ML20036A846
| ML20036A846 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 04/29/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20036A834 | List: |
| References | |
| 50-324-93-16, 50-325-93-16, NUDOCS 9305170079 | |
| Download: ML20036A846 (33) | |
See also: IR 05000324/1993016
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UNIT E D STAT ES
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NUCLEAR REGULATORY COMMISslON
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101 MARIETT A STRE ET, N.W.
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AT LANT A, GEORGI A 3G323
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Report Nos.: 50-325/93-16 and 50-324/93-16
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Licensee:
Carolina Power and Light Company
P. O. Box 1551
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Raleigh, NC 27602
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Docket Nos.: 50-325 and 50-324
License Nos.:
Facility Name:
Brunswick 1 and 2
Inspection Conducted: March 7 - April 2, 1993
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Lead Inspector:
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Da'te'igned
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R. L. PrevattC eniorp'sitsny'inspedfor
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Other Inspectors: D. J. Nelson, Resident Inspector
P.
Byron, Resident Inspector
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Approved By:
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M . [hr/ stensen, Chief
Dafe Signed
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Reactor Projects Section lA
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Division of Reactor Projects
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SUMMARY
Scope:
This routine safety inspection by the resident inspector involved the areas of
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maintenance observation, surveillance observation, operational safety
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verification, onsite review committee, onsite followup of events, and action
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on previous inspection findings.
Results:
Both units remained in cold shutdown for the entire reporting period.
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In the areas inspected, one violation was identified for failure to follow
procedures while venting a control red drive. An operator failed to return a
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control rod to the 00 position, parag aph 4.
An Unresolved item was
identified concerning the incorrect wiring of jet pump flow circuitry,
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paragraph 5.
This item will be further evaluated upon completion of the
licensee and NRC investigations.
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9305170079 930430
ADDCK 05000324
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A concern was identified regarding review of an Engineering Evaluation Report
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by the Plant Nuclear Safety Committee, paragraph 7.
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Effective .aintenance planning and execution were noted during the replacement
of a pressure transmitter, paragraph 2.
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REPORT DETAILS
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1.
Persons Contacted
Licensee Employees
- K. Ahern, Manager - Operations Support and Work Control
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G. Barnes, Manager - Shift Operations, Unit 2
- M. Bradley, Manager - Brunswick Assessment Project
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- M. Brown - Assistant PlaM " eager, Unit 2
- S. Calli
- On-Site Lice
,gineer
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- R. Godley, Supervisor
iry Compliance
J. Heffley, Manager -
ce, Unit 2
- C. Hinnant - Director
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dperations
M. Jones, Manager - Training
J. Leininger, Manager - Nuclear Engineering Department (Onsite)
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P. Leslie, Manager - Security
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- W. Levis, Manager - Regulatory Compliance
- G. Miller, Manager - Technical Support (Interim)
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D. M w ', Manager - Maintenance, Unit 1
- R. Mo.3An - Interim Plant Manager, Unit 1
R. Poulk, Manager - License Training
C. Robertson, Manager - Environmental & Radiological Control
J. Simon, Manager - Operations Unit 1 (Interim)
R. Tart, Manager - Radwaste/ Fire Protection
J. Titrington, Manager - Operations, Unit 2
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C. Warren, Plant Manager - Unit 2
G. Warriner, Manager - Control and Administration
E. Willett, Manager - Project Management
Other licensee employees contacted included construction craftsmen,
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engineers, technicians, operators, affice personnel and security force
members.
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- Attended the exit interview.
Acronyms and initialisms used in the report are listed in the last
paragraph.
2.
Maintenance Observation (62703)
The inspectors observed maintenance activities, interviewed personnel,
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and reviewed records to verify that work was conducted in accordance
with approved procedures, Technical Specifications, and applicable
industry codes and standards. The inspectors also verified that:
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redundant components were operable; administrative controls were
followed; tagouts were adequate; personnel were qualified; correct
replacements parts were used; radiological controls were proper; fire
protection was adequate; quality control hold points were adequate and
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observed; adequate post-maintenance testing was performed; and
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independent verification requirements were implemented. The inspectors
independently verified that selected equipment was properly returned to
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service.
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Outstanding work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance. The inspectors observed /
reviewed portions of the following maintenance activities:
91-APRI
Correct high vibration on nuclear service water
pump IB
93-AFUNI
Replace Unit 2 reactor vessel low pressure
transmitter 2-B21-PT-N021A
NRC Bulletin 90-01, Supplement 1, identified that some Rosemount Models
1153 and 1154 pressure and differential pressure transmitters had failed
due to a loss of fill oil. The Bulletin recommended that the affected
transmitters undergo increased surveillance or be replaced with ones
manufactured after July 11,1989 (i.e., with ones having a serial number
greater than 500,000). The licensee determined that pressure
transmitter 2-H21-PT-N021A, steam dome pressure, was a Model 1153
Rosemount transmitter having Serial No. 406248 and elected to replace
this transmitter rather than perform a monthly surveillance as directed
by the Bulletin.
The removal of the N021A pressure transmitter rendered one core spray
train inoperable and required entry into Technical Specification 3.5.3.1, which requires that the inoperable core spray train be returned
to an operable condition witnin four hours. The Unit 2, I&C performance
test crew pre-planned the replacement evolution by walking through the
procedure.
They obtained and prestaged additional parts, test equipment
and tools at the work location.
On March 5, the inspector atter.ded the PNSC meeting where 1&C presented
their plan for the N021A replacement. On March 11, the inspector
attended the pre-job briefing for the transmitter replacement. The
briefing was conducted in accordance with procedure PLP-17,
Identification, Development, Review and Conduct of Infrequently
Performed Operations. The inspector concluded that the briefing was
professionally conducted, all important segments were properly
identified and emphasized, and the briefing was attended by th:: persons
performing the task.
The briefing involved engineering and management
personnel.
The inspector observed the removal of the old Rosemount transmitter
(Scrial No. 406248) and the installation and calibration of the new
model 1153 transmitter (Serial No. 0504585) in accordance with the work
request. The I&C technicians had pre-calibrated and filled the
replacement instrument prior to stagieg it at the instrument rack. The
inspector observed that the technicians had problems with the digital
valt ohm meter and the hydrostatic pump used for the activity; however,
the problems did not affect the successful completion of the task.
Spare components had been prestaged nearby and their use minimized
transmitter change-out delay.
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The task took approximately two hours and was well supported by
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maintenance, health physics and operations.
Good pre-planning enabled
the licensee to perform the task well within the Technical Specification
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limitations. The inspector considered this to be one of the better
planned and executed repair tasks he had observed to date.
Work Control Processes
Site Wide Coordination / Scheduling
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The licensee's improvements in scheduling of outage activities
have centered around an improvement in the level of sophistication
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of scheduling technology.
This has been driven by an influx of
outside personnel and talent. Definite improvement is evident by
the level of detail existing in outage schedules and the use of
schedules as a living management tool.
Previous outage schedules
were sequences of outage activities, useful only as an indication
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of how much work was left to do or to be deferred.
The scheduling
improvements have been hindered in part by the high volume of
emergent work resulting from continued identification of plant
deficiencies. However, the recent implementation of the site work
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control center has the potential to produce further improvements
in coordination and efficiency.
Programmatic Issues
One of the intended results of the streamlined WR/JO process was
more supervisory oversight of maintenance activities in progress.
Field observation by the inspector and interviews with maintenance
managers indicated that continued improvement is needed. The gain
in supervisors' time due to lessening of planning-type functions
was offset by the additional work load caused by emergent work.
Recent implementation of " maintenance coordinators" has provided
more time for supervisory oversight by removing some non-
supervisory tasks from maintenance supervisors.
The new Temporary Modification Program procedure, PLP-22,
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Temporary Modification, was issued on March 8, 1993.
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inspector reviewed the new procedure and concluded that it
represented a major improvement over the previous procedures.
However, not all lessons learned from previous Temporary
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Modification problems were incorporated.
For example, no
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direction was included requiring that corrective maintenance on
installed temporary modifications be controlled by the WR/JO
process. This aspect was discussed in Inspection Report
325,324/92-21. Also, the licensee has retained the practice of
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using a single WR/JO for both installation and removal of
temporary modifications. This practice poses the risk of
bypassing work control attributes built into WR/JO closure and
initiation / authorization process. The licensee is evaluating the
program with regard to further enhancements.
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Maintenance Performance
Significant licensee attention has been given to the maintenance
planning function.
Performance based Planner / Analyst training was
completed in the last several months. Some improvement in the
planning product was apparent. Critical aspects such as ISI
review have been changed to require review by the appropriate
personnel.
The inspector reviewed the maintenance activities documented in
inspection reports 325,324/91-26; 92-44; and 93-05, and concluded
that indications of some improvement are evident in all areas of
work control. However, high efficiencies and desired management
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standards have not yet been achieved.
Procedural adherence and
procedure revision backlogs (1204 revisions) continue to be a
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management challenge.
In response to a Notice of Violation dated June 19, 1992
(Inspection Report 325,324/92-15), the licensee discussed
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implementation of fundamental changes to the work processes. The
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licensee identified 71 process improvements, many of which are
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related to improving Maintenance Work Control. These improvements
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were captured under the Three-Year Plan as initiative TY 310.
