training concerning this change was given to personnel
associated with implementation of modifications at Oconee.
Consequently,
the piping for Units 2 and 3 was fabricated with the isolation valve 12",
from the 12" pipe wall rather than from the centerline. Proper installa
tion would have resulted in the valve being 6" from the pipe wall.
The QA
inspectors also misread the drawings.
The prefabricated piping was
welded
into the Unit 2 LPI line on
September 11,
1986,
and Unit 2 was in operation from October 15,
1986,
until the failure was detected on April 8, 1987.
The piping was welded
into the Unit 3 LPI line on January 27,
1987, during refueling outage.
The
was visually inspected by Maintenance,
during heatup,
on
March 28, 1987. Total unit operation under nuclear heat, at a maxim power
level of 20%, was only about one day.
Duke
Power Company investigators determined that failure was due to
weakening of the pipe wall by stress induced by natural frequency vibra
tion. This was caused by the extra length of pipe putting.the pipe
section outside the seismic stress design basis.
It
appears that work and inspection were done correctly except for the
lack of understanding of the new drawing system.
This appears to be
another example of inadequate communication between Design Emgineering and
plant personnel. Currently, there is a violation open on the same subject
6
in the same time frame as described in Report No.
50-269,270,287/86-16.
That violation concerned inadequate communication concerning installation
of Keowee batteries.
The matter of communications concerning drawing
changes will be considered as another example of the referenced violation.
10.
Resident Inspector Safeguards Inspection
In the course of the monthly activities, the Resident Inspectors included
a review of the licensee's physical security program. The performance of
various shifts of the security force was observed in the conduct of daily
activities which included: protected and vital area access controls,
searching of personnel, packages
and vehicles,
badge issuance
and
retrieval, escorting of visitors, patrols and compensatory posts.
In
addition, the
Resident Inspectors observed protected area lighting,
protected and vital area barrier integrity and verified interface between
the security organization and operations and maintenance.
The Resident
Inspectors also witnessed spent fuel shipment and visited central
and
secondary alarm stations.
11.
Information Notice 87-19: Perforation and Cracking of Rod Cluster Control
Assemblies
The referenced notice concerns perforation and cracking of Westinghouse
control rod assemblies. Since Westinghouse assemblies in which problems
were detected are about the same age as those at Oconee, the inspectors
made inquiries and reviewed documentation to determine control
rod
assembly conditions at Oconee.
Control
rod assemblies at Oconee are inspected periodically during
refueling outages and a schedule of routine partial replacement of
assemblies is in place which will replace all rods over a 10 -
12 year
interval.
Due primarily to significant differences in construction,
Babcock and Wilcox assemblies do not appear to be subject to the fretting
and wear of the Westinghouse assemblies.
The major factors in this case
are the long "C" and "Split" guide tubes of the B&W assemblies which guide
the rod fingers when withdrawn. The Westinghouse assemblies do not use
such long rod guides. The problems of wear and fretting of rods due to
flow-induced vibration have not been observed at Oconee.
12.
Reduced Efficiency of Reactor Building Cooling Units and Decay Heat
Removal Coolers
During the report period,
the licensee determined that heat transfer
capability of reactor building cooling units (RBCUs)
and decay heat
removal
(DHR)
coolers had fallen below design requirements.
For power
operation, Technical Specifications (TS) require two independent trains of
low pressure injection, including the DHR coolers, be completely operable
and that three independent trains of reactor building cooling, including
the RBCU's,
be completely operable.
The above requirements allow some
relief for maintenance.
7
Extensive cleaning and testing was carried out by the licensee and a
Confirmatory Order was issued by
NRC.
A Region
II
inspection team
examined data and history to determine if
the licensee had knowingly
operated outside of requirements. The team findings and a description of
events,
and data, will be provided in Report No.
50-269,270,287/87-17;
therefore,
the resident inspectors'
report will deal primarily with
operational aspects during the report period.
The first indication of reduced heat transfer capacity of DHR coolers was
observed in 1985 when the licensee noted that a Unit 1 cooler seemed to
take longer than usual to cool down the RCS. During 1986 the licensee had
considerable communication with the RBCU vendor in an attempt to evaluate
test data. Some RBCU and DHR cooler cleaning was performed and the method
of evaluation available indicated that performance was satisfactory.
A
section of report no. 50-269,270,287/86-20 discusses an inspection of
bio-fouling and states that no significant degradation had occurred due to
the cleanliness of Lake Keowee water, which is used in the low pressure
service water (LPSW) system (the cooling water supply to the coolers). It
also discusses the licensee's method of determining flow degradation.
