ML20046A129
| ML20046A129 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 07/19/1993 |
| From: | Stetka T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20046A126 | List: |
| References | |
| 50-382-93-19, NUDOCS 9307270004 | |
| Download: ML20046A129 (15) | |
See also: IR 05000382/1993019
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-382/93-19
Optrating License: NPF-38
Licensee:
Entergy Operations, Incorporated
P.O. Box B
Killona, Louisiana 70066
Facility Name: Waterford Steam Electric Station, Unit 3 (Waterford 3)
Inspection At: Taft, Louisiana
Inspection Conducted: May 16 through June 26, 1993
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Inspectors:
E. J. Ford, Senior Resident Inspector
J. L. Dixon-Herrity, Resident Inspector
K. M. Kennedy, Project Engineer
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Accompanying Personnel:
D. M. Garcia, NRC Intern
Approved
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JJhomas F. Stetka, Ejef, Project Section D
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Inspection Summar_y
Areas Inspected:
Routine, unannounced inspection of plant status, onsite-
response to events, operational safety verification, engineered safety
features walkdown, maintenance and surveillance observations, followup on
inspection items, and review of licensee event. reports.
Results:
The operators maintained an appropriate awareness of plant activities
and control board indications. Their response to the reactor trip, and
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the coordination of activities to recover plant equipment and an
emergency diesel generator (EDG) day tank level indication was vary good
(Sections 2.1 and 3.1.6).
However, a violation was identified fer 15e
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failure to adequately implement a plant status control requirement 4 r a
locked valve (Section 3.1.1).
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Appreciable improvement was noted in the area of housekeeping and the
centrol of radiological areas.
Recent painting activities have enhanced
several areas of the plant, including the EDG rooms.
Additional
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9307270004 930720
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management attention to enhance radiological postings and restore ready
access to previously contaminated areas was evident (Section 3.1.3).
However, continued management attention was needed to assure transient
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materials were properly stored (Section 3.1.5).
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The licensee addressed plant activities and emerging issues with an
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appropriate safety awareness. The licensee's safety evaluation for the
increased radioactivity in the component cooling. water (CCW) system was
conservative (Section 2.1).
A heightened awareness of a potential
industrial hazard was noted (Section 3.1.4).
The EDG system engineer
demonstrated an excellent sense of system ownership (Section 3.1.3).
The CCW and auxiliary CCW systems were appropriately aligned to perform
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their safety functions. Several deficiencies were noted which were not
identified in the licensee's corrective action program. Additional
management attention was needed to ensure that plant personnel promptly
identify and document deficient equipment conditions (Section 4).
The maintenance and surveillance programs were appropriately implemented
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(Sections 5 and 6).
Summary of Inspection Findings:
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Violation 382/9319-01 was opened (Section 3.1.1).
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Inspection Followup Item 382/9208-03 was closed (Section 7 1).
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Licensee Event Report 382/92-008 was closed (Section 8.1).
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Licensee Event Report 382/92-010 was closed (Section 8.2).
Licensee Event Report 382/92-011 was closed (Section 8.3).
Licensee Event Report 382/92-012 was closed (Section 8.4).
. Licensee Event Report 382/92-019 was closed (Section 8.5).
Attachments:
Attachment - Persons Contacted and Exit Meeting
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DETAILS
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1 PLANT STATUS
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The plant was operating at full power at the beginning of this inspection
period until June 12, 1993, when power wcs reduced to 92 percent to allow'for
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surveillance testing of the main turbine steam inlet valves. On
June 15, 1993, the reactor tripped due to high level in Steam Generator 1
caused by a feedwater regulating valve failing open. The plant was restored
to full power operation on June 16, 1993, where it remained through the end of
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this inspection period.
2 ONSITE RESPONSE TO EVENTS (93702)
2.1 Reactor Trio Oue to Failure of Feedwater Regulatina Valve
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On June 15, 1993, at approximately 4:04 p.m., the reactor tripped from full
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power due to high water level in Steam Generator 1.