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The inspector considers the planned and in progress work control
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improvements satisfactory for restart. The completion of the work
control improvements will be tracked under existing violation
325,324/92-44-01.
Recirculation Pumo Seal Replacement
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Technical Specification 3.5.3.2 requires that two systems be available
to provide shutdown cooling (SDC) while in Mode 4.
Both RHR systems are
normally used to provide SDC. The condenser is used as a backup method
for SDC if an RHR system is unavailable. The condenser mode has been
frequently used as the primary method of SDC with RHR as backup during
the current outage. While in condenser cooling, a recirculation pump is
operated at low flow to provide improved reactor water mixing and
temperature indication. The licensee used condenser cooling for
approximately four months during the current outage. During discussions
with the vendor, Bingham Pump Company, the system engineer was informed
that the pump should only be operated at low flows for a short period of
time. The vendor's definition of short time was three to seven days.
The vendor stated that pump seal failure could occur and recommended
that the seal be replaced. The licensee concurred with the
recommendations to replace the seal on recirculation pump 2A.
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clearance to remove the seal was hung on March 5,1993, and work was
completed on March 10. The vendor representative observed the
replacement.
Inspection of the removed seal by the licensee revealed a shiny surface
which the vendor thought could be Nickel leaching. No other damage was
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observed. The seal was then sent to the Harris E&E Center for analysis.
The analysis determined that the shiny surface was Nickel. The
inspector reviewed the photographs of the seal and observed the
distinctive leaching indications. The seal consists of two parts; a
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stationary part made of carbon (graphite) and a rotating assembly made
of 92% Tungsten Carbide and 8% Nickel. The Nickel acts as a binder for
the Tungsten Carbide. The vendor informed the licensee that the failure
mechanism is Nickel leaching caused by stagnation which allows chips of
Tungsten Carbide to come out of solution. The chips can damage the
carbon surface of the stationary section of the seal. This would then
result in excessive wear.
After the above investigation, the licensee replaced the recirculation
pump 2B seal as a precautionary measure. Work commenced on March 19 and
was completed on March 23. The licensee sent the 2B seal to the Harris
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E&E Center for analysis. The licensee and vendor plan to evaluate the
results of the analysis and attempt to learn more about the Nickel
leaching phenomena. The licensee has polled the industry and determined
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that LaSalle had a similar problem.
LaSalle sent its seals to Argonne
National Laboratory for analysis. Argonne determined that Nickel
leaching was not a cause but a contributor to the failure of the LaSalle
recirculation pump seals. The inspector considers the licensee's effort
to implement the vendor's recommendation and pursue the basis of the
failure mechanism to be satisfactory.
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Violations and deviations were not identified.
3.
Surveillance Observation (61726)
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The inspectors observed surveillance testing required by Technical
Specifications. Through observation, interviews, and record review the
inspectors verified that: tests conformed to Technical Specification
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requirements; administrative controls were followed; personnel were
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qualified; instrumentation was calibrated; and data was accurate and
complete. The inspectors independently verified selected test results
and proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following test
activities:
2MST-RHR 26R
RHR Core Spray low Reactor Pressure
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Permissive Instrument Channel Calibration
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The inspector observed the I&C technicians calibrate Steam Dome Low
Pressure Transmitter 2-821-PT-N021A in accordance with Section 7.3 of
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2MST-RHR26R. This calibration was part of the installation instructions
(WR/JO 93-AFUN1) for N021A. The inspector observed that the technicians
used the applicable instructions and procedures.
Calibration was
achieved with minimal effort. The inspector considers that the
evolution was performed well.
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Violations and deviations were not identified.
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4.
Operational Safety Verification (71707)
The inspectors verified that Unit I and Unit 2 were operated in
compliance with Technical Specifications and other regulatory
requirements by direct observations of activities, facility tours,
discussions with personnel, reviewing of records and independent
verification of safety system status.
The inspectors verified that control room manning requirements of 10 CFR 50.54 and the Technical Specifications were met. Control operator,
shift supervisor, clearance, STA, daily and standing instructions and
jumper / bypass logs were reviewed to obtain information concerning
operating trends and out of service safety systems to ensure that there
were no conflicts with Technical Specification Limiting Conditions for
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Operations. Direct observations of control room panels, instrumentation
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and recorded traces important to safety were conducted to verify
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operability and that operating parameters were within Technical
Specification limits. The inspectors observed shift turnovers to verify
that system status continuity was maintained. The inspectors also
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verified the status of selected control room annunciators.
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Operability of systems used for shutdown cooling were verified weekly by
ensuring that: each accessible valve in the flow path was in its
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correct position; each power supply and breaker was closed for
components that must activate upon initiation signal; there was no
significant leakage of major components; proper lubrication and cooling
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water available; and conditions which could prevent fulfillment of the
system's functional requirements did not exist.
Instrumentation
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essential to system operation or actuation was verified operable by
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observing on-scale indication and proper instrument valve lineup.
The inspectors verified that the licensee's HP policies and procedures
were followed. This included observation of HP practices and a review
of area surveys, radiation work permits, posting and instrument
calibration.
The inspectors verified by general observations that: the security
organization was properly manned and security personnel were capable of
performing their assigned functions; persons and packages were checked
prior to entry into the PA; vehicles were properly authorized, searched
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and escorted within the PA; persons within the PA displayed photo
identification badges; personnel in vital areas were authorized;
effective compensatory measures were employed when required; and
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security's response to threats or alarms was adequate.
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The inspectors also observed plant housekeeping controls, verified
position of certain containment isolation valves, checked clearances and
verified the operability of onsite and offsite emergency power sources.
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Mispositioned Control Rod
On February 23, 1993, during CRD HCU venting operations on Unit 2, a
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control rod was unintentionally left at the 02 notch position (one notch
from fully inserted) following venting of its HCU. The venting
operation requires that individual rods be fully withdrawn and
reinserted in a succession of movements in conjunction with opening of
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HCU vent valves. The desired result is that all air is purged from the
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hydraulic lines and components for optimum control rod operation.
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Following the venting of HCUs on those rods that displayed some
sluggishness, the reactor operator performed an additional rod
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manipulation to verify the effectiveness of the venting. This involved
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withdrawing the rod back out to 02, then fully reinserting it again.
This action was not procedurally specified by the venting procedure
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(Operating Procedure OP-8, CRD Hydraulic System, Rev. 29, Section 8.15,
Venting an HCU) but was considered by the operator and SR0 to be within
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the guidelines of Operating Procedure OP-7, Reactor Manual Control
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Rev. 52.
Upon completing venting operations on CRD HCU 42-19, the associated rod
was withdrawn to 02. At this time, the R0 was apparently distracted by
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shift turnover plans and forgot to reinsert the rod. Venting was
secured for the shift at approximately 6:34 p.m.
A normal shift
turnover took place at approximately 7:00 p.m. without identification
that the rod was not fully inserted. At approximately 7:30 p.m., prior
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to the oncoming shift recommencing venting operations, a Nuclear
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Engineer discovered the condition when he observed the Rod Worth
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Minimizer display in the control room back panels. This display is
duplicated on the RTGB, but requires specific operation of the RWM panel
to obtain control rod position information. He informed the oncoming
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R0, who selected the rod and returned it to 00.
Shift management was
not informed of the problem nor of the corrective rod repositioning to
the 00 position.
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On February 26, following additional investigation, the Nuclear Engineer
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initiated a Minor Adverse Condition (MAC) report. On March 3, the MAC
was brought to the attention of the Manager af Operations who, like the
shift management, was unaware of the occurrence. As a result, the MAC
was escalated to a Significant ACR and the fallowing immediate
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corrective actions were taken:
All operations work was stopped until the shifts were briefed on
procedural compliance and recent events were reviewed.
Rod position changes will tempararily require a second checker.
Rod position checks will be done twice each shift.
The involved R0s were counseled.
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The inspector concluded that there was no safety significance associated
with the rod remaining at the 02 position. The Technical Specification
requirements for shutdown margin with the highest worth control rod
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fully withdrawn (notch 48) were demonstrated following the last Unit 2
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refueling.
The Maximum Subcritical Banked Withdrawal Position for the
current fuel load is notch 02, meaning that at any time in core life,
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subcriticality at cold, Xenon free conditions will be maintained with
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all rods at 02. This is documented in the B2C10 Cycle Management
Report. The venting operations took place with the mode switch in
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REFUEL. This enables the "one rod out" interlock to prevent more than
one rod from being withdrawn at a time. The Technical Specification
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required surveillance to verify the operability of the interlock was
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performed within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> prior to the first rod withdrawal. The
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inspector reviewed the surveillance documentation and determined that it
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had been correctly performed. Therefore, had the Nuclear Engineer not
discovered the mispositioned rod, the interlock would have prevented
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another rod from being withdrawn when venting recommenced approximately
one hour later. Subsequent to the event, the interlock operability was
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reverified as required within seven days of the first surveillance.
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This event revealed several management / operational problems:
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The additional rod manipulations, in addition to being outside the
procedural controls, were not authorized by nor communicated to
the SRO.
The Reactor Operator failed to ensure the rod was returned to 00
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after deciding the extra manipulation was within his overall
reactivity manipulation responsibilities.
