ML20036C317
| ML20036C317 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 05/27/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20036C311 | List: |
| References | |
| 50-324-93-19, 50-325-93-19, NUDOCS 9306160096 | |
| Download: ML20036C317 (28) | |
See also: IR 05000324/1993019
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UNITED STAT ES
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101 MARIETTA STREET, N.W.
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Report Nos.:
50-325/93-19 and 50-324/93-19
Licensee:
Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC 27602
Docket Nos.:
50-325 and 50-324
License Nos.: DPR-71 and DPR-62
Facility Name:
Brunswick 1 and 2
Inspection Conducted: April 3 - 30, 1993
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Lead Inspector:
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R.~ L. Prevatte, Senior. Resident Ingiector
Dhte Signed
Other Inspectors:
D. J. Nelson, Resident Inspector
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P. M. Byron, Resident Inspector
C. Hughey, Resident Inspector
D. Starkey, Resident Inspector
G. Maxwell, Senior Resident Inspector
G. Harris, Project Engineer
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Q;vH. Christensen, Chief
DatelSisned
Reactof Projects Section IA
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
verification, outage activities and plant restart, Operational Readiness
Assessment Team, preventive maintenan'ce improvement program, engineering,
onsite review committee, review of licensee event reports, sustained Control
Room observation, and action on previous inspection findings.
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Results:
In the areas inspected, one violation was identified involving inattention to
detail on clearance and control board walkdowns, paragraph 4.
Also identified was:
a weakness involving the seismic qualification of-
containment atmosphere sump level and flow equipment, paragraph 11; a strength
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in the management self-assessment of readiness for restart process, paragraph-
5; and a need to conduct periodic continuity testing of the Diesel Generator
jet assist 2X LOCA circuitry, paragraph 10.
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9306160096 930528
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ADDCK 05000324
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Unit I remained in a forced outage that began on April 21, 1992. A decision
was made to refuel this unit prior to restart and fuel was removed during this
reporting period. NRC approval to restart Unit 2 was granted on April 27,
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1993 Unit 2 subsequently achieved criticality on April 29, 1993.
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REPORTS DETAILS
1.
Persons Contacted
Licensee Employees
- R. Anderson - Vice-President, Brunswick Nuclear Project
- K. Ahern, Manager - Operations Support and Work Control
G. Barnes, Manager - Shift Operations, Unit 2'
M. Bradley, Manager - Brunswick Project Assessment
M. Brown - Plant Manager, Unit 1
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- S. Callis - On-Site Licensing Engineer
R. Godley, Supervisor - Regulatory Compliance
- J. Hefley, Manager - Maintenanc.e, Unit 2
- C.
Hinnant - Eirector of Site Operations
G. Hicks, Manager - Training
- J. Leininger, Manager - Nuclear Engineering Department (0nsite)
- P. Leslie, Manager - Security
- W. Levis, Manager - Regulatory Compliance
G. Miller, Manager - Technical Support (Interim)
D. Moore, Manager - Maintenance, Unit 1
R. Poulk, Manager - License Training
C. Robertson, Manager - Environmental & Radiological Control
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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,
engineers, technicians, operators, office personnel and security force
members.
NRC Personnel
- H. Christensen, Chief, Division- Reactor Projects, Section IA
- Attended the exit interview.
Acronyms and initialisms used in the report are listed in the last
paragraph.
2.
Maintenance Observation (62703)
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The inspectors observed maintenance activities, interviewed personnel,
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:
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 pcst-maintenance testing was performed; and
independent verification requirements were implemented. The inspectors
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independently verified that selected equipment was properly returned to
service.
Outstanding work requests were reviewed to ensure that the licensee gave
priority to safety-related maintenance.
The inspectors observed and
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reviewed portions of the following maintenance activities:
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93 0FH003
CAC 1261 Preventative Maintenance PM
93 AIDX1
Repair turning gear annunciator
The technicians performing the above tasks followed procedures and work
instructions. No deficiencies were noted. Maintenance activities
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observed during Unit 2 restart are addressed in paragraph 5.
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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
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 and reviewed portions of the following test
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activities:
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2MST-RPS21R RPS high main steam line radiation instrument
calibration channel D
This task initially proved to be very difficult.
Extensive
troubleshooting to locate a problem and effect repairs were required
prior to satisfactory completion of this task.
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Surveillance activities observed during Unit 2 restart are addressed in
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paragraph 5.
Violations and deviations were not identified.
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4.
Operational Safety Verification (71707)
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The inspectors verified that Unit I and Unit 2 were operated in
compliance with Technical Speci~fications and other regulatory
requirements by direct observation of activities, facility tours,
discussions with personnel, reviewin; records and independent
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verification of safety system status.
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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
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jumper / bypass logs were reviewed to obtain information concerning
operating trends and out-of-service safety systems to ensure that there
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were no conflicts with Technical Specification Limiting Conditions for
Operations. Direct observations of control room panels instrumentation
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and recorded traces important to safety were conducted to verify
operability and that operating parameters were within Technical
Specification limits. The inspectors observed shift turnovers to verify
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that system status continuity was maintained. The inspectors also
verified the status of selected. control room annunciators.
Operability of ESF systems used for shutdown cooling and ECCS were
verified weekly by ensuring that:
each accessible valve in the flow
path was in its correct position; each power supply and breaker was
closed for components that must activate upon initiation signal; there
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was no significant leakage of major components; proper lubrication and
cooling water available; and conditions which could prevent fulfillment
of the system's functional requirements did not exist.
Instrumentation
essential to system operation or actuation was verified operable by
observing on-scale indication and proper instrument valve lineup.