A few seconds after the
trip, an emergency feedwater actuation signal came in, as designed, due to low.
level in Steam Generator 2 as- a result of shrink following the trip. The A-1
6.9 KV bus failed to automatically fast transfer from the unit auxiliary
transformer (supplied by the main generator) to the~ start-up transformer,
causing Reactor Coohnt Pumps IA and 2A, Condensate Pumps A and C, and
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Circulating Water Pumps A and C to trip off line. After implementing
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Emergency Operating Procedure'OP-902-000, Revision 6, " Emergency Entry
Procedure," the operators initiated actions required by Emergency Operating
Procedure OP-902-005,' Revision 8, " Loss of Offsite Power / Station Blackout
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Recovery," minutes after the trip occurred. All other systems functioned.as
required, and the plant stabilized in Mode 3 (hot standby). After the plant
had stabilized and more was known'about what had caused the trip,'they exited
Procedure OP-902-005 and entered General Plant Operating Procedure OP-010-001,
Revision
'5, " General Plant Operations."
The operators had indications of problems with the feedwater regulating valve
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and auxiliary transfe"mer in the control room prior to the trip, but did not
have time to diagnose or react. The steam generator level increased due to
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feed regulating valve, FW-173A, going full open.
Instrument and
controls (I&C) technicians were called to the control room to observe
Valve FW-173A after operators noted that it was oscillating. The technicians
were taking readings from the feedwater cabinet in the control room when they
noted that the valve was going open at a very quick rate. They immediately
informed the control . room operators. The operators checked the steam
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generator levels, verified that they were high, and took the valve to manual,
but not in time to stop the transient.
Electrical maintenance personnel were calibrating the Unit A-1 auxiliary
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transformer -voltmeter, 7KVEM1A, earlier the same day.
After they removed it,
operators noted that the reading on the Unit A-1 bus megawatt-hour meter was
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considerably less than it had been.
The megawatt-hour meter was in the same
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circuit as the voltmeter that had been removed. When the trip occurred, the
technicians were about to inform the control room that the cause of the low
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meter reading was a fuse which had blown in the auto-transfer sync-check .
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circuitry. This prevented the circuit from verifying that the associated
startup transformer and bus were synchronized, thus preventing the bus from
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transferring. The reason that the fuse blew could not be determined, but the
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licensee suspected that it was a combination of age and added stress on the
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fuse due to work that was being done on the voltmeter.
Similar fuses in the
6.9 kV and 4.16 kV bus transfer circuits were replaced and these and the
failed fuse were sent offsite for analysis.
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The licensee determined that probable failure of the feedwater flow square-
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root extractor module and the adjustable feedback limiter module in the
feedwater control system caused Valve FW-173A to open. The apparent failure
of the modules caused the control system to react as if there was a loss of-
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feed flow, causing a large mismatch between feed flow and steam flow.
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caused the control system to demand that the feed regulating valve go full
open. The licensee replaced the two modules and sent them back to their
manufacturer to determine the cause of the failure. The manufacturer
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determined that only the square root extractor module had failed and that the
cause of failure was a failed transistor. They hypothesized a random
component failure due to a lack of prior history of.that transistor failing.
A records review by the licensee identified three possible square root
extractor module failures.
They were evaluating the need for periodic
replacement of square root extractor modules in both the feedwater and steam
bypass control systems. The issue will be resolved.when the resulting
licensee event report (LER 382/93-002) corrective actions are finalized.
2.2 Increase in CCW System Activity
As a result of the reactor trip on June 15, 1993,' activity levels increased in
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the reactor coolant system and, through a leak-in the letdown heat exchanger
(previously noted in NRC Inspection Report 50-382/93-07, Section 3.2), the
CCW system. The licensee performed a safety evaluation to address the
acceptability of low levels of radioactivity in the CCW system (less than
10" microcuries/gm) and low leakage rates in the letdown heat exchanger
(.30 gpm).
The licensee approved this safety evaluation on April 4,1992.
Due to iodine spiking as a result of the trip, CCW activity increased to a
point where the licensee mticipated that the activity might surpass the
10-' microcuries/gm safet: evaluation limit. The licensee performed a second
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safety evaluation screening that expanded the acceptable range for. initial CCW
activity. The conclusion was that the presence of activity in the CCW system
of less than 10 microcuries/gm Dose Equivalent Iodine (DEIni) would have
only a negligible effect on the consequences of any accident, thus, operation
with a CCW system activity of 10 microcuries/gm was considered acceptable
provided the existing 0.30 gpm reactor coolant system to CCW leak rate limit
was not exceeded. The maximum activity for CCW during the event was 8.03 x.
