ML20036A129
| ML20036A129 | |
| Person / Time | |
|---|---|
| Site: | Vogtle  |
| Issue date: | 04/16/1993 |
| From: | Balmain P, Brian Bonser, Skinner P, Starkey R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20036A118 | List: |
| References | |
| 50-424-93-04, 50-424-93-4, 50-425-93-04, 50-425-93-4, NUDOCS 9305100081 | |
| Download: ML20036A129 (20) | |
See also: IR 05000424/1993004
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UNITED ST AVES
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NUCLEAR REGULAVORY COMit9tSSIOM
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REGION 11
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101 MARIETTA STREET, N.W.
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AT LANT A, G EORGI A 30323
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Report Nos.:
50-424/93-04 and 50-425/93-04
Licensee: Georgia Power Company
P. O. Box 1295
Birmingham, AL 35201
Docket Nos.:
50-424 and 50-425
License Nos.: NPF-68 and NPF-81
Facility Name: Vogtle 1 and 2
Inspection Conducted:
February
1993 - March 27,1993
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Inspector:
M
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'B. R. Bonser, Sphior Resident Irispector
Date Signed
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R.D'Starkey,pesidentliispectorf
Date Signed
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P. A. Balmain, Resident Inspector
Date Signed
Accompanied by:
J.L. Starefos
Approved by:
~ in ce
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P. ' Skinner, Chief
Date Signed
Reactor Projects Section 3B
Division of Reactor Projects
SUMMARY
Scope:
This routine, inspection entailed inspection in the following
areas: plant operations, Engineered Safety Features Systems walk-
down, surveillance, maintenance, Mid Loop / Reduced Inventory
activities, evaluation of licensee self-assessment capability,
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refueling activities, and follow-up of open items,
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Results:
One violation of failure to follow procedures with multiple
examples and one unresolved item was identified.
The violation involved four examples of failure to follow
procedure. One example involved an improper independent
verification during a surveillance which resulted in rendering
both trains of the Residual Heat Removal (RHR) system inoperable
for a short time. This violation exemplifies a continuing
weakness in the area of procedural implementation and attention to
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detail by personnel during normal plant activities
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(paragraphs 2d, 2 , 2i, and 4c).
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The unresolved item addresses inadequacies in design change
package reviews and the scheduling of an RHR system modification
with only one train of decay heat removal in service.
Pulling a
circuit card for troubleshooting during the installation of an RHR
system modification caused a loss of decay heat removal.
Additional information is needed to review and evaluate the causes
of this event (paragraph 2h).
A strength was noted in operator response to the loss of shutdown
cooling. Although there were many ongoing activities in the
control room at the time of this event, the operators quickly
recognized the alarm, interpreted the indications, and took
appropriate action which prevented a more severe challenge to core
safety (paragraph 2h).
A strength was noted in the shutdown risk assessments performed by
the licensee. Prior to this Unit I refueling outage, an outage
schedule review for shutdown risk resulted in several adjustments
to the schedule. Assessments performed while shutdown have
increased awareness of plant configuration and contingency plans
(paragraph 7).
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REPORT DETAILS
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1.
Persons Contacted
Licensee Employees
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- J. Beasley, Assistant General Manager Plant Operations
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S. Bradley, Reactor Engineering Supervisor
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- R. Brown, Acting Manager Training
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- W. Burmeister, Manager Engineering Support
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- S. Chesnut, Manager Engineering Technical Support
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- C. Christiansen, SAER Supervisor
C. Coursey, Maintenance Superintendent
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R. Dorman, Manager Training and Emergency Preparedness
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- G. Frederick, Manager Maintenance
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M. Griffis, Manager Plant Modifications
M. Hobbs, I&C Superintendent
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- K. Holmes, Manager Operations
- D. Huyck, Nuclear Security Manager
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- W. Kitchens, Assistant General Manager Plant Support
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- R. LeGrand, Manager Health Physics and Chemistry
- L. Mayo, Emergency Preparedness Specialist
- G. McCarley, ISEG Supervisor
- J. Roberts, Emergency Preparedness Coordinator
- W. Shipman, General Manager Nuclear Plant
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- M. Sheibani, Nuclear Safety and Compliance Supervisor
- C. Stinespring, Manager Administration
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- J. Swartzwelder, Manager Outage and Planning
C. Tynan, Nuclear Procedures Supervisor
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Other licensee employees contacted included technicians, supervisors,
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engineers, operators, maintenance personnel, quality control inspectors,
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and office personnel.
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Oglethorpe Power Company Representative
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- T. Mozingo
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NRC Inspectors
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- B. Cline
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- J. Kreh
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- B. Bonser
- D. Starkey
- P. Balmain
- J. Starefos
- Attended Exit Interview
An alphabetical list of abbreviations is located in the last paragraph
of the inspection report.
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2.
Plant Operations - (71707)
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General
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The inspection staff reviewed plant operations throughout the
reporting period to verify conformance with regulatory
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requirements, Technical Specifications, and administrative
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controls.
Control logs, shift supervisors' _ logs, shift relief
records, LC0 status logs, night orders, standing orders, and
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clearance logs were routinely reviewed. Discussions were
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conducted with plant operations, maintenance, chemistry, health
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physics, engineering support and technical support personnel.
Daily plant status meetings were routinely attended.