The shift turnover process and included control board walkdowns
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did not identify the mispositioned rod.
Discovery and correction of the unexpected condition was not
immediately communicated to shift management nor documented in the
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Control Operators Log as required by Operating Instruction 01-1,
Conduct of Operations, Rev. 50 and/or Brunswick Site Procedure
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BSP-50, Command, Control and Communications, Rev. 1.
The second
Reactor Operator on shift, officially acting as the Plant Monitor
- Reactor Operator (PMR0), was also not informed of the condition
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even though the PMRO is specifically assigned to respond to plant
parameter changes and, in this case, should have been the operator
to insert the rod. The operator who actually inserted the rod was
officially acting as the Balance of Plant Reactor Operator, whose
main duties are to perform administrative tasks although this
position may be secured on a shutdown unit.
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The operator's contention that the rod manipulations outside of
Procedure OP-8 were authorized by OP-7, was not entirely correct
in that OP-7 relies on a pull sheet to control the final
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position of rods. No pull sheet was in use at the time since the
intended final position of all rods was 00, as directed by the
venting procedure.
A previous example of inadequate shift turnovers was the subject of a
Notice of Violation dated August 25, 1992 (Inspection Report
325,324/92-21).
In that case, four days and nine shift turnovers had
occurred prior to the identification that a valve indicated closed on
the RTGB instead of open as required by a clearance tag on its control
switch. Corrective actions with regard to that event had not been
completed at the time of the rod misposition event. However, during the
time period that HCU venting was conducted (encompassing several days),
the inspector noted burned out full-in lights on the full core matrix on
three separate occasions immediately following shift turnover. The
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operators replaced the lights upon questioning by the inspector. With
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the mode switch in REFUEL, allowing single rod withdrawal, non-
illuminated full-in lights should attract greater scrutiny than when in
SHUTDOWN when no rod movement is possible. The several occurrences of
burned out lights on the full core matrix indicates that the shift
turnovers at the time of the mispositioned rod were inadequate.
The licensee conducted a root cause analysis (RCA) of this event. While
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the RCA resulted in adequate analysis of the cause of the event, some
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pertinent issues were omitted with regard to the discovery and
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supplemental actions.
Specifically, the RCA did not address:
Failure of the shift turnover process to identify the
mispositioned rod. The RCA report stated that "there was no
requirement to verify rod position at the beginning of each shift.
Current requirements are for Modes 1, 2 and 5.
As a result, the
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second RO remained unaware of the position of rod 42-19."
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inspector considered this to be a compliance oriented approach
inconsistent with fundamental operating practice.
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Actions of the second R0, while officially assigned as B0P-RO,
neglecting to communicate to the PM-R0 following discovery ar.d
correction of the problem for which the PM-R0 is specifically
assigned.
Potential relationship to the previous events. No identified
Human Performance Problems were considered to be a repeat.
OP-8 requires that control rods be at position 00 at the completion of
venting individual HCUs. Control rod 42-19 was left at position 02.
The failure to follow procedure OP-8 is a Violation (324/93-16-02).
On March 24, 1993, the inspector observed that the entire Unit 2, P601
portion of the RTGB had been masked for painting with the exception of
annun:iator panels and meter faces which were covered with clear
plast ic. The P601 panel includes all RTGB controls and indication for
the iCCS systems (HPCI, ADS, RCIC, Core Spray, and RHR) including the
operating RHR shutdown cooling loop and the majority of PCIS isolation
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indicators. All control switch label plates had been removed and
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oriented in a mimic fashion on the nearby E0P table for the operator's
reference. All red / green indicating lights were taped over and
effectively blocked. The inspector questioned shift management why both
RHR loop sections were being painted simultaneously instead of one at a
time, allowing one operating loop to be unaffected at all times. The
operators acknowledged the benefit of a two step approach, but
considered the temporary degradation of the full P601 panel to be of
minimal concern given the low decay heat of the Unit 2 core and
retention of the ability to operate any affected components with little
risk of misidentification. The on-watch Reactor Operator successfully
identified all component control switches needing to be operated to
restore shutdown cooling in the event of a PCIS Group 8 isolation.
The inspector concluded that while this situation was not desirable from
a control standpoint, all affected safety systems were maintained in
appropriate configurations and were capable of performing their intended
functions. The operators stated that removal of the operating SDC loop
masking would occur first after the relatively short paint application
time.
The inspector voiced his concern with the Operations Manager, who
was aware of the situation, and then to the Unit 2 Plant Manager who was
not. Subsequently, the licensee stated that the situation should not
have been entered into and agreed that this did not represent the
desired level of performance.
One violation was identified, which indicated that effective command,
control, and communication continue to be a challenge.
5.
Plant Specific Startup Issues (71707)(62703)(37828)
(Note: CAL items are addressed in Enclosure 3 of CP&L's letter dated
July 23, 1992.)
CAL Item A3 - Instrument Racks
As a result of concerns identified by the NRC in early 1992, the Unit 2
instrument racks were inspected and evaluated to determine if any work
was needed to address corrosion and seismic concerns. This effort
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resulted in work being performed on twenty-four instrument racks under
Plant Modification, PM 92-071. This work ranged from rack replacement
to the addition of supports and/or bracing. Racks H21-P014 (HPCI),
H21-P018 (RHR-A) and H21-P021 (RHR-B), which are located at the minus 17
foot elevation, were replaced with corrosion resistant stainless steel
racks. The remaining five instrument racks at this elevation are
scheduled to be replaced by the end of the next refueling outage which
is scheduled for 1994. The instrument racks located on the 20 foot and
50 foot elevations had new supports added or existing supports
strengthened. Many of the racks had rigid conduits attached and nine
racks had the rigid conduits replaced by flexible conduits to meet
seismic requirements. The inspector followed these efforts from
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original rack replacement through instrument calibration. These
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inspection efforts have been documented in Inspection Reports
325,324/92-21, 92-22, 92-28, 92-44 and 93-10.
The inspector determined that the observed work was done in accordance
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with procedures, the quality of work was acceptable and hydrostatic
testing and calibrations were satisfactory.
In addition, a Region II
specialist inspected the racks for corrosion and structural
considerations (Inspection Report 325,324/93-02) and found the
modification work acceptable. The licensee completed p.m.92-071 on
March 9, 1993. Based on the NRC inspection efforts the Unit 2
instrument racks are acceptable for restart.
In conjunction with instrument rack modifications, the licensee
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discovered a wiring error associated with Unit 2 jet pumps 1 and 6.
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flow input signals from the No. I jet pump flow transmitter was wired to
the flow circuitry of both pumps. This resulted in the No. 6 jet pump
flow signal not inputting to the flow circuit. The licensee has
corrected the error, but has not completed its investigation of how the
wiring error occurred.
Initial indications suggest that the error
occurred during instrument rack work performed since the beginning of
the forced outage. This assumption is based on surveillance data from
before the shutdown. The data shows independent, non-identical
-
measurements from the two pumps.
Pending completion of the licensee's
investigation of this issue and further review and ev6uation by the
NRC, this issue will be Unresolved item (324,93 5 0)).
CAL Item D2 - Reduction of Temporary Conditions
l
Temporary conditions are the responsibility of Technical Support and are
included in their data base.
Subsets of these items are also tracked by
other organizations (i.e., NED tracks STSI items and Operations tracks
operator work arounds). However, the data contained in the subsets are
not consistent.
For example, Operations only tracks disabled
annunciators on the reactor turbine generator board (RTGB) while
Technical Support tracks all disabled annunciators. This is illustrated
'
by the operator work-around list dated March 29, 1993, where Operations
lists 12 disabled annunciators while the Technical Support Temporary
Condition Summary dated March 24, 1993, lists 24 disabled annunciators.
The same Operations operator work-around list showed 20 clearances
greater than 30 days old while Technical Support listed only 11 in the
same category. The inspector's review determined that not all the
information tracked as operator work-arounds is tracked by Technical
,
Support as a Temporary Condition. The inspector concluded that the
i
licensee's lack of consistency and the multiplicity of organizations
which track similar information makes it difficult for the license to be
fully aware of what remains in the backlog.
However, the inspector determined from existing Technical Support data
that 120 non-STSI Unit 2 temporary conditions existed on April 21, 1992,
and that 67 have been completed during the current outage. An
!
_ - _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ - _ _ _ _ _ _ _ _ _ _ _ .
,
12
additional 114 non-STSI temporary conditions were identified during the
outage and 53 of these have been completed.
All of the open temporary conditions are listed in the integrated
backlog item report (IBIR) and have been subjected to the PN-30 review
process.
This provides a degree of confidence that those temporary
conditions which meet the requirements of Priorities One through four
have been or will be completed prior to restart. As documented in
Inspection Report 325,324/93-10, NRC inspectors walkded down and
reviewed the IBIR items on six of the 19 critical systems. This
inspection effort, as well as those documented in Inspection Reports
325,324/93-02; 15; and 17, determined that the licensee's prioritization
process was effective and acceptable.
The inspector discussed his
concern about the difficulty in reconciling data from different data
bases with the licensee. The licensee stated that it will investigate
the conversion of temporary conditions into temporary modifications and
tracking by a single data base. The Three-Year Plan has an initiative
for the Management of Temporary and Substandard Conditions (TY 509).