10" microcuries/gm DEI n3
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The licensee established a task force to examine'the different options
available to the site to repair the leak.
The options discussed thus-far
included plant shutdown to repair the heat exchanger before Refuel ~0utage 6
and repairing the leak while operating.
A third safety evaluation was being .
prepared to address the possibility of increased leakage and/or-activity.
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2.3 Conclusions
Operator awareness of plant activities and main control board indications was
appropriate.
This resulted in their promptly observing the feedwater
regulating valve failure and anticipating the reactor trip.
Coordination
between the operation and maintenance organizations to recover plant equipment
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was very good.
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The licensee demonstrated appropriate safety awareness in response to the
increased radioactivity in the CCW system.
The. engineering safety evaluation
was conservative.
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3 OPERATIONAL SAFETY VERIFICATION (71707)
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The objectives of this inspection were to ensure that this facility was being.
operated safely and in conformance with regulatory requirements and to ensure
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that the licensee's management controls were effectively discharging the
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licensee's responsibilities for continued safe operation.
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3.1 Plant Tours
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3.1.1
Locked EDG Air Receiver B2 Outlet 1 solation Valve
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During a tour of EDG Room B on June 10, 1993, the inspector observed that the
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locking device for EDG B Air Receiver B2 Outlet Isolation Valve EGA-152B was
not threaded through the valve yoke or otherwise attached to prevent-
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repositioning of the valve. The locking device was attached to the valve
handwheel and draped over the valve yoke such that it; appeared to.be-locked.
The valve appeared to the inspector to be in the open position.
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Administrative Procedure OP-100-009, Revision 11, " Control of Valves and
Breakers," required that this valve-be locked in the open position with a lock
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or positive locking device.
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The shift supervisor, after learning of this condition from the inspector,
dispatched an operator to determine the valve position and lock the valve.
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The operator verified that the valve was in the open position and locked the
valve.
A second operator was dispatched to independently verify that the
valve was in the open position and locked.
In addition, the shift supervisor
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dispatched an operator to verify that other EDG starting air va'1ves required
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to be locked by Administrative Procedure OP-100-009 were correctly locked.
In
an attempt to determine when the valve was last manipulated, the shift
supervisor identified that, while portions of the starting air system were-
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tagged out on June 9, 1993, Valve EGA-152B was not one of the valves tagged
out.
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Administrative Procedure OP-100-009 required that the position of valves and
breakers listed on the locked valve and breaker list be verified at least
quarterly.
The shift supervisor determined that Valve EGA-152B was verified
to be in the locked open position during a quarterly verification conducted on
May 7, 1993.
The inspector identified the failure to lock Valve EGA-1528 as a violation of
Technical Specification 6.8.1.a. and Administrative Procedure OP-100-009
(VIO 382/9319-01).
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3.1.2 CCW Heat Exchanger Fire D,or
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On June 18, 1993, while touring the reactor auxiliary building, the inspector.
found that Door 41 to CCW Heat Exchanger A could not be fully closed.
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latch on the door appeared to be sticking inside of the lockset. The door was
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posted as a fire door and was required to fully close. The inspector notified
security. The door had been verified as functional on June 17, 1993, in
accordance with Security Procedure PS-015-lll, Revision 4, " Fire Door
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Surveillance"; however, the inspector identified the hardware deficiency prior
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to the next scheduled surveillance.
Condition Identification 286358 was
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generated to assess what additional corrective actions may be needed.
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addition, a fire impairment tag was posted on the door and the door was added
to the hourly fire watch patrol. The licensee's response to this condition
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was appropriate.
3.1.3 General Site lour
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During site tours on June 14 and 15, 1993, the inspector noted many
improvements made in the area of housekeeping around the site.
In addition to
the painting mentioned in previous reports, different areas of the plant have
been upgraded in appearance due to the painting program. The two most notable
were the +15-foot level of the turbine building and the EDG rooms.
