ML16148A599
| ML16148A599 | |
| Person / Time | |
|---|---|
| Site: | Oconee  |
| Issue date: | 01/29/1992 |
| From: | Belisle G, Binoy Desai, Harmon P, Poertner W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML16148A597 | List: |
| References | |
| 50-269-91-35, 50-270-91-35, 50-287-91-35, NUDOCS 9202140115 | |
| Download: ML16148A599 (10) | |
See also: IR 05000269/1991035
Text
Vs
REGU4
UNITED STATES
NUCLEAR REGULATORY COMMISSION
10
.REGION
II
101 MARIETTA STREET, N.W.
ATLANTA, GEORGIA 30323
Report Nos.:
50-269/91-35, 50-270/91-35 and 50-287/91-35
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 Conductedi November 24, 1991 - January 4, 1992
Inspector:
nz ,
lr
sident Inspector
Date Si ned
aiB-.De1,
as-tdent'Inspector
Dae Signed
W. K. Poert er,
esi ent Inspector
Date Si ned
Approved by:
.Z/
G. A. Belisle, Sectiii'>hief
Date
gned
Division of Reactor Projects
SUMMARY
Scope:
This routine, announced inspection involved inspection on-site in
the areas of operations, surveillance testing, maintenance activities
and inspection of open items.
Results: One violation with two examples for failure to follow procedures was
identified.
Both examples involved controlled and configured valves
being found in the wrong position.
In one instance, the licensee
generated a LER because the valve found out of position was a
containment isolation valve. In the other instance, an inadvertent
dilution of a concentrated boric acid storage tank occurred over a
period of several days.
These two examples indicate a problem in the
configuration control area.
9202140115 920129
PDR ADOCK 05000269
REPORT DETAILS
1. Persons Contacted
Licensee Employees,
- H.. Barron, Station Manager
- J. Davis, Quality Assurance Manager
D. Deatherage, Operations Support Manager
- W. Foster, Superintendent, Mechanical Maintenance
J. Hampton, Vice President, Oconee Site
.0. Kohler, Compliance Engineer
C. Little, Superintendent, Instrument and Electrical (I&E)
- M. Patrick, Compliance Manager
- S. Perry, Assistant Licensing Coordinator
G. Ridgeway, Shift Operations Manager
G. Rothenberger, Superintendent, Integrated Scheduling
- R. Sweigart, Superintendent, Operations
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
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
2
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 reviewed, licensee activities were satisfactory.
b.
Plant Status
Unit 1 operated at power for the entire reporting.period.
Unit 2 operated at power for the entire reporting period.
Unit 3 remained in a shutdown condition the entire reporting period
as a result of an unisolable reactor-coolant system (RCS) leak from a
failed instrument fitting.
During the subsequent startup after
repairs and equipment, inspections,
a dropped control. rod on
December 8. forced a return to cold shutdown for repairs to several.
rod drive mechanisms.
On December 15,
during plant heatup and
pressurization, a through-wall crack in the RCS decay heat removal
dropline was discqvered.
The unit was again shut down and
depressurized to repair the leak.
At the end of the reporting
period, the unit was in the process of returning to power.
c. Mispositioned Containment Isolation Valve
On December 9, the Operations Manager informed the resident staff of
a Unit .3 containment isolation valve that had been found out of
position. The val-ve, 31A-91, is a 3 inch containment isolation valve
for the Instrument Air System.
The valve is a manually operated
valve located inside containment, and is required to be closed to
meet containment isolation criteria.
Technical Specification (TS)
3.6.1 requires containment integrity to be established when RCS
temperature is greater than 200 degrees, pressure is above 300 psig,
3
and fuel is in the reactor vessel.
Valve position is controlled by
Enclosures 13.1 and 13.2 of procedure PT/3/A/115/08, Inside Reactor
Building Manual Isolation Valve Checklist Verification.
The last
documented manipulation of 31A-91 occurred on March 27,
1991, when
the unit was being prepared for startup after a refueling outage.
Several entries into containment were performed after that.date, but
there had been no documented position change of the valve.
On November 30,
1991, a non-licensed operator entered the reactor
building to perform valve lineups, including opening valve 31A-91.
The NLO found the valve *in the open position and notified the Unit 3
supervisor.
Several individuals had made containment entries since
the November 23 shutdown, but none questioned admitted operating the
valve.
The valve is not in a high traffic area in containment, and
is not subject to inadvertent operation. A Shift Incident Report
(SIR)
was initiated on December 1, 1991,
but an LER was not
immediately initiated. . An LER was initiated on December 9.