In 1986, the licensee continued cleaning and testing of coolers and issued
a contract to a consultant to develop state of the art formulas for
determining heat transfer under plant conditions.
The computer program
was received from the consultant on March 30,
1987..
On March 31,
Duke
Power Company (DPC)
notified NRC that full power operations could not be
supported for Unit 3, which was in refueling shutdown at the time, due to
inadequate decay heat removal capability.
After completion of operability evaluations for Units 1 and 2, on April 1,
DPC notified NRC that full power operation could not be supported for
Units 1 and 2.
The licensee determined that heat removal capabilities
would permit operation of Unit 1 at power levels below 91 %. Unit 1 was
then operating at 88% power as limited by the main stepup transformer in
use.
DPC also determined that Unit 2 operation below 66% power was
acceptable. At the time, Unit 2 was operating at 97%; power was then
reduced to 60%.
On April 6 DPC issued a request to NRC for an amendment to the operating
license permitting continued operations with reduced maximum power trip
set points.
The request specified increasing
LPSW flow through
coolers from
3000 gpm to 5000 gpm during certain accident conditions
to assure adequate cooling.
NRC responded with a letter on April 7
acknowledging the verbal
temporary waiver of compliance extended on
April 3. The temporary waiver was later extended until 5:00 p.m.
on
April 10.
On April 10,
the
NRC
issued a Confirmatory Order placing
restrictions of operation on all three units until all RBCU's and DHR
coolers had been verified to meet design requirements.
8
As described in Report 87-17, all three units underwent cleaning, and in
the cases of Units 2 and 3, all coolers were tested. Unit 2 was shut down
for cleaning and testing. Unit 3 coolers were cleaned during shutdown,
then the unit was shut down again for additional cleaning and testing.
Unit 1, which had already been tested, had one DHR cooler cleaned but not
tested while the reactor was on line.
The Confirmatory Order of April 10
dealt with those coolers which had not yet passed inspection for full
power operation at the time of the order.
In brief, the order placed the following conditions for operation of the
separate units.
Unit 1:
Until the 1A LPI (0HR) cooler is cleaned, tested, evaluated
and approved for full power operation, the maximum power shall be
91.5% of rated power with the high flux trip point set at that power,
and the remaining non-ES LPI pump shall be operable.
Also Oconee 1
shall not operate at any power level following the cycle 10 refueling
outage unless the Regional Administrator, Region II, has approved the
1A LPI cooler for full power operation.
Unit 2:
Until the 2A LPI cooler is cleaned, tested, evaluated and
approved for full power operation by the Regional Administrator,
Region II,
the maximum power level shall be 81.7% rated power with
the high flux trip point set at that level.
Should lake cooling
water rise above 550 F the unit shall be shut down. The remaining
non-ES LPI pump shall be operable.
Unit 3:
Oconee Unit 3 shall not operate at any power level after
midnight of April 22,
1987,
unless the
Regional
Administrator,
Region II, has approved full power operation.
On April 13,
1987,
and until the end of the report period, the status of
the Oconee units was as follows:
Unit 1:
As verified by NRC inspectors, Unit I is operating under the
above restrictions. (The unit is currently limited to approximately
88% power by the temporary main step-up transformer in use.)
The
Confirmatory Order conditions remain in effect.
Unit 2:
On April
11,
NRC inspectors reviewed test results and
analyses on Unit 2 LPI coolers and reactor building cooling units
and found that they met conditions of the Confirmatory Order.
The
required approval for power ascension to 100% was given by Region II
to the station manager at 11:00 a.m.
on April
11.
(Unit 2 is
currently limited to 88% power due to high steam generator levels.)
Unit 3:
Unit 3 LPI coolers and reactor building cooling units were
cleaned and tested. Test results and analyses were reviewed by NRC
inspectors on April 12, and found to satisfy the requirements of the
9
order.
The required approval for startup was given by Region II to
the station manager at 2:00 p.m. on April 12.
The resident inspectors will continue followup of any developments
concerning the cooling units.
13.
Unit Three Steam Generator Tube Leak
Unit Three was shut down on April 23,
to repair a primary to secondary
leak in the A steam generator. The leak was approximately 0.1 gallons per
minute. A total of eight steam generator tubes were plugged and the unit
was returned to service on May 2, 1987.
No violations or deviations were identified.
14.
Inadequate Overpressure Protection for Auxiliary Steam Header
During followup reviews of the Safety System Functional Inspection (SSFI)
concerns on undersized relief valves, the licensee discovered a potential
failure of the Turbine Driven Emergency Feedwater Pump due to possible
overpressurization of the Auxiliary Steam System.