It was
noted that the EDG system engineer was cognizant of a recent industry event
where an EDG was rendered inoparable because of painting activities.
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individual demonstrated a heightened awareness of the activities in the EDG
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rooms and periodically assured himself that the EDGs had not been
inadvertently painted.
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Other programs, like the labeling program, have made good progress. The
changes to the radiation posting practices were noted throughout the site and
were definitely a positive improvement in both housekeeping and safety
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most noted improvement was the condition of the safety injection pump rooms.
These areas had been decontaminated and the hot particle protection barrier
removed from around the low pressure safety injection pumps, allowing the
pumps to be viewed freely.
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3.1.4
Addition of Chenicals' to Wet Cooling Tower
On June 22, 1993, the inspector observed the addition of chemicals by the
licensee to the west wet cooling tower.
The towers were operating at the
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time. The technicians were adding Calgosil, a corrosion prohibitor, directly
into the basin from the second level up.
A large aarrel of the chemical, a
dry powder, was poured into the basin from a plast.: bag. While the chemical
was being added, the inspector noted a plastic cup floating on the surface of
the basin. The cup.had sunk when the inspector went a level lower to check
after the addition of the chemical. The inspector discussed the addition of
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chemicals and the cup with the shift supervisor. The technicians had already
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reported the cup. The shift supervisor spoke with systems engineering to see
if it would cause a problem in the system.
The system engineer cited a
licensee probabilistic risk assessment report that was done on the impact of
debris in the west cooling tower basin on December 8, 1992, and stated it
would not be a problem.
The inspector questioned the practice of adding the chemical from the second
level up from the basin's edge. Although most of the chemical went into the
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basin, a small amount was blown out. The chemistry supervisor explained that
this was the accepted practice when the tower was operating during_the summer
because the draft caused by the falling water caused the chemicals to blow
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back into the technicians faces. During the rest of the year, chemicals were
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added at the next level down at the basin's edge. Neither practice was
considered desirable,
in the first instance, not all of the chemical made it.
into the basin, depending on the wind or drafts.
In the second,_the
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technicians had to lean out over the guardrail or get on the edge of the-basin
to pour in the chemical.
In both practices, the large barrel containing the
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chemical had to be lowered down several stairways to get to the basin.
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inspectors have identified previous similar concerns with adding chemicals to
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the wet tower basins to the licensee. The licensee subsequently identified
that the chemistry department had initiated a design change request to install
a chute above the basins to allow easy addition of chemicals without
endangering personnel.
3.1.5 Tour of Cooling Towers
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On June 22, 1993, while touring the east cooling tower, the inspector noted
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that a raincoat had been draped over a pipe next to the basin edge, and a
large cover from the control room breathing air compressor was leaning on the
breathing air tanks.
The raincoat had been noted on an earlier date, but was secured around the
pipe at the time so that it would not be inadvertently blown into the basin.
The shift supervisor had it removed from the area immediately.
The shift
supervisor also investigated the missing compressor cover.
It was determined
that a condition identification had been written to identify that the cover
hinges were broken. The licensee indicated that the breathing air compressor
was operable without the cover installed.
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3.1.6
Loss of EDG Day Tank A Level Indication
On June 25, 1993, during the night shift, operators noted a slight burnt smell
in the back of the control room.
I&C technicians on duty were notified. They
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identified a burnt card in the Train A balance-of-plant process analog control
cabinet.
In addition, they found that the primary power supply for that
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cabinet had failed and that power to the cabinet was being supplied from the
backup power supply. The card provided level indication for the EDG A day
tank. The operators entered Technical-Specification 3.8.1.1.1 Actions b
and d, declaring EDG A inoperable. The inspector observed from the control
room as the operators reacted and gained control of the situation. The level'
in the day tank was raised until the high level alarm was activated in the
control room to provide a means of monitoring the day tank level.
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Technica' Specification action statement was exited once Surveillance
Procedure OP-903-066, Revision 6, " Electrical Breaker Alignment Check," was
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completed. Condition identifications were written to replace the card and
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troubleshoot the failed primary power supply.
