ML20036A293
| ML20036A293 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 05/04/1993 |
| From: | Stetka T NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20036A281 | List: |
| References | |
| 50-382-93-07, 50-382-93-7, NUDOCS 9305110055 | |
| Download: ML20036A293 (15) | |
See also: IR 05000382/1993007
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APPENDIX
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-382/93-07
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Operating License: NPF-38
Licensee: Entergy Operations, Incorporated
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P.O. Box B
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Killona, Louisiana 70066
Facility Name: Waterford Steam Electric Station, Unit 3 (Waterford 3)
Inspection At: Taft, Louisiana
Inspection Conducted:
February 21 through April 3, 1993
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Inspectors:
E. J. Ford, Senior Resident Inspector
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S. J. Campbell, Resident Inspector, Arkansas Nuclear One' Station
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J. L. Dixon-Herrity, Resident Inspector
Accompanying Personnel:
D. M. Garcia, NRC Intern
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Approved:
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MF/O
Thomas F. Stetka, Chi
Profi/ct Section D
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Inspection Summary
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Areas Inspected:
Routine, unannounced inspection of plant status, onsite
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response to events, operational safety verification, maintenance and
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surveillance observations, and followup on corrective actions for violations.
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Results:
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Inadequate work package review by operators resulted in a reactor power
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cutback.
This was considered poor work controls (Section 2.1).
The licensee was proactive and thorough in correcting problems with the
uninterruptable power supply (Section 2.2).
Chemistry personnel's failure to have an adequate procedure and to
follow this procedure for maintaining chemical control of diesel fuel
oil, was noted as a weakness; however, prompt corrective actions were
taken to correct the error. A noncited violation was identified
(Section 3.1.3).
The licensee's recognition of a problem with the Technical
Specifications regarding the wet coolant tower fans and their lack of
action to correct the problem was noted as a weakness (Section 3.1.5).
9305110055 930504
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ADOCK 05000382-
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The storage of a breaker in an undesignated area in the electrical
safeguards switchgear room was inappropriate (Section 3.1.6).
Efforts by the technicians to prevent metal shavings from falling onto
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existing contacts by constructing an adhesive shelf from duct tape was
considered a good work practice (Section 4.2).
Summary of Inspection Findinas:
Violation 382/9203-01 was closed (Section 6.1).
Violation 382/9223-01 was closed (Section 6.2).
Violation 382/9223-02 was closed (Section 6.3).
Attachment:
Attachment - Persons Contacted and Exit Meeting
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DETAILS
1 PLANT STATUS
The plant was operating at full power at the beginning of this inspection
period until February 26, 1993, when power was reduced to 99 percent due to
moisture separator reheater (MSR) tube bundle leakage.
The plant returned to
full power on March 2, after tube bundle isolation.
On March 3, 1993, the
plant experienced a reactor power cutback to 45 percent power following the
loss of a main feedwater pump.
On March 4, 1993, a reactor trip occurred when
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plant protection system (PPS) Channels C and D deenergized.
The plant was
restored to full power operation on March 6, where it remained through the end
of this inspection period.
2 ONSITE RESPONSE TO EVENTS
(93702)
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2.1 Reactor Power Cutback
On March 3,1993, while the plant was at 100 percent power, Drain Collection
Tank 2B experienced level control problems.
Maintenance workers were assigned
to work on the Drain Collection Tank 2B alternate level control valve.
Due to
a misunderstanding, maintenance personnel presented operations personnel with
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an existing work package for the Feedwater Heater 2B alternate level control
valve in lieu of a work package for the drain collection tank alternate level
control valve. The shift supervisor reviewed and authorized that work package
without noting that it was not the correct component. When maintenance
personnel opened the heater valve, the three heater drain pumps tripped
simultaneously, due to low suction pressure.
This caused one of the two main
feedwater pumps to trip also due to low suction pressure, resulting in a
reactor power cutback system actuation.
The operators entered Off-Normal Procedure OP-901-003, " Reactor Power
Cutback," and manipulated control element assemblies to restore them to within
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Technical Specification insertion limits.
All systems operated as expected
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and the plant stabilized at approximately 50 percent reactor thermal power.
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The plant was restored to full power operation on March 4.