Technical Support Management informed the inspector that it would
initiate an effort to define the various categories now contained in
,
Temporary Conditions and assign tracking responsibility by category.
The inspector concluded that the backlog of temporary conditions has
been effectively evaluated and prioritized by the licensee, that all
items that could affect safe system operation have been addressed, and
that the items which will remain open will not affect Unit 2 restart and
safe operation.
CAL ltem D4 - Reduction of Corrective Maintenance Backloo
CAL Item 05 - Reduction of Preventive Maintenance Backloa
When both units shutdown on April 21, 1992, the backlog of corrective
maintenance items on Unit I was 783 outage and 993 non-outage items.
The Unit 2 corrective backlog was 673 outage and 1582 non-outage items.
The backlog of preventive maintenance on Unit I and Unit 2 was less than
100 items at shutdown.
Since shutdown, over 6863 corrective maintenance
WR/J0s have been initiated on Unit I and 11,813 on Unit 2.
As of
,
April 1, 1993, 4851 corrective maintenance WR/J0s items have been
l
completed on Unit I and 10,983 on Unit 2.
Additionally, a total of over
l
3700 preventive maintenance activities were completed on Unit I and over
5200 on Unit 2 since plant shutdown.
In the area of preventive
i
'
maintenance, approximately 257 items are in the backlog for Unit I and
l
19 for Unit 2.
The licensee has stated that they will complete the
majority of preventive maintenance items that do not require an actual
I
refueling outage on Unit 2 prior to restart. Any items that are not
completed will be evaluated in accordance with the PN-30 process. This
is adequate for Unit 2.
Unit 1 preventive maintenance will be reviewed
and addressed prior to Unit I restart.
i
When the plant was shutdown the licensee did not have a clear
l
understanding of the existing backlogs in preventive and corrective
maintenance. They expressed an intent to work off a large portion of
the maintenance backlog but did not effectively plan, schedule, and
I
-
m
~
,
13
person load each work item as needed to implement a redaction process.
The original outage plans did not extend past a few weeks for the first
3 to 4 months. The plan was always to restart the foliowing month so
the plant remained in a standby condition without releasing large
,
,
!
amounts of work to the field. The lack of a well plarned and integrated
'
I
schedule reduced the rate of backlog reduction.
In aodition to this,
hot and cold side walkdowns of selected plant spaces and a lowered
i
I
threshold for deficiency identification resulted in the initiation of 50
-
to 70 new work items each day while only 25 to 40 were being completed.
l
'
This has resulted in over 13,000 WR/J0s for new corrective maintenance
work items being initiated between April 21 and December 31, 1992.
'
During this same time span, approximately 11,000 corrective maintenance
,
WR/J0s have been completed.
This resulted in a net increase of
'
,
I
approximately 2,000 WR/JO backlog items in 1992.
i
In the licensee's July 23, 1992 response to the NRC, they described a
I
process that would be used to categorize and work off the existing
backlog. This process was implemented into a plant notice and
"
procedure, Integrated Recovery Methodology, PN-30, Rev. O, on October 2,
1992. A goal for corrective maintenance backlog of seven weeks had been
previously defined and documented in the Nuclear Generator Group Work
l
Management Policies and Standards dated August 24, 1992.
This
,
established a backlog of seven weeks, but did not provide dates for
meeting these goals.
Revision 1 of PN-30, issued on December 1, 1992,
refined the process used to address the backlog and categorized each
item into 7 categories. This procedure, PN-30, also established a
cutoff date of September 26, 1992, for adding new work to the outage
scope. On December 31, 1992, there were approximately 6500 WR/J0s in
'
the backlog.
Since implementation of the PN-30 process, all open
corrective maintenance has been reviewed on a system basis. Under this
process, the system engineers determined what work needed to be
accomplished and what work could be deferred without adverse impact on
system operation. This process included a review by a Backlog Review
Committee ar,d the Plant Nuclear Safety Committee for each work item that
was deferred until after each unit restart. NRC inspectors reviewed
'
this process in several inspection reports in 1992 and 1993 (Inspection
Reports 323/324/92-29; 93-02; 93-10; 93-15; and 93-17) and found it to
be an effective management tool.
In December 1992, in an effort to gain a better understanding and
i
establish better control over backlog work, the licensee shifted
i
emphasis to working backlog items by priority rather than the categories
defined in PN-30.
Each WR/JO that had been reviewed and categorized was
i
re-reviewed and prioritized using the nine priorities established in
Maintenance Management Manual Procedure, Corrective Maintenance, MMM03,
Rev. 14, dated August 14, 1992.
The top 4 categories in PN-30 closely
'
matched the top 4 priorities in MMM03. Therefore, the backlog item with
the highest category still retained a high priority under the new
process. This new method was an effort to ensure that the items with
the highest priority and oldest dates were incorporated into the
'
Integrated Schedule and worked first. This has been marginally
successful in focusing resources on the right work and has led to some
j
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.,
.
14
improvement in productivity. The number of WR/J0s completed each day
has increased from a seven day average completion rate of approximately
30 in December of 1992 to slightly over 50 per day in March 1993.
However, during this same time period the material condition walkdowns
i
of Unit 1 and Unit 2 spaces identified additional deficiencies. The
material condition walkdowns in Unit 2 completed in January 1993
1'
identified over 4400 items that required repairs. The Unit I walkdown
that recommenced in February has identified over 2800 items thus far.
This has had the overall effect of increasing the corrective maintenance
backlog to approximately 7000 items.
l
(
As noted in the above discussion, number wise, the backlog of corrective
maintenance has increased. However, the licensee has had some success
in correcting the older and higher priority maintenance items. The
l
pre-April 21, 1992 backlog has been reduced from 4465 to 811 items.
The
r
licensee has also established and made progress toward the new backlog
goals identified in the January 1993 meeting with the NRC. The
l
following is a listing of the licensee's present goals and progress as
,
l
of April 1,1993, in backlog reduction:
,
l
Ob.iective
Goal
Status
i
Systems important to
s 800
778
'
Safety (WR/J05)
Systems important to
s100
88
l
Safety (WR/JOS with
Priority 1-4)
All Systems (Priority
s100
186
1-4 WR/JOS)
WR/JOS less than 90
>50%
54.5%
,
l
Days Old
Running Rate Total
<120 days
99 days
Corrective Maintenance
(Both Units)
i
Average WR/JO Age
s120 days
152 days
Control Room
s10
20
Annunciators / Instruments
Operator Work Arounds
- s54
53
- s50
31
Permanent Caution Tags
0
2
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,
15
,
Preventive Maintenance Backloo Status
Unit 1
Unit 2
Q-list Preventive Maintenance
65
4
,
'
non-Q Preventive Maintenace
192
15
The licensee stated that resources will be added as needed to reduce the
backlog to a running rate of less than 120. However, the backlog has
risen by approximately 600 WR/J0s without the addition of resources.
'
There are also additional plant areas with scheduled material condition
wal kdowns. As with past walkdowns, this has lead to the identification
of additional deficiencies.
Also, the licensee has not fully addressed
how resources will be divided between the refueling outage on Unit 1,
the restart and power operation of Unit 2, and backlog reduction.
The licensee has expended considerable resources in their attempt to
address this issue and has corrected a significant number (over 16,000)
of deficiencies. As discussed in paragraph 2, the licensee's
scheduling, planning and work organization has challenged the
effectiveness of the backlog reduction effort. The licensee has
,
effectively reduced the backlog of high priority work items on safety
systems and has made significant progress in reducing deficiencies that
could have impact on safe or efficient operation of Unit 2.
The NRC
conducted system walkdowns and backlog reviews on six systems
(Inspection Report 325,324/93-.10). These inspections of six ECCS
i
systems found that the high priority maintenance work had been completed
or was scheduled for completion prior to restart.
this indicated that
the PN-30 process was being implemented effectively. The majority of
the corrective maintenance items that will remain open on Unit 2 can be
safely worked during power operation. The backlog of preventive
maintenance on Unit 2 has been found to be of a limited number, the
majority of which will be completed prior to the unit's restart.
The licensee's Three-Year Improvement Plan, Initiatives TY 103,
Corrective Maintenance Backlog, and TY 304, Backlog Reduction, were
developed to address the backlog problem. The licensee will provide
periodic reports to the NRC on the Three-Year Improvement Plan. The
inspectors will track the status and progress of these initiatives until
they are successfully implemented. The backlog on Unit I will be
addressed prior to its anticipated restart in the Fall of 1993. The
backlog on Unit 2 is acceptable for Unit 2 restart.
6.
Followup of Events (93702)
March 13. 1993 Unusual Event
On March 13, 1993, a severe storm (lasting approximately seven hours)
passed through the area with winds gusting to 90 mph. The storm was
unusual in that it was accompanied by minimum precipitation. Heavy
damage was sustained in the area including the loss of several 230kv
incoming offsite power lines to the site.
Each unit has four separate
i
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.,
!
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16
!
230kv offsite power lines. Weatherspoon, Delco East, Jacksonville and
Castle Hayne East provide offsite power lines for Unit 1.
Whiteville,
'
Delco West, Wallace and Castle Hayne West provide offsite power lines
7
for Unit 2.