The inspectors verified that the licensee's HP policies and procedures
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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
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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
security's response to potential threats or alarms was adequate.
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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Clearance Errors
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Several recent clearance errors have focused the need for continuing
diligence in clearance implementation and attention to detail.
One case included multiple errors on multiple clearance tags and was
similar to previous events.
Specifically, on April 21, 1993, the
inspector identified four Containment Atmospheric Control (CAC) valve
control switches on the Unit 2 Control Board in the " neutral" position
despite having clearance tags in place requiring the switches to be in
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the " closed" position. The switches are spring return to neutral from
open, or " click in" and remain in the closed position. The valve
positions had been independently verified. These valves (i.e, CAC-V4,
V55, V56, and V58) were tagged closed to prevent nitrogen from entering
primary containment while the drywell was open for personnel access.
Since the valves were actually in the closed position, no adverse
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results occurred; however, a control board tagout audit failed to detect
the discrepancies. When identified by the inspector, a Control Operator
placed one of the switches in the closed position with the danger tag
still attached rationalizing that he was returning it to its required
position. The inspector intervened prior to the other switches being
manipulated. The remaining three switches were placed in the closed
position after involvement of the Shift Supervisor and further
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verification.
Previous similar events include:
In April 1992, the same control switch position clearance error
for an identical clearance was discovered on the corresponding
Unit 1 CAC valves' control switches.
ACR 92-314 was initiated and
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the corrective actions were completed by September 13, 1992.
These actions consisted mainly of briefing Operations personnel
about the event.
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On July 20, 1992, the inspector discovered that Unit 1 Main Steam
Line Drain Isolation Valve, 1-B21-F016, indicated open on the RTGB
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instead of closed as required by a clearance tag.
This condition
had existed since July 16, and went undetected by a tagout audit
on July 17. Violation 325,324/92-21-02 was issued for an
inadequate procedure and failure to follow procedures with regard
to a clearance, clearance audit, and control board walkdowns.
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Corrective actions for this Violation were completed on April 1,
1993, and consisted mainly of training on attention to detail with
regard to clearance audits and control board walkdowns.
The CAC valve control switch tags, in addition to being improperly
placed and independently verified, were undetected through five shift
turnovers, multiple control board walkdowns, and a tagout audit. The
significance of this event compared to the July 20, 1992, event is
diminished by the fact that the CAC valves' actual position matched the
required position; only the control switches disagreed.
However, as it
is similar to an error previously identified, the NRC considers this to
be a similar violation. This is a violation, Inattention to Detail on
Clearances and Control Board Walkdowns (325,324/93-19-01).
Inadequate
control board walkdowns were also an issue related to a recent violation
(324/93-16-02) for which the licensee has not yet responded.
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One violation was identified.
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5.
Outage Activities and Plant Restart (71707)(71715)
The inspectors reviewed the licensee's Plant Notice PN-31, Line
Management Self-Assessment of Readiness for Restart of Brunswick Nuclear
Plant Unit 2, Revision 2.
This procedure provided the methods and means
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to document the plant's readiness for restart. This was accomplished
through document reviews, management reviews, personnel interviews, and
field observations of material conditions and personnel performance to
determine readiness. These processes culminated with affirmations by
key personnel and managers to the Site Vice President that their
respective areas were ready to support safe plant restart and operation.
The inspectors reviewed documentation and records to verify that these
affirmations were completed by the following organizations:
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Operations
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Maintenance
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Technical Support
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Environmental and Radiation Control (E&RC)
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Outage Management and Modification (OM&M)
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Security
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Quality Control
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Nuclear Engineering Department (NED)
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Training
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Work Control
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Project Services
The Site Vice President held meetings and detailed discussions with
managers of the above areas to further verify their readiness. The
inspectors observed the meetings with the Managers of Technical Support
on April 4, and Operations on April 22. The observed meetings were
detailed and the Vice-President asked thorough and searching questions.
People were sent back to do additional review and further verification
on some issues. The inspectors determined that the meetings were
conducted in sufficient depth and detail to assure Technical Support and
Operations readiness for restart.
The inspectors additionally held meetings with the managers of
Operations, Maintenance, Training, Regulatory Compliance, Technical
Support, E&RC, OM&M, Security, and NED to ascertain how they had
determined the state of restart readiness. All questions were
satisfactorily answered. Separate discussions were held with the Unit 2
Plant Manager and the Site NAD Manager to determine how they had
determined restart readiness.
Informal meetings and discussions were
also held with available shift supervisors and operators. Overall, each-
individual and group interviewed stated that they firmly believed that
significant improvements had been completed while the plant was shutdown
and that Unit 2 was ready for restart and safe operation. As an
additional measure, followup meetings were held with the system
engineers for six systems that had been inspected and walked down by the
resident and regional inspectors in February 1993. The system engineers
again confirmed that these six systems were ready for restart.
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addition, the inspectors attended the PN-31 affirmation meetings for
three systems.
Based on the above, it appears that the PN-31 readiness
assessment, which was completed, on April 25, was a good process and
effective management tool that prepared Unit 2 for restart. The efforts
and results obtained by this process were considered a strength.
NAD Startuo Assessment
The Nuclear Assessment Department completed a startup readiness
assessment of the Brunswick plant on February 12, 1993. The assessment
results were discussed and evaluated in NRC Inspection Report
325,324/93-10. The assessment identified five concerns, three of which
required remedial action prior to plant restart.