The root cause of this event was inadequate review of the work package by the
shift supervisor. The inspectors noted a lack of communications by both
operations and maintenance personnel and informed the licensee of their
concern in this matter.
The licensee initiated a Human performance Evaluation
formal review to determine what corrective actions were appropriate.
2.2 Reactor Trip due to PPS Actuation
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On March 4,1993, while the plant was operating at full power, the plant
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experienced an automatic reactor trip.
The trip occurred when PPS Channels C
and D deenergized, satisfying the coincidence logic. The operators initiated
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action required by Emergency Operating Procedures OP-902-000, " Emergency Entry
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Procedure," and OP-902-001, " Uncomplicated Reactor Trip Recovery Procedure."
All systems functioned as required, and the plant stabilized in Mode 3 (hot
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At the onset of the problem, the operators received a static uninterruptible
power supply (SUPS) Safety Measurement Channel (SMC) C trouble alarm, followed
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by a reactor trip. A frequency detection card had failed in SMC SUPS. causing
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the SUPS to trip.
The loss of SMC SUPS caused the core protection calculator
for Channel C to trip. With PPS Channel C in a tripped condition, a " half
trip" was generated in the PPS logic matrices associated with Channel C.
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The loss of SUPS SMC also interrupted power to all the power supplies in
PPS Channel C.
Since all power supplies performing vital functions in PPS are
auctioneered, the loss of the PPS Channel C power supplies required the
alternate supplies to assume the loads.
During this event, a power supply
(PS8) in PPS Channel D failed when its supply breaker tripped open on
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This occurrence deenergized the PPS Channel D logic unit.
Since
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Power Supply PS6 in Channel C, which is auctioneered with PS8 in
PPS Channel D, was already inoperable, a " half trip" occurred in all the
matrices associated with Channel D.
The occurrence of these two events
satisfied the necessary logic and resulted in a reactor trip.
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The failure of the frequency detection card in SUPS SMC C was a result of
age-related capacitor degradation. Subsequent analysis indicated that PS8
contained three capacitors that were reading significantly lower than their
rated value and another capacitor was demonstrating excessive current leakage
to ground.
The frequency detection card in SUPS SMC C and SMC D were
replaced, SMC B had been replaced after an earlier failure that occurred in
December 1992, due to age-related degradation.
The licensee had plans to
replace the SUPS frequency detection cards in all the channels during
Refueling Outage 6.
The card in SUPS SMC A will be changed out when a
replaceunt card is available.
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Power Supply PS8 was manufactured by Powermate and was replaced with an
updated Lamda power supply.
There were three Powermate power supplies
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remaining in PPS, and they were checked for any evidence of voltage variation
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in the output signal that would be indicative of power supply degradation.
Power Supply PS4 showed excessive ripple and was replaced with a Lamda power
supply. Upon further examination, four of the output capacitors were
degraded. Additional checks will be added to the scope of the periodic
maintenance performed on the PPS power supplies and the replacement interval
for the SUPS frequency cards.
On March 6, the plant was restored to full power.
The licensee was proactive
in identifying and thorough in correcting the problems associated with the
SUPS.
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2.3 Conclusions
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Inadequate work package review by operators caused a reactor power
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cutback to approximately 45 percent power.
This was considered poor
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work control.
The licensee was proactive and thorough in correcting the SUPS problems.
3 OPERATIONAL SAFETY VERIFICATION (71707)
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
licensee's responsibilities for continued safe operation.
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3.1 Plant Tours and Control Room Observations
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Throughout the inspection period, the inspectors observed control room
activities and monitored plant status on a regular basis.
3.1.1
Isolation of MSR B
Since Refueling Outage 5, the plant has been experiencing secondary-side
degraded performance. The licensee noted a loss of efficiency to the main
turbine and began to investigate this condition.
The licensee determined that
tube leaks existed in the east heater tube bundle of MSR B.
On February 26, 1993, main turbine governor Valve 4 was closed in order to
prevent wear of the valve.
Reactor power was reduced to 99 percent power and
the reactor coolant system cold leg temperature was maintained below 558of, as
required by Technical Specifications. On March 2,1992, the licensee isolated
main steam to the east tube bundle of MSR B.
As the plant began to increase
in efficiency, the licensee reopened governor Valve 4 to 13 percent and
adjusted reactor coolant boric acid concentration as required to maintain
reactor power at 100 percent.