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Activities within the control room were monitored during shifts
and shift changes. Actions observed were conducted as required by
the licensee's procedures. The complement of licensed personnel
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on each shift met or exceeded the minimum required by TS. Direct
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observations were conducted of control room panels,
instrumentation and recorder traces important to safety.
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Operating parameters were verified to be within TS limits. .The
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inspectors also reviewed DCs to determine whether the licensee was
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appropriately documenting problems and implementing corrective
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actions.
Plant tours were taken during the reporting period on a routine
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basis. They included, but were not limited to the turbine
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building, the auxiliary building, electrical equipment rooms,
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cable spreading rooms, NSCW towers, DG buildings, AFW buildings,
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the low voltage switchyard, and the Unit I containment building.
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During plant tours, housekeeping, security, equipment status and
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radiation control practices were observed.
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The inspectors verified that the licensee's health physics
policies / procedures were followed. This included observation of
HP practices and review of area surveys, radiation work permits,
postings, and instrument calibration.
The inspectors verified that the security organization was
properly manned and security personnel were capable of performing
their assigned functions.
Inspectors observed that persons and
packages were checked prior to entry into the PA; vehicles were
properly authorized, searched, and escorted within the PA; persons
within the PA displayed photo identification badges; and personnel
in vital areas were authorized.
b.
Unit 1 Summary
The Unit began the period at approximately 92% power coasting down
in preparation for refueling outage IR4. On March 12, with the
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unit at 8E% power, a controlled shutdown to Mode 5 was performed.
Prior to entering Mode 6, RCS chemical cleanup and the containment
ILRT were successfully completed. Mode 6 was entered on March 22.
The inspection period ended with the unit in Mode 6 with reactor
core off-load in progress.
c.
Unit 2 Summary
The unit began the period operating at 100% power and operated at
full power throughout the inspection period.
d.
Operator Error Renders Both Unit 1 RHR Trains inoperable
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On March 3, with Unit 1 in Mode 1 at 90% power, during performance
of procedure 14805-1, RHR Pump Response Time Test - Train B, a
control room operator incorrectly closed valve IHV-8716B, RHR
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Train B To Hot leg Crossover, instead of valve IHV-8716A, RHR
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Train A To Hot Leg Crossover. Subsequent valve manipulations
resulted in both trains of RHR being inoperable for approximately
four minutes due to a flow path being opened to the RWST on RHR A
train while the RHR B train discharge flow path was isolated.
With both trains of RHR inoperable due to the valve misalignment,
Unit I was placed in a condition prohibited by TS and entered TS 3.0.3.
When RHR pump B was started as required by the procedure,
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the operator noted that flow was not indicated as expected. He
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immediately notified the USS, the incorrect valve alignment was
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identified, the valves were placed in their correct position and
the test continued. Approximately four hours later, during a crew
critique of the misalignment, the control room staff realized that
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a condition had existed that rendered both trains of RHR
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It was at that time that a determination was made
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that an entry into TS 3.0.3 had occurred, and notification was
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made to the NRC Operations Center.
The inspector reviewed the procedure being used at the time of the
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event and discussed the event with Operations management.
Procedure 14805-1 was adequate and clearly identified the proper
valves to be operated. The procedure also required an independent
verification of valve position when lHV-8716A was closed. The IV
was performed by a second licensed operator who failed to detect
the error. The procedure was initialed indicating that 1HV-8716A
was closed when, in fact, it was open and 1HV-8716B had been
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closed. This event, although caused by one operator, should have
been prevented if a proper IV had been performed by the second
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operator. The inspectors were concerned that this failure to
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follow procedure was compounded by an inadequate IV.
In this case
an improper IV resulted in both ECCS subsystems being inoperable.
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This failure to close valve 1HV-8716A and to properly IV that
closure is a violation of step 5.2.9 of procedure 14805-1, and is
identified as an example of violation 424,425/93-04-01, Failure to
Follow Procedure.
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The licensee counseled the operators involved and issued a shift
briefing item concerning the importance of procedure adherence and
proper IV techniques. The licensee has revised procedure 14805-1
to require that the test will be run on pump mini-flow rather than
recirculation back to the RWST.
This should reduce the
possibility of rendering both RHR trains inoperable due to this
testing.
e.
TS 3.0.3 Entry For Inoperable Pressurizer Safety Valves
On March 13, with Unit 1 in Mode 3 and shutting down for the
refueling outage, the licensee performed setpoint verifications on
the pressurizer code safety valves. This is a normal surveillance
test performed while shutting down. The lift setpoint on IPSV-
8010B was found at 2531 psig which is greater than the setpoint
tolerance of 2485 psig 11%.
The LCO for TS 3.4.2.2, Safety
Valves-Operating, was entered at 2:17 a.m. and testing proceeded
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to a second valve IPSV-8010C. The lift setpoint on the second
safety valve was also found out of specification high. At 2516
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psig. With_ two safety valves inoperable, the unit was placed in a
condition not covered by TS. TS 3.0.3 was entered at 2:28 a.m.
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At 6:48 a.m. the plant entered Mode 4 and TS 3.0.3 was exited
since the requirements of TS 3.4.2.2 were not applicable. The
inspector reviewed the licensee's actions and concluded that the
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licensee had performed prudently by promptly cooling down and
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entering Mode 4 where only one safety valve is required.