Since the initial
assessment, the inspectors have observed NAD conducting assessments of
control room, simulator and work control activities. On April 14, 1993,
in a memorandum to the Site Vice President and the Executive Vice
President for Nuclear Generation, NAD stated that the plant's corrective
actions required for restart had reached an acceptable level. They
noted that Item 1 (lack of management and supervisory involvement in
operations), Item 3 (organization and administration) and Item 4 (PNSC)
were closed. The report indicated that improvement was observed on
Item 2 (work scheduling and coordination) and that it was satisfactory
for startup.
Item 5 (Corrective Action Program) was not considered a
startup issue and was evaluated under a separate NAD assessment during
the period of March 8 through 24.
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The inspector reviewed the above memorandum and discussed these issues
with the NAD site manager. NAD's assessment was based on several
hundred hours of field observations in the areas of work control process
changes and operator performance in the plant and on the simulator. The
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inspectors, through independent field observations, also concurred that
progress had been made in each of the above areas. The inspectors
noted that changes in the area of work control were new and were still
experiencing growth problems. This area will continue to require
management and supervisory attention, as well as NRC followup.
Drvwell and Torus Inspection
On April 8, the inspector performed a drywell walkdown inspection.
There were significant improvements in housekeeping since the previous
drywell entry (Inspection Report 325,324/93-01).
Lighting at the five
foot elevations was the only temporary power installation observed. The
inspector noted that the bands which fasten the mirror insulation at the
joints were not always clamped. Many bands were not latched or they
were held together by locking wire. The inspector also observed that
some flexible ventilation duct joints at the five foot elevation were in-
poor condition. Other sections had been repaired, however several of
the repairs had air leaks.
Housekeeping around the air handling units
was poor and not at the same level as the remainder of the drywell. The
inspector discussed these observations with the licensee and each was
satisfactorily resolved.
The inspector did not identify any drywell
discrepancies which would affect Unit 2 restart. The air handling units
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are not required during power operation and the licensee acknowledged
the poor condition of some mirror insulation bands. They stated that
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the Unit 2 mirror insulation in the drywell was scheduled to be replaced
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in the next refueling outage. Crews were sent back into the drywell to
conduct additional cleanup and repair other licensee identified
discrepancies.
Reactor Startuo to Criticality
On April 27, the licensee was granted permission by the NRC to commence
Unit 2 reactor startup.
Prior to withdrawing the first control rod,
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several briefings were conducted by plant management and control room
supervision.
Specifically, the. Unit 2 SS briefed the control room staff
on the performance of GP-2, Approach to Criticality and Pressurization
of the Reactor, Rev. 45. He stressed the precautions and limitations
stated in GP-2, reviewed licensed operators' instructions in GP-2,
discussed control room decorum during the startup and reminded the
operators of how reactor criticality would be determined. The SS als:
conducted a briefing on procedure GP-10, Rod Sequence Check Off Sheet,
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Rev. 20. He noted that one high worth rod had been identified by
reactor engineering, discussed the ECP and the range of procedural steps
where criticality could occur, discussed actions to be taken if a fast
SRM period were experienced, and noted the procedural requirement to
verify SRM/IRM overlap. Additional comments were made to the operating
staff by the Unit 2 Operations Manager and the Plant Manager. They
stressed that operators should proceed slowly and deliberately in order
to achieve a successful startup.
On April 28, the inspector reviewed the completion of GP-01, Prestart
Checklist. At that time the majority of the procedure steps had been
completed with the exception of reviewing open LCOs. The inspector
reviewed each open LC0 and determined that only one would restrict a
change from Condition 3 to Condition 2.
That LCO concerned the main
steam line 'D' radiation monitor which had failed downscale. The
corrective action included replacing the detector; however, the source
of the failure was later identified as a loose connector on the high
voltage to the detector. The connector was repaired and, after testing,
the radiation monitor was returned to service.
The first control rod was withdrawn at 9:39 a.m., on April 29, using
Sequence B2 of procedure GP-10. After completing step 28 of the rod
pull sequence, rod withdrawal was stopped while the SS briefed I&C and
the operators on 2MST-IRM25NA, IRM Channel Correlation Adjustment. The
IRM range correlation verification takes place between IRM ranges 6 and
7 and adjusts the amplified gain on the upper IRM preamplifier to ensure
correlation between the ranges. All eight IRMs were subsequently tested
while control rods continued to be withdrawn.
During the rod withdrawal sequence, several rods were difficult to move
off position 00.
In each case, control rod drive water pressure was
increased by the operator and the rod was able to be withdrawn.
Control rod 26-35, in particular, proved to be very difficult to move. After
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approximately 20 minutes of varying the drive water pressure, rod 26-35
was withdrawn to position 48 as required by the pull sequence. The SS
instructed that a WR/JO be written on rod 26-35.
At 1:42 p.m., the Unit 2 reactor was declared critical.
Criticality was
achieved on step 59 of the pull sequence with a period of 227 seconds.
Occurring within the ECP band, criticality was one pull sequence step
away from the nominal ECP pull step of 60. As SRM counts increased,
proper overlap of the SRMs/IRMs were verified. When range 6 of the IRMs
was reached, the IRM Channel Correlation Verifications were successfully
completed by I&C.
The inspector observed the startup evolution from the time of the pre-
job briefings through criticality. The entire sequence of events
progressed smoothly. Operator and supervisor actions were unhurried and
deliberate. Good command and control was exhibited with minimal
interruptions to distract operators. The startup evolution to
criticality was conducted in a professional and safety conscious manner
by Operations personnel.
Sustained Control Room Observations
The NRC began sustained Control Room observations on April 27, 1993.