There are two 230kv busses per uait and each incoming line
i
has two power circuit breakers (PCBs), each feeding one of the two
busses. At 2:25 p.m., multiple switchyard alarms were received and PCBs
,
for Jacksonville and Castle Hayne East and West cycled and locked open.
!
The Unit 1 SRO observed the following trips:
1/2 scram on A channel
1/2 Group 8 isolation - Ell F009, Inboard RHR shutdown cooling
'
isolation valve closed
1/2 Group 2 isolation - G16 Radwaste F003 and F019 closed
i
1/2 Group 10 isolation - Division II realigned
Group 6 isolation - Drywell purge secured
[
l
1/2 Group 1 isolation - No action (MSIVs already closed)
'
,
Reactor Building HVAC isolated - SBGT started
RWCU tripped
The SR0 established the return of shutdown cooling and RWCU reject as
first priorities. Unit 2 received a Group 1 isolation signal with no
action as the MSIVs were closed; a Group 10 isolation; and a Group 6
isolation, but the SBGT did not start as it was under clearance. Both
units lost their D air compressor and the backup Joy (A,B & C) air
compressors auto started.
A precautionary Unusual Event was declared at 2:35 p.m. due to the loss
of three offsite feeder lines (Castle Hayne East and West and
Jacksonville). The TSC was manned, but not activated. This action was
initiated as an anticipatory measure due to loss of the local telephone
paging system tower and hazardous travel conditions. The scram signal
and was reset on Unit I the isolation signals were rest on both units.
The Castle Hayne West feeder breaker to Bus A (PCB27A) was closed at
4:02 p.m. and PCB27B was closed at 6:09 p.m.,
restoring all offsite
power to Unit 2.
Unit 2 experienced no other difficulties during the
course of the event.
Earlier in the day, the licensee made preparations to changeout
substation E5 compartment AT5 which feeds MCC ICA (WR/JO 92-BAUY1).
Battery charger loads on chargers lA-1 and 1A-2 were either isolated or
placed on alternate power sources. The "A" RPS bus was placed on its
alternate power source which is fed directly from an MCC. The normal
power source is a high inertia MG set with a flywheel which tends to
smooth out power fluctuations.
.-
s
.
17
't
The licensee determined that the Castle Hayne East line had come in
contact with the Jacksonville line approximately one mile from the site.
The contact of the two feeder lines caused the fault. The Delco East
-
line was lost four times between 5:31 p.m. and 8:37 p.m.
Various group
isolations and one half RPS trips were received each time there were
voltage transients on the bus. During the event the TSC lost power at
7:57 p.m., which resulted in the loss of telephone communications in the
!
TSC.
Power was restored from the TSC/ EOF DG at 9:35 p.m.
Investigation
revealed that the TSC/ EOF DG had load logic problems and an undersized
fuel oil transfer pump, see paragraph 9.
The Unusual Event was
terminated at 11:37 p.m. after both Delco East PCBs were closed. Castle
Hayne East was restored at 1:22 p.m. on March 14, and the Jacksonville
line restored at 8:13 p.m. on the same date.
.
The licensee investigated the reason why one half isolation signals were
received but the DGs did not start. They determined that the EPA
a
'
circuit breakers which protect the RPS have a higher undervoltage
setpoint (108 volts) than the rest of the system which causes them to
respond more quickly than the rest of the system. The normal RPS power
source has sufficient cushion with the rectifier, invertor, aad high
inertia MG set to accommodate transients.
The alternate power source
removes the buffers and as such responds more quickly to perturbations.
The voltage dips were not low enough nor of sufficient duratio:i to
initiate other equipment.
,
The storm caused extensive property damage and numerous power outages
1
locally.
It took approximately 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> for the licensee to restore
most customer service. Areas along the coast experienced insulator
~
arcing and transformer flashing.
Local fire companies assisted the
licensee and other local power companies by washing down affected
"
,
components to remove the accumulated salt deposits.
March 16. 1993 Unusual Event
I
On March 16, at 6:55 p.m., Unit 2 experienced a 230kv bus 2B lock out
resulting in a loss of offsite power (LOOP) which was being backfed
through the UAT. The following automatic actuations were observed:
All four DGs started, DGs 3 & 4 loaded
,
Reactor scram signal (all rods were already inserted)
4
Groups 1, 2, 3, 4, 5, 6, 8 and 10 isolation
,
Reactor building isolation dampers did not close due to SBGT being
,
under clearance
All automatic functions performed as designed.
At the same time, Unit 1 experienced a loss of shutdown cooling (SDC)
due to the RHR pump (powered from a Unit 2, E bus) tripping.
Additionally, a Group 6 isolation occurred, with Reactor Building
^
,
.
.
18
ventilation isolation and SBGT starting, because Unit 2 lost power to
the main stack radiation monitor. An Unusual Event was declared at
7:03 p.m.
SDC was restored for Unit I at 7:34 p.m. and at 7:59 p.m. for
Unit 2.
The operators observed a five to ten degree F SDC temperature
j
rise in Unit I and about a one degree rise in Unit 2.
t
f
The Senior Resident Inspector, upon being notified of the above
occurrence, responded to the site. At 8:50 p.m., Unit I lost power to
,
the 230kv bus B which resulted in a 1/2 scram, Group 1 isolation,1/2
l
group 10 isolation and a loss of common A and B busses which supplied
balance of plant (B0P) loads. The TSC was activated at 9:08 p.m.
The
'
TSC/E0F DG was manually started and loaded and supplied power for the
duration of the unusual event.
,
,
The Unit 2 - 230kv bus A was de-energized about midnight and bus B was
verified to be de energized as directed by the load dispatcher. The
.
licensee had determined the equipment in the switchyard and transformer
yard was encrusted with salt residue from the March 13 storm. The
residue provided a grounding path which affected the PCBs and
transformers.
I
The licensee commenced washing down the Unit 2 - 230kv switchyard
l
insulators at 3:00 a.m. on March 17. The 230kv bus IA tripped and
locked out at 3:28 a.m. resulting in a Unit 1 LOOP. Unit I was powered
through the UAT which was lined up to bus IA. The following events
occurred:
,
,
Reactor Scram
'
P
Groups 1, 2, 3, 4, 5, 6, 8 and 10 isolated
'
DGs 1 and 2 loaded
4
SDC lost
i
i
All automatic functions occurred as designed. Unit I restored SDC at
4:58 a.m. with less than a three degree F temperature rise.
I
The dual LOOP rer11ted in the loss of almost all site power. All first
shift, non-essential site personnel were sent home. The Unit I offsite
,
feeder lines supply power to some of the nearby service areas including
i
Southport and were not to be de-energized until crews were ready to work
i
in the Unit I switchyard. The EOF was activated at 9:20 a.m. to relieve
i
the TSC of offsite communication efforts.
The licensee completed washing down the Unit 2 switchyard about
.
10:35 a.m. and power was restored to both Unit 2 - 230kv busses and the
l
UAT were energized about 11:10 a.m..
The BOP busses were energized
!
about Noon. The licensee decided to leave DGs 3 and 4 loaded on busses
i
E3 and E4 until power was restored to both units.
It was estimated that
the Unit I cleaning and restoration would take 10-12 hours based on the
.
Unit 2 effort. The cogentrix and south port feeders tripped and locked
l
i
.
,'
!
19
f
open at about 9:20 a.m.
The dispatcher then opened all the Unit 1230kv
feeder lines prior to notifying the control room. The licensee
commenced hanging the Unit I switchyard and transformer yard clearances
at 10:35 a.m.
The hanging of the clearance was stopped and the
clearance was revised so that the local feeders which were de-energized
_,
could be re-energized providing power to the local service area. The
'
dispatcher energized the Delco East feeder at 2:20 p.m., which restored
power to the local service area.
Efforts to clear the Unit I switchyard
and transformer yard continued until 10:20 p.m.
The Unit'l switchyard
was re-energized at 11:42 p.m. and UAT backfeed was established at
4:24 a.m. on March 18, 1993, with the Unit 1 UAT being energized at
6:43 a.m.
The Unusual Event was terminated ten minutes later.
The resident inspectors observed control room activities during the
event and TSC activities during the Unit 2 power restoration. The
inspector noted that the Site Emergency Coordinator (SEC) was effective
and clearly in charge. He conducted frequent briefings and consulted
'
with the technical staff prior to making decisions.
The operators took
appropriate actions, but the inspector observed command and control
issues during the Unit 2 system restoration effort.
It was noted that
individuals acting in subordinate support roles attempted to assume
their normal shift roles and direct activities.
It was difficult to
determine who was in charge. The inspector did not identify any
,
problems caused by this other than a perception of confusion. The
,
licensee was informed of this observation and is taking steps to
strengthen command and control functions.
,
On March 18, the Site Director of Operations organized an investigation
team to evaluate the equipment, staff, and emergency preparedness
response to the events which occurred between March 13 and March 17,
.