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The licensee was unable to determine the cause of the high
setpoints and removed all three pressurizer safety valves and
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shipped them off-site to a vendor for testing and resetting of the
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lift setpoints.
f.
Controls On Overtime Hours
The inspectors reviewed overtime records and discussed with
management overtime procedures implemented during the refueling
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period. The inspectors were informed that contract HP personnel
were onsite for 12.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> a shift for six days in a seven day
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period and were therefore onsite a total of 75 hours8.680556e-4 days <br />0.0208 hours <br />1.240079e-4 weeks <br />2.85375e-5 months <br />.
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Administrative requirements in Vogtle TS 6.2.1.e state, in part,
that an individual should not be permitted to work more than 72
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hours in any 7-day period, excluding shift turnover time. The
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limits in TS are applicable to plant staff in performance of
safety related functions, including key health physics
technicians. The inspectors discussed working hours with the
HP/ chemistry department manager and found that contract HP
personnel were in fact on site for 12.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> a shift but included
in this work period was a 30 minute lunch break (which is not
considered work time).
Shift turnover time of about 15 minutes at
the beginning and end of the work day is included in the work
period. The manager also identified that there is a difference in
contract and GPC HP employees work periods. GPC HP technicians
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work 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> shifts during refueling outages, however, their lunch
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breaks count as work time since they may be required to work
during that period. Their turnover is conducted before and after
the 12 hour1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> work shift which is allowed by TS.
Neither of these
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work schedules for contract and GPC technicians, if implemented as
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stated, would exceed the 72-hour maximum, excluding turnover time
as specified in TS. The inspectors reviewed time sheets for both
contract and GPC HP technicians and questioned HP technicians to
confirm their work hours. The inspectors also verified that the
contract technicians received a 30 minute lunch break and were not
required to work during that break.
Based on these reviews and
discussions, the inspectors concluded that overtime controls on HP
contract personnel and GPC HP personnel was in conformance with
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the TS guidelines.
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Charging Pump Miniflow Isolation Valve
On March 18, during normal power operations on Unit 2, operators
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shifted charging from the "A" CCP to the positive displacement
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pump. An annunciator, normally lit when the CCP is running, failed
to clear as expected. While investigating the cause of the
annunciator, the operators identified that valve 2HV-8110, CCP
miniflow isolation valve, was closed and not open as required.
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Further investigation by the licensee revealed that 2HV-8110 had
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been left closed following performance of surveillance procedure
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14612-2, SSPS Slave Relay K603 Train Test Safety Injection. As
part of the testing, the normally open miniflow isolation valve
automatically closes.
In this case the valve closed as expected.
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The restoration section of the procedure, step 5.15.4, requires
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the valve to be returned to the status recorded (open) in an
earlier step.
The operator performing the restoration, however,
left the valve in the closed position.
Valve 2HV-8110 was left in
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the closed position for about 10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />.
While shifting charging pumps, charging flow from "A" CCP was
reduced as flow from the PDP was increased. With the miniflow
valve open adequate flow would continue through the pump. With
the miniflow valve closed, flow through the "A" CCP was minimized
as the charging flow control valve was closed. The "A" CCP was at
this reduced flow condition for about one minute. This could have
resulted in damage to this pump. To verify operability of the
"A"
CCP, procedure 14808-2, Centrifugal Charging Pump and Check Valve
IST and Response Time Test was performed with satisfactory
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results. The failure to correctly restore the CCP miniflow
isolation valve is an example of violation 424,425/93-04-01,
Failure to Follow Procedure.
h.
Loss Of Decay Heat Removal
On March 16, Unit I was in Mode 5 with A train RHR in the shutdown
cooling mode of operation. The B train of RHR was out of service.
Unit I temperature and pressure were 160 degrees F and 280 psig
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respectively. The RCS was solid.
Several B train systems had
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been removed from service including B train RHR and the SSPS was
in test for maintenance.
At about 4:40 p.m.1HV-8701B, RHR Inlet Isolation Valve, closed
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isolating decay heat removal. The operators were alerted to this
condition by ERF computer alarms and immediately began to check
the RHR system.
The R0 noted dual indications on the valve
handswitch, indicating that the valve was closing. The R0
immediately held the handswitch for 1HV-87018 in the open
position. The valve reopened after it had completely cycled
closed restoring, RHR flow. The cycling of the valve took
approximately two minutes. The R0 continued to hold the valve
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handswitch in the open position until local control of valve IHV-
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8701B was taken at the remote shutdown panel. Transferring the
valve to local control defeated the autoclosure interlock and
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allowed the valve to stay open.
During this event the RCS
temperature increased approximately two degrees F.
The RHR inlet valve closed when the valve autoclosure relay was
energized.
It was later determined that an I&C technician, in the
process of trying to determine the cause of an illuminated OT
delta T bistable light (431D), had pulled a circuit card in a
process protection cabinet while checking for a blown fuse. When
the card was pulled the autoclosure relay for 1HV-8701B energized,
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causing the valve to close.
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In the existing plant configuration, since both trains of SSPS
were in test and outputs to RPS and SI components were blocked,
troubleshooting the OT delta T channel did not appear to the
technician to be a problem. The technician was troubleshooting
the cause of the bistable light in order to clear the bistable
prior to performing a functional test on a design change to the
reactor protection circuitry.