MSR heater tube bundle leaks have been a chronic problem at Waterford 3 due to
a design deficiency with the MSR internals.
The tube bundles are made of
90/10 copper / nickle (CuNi) based material, which, it appears, does not allow
sufficient movement of the bundles during heatup and cooldown cycles,
resulting in cracks or breakage. The licensee indicated that they plan to
replace the MSR internals with components made of stainless steel during the
next refueling outage.
3.1.2
Leakage into Component Cooling Water (CCW) System
On March 9, 1993, the shift supervisor briefed the inspector on suspected
reactor coolant system leakage into the CCW system.
Possible leakage was
suspected when the CCW radiation monitor entered the alert range on
March 8, 1993. After troubleshooting the problem, the licensee determined
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that both the letdown heat exchanger and the letdown radiation monitor heat
exchanger had minor leakage (.002 gpm based on equilibrium conditions).
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further analysis, the licensee determined that the leakage existed only in the
letdown heat exchanger.
The licensee plans to repair the leakage during the
next refueling outage as long as there is no increase.
Until then, the
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licensee has adjusted the letdown backpressure control valve so that pressure
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was reduced from 460 to 400 psig and plans to run the second charging pump
only when necessary. The CCW activity level stabilized after the backpressure
control valve was adjusted.
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3.1.3
Emergency Diesel Generator (EDG) Inoperable
On March 13, 1993, while observing control room activities, the inspector
noted that EDG A was declared inoperable on March 12, 1993, due to the failure
of the fuel oil oxidation stability to meet the Technical Specifications
limits. Technical Specification 4.8.1.1.2.c requires that new fuel oil, prior
to addition to the storage tanks, be sampled in accordance with
Procedure ASTM-0270-1975, and verified within the minimum requirements
(impurity level of less than 2 mg of insolubles per 100 ml) and tested within
the specified time limits (analysis shall be completed within 7 days after
obtaining the sample).
The chemistry department implemented
Procedure CE-002-030, Revision 3, " Maintaining Diesel Fuel Oil," to accomplish
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this Technical Specification requirement.
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New fuel was added to Fuel Oil Storage Tank A on March 5,1993.
Prior to the
addition, at 11:50 a.m. on March 5, fuel oil samples were taken in accordance
with Procedure CE-003-700, " General Grab Sampling Techniques;" one sample was
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to be utilized for onsite analysis and the other sample was to be shipped to a
contractor laboratory.
Onsite analysis was performed and the results were
within specifications.
Procedure CE-002-030, Revision 3, Step 10.2.7.3,
required, in part, that the sample be taken to materials management for
expeditious transport or hand delivered by chemistry to the contractor
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laboratory for analysis. On March 10, 1993, the contractor laboratory
received the other sample. The sample was not delivered for 5 days due to
miscommunications and personnel errors.
In the past, samples were normally
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delivered within that same working day, and the analysis was performed within
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3 days. Apparently the procedure was inadequate in that it did not provide
clearly defined time limits to assure that the TS requirements would be met.
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According to Step 10.2.8.1, of the same procedure, it required, in part, that
the chemistry supervisor ensure that the oxidation stability specification was
satisfied by calling the contractor laboratory and recording the
telecommunicated results.
On March 12, 1993, at approximately 10:45 a.m., the
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chemistry supervisor called the contractor laboratory to ensure that the
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analysis was complete; however, he did not ensure that the oxidation stability
results were within specifications as required by the procedure.
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until 4:45 p.m. that day, after the chemistry supervisor reviewed the results,
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that the results were found to be out of specification.
The control room was
notified at 5:29 p.m.,
and EDG A was declared inoperable.
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The chemistry supervisor contacted the vendor laboratory to redo the analysis
immediately. A condition report (CR-93-022) was initiated to enter the
corrective action program.
The chemistry superintendent informed the
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inspectors that chemistry personnel involved were counselled and that the
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procedure would be revised to clarify the sampling process by May 31, 1993.
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The results of the second analysis were within Technical Specifications and on
March 13,1993, at 9 p.m.,
The licensee found
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that Technical Specification requirements were satisfied by declaring EDG A
inoperable upon verifying that oxidation stability was out of specification.