1993. The multidiscipline team was composed of individuals from several
l
CP&L organizations including load dispatch, the transmission department,
l
and an individual from INP0 to assist in root cause determinations. The
team concluded that the loss of two Unit 1 offsite 230 KV feeder lines
on March 13 was caused by a faulty gaseous weather proofing impregnation
process (cellon) of the wooden transmission poles. The cellon
application did not thoroughly penetrate the poles, which allowed the
i
pole's center to deteriorate. The weakened poles were unable to support
the high wind loadings and two poles within one mile of the switchyard
,
fractured. This allowed the lightning line from one feeder line to come
!
in contact with the adjacent feeder line causing the site feeder
,
breakers to lockout. The team concluded that the equipment and staff
responded well and the execution of the emergency preparedness effort
went well.
It determined that on March 15, Operations had questioned
the advisability of not washing the salt encrusted insulators in the
switch and transformer yards prior to the power losses on March 16 and
17. The licensee has no program for cleaning high voltage insulators.
The team queried other coastal utilities and determined that all had
problems from salt buildup from the storm and few have programs to
>
remedy the problem. The licensee has or is in the process of revising
r
its adverse weather procedures, studying the feasibility of salt buildup
systems and methods for removing salt buildup, and inspecting cellon
l
,
I
i
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!
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.
.
l
e
I
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L
20
treated wood transmission towers. On April 5,1993, the licensee plans
f
to present the findings of the investigation team to Region II.
7.
Onsite Review Committee (40500)
l
The inspectors attended selected Plant Nuclear Safety Committee meetings
l
l
conducted during the period. The inspectors verified that the meetings
l
were conducted in accordance with Technical Specification requirements
!
'
regarding quorum membership, review process, frequency and personnel
i
qualifications. Meeting minutes were reviewed to confirm that decisions
'
'
and recommendations were reflected in the minutes and followup of
corrective actions was completed.
On March 16,1993, EER 92-0557 (Single Point Failure, Relays
,
Ell-K113 A&B) was discussed at the PNSC meeting. The inspector observed
>
that only one of the PNSC members or alternates present had any comments
regarding the EER. The Regulatory Compliance alternate member made
three comments that identified technical errors. The EER stated that
LOCA logic was two out of four taken twice when it is actually one out
i
of two taken twice. The evaluation also stated that the DG jet assist
will not work, however, a single unit LOCA will initiate four seconds of
jet assist when the RHR pumps start. The jet assist will not initiate,
[
however, when the relay failure on the non-LOCA unit starts the RHR
pumps simultaneously with the start of the core spray pumps on the LOCA
i
i
unit. The evaluation also stated that a non-LOCA scenario is not a
problem with reactor pressure at less than 410 psig because RHR will be
in shutdown cooling (SDC). This statement is in error for the following
,
!
reasons:
Normally, only one RHR pump operates in SDC
r
RHR injection will overflow the spent fuel pool and flood the
reactor building if the head has been removed
The PNSC approved the EER subject to inclusion of the above comments.
The inspector had two concerns regarding this issue. The first was that
l
an EER which contained technically incorrect information had been
'
subjected to two NED reviews and was approved. The second concern was
!
the adequacy of PNSC reviews. The inspector discussed his concerns with
the PNSC chairman. The chairman stated that the EER had been before the
PNSC earlier and he removed it from the agenda because the members were
not prepared. The inspector acknowledges that because of committee
makeup, not all members will have the same comments, but believes that
,
more than one member should have comments on a technically flawed
'
document. The inspector questioned if an ACR had been written. ACR 93-
i
0022, dated March 18 was initiated to document the deficiencies.
A revised EER 92-0557 was resubmitted to the PNSC on March 25.
It was
again removed from the agenda by the chairman because only one PNSC -
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.
.
f
21
,
,
member had reviewed it.
It had been reviewed and approved once more and
still contained technical errors. NED was again notified of the
deficiencies and is evaluating this item further. Review of the
corrective action associated with ACR 93-0022 is an Inspector Followup
!
Item (325,324/93-16-03).
The licensee has expanded their Nuclear Safety Review function by
t
establishing a Corporate Nuclear Safety Oversight Committee (NSOC) and a
Nuclear Safety Review Committee (NSRC) at each nuclear plant. The
corporate NSOC is composed of:
Mr. W. Cavanaugh
President and C00 of CP&L
Dr. J. Hendrie
Senior scientist, Brookhaven National
Laboratory and former chairman and
commissioner, US Nuclear Regulatory
,
Commission
Admiral K. McKee
USN (retired) former director Navy Nuclear
Propulsion
Mr. B. Lee, Jr.
Former President and CEO of Nuclear
Management and Resources Council, Inc. and
'
former director of Board of Commonwealth
Edison
Mr. L. Loflin
(Secretary) - Manager CP&L Nuclear
Assessment Department
The Brunswick site NSRC is composed of:
'
Mr. L. Loflin
Manager Nuclear Assessment Department
Mr. R. Anderson
Vice President Brunswick Nuclear Plant
Mr. R. Morgan
Plant Manager, Unit 1
Mr. C. Warren
Plant Manager, Unit 2
.
Mr. J. Titrington
Manager Operations
Mr. G. Miller
Manager Technical Support
Mr. M. Bradley
Manager Plant Assessment
Mr. A. Lucas
Vice President Nuclear Engineering
Department
Mr. B. Lee, Jr.
Former President and CEO of Nuclear
i
Management and Resources Council, Inc. and
'
former director of Board of Commonwealth
Edison
i
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_
_.
__
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22
Mr. K. Harris
Former Senior Vice president of Nuclear
Operations and Construction - Florida
,
Power and Light Company
'
The objectives of the oversight committee are to advise and assist the
CP&L Board of Directors in their responsibilities of nuclear operation.
,
The review committee will advise each plant Vice President on the
adequacy and implementation of the plant's nuclear safe'ty policies. The
composition of the above committees with the highly experienced outside
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members increases the industry and nuclear safety knowledge perspective
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available to the decision making process. This will provide a higher
level of understanding and awareness of nuclear safety issues by the
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CP&L Board of Directors, as well as senior corporate and site
management. These committees are one of the Corporate Improvement
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Initiatives (CII).
8.
Plant Readiness for Restart (71707)
Operator Preparation for Restart
The resident inspectors observed five Operations crews during phase two
of license operator requalification (LOR) training on March 5-11, 15-18,
22 and 23, 1993. The inspectors observed simulator and classroom
activities and reviewed the materials, procedures, and training
presented. The training days were divided into four, three-hour
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segments consisting of simulator training, two class room segments, and
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an additional three hours of simulator training.
Simulator training
consisted of a reactor startup, synchronizing to the grid and power
increase to 100 percent, and all reactor testing associated with the
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planned Unit 2 restart. The final exercise was to shut the reactor down
and place shutdown cooling in service.
The simulator instructors were observant and coached both the crew and
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individuals as needed. Classroom training was effective in most cases.
The inspector noted that two of the instructors may not have had
sufficient time to present their material since it was presented in a
rapid manner.
It was also noted that instructors were teaching outage
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modifications and plant changes without having walked down these changes
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in the plant. Crew performance improved each week. After discussions
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between Operations, Training, and the inspectors as to communication
standards and expectations, intra-crew communications improved. The
inspectors observed that crews focused their attention on the center of
the RTGB and were not always observant of indications at the extremes of
the RTGB.
The shift supervisors noted this on two different shifts and
had the trainers initiate alarms which annunciated at the extreme of the
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RTGB simultaneously with another at the center to challenge the crews.
Silencing the primary alarm silenced both and it took the reactor
operators over ten minutes to identify the second alarm. The crews
demonstrated overall good diagnostic and response skills when unscripted
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and abnormal events occurred. The shift supervisors responded
appropriately as the events unfurled and directed their crews to take
appropriate actions.
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It was also noted that the training staff did not appear to have been
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given adequate time to prepare all training material lesson plans and
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procedures prior to conducting the classes.
In some instances, draft
revisions of procedures were being used.
It appears that this is a
normal practice and that simulator classes are routinely used to
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identify and " debug" procedural problems prior to issuance. The
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inspector additionally noted that pages were missing in some procedures
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provided in the simulator which resulted in exercise errors. The
inspector also noted that Operations and Training had not reached a
consensus on what was an acceptable level of repeat back communications.
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The lack of clear guidance from Operations resulted in the instructors
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accepting varying standards of communications in the simulator.
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The above items were conveyed to Operations and Training for correction.
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Subsequent licensee performance improved in the last week of observa-
tions. Additional observations have been conducted in this area by
Regional Specialists over a five week period. The results of these
observations are documented in Inspection Report 325,324/93-06. Based
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on these observations the inspectors concluded that Operations
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performance is adequate for plant restart.
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Violations and deviations were not identified.
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9.
Action on Previous Inspection Findings (92701) (92702)
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(0 pen) P2191-07, Cracking Of Sulzer Bingham Recirculation Pump Shafts.
In a letter dated April 27, 1990, Sulzer Bingham advised the NRC of
axial cracks being found on the shafts of all four recirculation pumps
at LaSalle Units 1 and 2.
Believed to be caused by thermal fatigue,
these cracks were-located immediately above the impeller under the shaft
thermal sleeve. The letter, which indicated the affected nuclear
facilities would be advised via Sulzer Bingham Technical Advisory
Bulletin 82-9004-001, identified Brunswick as having been supplied
recirculation pumps with shafts of the same material as those at
LaSalle.