The test procedure prerequisites
required that no lights be illuminated on the trip status light
board in the control room. The technician consulted with his
foreman before removing the card. The foreman reviewed the DCP,
in which the circuitry had been previously reviewed, without
identifying any concerns. A subsequent review by I&C found that
the RCS wide range pressure loop, P-408, shares the card that was
pulled. Normally, on high RCS pressure a contact would close in
1HV-8701B autoclosure circuit and close the valve.
It was later
confirmed that pulling the circuit card actuated the autoclosure
circuit.
The root cause of this event was an inadequate review by the
design engineer and I&C prior to performing the modification, and
a failure to fully identify the impact of the modification on
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plant systems. At the close of the inspection period the
inspectors had not fully reviewed the cause of the inadequate
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reviews, the information accessible to I&C technicians to
determine the effects of deenergizing circuits, and the reason
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this modification was planned during a period when only one train
of decay heat removal was operable. This item is identified as
URI 424/93-04-02, Review Causes of Loss of Decay Heat Removal
Event, pending additional review by the inspectors.
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The inspectors concluded that operator response to this event had
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been excellent.
In view of the many activities going on in the CR
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at the time of this event, the operators quickly recognized the
alarm, interpreted the indications, and responded, thus preventing
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a more severe challenge to core safety.
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Fuel Handling Building ESFAS Actuation
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On March 23, a Unit 1 Fuel Handling Building ESFAS actuation
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occurred when a licensed operator placed the wrong FHB radiation
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monitor into " Test / Block" prior to changing an electric instrument
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distribution panel from its alternate to its normal power supply.
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The operator was using procedure 13431-1, 120V AC Vital Instrument-
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Distribution System, Checklist 1, step 2.c, directs the operator
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to place handswitch A-HS-2531C to the Test / Block Channel II
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position which would have blocked an ESFAS signal when the
anticipated power interruption occurred. The operator incorrectly
placed handswitch A-HS-2532C to the Test / Block Channel I position
due to his misconception of system operation and failure to self-
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verify the correct procedure actions. A FHB isolation resulted.
The direct cause of the actuation was a failure to' follow
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procedure by the licensed operator. -The inspectors reviewed'
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Procedure 13431-1 and found it adequate. However, it was
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difficult to follow because the handswitch terminology in the
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procedure did not exactly match the nomenclature on the control
room handswitch. This failure to follow procedure 13431-1 is
identified as an example of Violation 50-424,425/93-04-01,
Failure to Follow Procedure.
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One violation and one unresolved item was identified.
3.
ESF System Walk-down (71710)
On March 5, the inspectors completed a walk-down of both trains of the
Unit 2 diesel generators and their support systems. This included a
review of the DG air, fuel oil, lube oil, jacket water and ventilation
systems. The inspectors reviewed the appropriate sections of the TSs,
the FSAR, procedures, and system P& ids, and verified correct system
alignment on Train B and randomly verified system alignment on Train A.
The inspector examined valves for packing leakage, bent stems, missing
handwheels and improper labeling and identified no significant problems.
The inspectors also inspected component condition, labeling, and general
housekeeping and found them acceptable. The inspectors confirmed that
instrument calibration dates were current for a random sample of
instruments on each train. With the assistance of the licensee, the
inspector examined the inside of the local control cabinet for train A
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and B diesels. The inspector did not identify any significant concerns
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as a result of this walk-down.
No violations or deviations were identified.
4.
Surveillance Observation (61726)
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a.
General
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Surveillance tests were reviewed by the inspectors to verify
procedural and performance adequacy. The completed tests reviewed
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were examined for necessary test prerequisites, instructions,
acceptance criteria, technical content, data collection,
independent verification where required, handling of deficiencies
noted, and review of completed work. The tests witnessed, in
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whole or in part, were inspected to determine that approved
procedures were available, equipment was calibrated, prerequisites
were met, tests were conducted according to procedure, test
results were acceptable and systems restoration was completed.
SURVEILLANCE NO.
TITLE
28911-1
7-day Battery Surveillance and Maintenance
(Unit 1-Train B)
28912-C
Quarterly Battery Surveillance (Unit l-
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Train B)
28210-1
Main Steam Line Safety Valve IPSV-3001 IST
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14545-1
MDAFW A Monthly Operability Test
T-ENG-93-09
PDP Packing Break-In Period Test
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T-ENG 93-15
Sequencer UV/SI Anomaly Test
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14005-1
Shutdown Margin Calculations
14406-1
Boron Injection Flow Path Verification -
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Shutdown
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Unit 1 Steam Generator Safety Valve Failures
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On March 10-11, prior to the start of 1R4, the licensee performed
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in service testing on the Unit 1 SG safety valves using procedure
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28210-1, Main Steam Line Safety Valve In Service Test. There are
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5 safety valves on each of the 4 main steam lines.
The original
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scope of the testing included 10 of the 20 safety valves. TS 3.7.1, Safety Valves, identifies the required lift setpoints
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including allowed tolerance of each valve and requires in part,
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that an inoperable valve must be restored to operable status
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within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> or power operation may not continue.-
During the course of the safety valve testing several valves were
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found to be outside of the specified criteria. Due to these
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failures the scope of the testing was expanded to include all 20
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of the safety valves. When the testing was complete, a total of 8
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valves had failed to be within the allowable lift setting range.