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3.2 Conclusions
Operator performance was generally very good as demonstrated by their
cognizance of plant activities and response to the loss of EDG day tank level
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indication. However, a violation was identified for the failure to lock _ an
EDG starting air valve in accordance with the procedure requirement.
The licensee's housekeeping activities exhibited notable improvement as
reflected in its painting program,'and improved health physics postings and
decontamination practices.
It was noted though, that continued management
attention was needed in this area as indicated by the improper staging of a
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raincoat in an area where it could adversely affect equipment operation.
The licensee's action to initiate a design change for adding chemicals to the
wet cooling tower basins indicated a heightened awareness to reduce potential
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industrial hazards.
4 ENGINEERED SAFETY FEATURE (ESF) SYSTEM WALKDOWN (71710)
During this inspection period, the inspectors performed a detailed procedure
and drawing review and walkdown of the systems below to determine their
overall system condition and operational readiness. Although not ESF systems,
they are essential- support systems to a majority of the ESF systems.
4.1 CCW and Auxiliar_y CCW Systems (ACCW)
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The CCW system is a closed cooling water system serving all reactor
auxiliaries requiring cooling water.
Heat is removed from the system by dry
cooling towers and by the CCW heat exchangers, if required. The ACCW is a
separate system that cools the CCW after the dry cooling towers via the CCW
heat exchangers and then dissipates that heat to the atmosphere through the
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wet cooling towers. The ultimate heat sink consists of 9 of the 15 fans in
the dry cooling tower, the wet cooling tower, and the water stored in the wet
cooling tower basins.
The inspectors reviewed Procedures OP-002-001 and OP-002-003 and the Design
Basis Document, W3-DBD-004, Revision 0, " Component Cooling Water Auxiliary
Component Cooling Water Design Basis Document."
ihe inspectors conducted a physical walkdown of the safety-related portions of
the CCW and ACCW systems. Housekeeping was considered good'in most areas.
The west cooling tower was not as well kept as the east cooling tower due to
the continuing problem with pigeons, 'although the conditions had improved _ from
the observations discussed in NRC Inspection Report 50-382/92-27. The lowest
level of the towers was roped off as a radiological controlled area due to the
radiological contamination in the system.
(Paragraph 2.2 of the report
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provides a discussion for the cause of the system contamination.) The
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inspectors found the area radiological posting to be appropriate as this was
the only portion of the tower easily accessible to the CCW valves and piping.
The rest of the system was located in the reactor auxiliary building, a
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designated radiological controlled area.
Several lights were out in the
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expansion tank room. This room was a locked room on the roof of the reactor .
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auxiliary building. A technician replaced the bulbs as the inspectcrs walked
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down that portion of the system.
A comparison of samples of the physical plant to Flow Diagram G-160,
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" Component Cooling Water System," and the valve lineups from System Operating
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Procedures OP-002-001, Revision 8, " Auxiliary Component Cooling Water," and.
OP-002-003, Revision 9, " Component Cooling Water System," revealed several
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concerns.
The inspector noted a capped valve in the chemical feed portion of the system
that did not have a label and could not be identified on the drawing and two
valves, CC-505 and CC-508, the chemical feed tank inlet and outlet isolation
valves, that were open, but were required to be closed by the normal lineup.
The shift supervisor explained that these had been left open, as specified in
the applicable procedure, f ' lowing the addition of nitrates.
The inspectors also identified 12 or more unlabeled valves in the vicinity of
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the CCW and chilled water expansion tanks.
Some of these -valves were part of-
the CCW expansion tank, while the rest were part of essential chilled water
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system expansion Tank B.
Similar valves on essential chilled water expansion
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Tank AB, next to Tank B, were labeled. The valves were instrument valves and
were not on the drawing. One of these valves was missing its packing gland
nuts.
In addition, the CCW surge tank outlet Header B drain valve, CC-110B,
was badly corroded. These concerns were brought to the attention of the shift
supervisor.
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Condition identifications were written to replace the packing nuts and to
resolve the corroded valve. The inspectors determined that the instrument
valves were not required to be depicted on Drawing G-160. The system
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engineering group developed an action plan to resolve. the concerns with the
. unlabeled valves, which included a field walkdown to identify discrepancies.
between the drawings and field conditions. Condition identifications will be
initiated to resolve discrepancies.