General Electric (via SIL No. 459, Supplement _2) informed BWR
owners of the Sulzer Bingham Technical Advisory recommendation to
inspect its recirculation pump shafts for cracks after 25,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> of
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operation.
Based on a review of EWR 08171VR, the licensee did not consider the
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shaft cracking problem to be an immediate concern at Brunswick. The EWR
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indicated that the licensee's plans for long-term (versus short-term)
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resolution of this issue reflected the limited Technical Advisory
recommendation for shaft inspections (i.e., LaSalle Units 1 and 2, Nine
Mile Point 2, and Hanford 2). Referencing the Sulzer Bingham letter of
April 27,1990, the inspector questioned the long-term (versus short-
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term) resolution of this issue.
Consequently, in a letter dated
January 15, 1993, the licensee requested that Sulzer Bingham resolve the
disparity between the Technical Advisory and the April 27, 1990 letter,
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In a letter dated January 18, 1992, Sulzer Bingham informed the licensee
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that Brunswick's recirculation pumps were included in the group of pumps
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noted for potential shaft cracking and advised inspection of the pump
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shafts at the earliest opportunity. Accordingly, in lieu of pump
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disassembly in support of liquid penetrant examination, the licensee
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contracted with ENPROTECH Corporation to determine pump shaft integrity
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via a modal method. The ENPROTECH modal method for determining shaft
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integrity involves the generation of an analytical model and the
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measurement of high frequency lateral and torsional modal test data.
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The information derived from these two approaches is then compared and
correlated in such a manner that a determination of the shaft integrity
can be made.
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Both Unit 2 recirculation pump shafts underwent modal method testing on
February 13 and 15, 1993.
ENPROTECH's test report, which was received
!
by the licensee on April 1,1993, indicated there were no flaws detected
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in the Unit 2 pump shafts. The licensee presently plans to perform
similar testing on Unit I recirculation pump shafts prior to Unit I
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restart. Resolution of this issue is required for restart. This item
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will remain open pending NRC review of CP&L's final resolution report.
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(Closed) LER l-92-018, Failure of the CBEAF system to Meet Single
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Failure Criteria for Radiation and Fire Events. The above LER
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identified that on a loss of power in the control logic of the preferred
CBEAF train, the standby train would not automatically start as
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intended. This was due to a lack of a start signal upon loss of power.
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The system uses a 10 second timer to initiate a start signal to the
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standby train should the preferred train fail to start. As previously
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designed, a loss of power to the preferred train also deenergized the
timer and no automatic start signal could be sent to the standby train.
It was also found that the B train of CBEAF could not be restarted
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manually. The licensee's investigation determined that this was the
result of the chlorine detection system logic being powered by the A
train CBEAF control logic. A loss of control power to the chlorine
system fails the logic to a safe position which isolated control room
HVAC and secured or prevented CBEAF operation. The licensee initiated
plant modification 92-108 to correct the above deficiencies. This
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modification reversed the timer logic so that the preferred train fail
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to start relays are deenergized on a fail to start signal. This
automatically places the standby train in the preferred mode upon loss
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of power to the preferred train or if the preferred train fails to
start. The power . supply to the above timers' from train "A" preferred is
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now provided from a 120-VAC panel XU27, Unit 2, Division, I.
The power
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supply for Train
"B" standby is now panel XU28, Unit 2, Division II.
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The resolution of the chlorine detection logic single failure input to
the CBEAF was to provide a logic design that could take a single failure
without disabling the CBEAF protection function. This was accomplished
by installing four new detectors instead of the two previously installed
at the service water building and the control building air intake
ventilation areas. The logic of one-out-of-two-taken-twice will require
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that two detectors at each of the above locations will be required to
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sense chlorine in order to effect an isolation of the CBEAF.
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addition, the above logic and divisionalized power supply will require
the loss of power to more than one division to place the CBEAF in an
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isolated mode.
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The above design was reviewed and accepted by NRR in an SER and
technical specification change dated March 22, 1993. The system
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modification was completed and turned over to operations on March 26,
1993. The inspector reviewed the modification installation package and
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held discussions with the OM&M engineer assigned to complete these
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activities. Additional discussions and reviews were done with the
assigned system engineer. A field walkdown with the OM&M and system
engineer were completed on March 30, 1993. The above engineers were
able to resolve and answer questions and concerns identified by the
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inspector. The inspector additionally reviewed the testing completed
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prior to installation, the after installation calibration and testing of
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components, and the overall system operation and acceptance tests.
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These were all satisfactorily completed prior to system turn over.
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Additional discussions were held with the NED design engineer on
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March 31 relating to several spurious chlorine system alarms that
occurred in the chlorine system during service whter pump start. NED is
currently investigating this problem and believes it to be related to a
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detector overly sensitive to voltage changes. This item is being
tracked by the licensee. Based on the above, other than the sensitivity
issues, the licensee appears to have adequately addressed this issue.
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(0 pen) URI 325,324/92-34-03, Welding Program Problems. As indicated in
Inspection Report 325,324/93-13, the welding activities at Brunswick are
presently being conducted in an effective manner. Accordingly,
corrective actions implemented to date have been sufficient to prevent a
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welding program related impact on unit restart. No longer considered an
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unresolved restart issue, further program enhancements stemming from
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NAD's Brunswick and Corporate welding assessments (see Inspection
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Reports 325,324/93-10 and 325,324/93-13) will be reviewed as Inspector
Followup Item 325,324/92-34-03.
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(Closed) Inspector Followup Item 325,324/93-10-03, Molded Case Circuit
Breaker Replacement. This item involved a 10 CFR 21 report on defective
Westinghouse type HMCP and HFD 3070 breakers. The licensee at that time
had determined that all 141 HMCP breakers required replacement. The
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licensee's initial evaluation of the HFD 3070 breakers had not been
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completed. The licensee has completed their evaluation and based on
concerns involving equipment qualification, have also decided to replace
all installed HFD 3070 breakers. They have currently replaced 60 of the
73 HMCP defective breakers in Unit 2 and are scheduled to replace the
remaining 13 as outage system windows permit. They also have the
replacement breakers available to complete a HFD replacement on Unit 2.
They additionally have ordered and ensured availability of the
replacement breakers for Unit 1.
These activities will be completed on
each unit prior to restart. The inspector considers the above actions
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satisfactory and will conduct any additional needed followup under
10 CFR 21 closure.
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(Closed) Inspector Followup Item 325,324/93-10-04, TSC/ EOF Diesel
Generator Deficiencies.
Inspection Report 325,324/93-10 discussed the
preventive maintenance that had been accomplished in February on the
TSC/ EOF diesel generators.
The IFI was opened to track the development
of upgraded maintenance procedures, loa.1 testing of dual generators, and
replacement of the fuel oil transfer pump with a larger capacity pump.
On March 16-17, both units experienced severe voltage oscillations that
finally resulted in a loss of offsite power on both units (paragraph 6).
The TSC/ EOF diesel experienced automatic start problems. The DG was
manually started and the TSC/ EOF house loads were supplied for this unit
for approximately 32 hours3.703704e-4 days <br />0.00889 hours <br />5.291005e-5 weeks <br />1.2176e-5 months <br />.
After normal power restoration, the licensee replaced the existing
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1/3 hp, 2.5 gpm fuel oil transfer pump with a 1/2 hp, 7 gpm pump and
performed a four hour load test to verify that this pump could provide
adequate fuel. The inspector witnessed selected portions of the pump
replacement and load test.
The inspector also reviewed the licensee
plans for an upgraded maintenance program on this DG. This program will
add mechanical and electrical maintenance on the DG on a monthly, semi-
annual and 18 month frequency. The monthly preventive maintenance route
2-M-M1-630 to run the engine and perform a visual inspection has been
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implemented. The semi-annual and 18 months preventive maintenance will
be developed and implemented prior to being needed.
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The licensee has investigated the logic problem associated with the
automatic start of the DG during the power oscillations and determined
that a fuse had blown in the Southport power supply to the TSC/ EOF.
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This blown fuse gave false indication to the loss of voltage relays
which start the Emergency Diesel Generator. The loss of voltage relays
and logic, when actuated, transfer the TSC/E0F to the Emergency Diesel
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Generator. This logic also has a timer that will keep the loads on the
EDG for at least 10 minutes.
If, after 10 minutes, the Southport feeder
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is restored, then it will transfer the TSC/ EOF back to the Southport
feeder. The blown fuse resulted in the logic attempting to transfer the
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load back to the Southport feeder every 10 minutes. When the loads were
placed on the Southport feeder, it caused the voltage to drop to a level
that actuated the logic again and started the Emergency Diesel Generator
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and actuated a transfer. This circuit worked as designed. After a few
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transfers and temporary losses of power, the TSC/ EOF was manually
transferred and maintained on the EDG until repairs were completed and
the Southport feeder was restored. The licensee is currently reviewing
the above logic to determine if changes or improvements are needed.
This item is considered satisfactory for restart. The maintenance
procedural development and implementation, as well as the control logic
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review will be tracked under Violation 325,324/93-04-03.