The
station Compliance Manager informed the inspectors that this LER
would not be complete within the required 30 days from discovery of
the event, primarily due to the relatively late start on preparing
the LER and the intervening Christmas holidays.
The licensee sent a
memo to AEOD stating that the LER would be late.
The inspectors discussed with site management the lack of timeliness
in the licensee':s investigation into the circumstances of this event.
In addition, the fact that 9 days passed before the resident
inspector staff was notified of the event is not acceptable.
Failure to meet the requirements of procedure PT/3/A/115/08 resulted
in a mispositioned valve and a lack of configuration control for a
containment isolation valve.
This item is identified as Violation
50-287/91-35-01: Inadequate Configuration Control.
d. Unit 3 Loss of Feedwater
On December 7,. 1991, *at approximately 3:45 p.m., with the reactor
coolant system at 1230 psig and 519 degrees F, the operating Hotwell
pump (3A) tripped followed by the operating condensate booster pump
(3A) and the operating main feedwater pump (3A) resulting in a loss
of feedwater to the steam generators.
At the time of the event the
unit was subcritical and in the process of heating up in preparation
of returning the unit to service.
A hotwell pump and condensate
booster pump were restarted and the 3A main feedwater pump was reset
and feedwater was reestablished to the steam generators at
approximately 3:48 p.m.
The lowest level reached in. the steam
generators was 19 inches on the startup range level instruments. The
inspectors were in the control room during the event and monitored
the operators actions to restore feedwater.
4
The licensee determined that the trip signal was generated by an
erroneous low hotwell level signal from level, switch 3LS-28.
The
level switch was checked and no problems could be .found with its,
operation or setpoint..
The licensee theorized that relay chatter
associated with the feedwater pump low discharge pressure relay that
is physically located approximately four inches above the hotwell low
level relay may have caused the low level relay to actuate.
To.
prevent an inadvertent trip signal from being received with the unit
at power, the hotwell low level trip signal was removed from service.
'The licensee based this decision on the fact that the trip signal is
for pump protection only and a plant modification package had been
requested previously to delete the low hotwell level trip signal.
e. Unit 3 Water Hammer
On December 9, 1991, at approximately 5:30 a.m., a water hammer event
occurred on Unit 3 when the operators in the control room attempted
to place steam generator hot blowdown in service.
The inspectors
were in the turbine building at the time of the event and heard the
water hammer occur. The inspectors toured the turbine building and
observed piping insulation on the floor around the Unit 3 emergency
switchgears and several pipe supports that had been ripped from the
wall.
The inspectors proceeded to the control room and determined
that the water hammer had resulted when valves 3FDW-103 and 3FDW-104
had been opened to reestablish hot blowdown.
Hot blowdownhad been
secured during the Unit 3 startup.
However, the startup had been
stopped due to a dropped rod and the unit was returning to cold
shutdown to replace the control rod drive stator of the rod that had
dropped.
At the time of the event steam generator pressure was
approximately 850 psig.
The licensee walked down the piping,
evaluated the damage resulting from the water hammer and repaired the
broken hangers. * At the conclusion of the inspection period the
licensee was evaluating potential procedure changes to prevent a
recurrence of this event.
f. Erroneous Estimated Critical Position (ECP).Calculation
On December 8, 1991,
an ECP calculation was performed by the night
shift operations crew in preparation for the Unit 3 startup and
approach to criticality. The
ECP calculation determined that
criticality would be achieved at 19% withdrawn on group 6 based on.a
boron concentration. of 1304 ppm.
The
calculation was performed per Enclosure 13.2 of PT/3/A/1103/15 and
had been independently verified as correct.
Subsequent to shift
turnover, the oncoming shift questioned the adequacy of the ECP
calculation based on the RCS boron concentration prior to the unit
shutting down.
The oncoming shift performed another ECP calculation
per PT/3/A/1103/15 and did not obtain the same results as the
previous shift had achieved.
The previous ECP calculation was
5
reviewed and it was determined that the error was a result of not
reversing the reactivity coefficient sign in step 13.2.6 of the
procedure as specified in the procedure. Review of the incorrect ECP
calculationdetermined that both the person performing the ECP. and
the independent verifier had made the same error when performing .the
calculation.
The error introduced into the ECP calculation was in a
conservative direction such that criticality would not have been
achieved early in the rod withdrawal
sequence.
The licensee
initiated a shift incident report on this event and continued with
unit startup activities.
g. Valve 3CS-60 Mispositioned
On December
17,
1991, with the 3A bleed transfer pump taking a
suction on the. concentrated boric acid storage tank (CBAST) and
adding water to the letdown storage tank (LDST)
to increase the
reactor coolant system boron concentration, the expected increase in
system boron concentration was not achieved for the amount of boric
acid thathad been injected into the RCS. A water sample of the 3A
bleed transfer pump discharge was obtained with the pump running and
the results indicated 3317 ppm boron instead of the expected CBAST
concentration of 10550 ppm boron...' Investigation by the operators
determined that valve 3CS-60 was open approximately 5 turns instead
of in its required position of closed.