The inspectors attended the shift turnover briefings each day, observed
numerous pre-evolution briefings conducted by shift supervision, toured
the Unit 2 reactor building and turbine building with A0s as they did
their rounds, and observed Control Room decorum. The shift turnover
briefings were thorough enough to present an overview of plant
activities. The Control Room was somewhat crowded during these
briefings, but that did not seem to present a significant problem.
Control Room access was strictly maintained during the shift by the SS
and SRO, and noise levels were generally low except during periods of
shift turnover and following shift briefings.
Pre-evolution briefings observed by the inspectors, included: GP-02,
Approach to Criticality and Pressurization of the Reactor; OPM-TRB501,
Maintenance Instructions for The HPCI Hydraulic Overspeed Test; and
PT 10.1.3, RCIC System Operability Test.
Each briefing was
professionally conducted by a SS and covered the major steps of each
procedure. They were generally well organized and stressed the
importance of safety and accuracy.
Control Room decorum was observed to be good. No examples were noted of
inappropriate activities or unauthorized reading material. Operators
routinely repeated back instructions given by the SRO. Annunciator
response, which included verbal acknowledgement, was considered good.
Annunciator Response Procedures were used when needed and were readily
available in racks at the control panels. During tours of the reactor
building and turbine building with the A0s, the inspectors noted the
conscientious manner in which the A0s performed their duties. Also
notable was the overall cleanliness and the recent repainting of
equipment and rooms in these buildings.
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The inspectors observed the following maintenance and testing
activities:
PT 10.1.1, RCIC System Operability Test
This procedure was used to complete a PMTR on the RCIC Torus
Suction Valve, 2E51-F029 (WR/JO 93-AKTN-1). The test was
successfully conducted; however, there was some confusion with the
wording in step 7.1.2.4.
The step used the term " external lead"
which was confusing to the I&C technician who was lifting the lead
in a Control Room back panel. He suggested that the term " field
lead" was more familiar to I&C. The SS noted the recommendation
and stated that a procedure suggestion form would be. initiated.
2MST-IRM25NA, IRM Channel Range Correlation Adjustments, Rev. 3
During the surveillance, communications between the operators and
I&C technicians was good.
Proper readbacks and acknowledgements
were consistently used. No concerns were noted.
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OPM-TRB501, Maintenance Instructions For The HPCI Hydraulic
Overspeed Trip Test And Automatic Reset
Several problems occurred during the performance of this
procedure. The test was temporarily stopped because the tape used
as a " marker" for the stroboscope monitoring HPCI turbine RPM had
to be moved to another location on the shaft so the stroboscope
could pick it up properly. Another delay came when a fuse for a
HPCI control room indicator had to be replaced. A procedural
problem developed concerning the verification of the turbine
driven oil pump discharge pressure (step 7.1.32). During the
test, discharge pressure was observed to be about 98 psig. An
adjustment to between 105 and 110 psig was required via 2E41-V137;
however, this was a check valve. A note was made at the ehd of
the procedure by test personnel that adjustments should instead be
made via 2E41-RV150, a relief valve. Attempts were made to adjust
the relief valve to bring discharge pressure into the desired
band. The first attempt at overspeeding the turbine failed to
trip the turbine within the allowable range of 4900-5100 RPM. The
turbine had to be manually tripped locally at a speed of about
5340 RPM. The test was suspended until adjustments could be made
to the trip mechanism. After the adjustments, the HPCI turbine
past the overspeed test.
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PT-09.3, HPCI System - 165 PSIG Flow Test, Rev. 36
The inspector observed this test from the Control Room. The
reactor operator performing this test understood the procedure and
performed the test with no difficulties. Acceptance criteria for
the test was met. Communications between the reactor operator and
auxiliary operators stationed at the pump appeared to be good.
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2MST-RWCU-22M, RWCU Steam Leak Detection Channel Functional and
Setpoint
No problems were observed with this activity.
WR/JO 93-AJIMI, Annunciator Troubleshooting Activity
The inspector observed an.I&C Technician conducting
troubleshooting activities on several annunciators in Unit 1
electronic equipment room panels (control room). A review of the
work package revealed that the annunciators did not seal in
properly. The annunciators involved in the troubleshooting efforts
were ANX-UA-14-4.2 (CB Mach Room Vent Fan Trip), ANX-UA-14-4-5
(CAD LN2 Stor Vacuum Lo) and ANN-VA-02-3-4 (Turning Gear not
Engaged). The work package required the technician to use
maintenance instruction MI-16-37, Beta Annunciator Verification
and Testing, Rev. 000. The annunciators were checked by jumpering
or lifting leads. The I&C technician performed the task by
lifting and terminating the leads one at a time. This type of
alteration is called a momentary alteration when three or less
wires are lifted at any one time and the alterations are not left
unattended. The inspector observed the I&C technician tape the
leads and leave the area momentarily, approximately 45 seconds,
and go to the control room to verify that he had indeed lifted the
correct lead.
Independent verification was not required since
this was only a momentary lift.
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WRJ093-APPA1, Troubleshooting and Repair of Flow Comparator
Circuitry
No problems were observed'during this activity.
PT-01.6.2, Rod Worth Minimizer System Operability Test
No problems were identified with this activity.
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PT-01.10, IRM Detector Position Rod Block Functional Test
No problems were identified with this activity.
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OPM-TR508, RCIC Turbine Mechanical Overspeed Trip Test
No mechanical or electrical problems were observed with the RCIC
pump during the operability test. The test was delayed because a
step in the procedure conflicted with a precaution that did not
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allow the turbine's steam admission valve to be tripped closed
from the full open position. A subsequent review of the procedure
revealed that several procedural steps contained deficiencies.