The adequacy of Procedure CE-003-700 and the failure to follow Step 10.2.8.1
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in this procedure are considered to be a violation of Technical
Specification.6.81; however, this violation will not be subject to
enforcement action because the licensee's efforts in identifying and
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correcting the violation meet the criteria specified in Section VII.B.(2) of
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the enforcement policy.
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3.1.4
Reactor Cooling Pump Bearing Temperature High
On March 23, 1992, Annunciators L-9 and L-10 on Panel CP-33 were illuminated
for CCW System A and B low temperature, respectively.
The setpoint for the
CCW low temperature alarm was 80oF and the actual temperature was 780F.
Dry
Cooling Tower' Fans 7, 10, 11, 12, 13, 14, and 15 on both Trains A and B had
been turned on to lower CCW loop temperatures in order to maintain Reactor
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Coolant Pump 2A upper thrust bearing temperature approximately 187.3 F.
The
inspector questioned the licensee regarding the reason for placing the CCW
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system in an alarmed low temperature condition in order to maintain the upper
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thrust bearing temperature of Pump 2A below it's alarm setpoint.
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The_ normal operating temperature for three of the four reactor coolant pumps
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was between 160 F and 170oF.
Reactor Coolant Pump 2A had the highest upward
thrust because the shape of the pump's impeller was different compared to the
other three pumps.
This increased upper thrust increased the upper thrust
bearing temperature. The purposes for maintaining a low CtW temperature were
to increase the reactor coolant pump seal life and to control the upper thrust
bearing temperature.
The annunciator response procedure for Annunciators L-9 and L-10 directed
operators to Procedure OP-901-510, Revision 0, " Component Cooling Water System
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Malfunction." Operations personnel had concluded that, since the _ likelihood
for freezing components cooled by CCW during warm ambient conditions was_ low,
continued operations while the CCW loops were in a low temperature alarmed
condition was acceptable.
The licensee reassessed the CCW loop temperatures
and increased the temperatures to clear the alarms.
This action was effective
in that the resulting upper thrust bearing temperatures remained unchanged and
the CCW loop temperature alarm remained cleared.
The licensee stated that the
established emergency operating procedures provided provisions for operators
to place components from the manual to the automatic mode in the event that
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the emergency operating procedures were required to be entered.
The
licensee's actions and assessment were acceptable.
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3.1.5 Wet Cooling Tower (WCT) Fans Inoperable
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The plant has two trains of WCT fans with each train containing eight fans
divided into two cells of 4 fans each.
On March 24, 1993, while the inspector was reviewing the control room logs, it
was noted that WCT Fans 1-4 on Train A, which are within the same cell, were
declared inoperable in order to perform preventive maintenance utilizing Work
Authorization 01106393.
Technical Specification 3.7.4.f for the ultimate heat
sink was entered at 7:13 a.m.
The associated action statement requires the
measurement of both dry bulb and wet bulb temperatures hourly if more than one
dry cooling tower (DCT) or WCT fan was inoperable and the outside temperature
was greater than 70 F
Since the outside temperature was approximately 82 F,
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the measurements were required to be taken.
In addition, the Technical
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Specifications also require that 12 DCT and 4 WCT fans be operable and that
covers be installed on all of the out-of-service WCT fans.
The intent of this
Technical Specification was that covers be installed on out-of-service fans to
prevent a bypass flow past operable fans.
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On March 25, 1993, control room operators were preparing to place WCT Fans 1-4
back in service when they noticed that the previous crew had not entered
Technical Specification 3.7.4, Action C, during the period when the fan covers
were not installed on the inoperable fans.
Action C required a plant shutdown
if the number of operable fans were not restored within the requirements of
Table 3.7-3 within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. Table 3.7-3 required the installation of covers
on out-of-service fans.
Since covers were not installed on the out-of-service
fans, Action C was applicable and should have been entered by the crew.
Although this condition did not exceed the 72-hour time limit, operators
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failed to recognize that Action C was applicable.
WCT Fans 1-4 were returned to service at 2:44 p.m. on March 25, 1993.
Both
action statements for Technical Specification 3.7.4 were re-entered for
preventive maintenance on WCT Fans 5-8.
The licensee was questioned why Action C was not entered in the-control room
logs when the covers were not installed on out-of-service WCT Fans 1-4 as
required by Technical Specification 3.7.4.