Valve 3CS-60 is the bleed
transfer pump suction crossconnect valve and with the valve open the
3A bleed transfer pump was taking. a suction on the CBAST and the 3B
bleed holdup tank simultaneously. The boron concentration in the 3B
bleed holdup tank was less than .10 ppm and resulted in 'the reduction
of the expected increase in boron concentration of the RCS.
Valve
3CS-60 in the open position also allowed water from the 3B bleed
holdup tank to enter and dilute the CBAST.
A boron sample of the
CBAST was taken and indicated a boron concentration of 5341 ppm in
the CBAST as opposed to the expected 10550 ppm.
The licensee could not determine when 3CS-60 had been opened. Review
of the completed procedure files determined that the valve had been
opened on .December 9, 1991, to borate the RCS from the' CBAST using
the 3B bleed transfer pump; however, the procedure returns the valve
to the shut position and requires that the valve be independently
verified as shut after the boron addition and the system is flushed.
The inspectors consider this item 'not only a configuration control
problem but also a reactivity management issue.
The failure to
maintain configuration control of valve 3CS-60 is identified as .a
second example of violation 50-287/91-35-01 discussed in paragraph
2.c.
Within the areas reviewed, one violation with two examples was identified.
6
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 system restoration was
completed.
Surveillances reviewed and witnessed in whole or in part:
PT/0/A/115/07
Reactor Building Spray Valve Verification.
PT/0/A/305/01
Reactor Manual Trip Test.
PT/0/A/201/04
PORV Operability Test.
Within the areas reviewed, licensee activities were satisfactory.
No violations or deviations were identified.
4. Maintenance Activities (62703)
Maintenance activities were observed and/or reviewed during the reporting
period to verify that work was performed by qualified personnel and that
approved procedures 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 witnessed in whole or in part:
WR 36230C
Investigate and repair RPS Channel A Hot Leg Temperature
Indication
WR 35864C
Repair 1CCW-304
Unit 3 CRDM Stator Checkout/Replacement
Unit 3 Decay Heat Removal Dropline. Pipe Replacement
.Within the areas reviewed, licensee activities were satisfactory.
No violations or deviations were identified.
0
7
5.
Unit 3 Forced Outage
Unit 3 experienced a Reactor Coolant System (RCS) leak greater than 50 gpm
on November 23, 1991, and subsequently had to be shutdown. The leak was
caused when an improperly installed compression fitting failed.
Details
of the event are discussed in NRC Inspection Report (IR) 50-287/91-34.
The unit was still shutdown for repairs at the end of the inspection
period for IR 50-287/91-34 and all the activities conducted during the
outage. were not captured in the special inspection report. The following
items occurred during the Unit 3 forced outage and were not addressed in
IR 50-287/91-34..
a. Control Rod Drive Mechanism Problems
Following the RCS leak, various components in the reactor building
were inspected by the licensee for possible moisture intrusion.
Included in the components inspected were the Control Rod Drive (CRD)
.
mechanisms.
Due to airborne contamination in the reactor building,
the CRD stators were initially tested from the cable spreading room
on November 26, 1991.
Specifically, testing involved meggering to
measure resistance to ground values.
The resistance values found
from the cable spreading room were below the acceptance criteria of
200 megohms or more.
Low resistance values indicate that there may
be a problem.With the stator or the insulation.
Since all of the
readings taken from the cable spreading room were low, the licensee
decided to remegger the stators from within the reactor building.
The licensee chose eighteen stators and obtained megger readings from
the bulkhead (side wall of the refueling canal where the cables from
all stators are centrally located) to the stator.
All eighteen
stators meggered above the value of 200 megohms.
The licensee
concluded that the readings from the cable spreading room were in
error and that all the CRD mechanisms were free of any moisture
instrusion.
On December 8, 1991 during Unit 3 startup, CRD group 5, rod 6 dropped
into the core.
Startup was halted and investigation by the licensee
indicated that two phases of the stator had shorted together causing
the rod to drop into the core.
The unit was cooled down to repair
the stator and a decision was made to megger all sixty nine stators.
The stator for the dropped rod meggered above the acceptance
criteria; however, the connector was found to have moisture in it.
When meggering on all sixty nine stators was completed, there were
twenty nine stators that did not meet the designated acceptance
criteria. Consequently, they had to be removed from the vessel head
and dried.