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All of the valves were adjusted and declared operable within the
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TS allowed 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> period. These failures represented the most
failures experienced by the . licensee during any period of testing
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of SG safety valves.
The inspectors concluded that the surveillance procedure was
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adequate to test main steam line safety valves and that
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appropriate actions were taken for those valves found to be
outside of the allowable lift setting range.
c.
Failure to Perform 0DCM Special Condition Surveillance
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During the shutdown of Unit 1 on March 13 for the refueling
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outage, dose equivalent iodine in the RCS and plant vent noble gas
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effluent activity increased by more than a factor of three. When
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this occurs following a shutdown, Procedure 35110-C, Chemistry
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Control of the Reactor Coolant System, and the ODCM Section
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2.5.1.2.3, require change out of the plant vent monitor charcoal
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and particulate filters at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> _ for a least 7
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days. The basis for this requirement is to verify site boundary
limits for radioactive materials released in gaseous effluents are
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not exceeded. The filters were changed on March 13, 14, and 15,
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but not on March 16. Plant chemistry personnel were not aware on
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March 16 that a special condition surveillance was in effect
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because turnover for the oncoming foreman did not communicate the
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necessity for a sample, and other normal tracking mechanisms
failed. The requirements discussed above had been previously
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contained in TS. A TS amendment had been recently approved
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transferring the requirements for effluent monitoring to the ODCM.
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This event is identified as another example of Violation 424,
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425/93-04-01, Failure to Follow Procedure.
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One violation was identified.
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5.
Maintenance Observation (62703)
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General
The inspectors observed maintenance activities, interviewed
personnel, and reviewed records to verify that work was conducted
in accordance with approved procedures, TSs, and applicable
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industry codes and standards. The inspectors also verified that
redundant components were operable, administrative controls were
followed, clearances were adequate, personnel were qualified,
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correct replacement parts were used, radiological controls were
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proper, fire protection was adequate, adequate post-maintenance
testing was performed, and independent verification requirements
were implemented. The inspectors independently verified that
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selected equipment was properly returned to service.
Outstanding work requests were reviewed to ensure that the
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licensee gave priority to safety-related maintenance activities,
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The inspectors witnessed or reviewed the following maintenance
activities:
MWO NOS.
WORK DESCRIPTION
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19300854
Perform V0TES Testing on 1-HV2138, NSCW Cavity
Cooling Coil Return Valve
19301103
Perform Fuel Inspection and Repair Activities
19103865
Change Transformer Surge Arresters
19203046
Replace IB Battery Cells That Have a Low Voltage
Trend
b.
Sequencer Undervoltage/ Safety Injection Design Deficiency
The vendor that supplied the diesel generator sequencer, during
functional testing of sequencer circuit cards at the vendors
facility, identified that it was possible for circuit board
component tolerances to combine in such a way that given an
undervoltage signal followed by a safety injection signal, certain
of the SI loads might not be automatically started.
For the worst
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case scenario for the cards tested the SI pump, the RHR pump, and
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the CS pump would not start.
When the sequencer receives a UV signal, certain loads are
sequenced onto the diesel. These loads do not include the SI, RHR
and CS pumps.
If a SI signal is received during the UV sequence,
the sequencer should reset and restart sequencing on the SI, RHR
and CS pumps.
The vendor's test results indicated that if this
tolerance problem existed the sequencer would not reset and
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depending on where the sequencer is in the loading sequence, these
loads may start.
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To determine if the Vogtle sequencers exhibited symptoms of this
design problem, the licensee prepared a vendor recommended test to
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simulate to the postulated conditions.
The test was performed
twenty times on each sequencer on each unit. The problem
identified by the vendor did not occur during these tests, which
indicated that the components on the circuit cards do not exhibit
the condition.
The vendor is modifying the cards to correct a previously
identified design deficiency involving the automatic test
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insertion feature and will also perform an additional modification
to eliminate the possibility of this potential condition. The
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cards for the Unit I sequencers will be replaced during the
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current refueling outage. The Unit 2 cards are planned to be
replaced during the next refueling outage.
c.
Review of Atmospheric Relief Valve Actuator Deficiencies
The inspector reviewed the licensees corrective actions for recent
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examples where washers in the actuators on Unit 2 ARVs 2PV-3000
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and 2PV-3020 were found to be deformed and also had the incorrect
sized capscrews installed. The licensee's initiated DCs and
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performed an engineering evaluation and walk down and concluded
that the operability of the actuators was not impacted. The
licensee determined the cause of the washer deformation was an
interference between the washers and a weld on the bracket which
the capscrews and washers secured. MW0s 29300426 and 29300442
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were generated to replace these four capscrews and washers. The
inspector reviewed these MW0s and noted that instructions were
also generated to trim the washers that have limited clearance.
The inspectors reviewed the MWO history of the Unit 1 ARVs to
determine if any similar problems had occurred. The scope of the
review involved the installation of a hydraulic reservoir and hand
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pump to the ARVs for manual actuation.
Based on this review, the
inspector determined that this modification was installed during
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the later part of 1986. The inspector reviewed computer listings
for deficiency reports issued during this time and did not
identify any reports of fastener problems on the ARV actuators.
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The inspector also reviewed nine MW0s which required vendor QA
inspections that were performed from October 1986 through December
1986, and noted that one nonconformance report was generated by
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vendor personnel that involved gouges on a hydraulic cylinder.