4.2 Conclusions
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The CCW and ACCW systems were properly aligned to perform their safety
function.
Equipment deficiencies were generally identified by condition
identifications. However, it was noted that a number of deficiencies,
including unlabeled instrument valves and a badly corroded' valve had not been.
properly identified. This indicated that additional management attention was
needed to ensure that plant personnel promptly identify deficient equipment
conditions.
5 MONTHLY MAINTENANCE OBSERVATION (62703)
The station maintenance activities affecting safety-related systems and
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components listed below were observed and documentation reviewed to ascertain
that the activities were conducted in accordance with approved work
authorizations (WAs), procedures, Technical Specifications, and appropriate
industry codes or standards.
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5.1 High Pressure Safety Injection Pump (HPSI) Preventive Maintenance
On June 15, 1993, the inspector observed portions of work done by mechanical
maintenance technicians under WAs 01106856 and 01101579. The work consisted
of lubricating the HPSI A pump coupling and replacing the HPSI CCW inlet
header vent valve downstream flange gasket. The technicians were working to
Rework Procedure MM-006-Oll, Revision 5, " General Torquing and Detensioning,"
while reassembling the coupling. The crew supervisor observed the work,
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provided guidance, and assisted as necessary. The work package.was complete
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and all required signatures had been obtained. No concerns were identified.
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5.2 Troubler. hooting of Feed Regulatina Valve 1
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On June 15, 1993, the inspector observed portions of the troubleshooting of
feedwater regulating Valve 1 following the plant trip that occurred _ on the
same day.
The package was a basic troubleshooting package that had been
initialed by the shift supervisor, as required by Administrative
Procedure UNT-005-015, Revision 3, " Work Authorization Preparation."
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allowed the technicians to take readings and do tests that would not affect
plant operations to determine what the cause of the failure was before trying
to make repairs.
The technicians, job supervisor, and system engineer were
very knowledgeable of the system. No concerns were identified.
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5.3 Control Room Emergency Filtration Unit B
On June 22, 1993, the inspector observed a portion of the preventive
maintenance done on Control Room Emergency Filtration Unit B.
The unit was
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completely opened up when the inspector arrived at the work site.
The filters
had already been changed out and the technicians were completing some
maintenance on the heater coils. The compartments in the unit were fairly
clean. Much of the dust from the filter change out had been cleaned up.
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There appeared to be no interior or exterior corrosion or deterioration. The
technicians completing the work were knowledgeable of both the equipment and
the procedere (ME-004-401, Revision 7, " Heating and Ventilation Equipment")
they were working to. A confined space permit had been obtained to allow them
to work in the unit. The inspector was present for the final inspection and
while the doors were secured and locks replaced.
No concerns were identified.
5.4 Essential Chiller AB
On June 23, 1993, the inspector observed the filling of Essential Chiller AB
with freon.
The system had lost all of its freon through leaks on the packing
motor terminal and by three valves.
The leaks had been detected and repaired
and the system was being re-filled with freon as directed by WA 01109883. The
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paperwork in this package was complete and the technicians were knowledgeable
on the task they were performing. No concerns were identified.
5.5 Conclusions
The maintenance personnel were cognizant of the WAs instructions and
limitations. The I&C technicians, job supervisor, and system engineer were'
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very knowledgeable of the feedwater regulating valve control system. Other
routine maintenance activities were properly performed utilizing appropriate
procedural controls.
6 BIMONTHLY SURVEILLANCE OBSERVATION (61726)
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The inspectors observed the surveillance testing of safety-related systems and
components listed below to verify that the activities were being performed in
accordance with the licensee's programs and the Technical Specifications.
6.1
Plant Protection System Channel D Functional Test
On June 16, 1993, the inspector observed the high logarithmic power level and
the reactor protection system matrix test portions of the functional test on
Plant Protection System Channel D that was required prior to escalating power
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following the plant trip on June 15. The operators were properly using
Surveillance Procedure OP-903-107, Revision 11, " Plant Protection System
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Channel D Functional Test." The work package, which included WA 01110239, was
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in order. The operators were careful to' ensure that the reactor trip breaker
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phase current lights were energized while going through>the procedure as
required by the most recent procedure change. This procedure change was made
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as a result of a recent event during which an observant operator noted that
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the phase current lights associated with two trip breakers were deenergized,
while the multiple indications listed in the procedure all indicated closed.