Drying involved nitrogen purging and then, if needed,
electrical drying of the stators.
After drying, the twenty- nine
stators were remeggered and.at this time three stators did not meet
the acceptance criteria. The licensee decided to replace the three
In addition, one more stator had to be
replaced due to physical damage experienced when that stator was
dropped during handling.
The licensee also replaced twenty four
connector inserts with a new type of insert that is thought to be a
better quality insert. After reinstalling the twenty stators and the
connector inserts, the licensee remeggered all the stators and all
but one meggered within the acceptance criteria.
This stator was
redried and subsequently meggered greater than 200 megohms. With all
sixty nine stators meggering above the acceptance criteria, the
licensee .decided to proceed with unit startup.
On January 3, with RCS temperature at 240 degrees F, the stators were
again meggered.
At this time four stators did not meet the
acceptance criteria of at least 200 megohms. The licensee decided to
proceed with the startup.
This decision was based on industry
experience and the fact that the 200 megohm guideline set by B&W was
for new stators.
The stators in question were not newly installed
and due to some wear, the licensee postulated that megger readings
could be expected to be a lower value and the stator would still be
reliable. The licensee, at RCS temperature of 410 degrees F, again
meggered the four stators that had meggered below 200 megohms at RCS
temperature of 210 degrees. The results showed that meggering values
for stator readings had dropped slightly and two had risen
substantiality. Apparently, moisture from the leak had collected in
the stator at the bottom of the stator conduit and therefore the
initial reading at shutdown was not affected.
However, as heatup
began, moisture began to evaporate up the stator tube where it cooled
and condensed and then traveled back down the tube where it was
cooled.
This moisture trapped inside served to lower the megger
readings obtained during the subsequent checkout.
b. Through-Wall Crack in the Decay Heat Removal Dropline
At 8:30 a.m.,
on December 15,
1991,
during a tour of the reactor
building, the licensee noticed a small leak coming from the decay
heat dropline.
The exact location of the leak could not be
identified due to insulation. However, the leak was in the vicinity
of the decay heat drop line isolation valve 3LP-2. At this time the
unit was at 130 degrees F, 30 psig, with a pressurizer bubble
established and Low Pressure Injection (LPI)
aligned in the decay
heat removal mode.
The leak was later identified as coming from a
crack on. the decay heat dropline where a 3/4 inch piping relief
valve, 3LP-25, connects to the dropline.
The licensee determined
that the piping could possibly fail during further RCS pressuri
zation.
A decision was made on December 15 to depressurize and
cooldown to accommodate replacement of the portion of piping with the
crack. Additionally, the dropline had to be isolated to enable pipe
replacement. To remove decay heat, the licensee developed a special
procedure which involved aligning the spent fuel pool pumps to force
circulation through the core.
With the refueling canal full, vessel
head removed,
decay heat dropline isolated, the spent fuel pool pump
9
would take suction from a low point in the refueling canal and force
water through the core via the LPI'headers. The spent fuel cooler as
well as the LPI coolers were available heat sinks.
The licensee encountered some problems during filling.the refueling
canal.
The canal seal plate was. not leak tight during the initial
fill. *The canal had to be drained and portions of the rubber gasket
had to be shimmed to make the canal seal plate completely leak tight.
The licensee did not encounter any problems controlling core
temperature at approximately 90 degrees F during the time that they
were in the special spent fuel pump alignment.
The portion of the pipe with the crack was cut out and sent out to.
Babcock and Wilcox (B&W) for analysis. A replacement pipe was welded
on the decay heat dropline.
Preliminary analysis done by B&W
indicated that the failure mode for the decay heat dropline pipe was
high cycle, low amplitude load fatigue. There were no indications of
corrosion contributing to- the failure.
An NRC special materials
inspector closely followed the licensee's actions pertaining to the
crack and pipe replacement. Details of this issue will be documented
in NRC Inspection Report No. 50-287/91-37.
No violations or deviations were identified..
6.
Inspection of Open Items (92701)
The following open item was reviewed using licensee reports, inspection,
record review, and discussions with licensee personnel, as appropriate:
(Closed) Inspector Followup Item 56-269,270,287/90-34-01: Corrective
Actions Associated with LPSW Pilot and Solenoid Operated Valves for MDEFW
Pumps.
The licensee replaced the valve operator for the valves in
question with a different design of operator that does not use air as the
motive force to open the valve.
7. Exit Interview (30703)
The inspection scope and findings were summarized on January 10,
1992,
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.
Item Number
Description/Reference Paragraph
VIO 50-287/91-35-01
Inadequate
Configuration
Control
(paragraphs 2.c and 2.g)