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(Closed) Violation 325,324/92-15-05, failure to Maintain Configuration
Control Over Plant Systems. This violation consisted of three examples:
(1) removal of the 182 battery charger from service without assuring the
battery was still unloaded from an evolution five days earlier,
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resulting in battery damage from excessive discharge; (2) manipulation
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of the EDG 4 barring gear lever while mistakenly thought to be under
clearance, resulting in lockout of the EDG; and (3) incorrect placement
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and double verification of a local clearance, resulting in the wrong
control rod drive hydraulic control unit being isolated. The inspector
confirmed that the licensee performed the committed training related
actions for each of these three events.
In addition, APP UA-23,
Annunciator Procedure for Panel UA-23, for Units 1 (Revision 24) and 2
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(Revision 28) were reviewed by the inspector to verify the inclusion of
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specific guidance to preclude damage (i.e., polarity reversal of cells)
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to the 24/48 and 125/250 VDC batteries due to excessive discharge. The
inspector also reviewed PLP-21, Independent Verification, Revision 01
and Al-58, Equipment Clearance Procedure, Revision 42, to verify the
inclusion of independent verification requirements for safety-related
system alignments to negate the potential human performance errors
mutually made during double verification activities.
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Aside from this specific violation, NRC also requested that the licensee
address those actions being taken to reverse the apparent negative trend
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in systems control. The change from double verification to independent
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verification was one of the 27 initiatives presented in the licensee's
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August 3,1992 response as enhancements to work practices related to
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improving systems control. These 27 initiatives are a subset of the 71
process improvement recommendations made by the licensee's Staff
Assistance Team (SAT) in the latter half of 1992. As the completion and
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continued effectiveness of these SAT items is captured under the
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Brunswick Three-Year Plan (Initiative TY 310), the' inspector had no
further questions.
(Closed) Violation 325,324/91-02-01, Use of Improper 0-Ring Lubricant on
EQ Solenoid Valves. The root cause of this issue stemmed from the fact
that maintenance procedures for Valcor solenoid valves had not been
updated to reflect an addendum to the vendor manual disallowing the use
of silicone lubricants on silicone o-rings. Upon discovery, as
documented in Inspection Report 325,324/91-02, the silicone lubricant
was removed from affected Unit i valves and new silicone 0-rings were
installed per vendor instructions. The inspector reviewed the
licensee's operability assessment (EER 91-0112) and confirmed that the
56 affected valves in Unit 2 underwent subsequent o-ring replacement in
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refueling outage B210R1 (September 11, 1991 - January 3, 1992).
Additionally, the inspector reviewed the following related corrective
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maintenance procedures to verify the prohibition of silicone lubricants
on silicone o-rings: OCM-SV501A, Valcor Series V526-5683, Normally
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Closed Solenoid Valves, Rev. 3; OCM-SV502, CM For Valcor Series
V526-6500 and V526-6540, Modulating Solenoid Valves, Rev. 2; OCM-SV002,
Valcor Modulating Solenoid Valves, Models V526-6540-1, V526-6540-2, and
V526-6500-3, Rev. 4; and OCM-SV001, Valcor Direct Operating Solenoid
Valves, V526-5683 and V526-5891 Series, Rev. 7.
As further such
problems have not been identified, and enhancement of the vendor manual
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control process (SAT item A9) is accomplished and assessed for
effectiveness under the Brunswick Three-Year Plan (Initiatives TY 308
and TY 310, respectively), the inspector had no further questions.
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(0 pen) Violation 325,324/92-21-02; Inadequate Procedure and Failure to
follow Procedures With Regard to a Clearance, Clearance Audit, and
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Control Board Walkdowns. Corrective actions for this event were
completed on April 1,1993. However, inadequate control board walkdowns
continued to challenge the licensee. This issue will be closely
monitored during Unit 2 restart coverage.
(0 pen) Violation 325,324/92-35-01; Failure to follow Procedures With
Regard to Unnecessary Reactor Vessel Drain Down. Corrective actions for
this event were completed by the date indicated in the Reply to Notice
of Violation. The adequacy of communication between control room
personnel will be evaluated during Unit 2 restart coverage.
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(0 pen) 325,324/92-44-01, Inadequate Work Controls. As addressed in
paragraph 2, resolution of this item is considered satisfactory for
restart.
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10.
Other Areas
The licensee announced the following plant staff changes:
On February 10, 1993:
Mr. K. Ahern was assigned from Manager, Operations Unit 2 to
Manager, Operations Support and Work Control
Mr. J. Titrington was assigned from Manager, Operations Unit I to
Manager, Operations Unit 2
Mr. J. Simon was assigned from Manager, Shift Operations Unit I to
Manager, Operations Unit 1 (interim)
On February 22, 1993:
Mr. G. Miller was assigned as Manager, Technical Support
(interim). He replaced Mr. R. Helme who was placed in the SRO
training class.
On March 1, 1993:
Mr. J. Heffley was assigned from the corporate staff to Manager,
Maintenance Unit 2.
Mr. Heffley had previously been a maintenance
manager at the Davis-Besse plant.
Mr. M. Jackson was assigned from Manager, Maintenance Unit 2, to
the staff of the Unit 1 Plant Manager assigned to the Work
Management Enhancement Project.
On March 2, 1993:
Mr. C. Hinnant was assigned from the Plant General Manager at
Harris to Director of Site Operations at Brunswick.
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Mr. C. Warren, formerly Maintenance Manager at Arkansas Nuclear
One Plant was appointed Plant General Manager, Unit 2.
Mr. J. Brown, formerly Plant General Manager, Unit 2 (interim)
will remain as Mr. Warren's assistant until after Unit 2 is
restarted.
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On March 4, 1993:
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The licensee revised the structure of the Nuclear Generation Group
at the three nuclear sites.
In addition, the following position
changes were implemented at Brunswick:
Mr. E. Willett was named Manager - Project Management Section.
All organizations currently making up the OM&M Section will
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continue to report to Mr. Willett. Messrs. Hinnant and Willett
will develop a transition plan for reassigning outage management
and other project management functions for implementation after
Unit 2 start up.
Mr. G. Warriner will be the Manager - Plant Support Services.
Until staffing for the Site Controller position is announced, all
functions currently within the Control and Administration Section
will continue to report to Mr. Warriner.
Mr. J. Cowan will be Acting Manager - Regulatory Affairs.
Reporting to him will be Regulatory Compliance and Emergency
Preparedness. Until the transition plan for moving the licensing
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function from NSD to the site is finalized, it will continue to
report to NSD.
On March 19, 1993:
Mr. G. D. Hicks was named manager of the training section at
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Brunswick Nuclear Plant. Mr. Hicks previously was General Manager
of Plant Support at the Trojan Nuclear Plant.
The inspector reviewed the resumes of the above individuals and verified-
that they meet the qualification requirements of ANSI 18.1 - 1971.
11Property "ANSI code" (as page type) with input value "ANSI 18.1 - 1971.</br></br>11" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process..
Exit Interview (30703)
The inspection scope and findings were summarized on April 2, 1993 with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection findings in the
summary. Dissenting comments were not received from the licensee.
Proprietary information is not contained in this report.
Item Number
Description / Reference Paracraph
URI 324/93-16-01
Wiring Error On Unit 2 Jet Pumps 1 & 6,
paragraph 5.
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VIO 324/93-16-02
Failure To Follow Procedure While Venting CRDs,
paragraph 4.
IFI 325,324/93-16-03
Review Corrective Actions For ACR 93-0022,
paragraph 7.
12.
Acronyms and Initialisms
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ACR
Adverse Condition Report
Automated Depressurization System
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B0P
Balance of Plant
Boiling Water Reactor
CBEAF
Control Building Emergency Air Filters
Carolina Power & Light Company
Control Rod Drive
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Diesel Generator
E&E
Energy & Environment
Engineering Evaluation Report
E0F
E0P
Emergency Operating Procedure
Electrical Protection Assembly
Engineered Safety Feature
Engineering Work Request
F
Degrees Fahrenheit
Hydraulic Control Unit
Health Physics
High PressJre Coolant Injection
Heating Ventilation and Air Conditioning
Instrumentation and Control
IBIR
Integrated Backlog Item Report
IFI
Inspector Followup Item
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Institute of Nuclear Power Operations
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Inservice Inspection
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LER
Licensee Event Report
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Loss of Coolant Accident
Licensed Operator Requalification
MAC
Minor Adverse Condition
Motor Control Center
Motor Generator
MMM
Maintenance Management Manual
NAD
Nuclear Assessment Department
NED
Nuclear Engineering Department
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NRC
Nuclear Regulatory Commission
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Nuclear Reactor Regulation
NSOC
Nuclear Safety Oversight Committee
Nuclear Safety Review Committee
OM&M
Outage Management & Modification
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OP
Operating Procedure
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Protected Area
PCB
Power Circuit Breaker
Primary Containment Isolation System
PLP
Plant Procedure
Plant Modification
PM-R0
Plant Monitor - Reactor Operator
PNSC
Plant Nuclear Safety Committee
Pounds Per Square Inch Gauge
Reactor Core Isolation Cooling
R0
Reactor Operator
Reactor Turbine Gauge Board
Startup Auxiliary Transformer
Standby Gas Treatment
SEC
Site Emergency Coordinator
Safety Evaluation Report
Senior Reactor Operator
STSI
Shirt Term Structural Integrity
Unit Auxiliary Transformer
Unresolved Item
WR/JO
Work Request / Job Order
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