There were no records of other deficiency reports or
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nonconformances initiated by vendor QA personnel referenced in
these MW0s.
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Based on this review the inspector did not have concerns in this
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area.
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No violations or deviations were identified.
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6.
Mid-loop / Reduced Inventory Activities (GL 88-17)
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The inspector reviewed the licensee's preparation for midloop/ reduced
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inventory activities for 1R4. The inspector verified that appropriate
procedures are in place which address the concerns of Generic Letter 88-
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17 (Loss of Decay Heat Removal) dated October 17, 1988.
During 1R4,
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the licensee, as part of their shutdown risk management,' plans to
maintain three out of four on site and off site power sources available
when fuel is in the vessel. This requirement is stated in Procedure
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12008-C, Mid-loop Operations, Rev. 7.
During 1R4, the RCS is planned to
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be drained to midloop while fuel is in the vessel. The midloop
draindown will permit SG nozzle dam removal and should be approximately
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18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />. During the midloop operation the 1A DG is scheduled to be
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inoperable and the 18 DG and two off-site sources will be available.
On
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March 22, the inspector verified the RCS sightglass manifold lineup
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using Procedure 11899-1, RCS Draindown Configuration Checklist. This
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procedure is performed by the licensee at four hour intervals while in
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reduced inventory. The inspectors also reviewed the licensee's
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contingency plans and verified supporting system lineups.
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The inspector reviewed procedures for use during midloop/ reduced
inventory conditions and verified that they are active and implement
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requirements for the following areas:
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Containment closure capability for mitigation of radioactive releases -
Procedure 14210-1, Containment Building Penetration Verification-
Refueling, Rev. 10, is used to verify containment building penetration
status prior to and during refueling or core alterations or movement of
irradiated fuel within the containment.
Procedure 18019-C, Loss of
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Residual Heat Removal, Rev.13, states when to initiate containment
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closure procedure 14210-1 during a loss of RHR capability or RCS
leakage. Additionally, procedure 12008-C, Mid-loop Operations, 'Rev. 7,
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requires that while operating with the RCS level below 191 feet
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elevation (reduced inventory is defined as 3 feet below the reactor
vessel flange, the reactor vessel flange is at 194 feet) the containment
equipment hatch shall be closed with a minimum of four bolts. This
limitation may be waived provided that:
(1) A method is provided for
closing the containment equipment hatch without the use of electrically
operated equipment for blackout concerns; (2) The containment equipment
hatch is capable of being closed with a minimum of four bolts within 25
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minutes without using electrically operated equipment; (3) The-
containment equipment hatch is continuously manned with a hatch closure
crew while operating the RCS level below 191 feet elevation; and, (4)
four containment cooling units are operable and capable of being
started. Maintenance procedure, 27505-C, Opening and Closing
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Containment Equipment Hatch, Rev. 4, gives direction for the actual
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closing of the equipment hatch.
RCS temperature indications - Procedure 12008-C, Mid-Loop Operations,
Rev 7, requires a minimum of two incore thermocouples in opposite
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quadrants for use while the reactor head is installed.
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RCS level indication - Procedure 12007-C, Refueling Operations, Rev. 25,
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requires that when RCS level is below 15% pressurizer level
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(approximately 207 feet) that temporary RCS level indication must be
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installed. There are two independent Control Room . indicators and a
local RCS sight glass which are used to meet this requirement.
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Additionally, there are two control room trend recorders used to trend
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changes in RCS level. A RCS sight glass watch is required any time the
RCS level is being changed while the.RCS level is below 15% pressurizer
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level. With the Control Room temporary RCS level indicators _in service,
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comparison checks are made every four hours between the Control Room
temporary RCS level indicators and the RCS sight glass using procedure
11899-1, RCS Draindown Configuration Checklist. The Control Room
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indicators should agree within seven per cent of scale with the sight
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glass.
If neither Control Room RCS level indicator is available, then a
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continuous sight glass watch is established while RCS level is below 15%
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pressurizer level. Similar temporary level indication requirements are
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stated in Procedure 12006-C, Unit Cooldown to Cold Shutdown, Rev. 26,
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Section D.
Procedure 23985-1, RCS Temporary Water Level System, Rev. 5,
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provides instructions for the installation, channel calibration and
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removal of the RCS Temporary Wat'er Level System.
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RCS perturbations avoidance - Procedure 12008-C, Mid-Loop Operations,
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Rev. 7, states that with the RCS level below 191 feet elevation, all
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work activities should be closely scrutinized and any work activity
limited that has the potential for reducing RHR system capability.
RCS inventory addition - Procedure 18019-C, Loss of Residual Heat
Removal, Rev.13, Attachment A, provides instructions to operators on
how to gravity drain the'RWST to the RCS. Procedure 12007-C, Refueling
Entry, Rev. 25, describes two boron injection flow paths, one of which
must be available while in Mode 5 and 6.
One of these flow paths is
from the Boric Acid Storage Tank via a Boric Acid Transfer Pump and a
Charging pump to the RCS The second flow path is from the RWST via a
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charging pump to the RCS.