The licensee stated that Train A
of the auxiliary CCW system was operable because the train consists of the two
physically separated cells.
Since WCT Fans 5-8 were available for operation
while WCT Fans 1-4 were out of service, Train A was still able to perform it's
intended safety function. As a result, the operators felt that the minimum
number of four WCT fans as required by Technical Specification 3.7.4 were
satisfied. The wording in the Technical Specifications regarding the minimum
number of fans and the lack of the Technical Specifications to recognize the
cell division within a train caused confusion within the operating staff.
Based upon verbatim compliance with the Technical Specification, the licensee
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should have entered Action C during the period that the fans were made
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inoperable until the covers were installed. As a result, Condition
Report CR-93-029 was initiated at 2:17 p.m. on March 26, 1993, to address the
concern.
The licensee proposed corrective actions for Condition Report CR-93-029, which
included the following:
Debrief personnel involved in accordance with the Improving Human
Performance program.
Conduct training, as appropriate, on the Technical Specification and
procedural requirements relative to the event.
Evaluate a Technical Specification change to clarify the requirements of
Technical Specification 3.7.4.
These corrective actions were considered acceptable to address the condition.
3.1.6
Electrical Breaker Storage
On March 24, 1993, the inspector observed the auxiliary CCW Pump A breaker
removed from the cubicle and stored behind the reactor auxiliary
building normal exhaust Fan A breaker cubicle.
The breaker had been removed
on February 22, 1993, under WA 01106365, because the breaker's arc chute was
burned. This condition was documented in Condition Identification 284669. A
spare breaker had been removed from a storage bin and installed in the cubicle
for this pump.
Since the breaker was on wheels, the potential to trip the safeguards bus may
have existed during a seismic event.
The licensee was questioned by the
inspector with regard to seismic consideration for storing the breaker in that
location.
The licensee stated that, since the under-voltage relays and
breaker trip mechanisms associated with the bus were located in the front of
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the safeguards bus, the potential to trip the bus was minimal if a seismic
event occurred.
The licensee then placed the breaker in the storage bin which
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was located in the electrical safeguards room.
Although the storage location
for this breaker was inappropriate, no operability or procedural concerns were
identified.
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3.2 Waterford 3 Actions Taken Due to San Onofre Nuclear Generating
Station Core Protection Calculators (CPC) Problem
On February 26, 1993, San Onofre Nuclear Generating Station notified the NRC
that their CPC shape annealing matrix failed to model core power distribution
correctly late in their fuel cycle. Due to its similarity, the NRC noted that
this problem could exist at Waterford 3 and informed the licensee of this
occurrence.
In response to this notification, the licensee recorded the 20-node power
distribution for the CPCs while collecting Combustion Engineering core
operating report data and core operating limit supervisory system data.
This
data was plotted and then compared. A definite flattening of the
beginning-of-cycle flux shape curve was observed which was consistent with the
flux shape curve that would have been expected at this period of core life for
Cycle 6.
In addition, the licensee verified that they did not have this
problem at the end of the last operating cycle (Cycle 5).
The licensee
compared their assessment with an assessment conducted by Combustion
Engineering and determined that the core power distributions were in
agreement.
The inspector reviewed the power distribution data and compared the curves.
There were no discrepancies noted.
3.3 Conclusions
Chemistry personnel's failure to follow the requirements for maintaining
chemical control of diesel fuel oil was noted as a weakness; however,
prompt corrective actions were taken to correct the error. A noncited
violation was identified.
The licensee's recognition of a problem with the Technical
Specifications regarding the WCT fans and their lack of action to
correct the problems is noted as a weakness; however, the licensee is
now evaluating a Technical Specification change to clarify the
requirement.
This action and the licensee's other corrective actions
should be sufficient to prevent a recurrence of this problem.
The undesignated storage of a breaker on wheels in the electrical
safeguards switchgear room was inappropriate.
4 MONTHLY MAINTENANCE OBSERVATION (62703)
The station maintenance activities affecting safety-related systems and
components listed below were observed and documentation' reviewed to ascertain
that the activities were conducted in accordance with approved WAs,
procedures, Technical Specifications, an6 appropriate industry codes or
standards.