The operator challenged the procedure and suspended testing while maintenance
checked the trip breakers.
It was found that one breaker was not completely
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closed due to a loose spring.
Had testing continued, a reactor trip would
have occurred.
In addition to the procedure change, an Operator Experience
Report was written up for this event and was required reading for operators.
No concerns were identified while observing this surveillance.
6.2 Conclusions
The surveillance test was performed in accordance with the procedure
requirements. The operators' performance during the test was very good and
they were fully cognizant of expected indications and potential system
failures.
7 FOLLOWUP (92701)
,
7.1
(Closed) Inspection Followup Item 382/9208-03:
Loss of Shutdown Margin
This inspection followup item addressed a licensee identified failure to
maintain shutdown margin requirements following a plant shutdown due to
weaknesses in operator training as well as a weakness in the shutdown margin
determination procedure.
This event was reported to the NRC in Licensee Event
Report 382/92-19.
This licensee event report is closed in Section 8.5.
The
procedure did not require the operators to project changes in shutdown margin
due to Xenon decay.
Because of this, the operators did not anticipate the
effect that Xenon decay would have on shutdown margin following a reactor
shutdown.
The inspector reviewed Surveillance Procedure OP-903-090, Revision 6,
" Shutdown Margin," which added steps to verify that the required shutdown
margin would be maintained during the 24-hour interval of the Technical Specification 3.1.1.2 surveillance requirement.
In addition, the event was
discussed with all operations personnel, reviewed in continuing training for
plant staff personnel, and added to the requalification training curriculum
for reactivity management.
.i
8 ONSITE REVIEW OF LICENSEE EVENT REPORTS (92700)
8.1
(Closed)
Licensee Event Report 382/92-008P?E
khtESFActuation
due to Plant Protection System
i
,
This event, which occurred on July 26, 1992, resE NEP N [ a failure of
circuitry provided for testing the ESF matrix relays (Channel C). The root
cause determination and corrective action were submitted in a supplemental
report, Licensee Event Report 92-008-01, on January 29, 1993.
wo
A Kepner Tregoe analysis revealed that the problem were related to the matrix
test circuit for Matrix AC. Additional testing and inspections did not
identify the exact component (s) which caused the inadvertent actuation, thus,
the root cause remained indeterminate. Corrective measures specific to the
root cause could not be applied.
r-
ti
e
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P
.During Refuel Outage 5, a station modification (Design Change 3371) was
performed on the matrix test circuit. The modification replaced the-matrix
hold push-button with a three-position selector switch, provided test power
channelization, and eliminated the terminal block for.all six matrices.
It'
was expected that the design change would address the problem.
,
The inspector reviewed the documentation of the root cause and the design
change and determined that the licensee had taken the necessary corrective
action to close this item.
3
,
event Report 382/92-010: Noncompliance with Boron
8.2 (Closed) Licensee
Dilution Technical Specification
This report addressed the licensee entering Mode 4 during a plant shutdown
while in an operating configuration prohibited by Technical
-
Specification 3.1.2.9, " Boron Dilution." The plant had three charging pumps
running in an effort to maximize the removal of cobalt-60 from the reactor-
coolant system to reduce radiation exposure to personnel during the shutdown
ps.'od.
The Technical Specification required that one of.the charging pumps
be secured and the breaker racked out to prevent inadvertent boron dilution in
the reactor coolant system. The root cause for this event was. determined to
be an inadequate step in the procedure, with inadequate attention to detail by-
the operating crew as a contributing cause. The inspector reviewed the
revision of the procedure that was approved by the Plant Operations Review
Committee on November 11, 1992. The revision _added precaution and caution
statements and clearly identified that Technical Specification 3.1.2.9 must be
met before entering Mode 4.