These deficiencies included multiple actions per step, cautions
written within instructional steps, inadequate instructions,
inadequate documentation of method used to control steam admission
to turbine, and no method to track that a step had been completed.
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Although the procedure contained these deficiencies the RCIC
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turbine mechanical overspeed trip test was completed
satisfactorily and without incident. There were no observable -
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water or steam leaks or noises observed during the test.
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2MST-IRM-12W, IRM Channels B,D,F & H Functional Test
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No problems were observed during this activity.
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OPM-TRB501, Maintenance Instructions for the HPCI Hydraulic
Overspeed Trip Test and Automatic Reset
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No problems were observed ~ during this activity.
The test
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procedure, however, had similar problems as described in the RCIC
overspeed test but these discrepancies did not affect test
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performance.
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WR/JO 93-APWNI, Troubleshooting and Repair of Electrohydraulic
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Control 125 VDC Power Supply
No problems were observed during this activity.
PT-10.16.L, Remote Shutdown Panel RCIC Flow Controller Local
Control Operability Test
No problems were observed with this activity.
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PT-10.1.3, RCIC System Operability Test - Flow Rate at 150 psig-
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No problems were observed with this activity.
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PT-09.10.L, HPCI System Component Local and ASSD Control and
Operability Test
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During the ' conducting of this test, the HPCI barometric vacuum
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pump wac cbserved to auto-start when its hand switch was taken
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fror. the Normal to the Local position. A trouble ticket had been
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previously written to document this problem. No other p.oblems
were observed with this test.
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Troubleshooting activities associated with the drifting of rod 38-15 .
were also observed. These activities were performed per Troubleshooting.
Control Form 93-056. Testing was completed with no anomalies observed
and the rod drift could not be duplicated. At a post testing meeting,
the shift supervisor decided to continue with the power ascension. A
vendor representative was involved with the troubleshooting and provided
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key input to the shift supervisor's decision.
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Operational Readiness Assessment Team (0 RAT)
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The NRC conducted an ORAT inspection of the plant during the per:nd of
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March 29 through April 9,.1993. During the inspection, the team
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identified several issues that required corrective action prior to plant
restart.
The following is a description of these items and corrective
actions taken.
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Operator Aids
The team identified the use of unauthorized and uncontrolled information
aids at various locations in the plant. These aids were in various
forms from simple handwritten notes on the RTGB to potentially outdated
wiring diagrams on the interior of control cabinets. Although no plant
events / errors have been attributed to these aids, the risk of errors due
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to outdated / incorrect information was clearly present.
The licensee removed unauthorized and uncontrolled aids from the plant.
Legitimate, but unofficial aids were identified for replacement with
official plant aids / labels in accordance with AI-97, Plant Labeling
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Procedure, and 01-41, Operator Aids.
Some identification aids were not
removed due-to the potential of creating identification problems with
the equipment. Official labels will be made to replace these
identification aids.
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The inspector examined RTGBs for both units and the interior of all
Unit 2 back panels and found no. uncontrolled aids except for the
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miscellaneous identification back panel labels noted above.
The
licensee is still evaluating the root cause and long-term corrective
actions.
This issue is satisfactory for Unit 2 restart.
Alternate Safe Shutdown (ASSD)
On April 5,1993, the team conducted a walk through exercise on
operators to determine their ability to shutdown a unit using the ASSC
control panels. This exercise identified the following deficiencies
that were required to be corrected prior to Unit 2 restart:
The primary means of communication used in the exercise was found
to be inadequate and a secondary means had not been procedurally
established. The licensee was required to repair and test the
dedicated sound power communication system and designate a back-up
means of communication.
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The operator in the SWPH experienced difficulty in completing his
ASSD task, and another operator required instructor / evaluator
prompting.
The ORAT required the licensee to verify that shift
personnel were qualified to perform this task. The licensee
stated that job performance measures (JPMs) would be conducted on
selected shift personnel to verify this.
The ORAT agreed with
this approach.
The inspector reviewed licensee training records and verified that JPMs
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had been conducted on a total of 20 Reactor Operators and Auxiliary
Operators for all four shifts to verify their ability to conduct an
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alternate safe shutdown from outside the Control Room. The JPMs tested
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the operators ability to:
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Manually start and load a diesel generator locally during a
control building fire.
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Establish shutdown cooling external to the Control Room.
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Start and align the RCIC system locally.
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Align the service water system at the SWPH to support plant
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shutdown.
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Three to five operators from each shift were tested by the licensee's
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training department on April 7,' 8, 20, 21, and 24 on the above
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evolutions with satisfactory results.
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The licensee upgraded the communication equipment with new amplified
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headsets. On April 23, 1993, the inspector witnessed the performance of
PT 48.4, to verify the operability of the communication equipment. The
inspector attended the pre-evolution briefing and observed the operators
testing the sound powered phones at various stations for both channels.
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During the test, the inspector found that communications was
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intermittent on the headset he was using at the Unit 2 remote shutdown
panel (RSP). The. inspector considered the PT unsatisfactory. The
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licensee trouble shot the system and stated that they had identified and
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repaired the. intermittent nroblem. They re-performed PT 48.4 later on
the same day. The inspector observed that all headsets functioned
except one at the Unit 2 RSP. This station was experiencing the same
problems as the inspector had previously identified. Again the test was
terminated 'and additional trouble shooting was performed.