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4.1 Cabinet Internal Inspection for Controlled Ventilation Area System (CVAS)
Train A
On March 23, 1993, Breakers HVREBKR 311A and HVREBKR 313A were danger tagged
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and opened to perform routine maintenance and modifications on CVAS Train A.
lhe licensee entered a 7-day LC0 for Technical Specification 3.7.7.
Internal
inspections of the CVAS Train A heater control cabinet and the auxiliary
control panel (EHC-48) were performed using WA 01105529.
The inspector noted that the cabinet internals were free of debris and in good
condition. All terminal contact points were shiny and conductors well
insulated. A digital voltmeter with a calibration due date of
December 11, 1993, was utilized to verify terminal voltages.
The technicians
worked in accordance with the approved instructions and no discrepancies or
unauthorized deviations were noted.
4.2 Replacement of Thermocouple Controllers on CVAS Train A Heater Control
Cabinet
On March 23, 1993, a modification to replace the existing thermocouple
controllers was performed utilizing WA 99003292.
Condition
Identification 281135, initiated on June 12, 1992, indicated that the
thermocouple controllers on the CVAS Train A heater control cabinet were
unrel iable.
The rcplacement required that two primary overtemperature and two secondary
overtemperature thermocouple amplifier controllers be replaced. The wires
were disconnected, labelled, and logged into a wire removal and restoration
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record. Technicians had to drill holes in order to install the new
controllers.
Efforts by the technicians to prevent metal shavings from
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falling onto existing contacts by constructing an adhesive shelf from duct
tape was considered a strength.
An environmental qualification question was raised when the existing
controllers were identified as having an environmental qualification sticker
affixed to them. The corresponding WA indicated that an. environmental
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qualification review was not required because the environment in which the
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controllers were located was downgraded to a mild environment. The
downgrading of the environment was documented in an Ebasco letter (LW3-735-83)
dated May 11, 1983.
Area dose calculations were performed and were affixed to
the letter. During this time period, a safety evaluation report was not
required and the downgrade was performed in accordance with the requirements
of 10 CFR Section 50.59.
The maintenance activity was performed in accordance with established
procedures. The new controllers were installed and connected.
The identified
issues were addressed and no deficiencies were noted.
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4.3 Replacement of Demister Filters on CVAS Train A
On March 24, 1993, Condition Identification 280006 was initiated when the
differential pressure across the demister filters on CVAS Train A increased to
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above the normal operating range for the filter.
WA 01093105 was established
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to remove the existing filters and replace them with new demister filters.
The inspector noted that security was contacted and present when the filter
access doors were unlocked and that health physics surveyed the effected
areas.
The filters were replaced with new, clean filters.
The old filters
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were properly transported for decontamination.
No issues were identified
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during the activity and the filter replacement was performed in accordance
with the WA.
4.4 Preventative Maintenance on Switchgear Heating. Ventilation, and Air
Conditioning System Recirculation Fan
On March 31, 1993, the inspector observed the performance of preventative
maintenance on heating, ventilation, and air conditioning Recirculation
Fan 28. The work was being performed according to Procedure UNT-005-007,
Revision 4.
The work consisted of lubricating the fan bearings and coupling,
replacing the filters, and cleaning the coils.
The component was properly isolated and taken out of service using an
appropriate clearance.
The test for confined space access was also performed
satisfactorily. The maintenance technicians performed the tasks as directed
by WA 01105185 instructions.
Proper lubricants were verified in compliance
with the plant lubrication manual.
The technicians kept the work area clean.
No problems were identified.
4.5 Conclusions
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Efforts by the technicians to prevent metal shavings from falling onto
existing contacts by constructing an adhesive shelf from duct tape was
considered a good work practice.
5 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
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accordance with the licensee's programs and the Technical Specifications.
5.1 EDG and Subgroup Relay Operability Verification
On March 1, 1993, the inspector observed licensee personnel performing
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portions of Surveillance Procedure OP-903-068, Revision 8, " Emergency Diesel
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Generator Surveillance Test and Subgroup Relay Operability Verification," for
Train A, and portions of the EDG A vibration data acquisition. Operations,
maintenance, and engineering personnel were involved in the performance of the
test.
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,
The procedure was recently revised to combine EDG operability verification
with engineered safety feature actuation system subgroup relay testing in the
interest of minimizing EDG starts.