Nozzle dams / loop stop valves - Procedure 12008-C, Mid-Loop Operations,
Rev. 7, addresses the use of nozzle dams. This procedure states that if
no cold leg opening is to be established, then:
(1) Remove the
pressurizer manway, or (2) Remove a SG manway on a hot leg that will not
be dammed, or (3) Remove three pressurizer code safety valves.
If there
is or will be a cold leg opening, then the only adequate vent path is to
remove a SG hot leg manway on a SG with no dam installed.
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Repower to vital busses from alternate source if primary source is lost
- Procedure 13427-1, 4160V AC lE Electrical Distribution System, Rev.
17, provides instructions on powering the 4160V IE Switchgear through
the emergency incoming breaker.
Procedure 13417-1, Main and Unit
Auxiliary Transformer Backfeed to the 13.8KV and 4160V Busses, Rev. 7,
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provides instructions for energizing 4160V IE Busses from the 4160V Non-
lE Busses when backfeed through the main and Unit Auxiliary Transformers
is the only off-site source of power available, DG 1A and IB are
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inoperable, and either RAT can be energized.
No violations or deviations were identified.
7.
Evaluation of Licensee Self-Assessment Capability - Review of Shutdown
Risk Assessment (40500)
Prior to the outage the licensee developed pre-planned contingencies for
outage evolutions that were determined to involve increased exposure to
shutdown risk events.
The evolutions included removal of systems for
maintenance, and RCS draining activities. The inspectors reviewed the
licensee's implementation of shutdown risk contingency plans developed
for the current Unit I refueling outage. On March 16 the inspector
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accompanied an outage area coordinator on a walk down of the B train
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MDAFW flow path to SGs 2 and 4 and verified it was available. During
this time the Unit was in Mode 5 with only one train of RHR available to
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provide core cooling. The AFW flow path availability ensured that a
heatsink for core cooling was available if the operating RHR system was
disabled.
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In addition to reviewing risk contingency plans, the inspector also
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reviewed two recent shutdown risk assessments that were performed by
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ISEG. The assessments were conducted by an ISEG member who holds an SR0
license. One assessment was conducted at a relatively high risk
condition for core cooling and the other was conducted in an overall
moderate risk condition. The inspector noted that the ISEG assessments
included plant walkdowns, and interviews with control room personnel.
These assessments were thorough and of high quality.
In addition to the
periodic assessments, ISEG performed an independent review of the Unit 1
outage schedule prior to shutdown for refueling. The inspector noted
that several comments from this review resulted in corrections to the
schedule.
Management attention to shutdown risk is evident. During the daily
operations status meeting, a schedule is distributed that shows the
seven day window for systems that provide decay heat removal, electric
power availability, RCS inventory control, and containment closure
status.
In addition, contingency plans are also discussed at this
management meeting. The control room staff is also provided with this
information. The inspectors observed that the licensee has had an
increased awareness of shutdown risk and contingencies. This was
evident in the control room operators response to the loss of RHR event
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discussed in paragraph 2h. The inspector also concluded that ISEG's
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risk assessments enhanced safety and noted these efforts as a strength.
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No viol. t Ms nr deviations were identified.
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8.
Refueling Activities (60710)
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a.
General
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The inspectors monitored Unit I refueling operations in the
control room, observed defueling of the core from the refueling
bridge in containment, and observed fuel movement at the spent
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fuel pool. The licensee implen,ented extensive fuel inspection
activities to determine the extent of Unit I fuel failures that
occurred during the last operating cycle and to preclude the
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reload of damaged fuel. The inspectors also observed fuel
assembly inspection activities at the spent fuel pool and the
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reconstitution of a leaking fuel assembly.
The licensee used a combination of fuel sipping and UT inspections
to identify failed fuel rods.
One fuel rod in one fuel assembly
was found to be leaking. This fuel rod was subsequently removed
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and replaced by a stainless steel rod.
The reconstitution
evolution proceeded as planned with no complications. The
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inspectors will rvview the results of the licensee's completed
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fuel inspection and repair activities during subsequent
inspections.
b.
Interaction of A New Fuel Assembly with New Fuel Elevator
In preparation for 1R4 operations personnel were transferring new
fuel from the new fuel storage vault in the FHB to the spent fuel
storage pool. This evolution requires that the new fuel assembly
be moved to the fuel transfer canal where it is placed in the new
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fuel elevator. When the assembly is in the elevator, the new fuel
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handling tool is removed from the assembly, the elevator is
lowered, the spent fuel handling tool is attached, and the
assembly is raised and moved to the spent fuel pool for storage.
On March 2, new fuel assembly 5G05 had been removed from the new
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fuel elevator and was about to be moved to the spent fuel stora,e
pool. The PE0 operating the new fuel elevator thought that the
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assembly had cleared the area directly above the elevator. He
began to raise the elevator.
However, the assembly had not
cleared the vertical rath of the elevator and contact was made
between the fuel ass; tly and the elevator. The impact slightly
lifted the assembly and caused it to tilt from its vertical
position. The elevator was immediately stopped and lowered. Both
the assembly and elevator were inspected visually and no damage
was observed. The assembly was then placed in the spent fuel
storage pool.
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On March 4 the licensee removed the assembly from the spent fuel
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pool to conduct a more thorough visual inspection. One small
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scratch was found on the bottom nozzle, and no structural damage
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was observed.
Later that day a confirmatory drag test was
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performed with an RCCA to determine if the guide thimbles had been
damaged.