This was reported to
the NRC operations duty officer on February 27,
1987.
Analysis of safety
valves on steam lines to the Emergency Feedwater Pump Turbine revealed
that if control valves MS-126 (6 in. steam to auxiliary steam) and MS-129
(2 in. main steam to auxiliary steam) fail open, overpressurization of the
auxiliary steam system and the Emergency
Feedwater Pump Turbine could
occur. The potential overpressure situation is due to the undersizing of
the auxiliary steam header safety valves (AS-23) and is the subject of LER 269/87-03 of March 30, 1987.
LER 269/87-03 detailed corrective action steps taken as an interim measure
until permanent corrective actions were completed. These actions included
installation of travel stops on each unit's MS-126 to limit valve stroke,
and administrative control of bypass and control valves.
These adminis
trative controls are to ensure that:
Only one unit is supplying the
auxiliary steam header at a given time (other 2 units MS-126 and MS-129
shut); auxiliary steam header section block valves between units are open
(ensures a total of 3 sets of 2 relief valves are available); and the
manual bypass valves around MS-126 for each unit (MS-131) are shut. These
actions will maintain system pressure within applicable code limits and
allow sufficient auxiliary steam flow for unit startup.
During the incorporation of these interim measures,
an error caused the
auxiliary steam header to be supplied from Unit I before travel stops
were installed on that unit's MS-126.
A scaffold had been installed at
1 MS-126 so that the modification could be performed.
Through an error,
maintenance removed the scaffold without having performed the work,
and
operations was informed, erroneously, that the job was complete.
Unit 1
10
then supplied the auxiliary header from March 23 to April 21, with some of
the administrative controls relaxed due to the misunderstanding.
On
April 21 the situation was corrected by shifting the auxiliary steam
header back to being supplied from Unit 2 which
had travel
stops
installed. Travel stops were then promptly installed on Unit 1 MS-126,
completing all the interim corrective actions.
Administrative control of
the associated steam valves has been closely followed by the resident
inspectors.
Operation with Unit 1 supplying auxiliary steam without travel stops
installed and with some of the administrative controls relaxed was a
violation of a commitment to NRC.
However, the licensee identified the
error during a routine surveillance, took immediate corrective action,
and the situation appears to meet all requirements of 10 CFR Part 2,
Appendix C; therefore the event will not be cited as a deviation.
15.
Inspection of Open Items
The following open items are being closed based on inspection and/or
record review and discussions with licensee personnel as appropriate.
(Closed)
LER
50-269/86-09;
Keowee Battery Racks Outside of Design
Specifications.
The immediate problem was corrected within hours of
discovery. Satisfactory corrective actions have been taken to correct the
underlying cause,
communications
between
Design Engineering
and site
personnel.
(Closed)
UNR 50-269,270,287/86-20-03; Discrepancy in Document/Design
Control.
Same as LER 86-09 above.
(Closed)
LER 50-269/86-11;
Inoperability of Emergency Condenser
Circulating Water System. This problem was discussed in Reports 86-26 and
86-33. Resolution was satisfactory.
(Closed)
LER
50-269/86-14;
TS 4.16 Violation-Source Leak Test Not
Performed. Corrective action has been reviewed and found acceptable.
(Closed)
LER
50-270/86-03;
Core Flood Tank Concentration Below T.S.
Limit.
Problem and corrective action were reviewed and found satis
factory.
(Closed)
IFI 50-270/86-26-01; Revisions to the Keowee Load Shed Surveil
lance Test. Test revisions were reviewed and found satisfactory.
(Closed) IFI 50-270/86-26-02; LPSW Valves to Decay Heat Coolers Did Not
Appear to Respond Correctly.
Repeated tests have not revealed a
discrepancy.
(Closed)
LER 50-287/86-01; Reactor Trip From High Reactor Coolant System
Pressure. Failure of Al Feedwater Transmitter.
Defective module was
identified and replaced.
(Closed) LER 50-287/86-03; Turbine Building Sump Radiation Monitor Found
in Bypass Due to a Defective Procedure.
Corrective action was reviewed
and appears satisfactory.
(Closed) IFI 50-287/85-07-02;
Improve Valve LP-2 Operability.
Valve
operator has been rebuilt and MOVATS tested.
(Closed) Part 21 50-269,270,287/P2184-01; HVAC Equipment Mfg. by Bahnson.
In response to IE Information Notice 84-30 the licensee inspected welds in
the Bahnson supplied air handling unit in the standby shutdown facility
and performed an as-built weld stress calculation. Thirty-eight defective
welds were identified, but were eventually determined to be cosmetic in
nature. No repairs were required.