Personnel conducted the test in a
conscientious, step-by-step manner.
The inspector reviewed the test data and
found no discrepancies.
5.2 Conclusions
A routine surveillance was run by plant personnel in a conscientious
manner.
6 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
6.1
(Closed) Violation 382/9203-01:
Failure to Provide a Complete and
Accurate Licensee Event Report (LER)
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This violation involved the failure of the licensee to properly report an
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event in LER 92-001. This event addressed a problem with the core operating
limit supervisory system tilt alarm setting and surveillance test
deficiencies. The report failed to address related problems found on the
margin alarms associated with the peak linear heat generation rate and the
departure from nucleate boiling ratio.
In response to this violation, the
licensee issued a revision to LER 92-001 on March 6, 1992, which included a
description of these related problems.
The licensee also issued Revision 4 of
Administrative Procedure UNT-006-012, " Development and Review of Licensee
Event Reports, Special Reports, and Security Incident Reports," which added a
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requirement for the licensing department to schedule a meeting between the
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licensing department and appropriate plant management and their designees to
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develop a plan for the disposition of LERs.
The purpose of this meeting was
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to ensure that all relevant issues related to the LER were identified early in
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the process and thoroughly evaluated by the cognizant personnel.
6.2
(Closed) Violation 382/9223-01:
Failure to Perform an Engineering
Evaluation for Scaffolds Built Over Eauipment
This violation involved the failure to perform an engineering evaluation for a
scaffold installed directly over, and within 1/16 inch of, the safety-related
motor operator for Safety Injection Flow Control Valve SI-226A.
In response
to this violation, the licensee dismantled the scaffold, conducted training
with appropriate scaffold personnel on this event, and reviewed approximately
600 scaffold records on file.
As a result of these reviews, the licensee
determined that posterection engineering evaluations were not performed for
101 scaffolds.
Subsequent walkdowns revealed that 2 of these 101 scaffolds
did not meet the procedural requirements of Nuclear Operations Construction
Procedure NOCP-207, Revision 4, " Erecting Scaffolding." The licensee
reconfigured these scaffolds.
To prevent further violations, the licensee issued Revision 5 to
Procedure NOCP-207 on February 26, 1993.
This revision added instructions in
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the body of the procedure for forwarding applicable scaffold request forms to
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field engineering for posterection engineering evaluations and revised the
scaffold request form to more clearly display the instructions for forwarding
the form to field engineering.
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6.3 (Closed) Violation 382/9223-02:
Excessive Combustible Material left
Unattended in a Safety-Related Area
This violation involved the failure to remove untreated combustible packing
materials from a safety-related area immediately following the unpacking of
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new batteries or to post a dedicated fire watch to attend to the combustible
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materials.
In response to this violation, the licensee took actions to comply
with Procedure FP-001-017, Revision 8, " Transient Combustibles and Designated
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Storage Areas," and issued Quality Notice QA-92-120 to document this as a
In order to avoid further violations, the
licensee discussed the event with maintenance, modification, and construction
personnel to ensure that similar conditions are promptly recognized and
appropriate actions taken; discussed the event during site-wide safety
meetings to accentuate lessons learned; reviewed Procedure FP-001-017 to
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verify that it contained sufficient guidance to ensure that fire protection
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requirements were clearly defined; and, distributed Quality Notice QA-92-120
to selected manag". ment personnel,
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ATTACHMENT 1
1 PERSONS CONTACTED
1.1
Licensee Personnel
- R. E. Allen, Security and General Support Manager
- T. J. Gaudet, Operational Licensing Supervisor
L. W. Laughlin, Licensing Manager
D. C. Madere, Chemistry Supervisor
D. F. Packer, General Manager, Plant Operations
R. D. Peters, Electrical Maintenance Superintendent
R. G. Pittman, Instrumentation & Controls Maintenance Superintendent
- P. V. Prasankumar, Principal Engineer
- J. A. Ridgel, Radiation Protection Superintendent
- D. A. Schultz, Operations Supervisor
R. S. Starkey, Operations and Maintenance Manager
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D. W. Vinci, Operations Superintendent
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1.2 NRC Personnel
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- D. M. Garcia, NRC Intern
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- 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 April 9, 1993, with those
persons indicated in paragraph I 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.
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