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The licensee found that while converting the headsets from three
channels to a single channel, they had improperly crimped the telephone
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type connectors which connected to the headset battery packs. This
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resulted in poor continuity and caused the intermittent problems. On
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April 24, the licensee successfully demonstrated the adequacy of the
ASSD sound-powered telephone system to the inspector. The GAI-tronic
paging system was demonstrated as a backup communication system.
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The inspector also reviewed Quarterly PT 48.1, Public Address Page
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System, Revision 16, and the annual PT 48.3, Revision 9, test for the
same-system, to verify that the system is checked for audibility. The
AESD procedures for both units were reviewed and found to have been
revised to contain a step that designates GAI-tronic as the backup
related system.
The inspector verified that the licensee had adequately addressed the
ASSD communications concerns for Unit 2 startup.
Backloa of Deferred Items
The team expressed a concern that the existing backlog of-items deferred
until after Sant restart may place a burden on routine plant
activities. This item has been the subject of numerous reviews and has
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been documented in several NRC Inspection Reports. Several of these
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items were tracked as items that required completion or acceptable
resolution prior to Unit 2 restart. The licensee's PN-30 process
categorized and prioritized the backlogs on a system basis and
determined which items were required to be corrected prior to the
startup of Unit 2.
NRC reviewed the implementation of this process on
11 safety-related systems and it was found to be effective. This item
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has been discussed in detail in monthly NRC/ licensee /public meetings,
the last of which occurred on April 26, 1993. The licensee has
established goals and is currently, as a part of The Brunswick Three-
Year Plan, (Item TY-304), developing plans to meet their goals. These
plans will be completed by June 15, 1993. The licensee anticipates
achieving the majority of these goals by October 1995. The licensee's
progress on this item is acceptable for startup.
Maintenance Procedures Backloa
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The team expressed a concern that the backlog of maintenance procedure
revisions may affect Maintenance's ability to effectively maintain plant
equipment. Approximately 1735 maintenance procedures require revisions.
About 535 procedures have technical discrepancies while the balance
require administrative enhancements. The technical changes ranged from
a minor change (i.e., meter range) to significant changes such as
incorporate modification changes to equipment. The licensee was
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questioned on the existence of controls to prevent the possible use of
technically inadequate procedures. The licensee's existing controls
were that the maintenance planner, the Work Control Center, and the
implementing foreman were required to verify on the computerized Nuclear
Revision Control System (NRCS) that the correct procedure revision was
being used. The NRCS procedure listing carries a notation to identify
if a procedure revision request (PRR) is outstanding. The procedure
user is then supposed to review and determine the impact of the needed
revision. The licensee enhanced this system by placing a sticker on the
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applicable procedure which stated that a PRR was outstanding and the
user should contact the procedure writer for instructions. The above
procedure was then reviewed by the procedure writer to determine if the
PRR was applicable to the requirements of the WR/J0.
If the PRR was
applicable, the PRR would be attached. The procedure writers maintain a
log of all such transactions.
In addition, NRCS was updated and a PRR
menu was added such that the user could read the PRR.
On April 22, the inspector verified the above process.
He reviewed
maintenance procedures which had outstanding PRRs and observed the
notice on the cover sheet. The inspector asked what procedures covered
the changes and was informed th'at a procedure governing the control of
maintenance procedures with outstanding technical PRRs was in the
process of being written.
Having informed licensee management of his concern, the inspector was
told that all procedures containing technical errors would be removed
from the library. The only procedures with technical errors now in use
are in the custody of the procedure writers. The inspector verified
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that the action took place on April 23. The removal of affected
procedures from the library provided a positive means of controlling the
inadvertent use of these procedures.
In addition, the licensee removed
all controlled copies of the affected procedures from other plant
locations. This action was witnessed and verified by the inspector.
Revisions to correct technical deficiencies are scheduled for completion
by October 1994, and procedural enhancement revisions are scheduled for
completion by October 1995.
This item is satisfactory for Unit 2
restart.
7.
Preventive Maintenance Improvem'ent Program
In December 1992, the licensee initiated The Brunswick Three-Year Plan
to improve plant performance. One initiative of this plan was the
Preventive / Predictive Maintenance Program Improvement (Item TY 501).
One of the goals of this item was to enhance the preventive maintenance
program by reconstructing the PM bases for tasks and frequency. To
ensure the accuracy of the above required a review of some of the
following: Engineering Data Base Systems, Vendor Manuals, PM. procedures,
WR/J0s, AMMS, and other engineering and ver. dor data that may contain
information on maintenance basis and periodicity.
Although the Three-Year Plan was approved in December 1992, a contractor
was hired and work was started on this project in early November 1992.
When the contract work initially started, supervisory verbal
instructions were used to guide and direct personnel performing this
task until sufficient knowledge on project scope and depth could be
obtained. On December 18, 1992, the General Expectations and Guidelines
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for Task Assignment was approved and provided to the contractor in a 50
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page procedure " Preventive Maintenance Project Guideline 1".
Additional
guidance was provided to the reviewers / analysts on this task by the
contractor supervisor and licensee contract supervisor during the period
of November 9, 1992, through January 24, 1993. On' January 24, 1993,
detailed written instructions and guidance was provided to the
reviewer / analyst.
A part of the job task was to review vendor manuals to determine manual
accuracy for equipment model numbers, minor PM recommendations,
calibration requirements, equipment tag numbers, etc. This review was
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planned on approximately 460 vendor manuals for equipment with active
PMs.
Forms were provided to compile any deficiencies identified during
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the reviews.
The inspector reviewed the procedures and guidelines that had been
provided to personnel accomplishing the above reviews.