The shift supervisor on duty the day of the event
reviewed Operating Instruction 01-030-000, " Improving.0perator Performance,"
with his shift. All other operations personnel reviewed the event via
required reading. The revision of the procedure.and. training of personnel
were found to be adequate to prevent repetition'of the event and allow closure
of this item.
8.3 (Closed) Licensee Event Report 382/92-011:
Technical Specification
'
Required Sample Obtained Late as a Result of Personnel Error
On September 24, 1992, while in Mode 5 (cold shutdown) the licensee discovered
that a CCW system grab sample required by the Technical Specifications had not
been taken within the required frequency.
The root cause was determined to be personnel error by the contractor
technician. The technician appeared to simply overlook the sample
requirement. A contributing factor was inadequate oversight responsibility
for count room activity by permanent plant staff personnel.
.
Corrective actions included assignment of clear oversight responsibility to
i
specific individuals and temporary removal of contract personnel from
Technical Specification related sampling requirements until the existing
'
training and qualification requirements for contract personnel were evaluated.
a
i
]
r
.
.
-14-
Procedure NTC-230, Revision 4, " Health Physics Contract Technicians ' Training,"
was revised and became effective April 7, 1993. The revision separated the
current count room _ technician qualification card into two cards; H100-042-04,
" Senior Contractor Count Room Technician Qualification Card" and H100-043-00,
" Junior Contractor Count Room Technician Qualification Card." Personnel
'
qualified to the basic level will be somewhat limited in the tasks that they
,
I
may be assigned.
Based on the inspector's review of this documentation, it was determined that
the licensee has implemented appropriate corrective actions to address the
identified event.
8.4 (Closed) License Event Report 92-012: Jumper Error Results in Partial
Engineered Safety Features Component Actuation
On October 2, 1992, during the licensee's fifth refueling outage, while
performing maintenance to replace a relay in the engineered safety features
,
actuation systems, an improperly placed electrical jumper caused a limited
number of ESF actuation relays to deenergize, resulting in an invalid-
l
actuation. The root cause was determined to be an improperly positioned
_
'
'
alligator clip, which, while on the correct terminal point, did not establish.
electrical continuity.
The immediate corrective actions for this event were to properly land the-
jumper and restore actuated components to their normal conditions.
Photographs were taken of the temporary jumper installation for review by the
-
personnel responsible in the relay replacement work.
The inspector determined
that this review had been completed and that the licensee event report had
i
I
been reviewed with electrical and I&C maintenance personnel during a shop
meeting to prevent recurrence of the event.
8.5 (Closed) Licensee Event Report 382/92-019: Loss of Shutdown Marqin
,
This licensee event report addressed a loss of shutdown margin, caused by
,
xenon decay, due to inadequate procedural guidance and the failure of shift
,
operating crews to anticipate changes in xenon concentration and its effect on
shutdown margin. The licensee's corrective actions for this event were
reviewed by the inspector during closecut of Inspection Followup
Item 382/9208-03 and found to be satisfactory (Section 7.1).
>
>
f
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ATTACHMENT'
1 PERSONS CONTACTED
1.1
Licensee Personnel
R. E. Allen, Security and General Support Manager
- L. W. Laughlin, Licensing Manager
T. R. Leonard, Technical Services Manager
D. E. Marpe, Mechanical Maintenance Superintendent
- D. F. Packer, General Manager, Plant Operations
R. D. Peters, Electrical Maintenance Superintendent
R. G. Pittman, I&C Maintenance Superintendent
J. A. Ridgel, Radiation Protection Superintendent
- R. S. Starkey, Operations and Maintenance Manager
l
D. W. Vinci, Operations Superintendent
1.2 Other NRC Personnel
T. F. Westerman, Chief, Engineering Section, DRS, Region IV
D. L. Wigginton, Project Manager, NRR
- Denotes personnel that attended the exit meeting.
In addition to the above
'
personnel, the inspectors contacted other personnel during this inspection
period.
2 EXIT MEETING
The inspection scope and findings were summarized on June 30, 1993, with those
persons indicated in paragraph 1 above. The licensee acknowledged the
__
inspectors' findings.
The licensee did not identify as proprietary any of the
material provided to or reviewed by the inspectors during this inspection.
,.