Drag forces were normal .
Based on the results of the
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visual inspection and drag test the assembly was determined to be
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acceptable for use.
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The inspector reviewed procedure 93210-C, New Fuel Elevator
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Operating Instructions, which was being used at the time of this
event. The procedure clearly states that the new fuel elevator
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area is to be checked for obstructions prior to elevator movement.
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The inspector determined that procedure 93210-C was adequate-to
safely perform this evolution, but that the PE0 controlling the
elevator was not observing due care in the performance of his
duties. The inspector concluded that this error had no safety
significance and further determined that the licensee's fuel
assembly inspection efforts were adequate to ensure that the
assembly was acceptable for use.
No violations or deviations were identified.
9.
Follow-up (90712) (92700) (92701)
The LERs and follow-up items listed below were reviewed to determine if
the information provided met NRC requirements. The determination
included:
adequacy of description, verification of TS compliance and
regulatory requirements, corrective action.taken, existence of potential
generic problems, reporting requirements satisfied, and relative safety
significance of each event.
a.
(Closed) Part 21 50-424,425/91-03
In a Rockbestos Company letter dated March 1,1991, problems were
identified concerning KS-500 Silicone rubber insulated fire wall
SR Cable which could have been installed in nuclear safety related
applications.
Results of testing indicate a variation from
thermal life data utilized in the original 1978 report and in-the
supplemental 1987 report. The licensee reviewed the affected
cables and none were used in safety related applications. The
licensee's Cable and Raceway Program has been updated to prevent
the use of these Rockbestos cables in safety related applications.
Based on this review of the licensee's actions, this-item is
closed.
b.
(Closed) LER 50-424/91-08, Rev 0, Transformer Failure Leads to ESF
Actuation and Technical Specification Violation.
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The inspector previously reviewed the licensee's corrective
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actions and recommer.dations to improve the reliability of SOLA
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transformers and found the actions to be adequate (NRC 1R 50-424,
425/92-12 and 92-23).
The inspector reviewed procedure 14666-1, Train A Diesel Generator
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and ESFAS Test, and verified that PERMS equipment that will be
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affected during testing is listed in step 4.34.1.
In addition,
precaution and limitation step 2.39 required notification of
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chemistry for initiation of alternative sampling if the plant vent
monitor 1-RE-12444 is not in service. An additional verification
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that the plant vent airborne monitor is also operable is required
by step 4.35 of the procedure.
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Based on these procedure revisions and the previous review of SOLA
transformer enhancements, this item closed.
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No violations or deviations were identified.
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10.
Exit Meeting
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The inspection scope and findings were rummarized on March 26, 1993,
with those persons indicated in paragraph 1.
The inspector described
the areas inspected and discussed in detail the inspection findings
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listed below. No dissenting comments were received from the licensee.
The licensee did not identify as proprietary any of the material
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provided to or reviewed by the inspectors during the inspection.
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Item No.
Description and Reference
VIO 424,425/93-04-01
Failure to Follow Procedure (multiple
examples
URI 424/93-04-02
Review Causes Of Loss Of Decay Heat
Removal Event
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11.
Abbreviations
1R4
- Unit 1 Refueling Outage Number 4
- Alternating Current
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- Auxiliary Feedwater System
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- Atmospheric Relief Valve
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- Centrifugal Charging Pump
CFR
- Code of Federal Regulations
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CR
- Control Room
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- Deficiency Card
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- Design Change Package
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DEI
- Dose Equivalent Iodine
- Diesel Generator
- Emergency Core Cooling System
- Emergency Response Facilities
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- Engineered Safety Feature
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- Engineered Safety Features Actuation System
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F
- Fahrenheit
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FHB
- Fuel Handling Building
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- Final Safety Analysis Report
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GL
- Generic Letter
GPC
- Georgia Power Company
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- Health Physics
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- Instrumentation and Controls
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IR
- Inspection Report
ISEG
- Independent Safety Engineering Group
- In-Service Test
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IV
- Independent Verification
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KV
- Kilovolt
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LC0
- Limiting Condition for Operation
LER
- Licensee Event Report
MD/iW
- Motor Driven Auxiliary Feedwater System
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MO
- Motor Operated Valve
MWi i
- Maintenance Work Order
Nr/
- Nuclear Power Facility
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NRC
- Nuclear Regulatory Commission
- Nuclear Service Cooling Water System
- Offsite Dose Calculation Manual
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OT delta T - Overtemperature delta Temperature
- Protected Area
PE0
- Plant Equipment Operator
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PERMS
- Process and Effluent Radiological Monitoring System
- Piping and Instrument Diagram
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PDP
- Positive Displacement Pump
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psig
- Pounds per Square Inch
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- Quality Assurance
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- Reserve Auxiliary Transformer
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RCCA
- Rod Cluster Control Assembly
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- Residual Heat Removal System
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R0
- Reactor Operator
- Refueling Water Storage Tank
SAER
- Safety Audit And Engineering Review
- Safety Injection
SR0
- Senior Reactor Operator
SSPS
- Solid State Pre...ction System
- Safety Parameter Display System
TS
- Technical Specifications
- Unresolved Item
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USS
- Unit Shift Supervisor
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- Ultrasonic Testing
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- Under Voltage
V
- Volt
- Violation
WRT
- Work Request Tag
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