Interviews were
conducted with contractor employees and licensee supervisors currently
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assigned to the project concerning scope, current status, and the extent
of verbal instructions and procedural guidance provided for this
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project.
It appears that adequate guidance had been provided to allow the
personnel to satisfactorily complete the reviews and data assembly
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required for this project. The inspector reviewed a random sample of
approximately ten percent of the deficiency forms that were generated
during the vendor manual reviews. The majority of these were related to
vendor manual revisions.
In each case, the_ identified deficiency had
been reviewed and evaluated with an acceptable resolution. None of the
deficiencies reviewed involved errors that invalidated data obtained for
use in this project.
The inspector noted that a separate Nuclear Engineering Department (NED)
initiative is presently underway to revise and update all currently used
plant vendor manuals over the next three years to meet the requirements
of A-14, NED Procedure Process And Control of Vendor Manuals, Rev. 3.
The updating of vendor manuals and the predictive / preventive maintenance
program improvements, when completed, should lead to improved equipment
and plant performance.
No violation of NRC requirements were identified during this inspection.
8.
Engineering
Drawina Backloa (37702)
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On April 26, while on a Control Room tour, the inspector requested the
control room drawing for the Hardened Wet Well Vent (PM 92-073) which
had been installed during the recent cutage. The P&ID (Drawing D-02515
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Sheet ID), was not available in the control room. The Shift Technical
Advisor was able to obtain a copy of the drawing from an aperture card
located in the nearby work control center. The inspector reviewed
Revision 0 of the P&ID and noted that the radiation monitor was to be
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added later. The radiation monitor is in place and the modification was
declared operable on March 29, 1993. The inspector verified via the
NRCS that Revision 0 was the current revision. The inspector questioned
the licensee as to the reason that an as-built P&ID was not in the
control room for an operable system.
Revision One to the P&ID was
issued on April 27 and placed in the Control Room. The licensee
reviewed the remaining modifications completed during the recent outage
and found two other modifications where the final drawings had not been
issued. The two modifications had not been declared operable and final
drawings will be issued prior to the operability. The licensee
determined that a personnel error was the cause of the correct revision
not being issued. This concern did not affect Unit 2 restart.
9.
Onsite Review Committee (40500)
The inspector attended the NSRC meeting held on April 13 and the NSOC
meeting held on April 14, 1993. These are the recently initiated
committees established to advise senior management and the Board of
Directors (NSOC) and the Site Vice President (NSRC) on the operatiota of
Brunswick and the other two nuclear plants. This was the second meeting
of each committee. The emphasis and reports made to each committee
focused on Brunswick issues and readiness for restart. Video conference
discussions were also conducted by the NSOC with the Robinson and Harris
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sites. A majority of the efforts in the above meetings focused on
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familiarizing the new non-CP&L members with past and current issues.
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Site tours and badging were also completed for non-utility committee
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members.
It appears that these committees will add credibility to the
licensee's efforts to improve their nuclear operations.
On April 25, the inspector attended the PNSC meeting where all unit
managers made presentations to the committee on the status of readiness
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for restart, as required by Plant Administrative Instruction Al-96,
Drywell Inspection, and PNSC Outage Pre-startup Checklist Instruction.
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Each unit manager briefed the committee on his unit's readiness and
discussed in detail any existing or emergent items that were in the
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process of closure.
Each unit affirmed their readiness for restart.
The inspector found the questions and discussions to be very open,
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frank, and detailed. The PNSC exhibited a questioning attitude. The
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inspector found the above meeting to be a very thorough and effective
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process for the committee to determine final restart readiness. No
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concerns were identified in the additional PNSC meetings attended.
10.
Action on Previous Inspection Findings (92701) (92702)
(Closed) Unresolved Item 324/93-10-06, Deferral of Preventive
Maintenance. This item involved the licensee's deferral of 566
preventive maintenance routes with a refueling outage periodicity on
Unit 2.
The licensee's technical support group had completed a generic
analysis which permitted the extension of the above PMs from an 18 month
frequency to periods of up to approximately 35 months. This generic
analysis had been presented to and approved by the PNSC in a memorandum
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dated November 18, 1992. The inspector questioned the validity of this
analysis since it used an Age Reliability Characteristic Curve and did
not consider past history and performance of the individual pieces of
equipment. This issue and the associated concerns were discussed in
detail with the licensee. As a result of these discussions, the
licensee conducted an additional review of the deferred items and added
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343 items back into the schedule for completion prior to unit restart.
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This review also found that 83 of the 566 items had been worked during
the current outage under a modification or as part of a corrective
maintenance activity. The licensee then had a consultant conduct a risk
analysis to determine if there was any significant risk in deferring the
remaining 184 items. This analysis was completed and forwarded to the
licensee on March 29, 1993.
It provided a basis and justification for
deferring all 184 items. The inspector reviewed the analysis and
discussed the details with the licensee. The inspector questioned the
deferral of the following:
RHR Pump Seal Cooler Heat Exchanger Disassembly Inspection
This was questioned since they may be susceptible to biofouling.
The licensee stated that these units had been replaced during the
1990-1991 outage. The new heat exchangers are coated with a
corrosion / erosion medium that will inhibit biofouling.
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switches with alarms will also provide a warning _ of biofouling.
The components do not have a history of biofouling.
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RHR Heat Exchanger 2A Discharge Conductivity Switch
2-Ell-CIS-R001A
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This component was replaced on November 11, 1992, and calibrated-
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under plant modification PM 92-071 therefore, its calibration is
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current until the next refueling outage in 1994.
Diesel Generator Four Day Tank Level Switches
These switches are currently being or have been replaced under-
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plant modifications81-084 and 91-010.
VA-TC-5325 Standby Gas Treatment Heater Temperature Controller
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This component was deleted under Plant Modification 92-106.
Standby Gas Treatment Temperature Switches
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These are seven temperature switches in each SBGT train. These
temperature switches are adequately redundant and have sufficient
tolerance to provide acceptable operation if some drift in
setpoint'should occur between calibrations. They do not have a
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history of setpoint drift between calibrations.
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Preventive Maintenance On RHR And CS HVAC Cooling Units And Fans
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The inspector expressed a concern with deferring maintenance on
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HVAC systems since past maintenance in this area has been focussed
on "fix it when'it-breaks" rather than scheduled preventive-
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maintenance. The licensee ~ acknowledged that past maintenance in
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this area was weak and agreed to accomplish the PM on this
equipment prior to restart.
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HPCI Turbine 18-month Preventive Maintenance
The licensee, in addition to the consultant's evaluations, did a
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specific evaluation of this deferral under EWR 11501, dated
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March 26, 1993. The evaluation provided a basis for deferral of
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each item. The inspector reviewed the' evaluation which showed
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that this component had a comprehensive tear down inspection.
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during the 1990-1991 outage. Unit 2 had only operated a few
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months prior to the present shutdown. While shutdown, a monthly
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PM (WR/J0) was implemented that rolled the turbine and ran the
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lube oil system.. In addition to these preventive measures, this
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unit will be subjected to extensive _startup testing when steam:is
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available. That should detect any existing deficiencies. The
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evaluation also noted that many of the deferred items are for-
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Based on a review of the licensee's justification for deferral of the
184 PM activities, as well as their consultant risk analyses and
justifications, the inspector concluded that it was acceptable to defer
these activities until the next scheduled refueling outage in March
1994. Additional assurance is provided by the licensee's completed
PN-30 reviews that were performed on each system. This coupled with the
PN-31 reviews and planned startup and power ascension testing should
reveal any significant existing, system and component problems associated
with the above deferrals.
(Closed) Inspector Followup Item 325,324/93-10-02, Seismic Qualification
of CAC Systems. This issue is the subject of LER 2-93-001, which is
addressed in paragraph 11 below. This inspector followup item is
administratively closed.
(0 pen) Violation 325,324/91-09-01, Inadequate EDG Corrective Action
(Item 7 - Emergency Diesel Generator Jet Assist 2X LOCA Logic Testing).
As a result of the NRC Electrical Distribution System Functional
Inspection conducted on March 25 - May 21, 1991, a violation of
10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, with
multiple examples was issued.
Findings 91-09-05 and 91-09-07 identified
in Inspection Report 325,324/91-09 noted that calibration and testing of
the EDG jet assist feature had not been conducted for several years.
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During an Enforcement Conference held on August 2, 1991, CP&L committed
to establish procedures for and to perform testing of the EDG jet assist
logic.
The licensee performed testing on the IX LOCA Logic (single Unit
LOCA).
The licensee agreed to test the 2X logic during the next Unit I
and Unit 2 refueling outages. The September 20, 1991 response to
Violation 325,324/91-09-01 reaffirmed the EDG 2X LOCA Logic testing
commitment.
The 2X logic is designed to cope with a LOCA on one unit with a spurious
LOCA signal on the other unit. During the subsequent Unit 2 refuel
outage from September 11, 1991, through December 13, 1991, no testing of
the EDG 2X LOCA Logic was performed. By letter dated March 16, 1993,
the licensee requested a revision of the commitment regarding EDG 2X
LOCA Logic Testing. Specifically, CP&L proposed individual component
testing as an alternative. The basis for the revised commitment was
that the 2X LOCA Logic did not perform a safety-related function and was
considered a design requirement to cope with multiple failure events
(dual unit LOCA). The licensee indicated that the 2X LOCA Logic was
nonsafety-related and as such, the initial testing performed during
plant licensing was acceptable to demonstrate the functional capability
of the system.
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The NRC has reviewed the basis for the commitment revision request.
The
2X LOCA Logic feature is designed to cope with a multiple failure event
scenario, yet it is still considered safety-related because the design
includes it within the safety-related EDG control circuits. The
licensee indicated that the jet assist feature will be maintained in
accordance with good maintenance practices for nonsafety-related equipment.
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The NRC has reviewed the initial 2X LOCA startup testing data (letters
dated December 98, 1974, and April 18,1975) and the results of the last
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set of 2X LOCA Logic relay calibration data (performed from June 5,
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1992, through March 25,1993). During telephone conversations between
the licensee and the NRC on April 23, 1993, the licensee explained that
with periodic calibrations of the 2X LOCA Logic relays all components
with the 2X LOCA Logic received individual functional tests. Testing of
the LOCA relays, various breaker contacts and the 2X LOCA Logic relays
are all performed in separate component tests. The licensee stated that
the individual test procedures would be revised to include verification
of the equipment associated with the 2X LOCA Logic feature during the
existing periodic component testing.
Based on the review, the NRC concurred with extending the commitment
until the next refueling outage. Additional periodic testing to
demonstrate continuity of the 2X LOCA Logic should be considered.
(Closed) Unresolved Item 324/93-16-01, Wiring Error on Unit 2 Jet Pumps
1 and 6.
This item concerned t.he discovery that Unit 2 jet pumps 1 and
6 flow indication was derived from only the No. I pump flow transmitter.
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Had this condition existed during plant operation, jet pump 6 would not
have been monitored for Technical Specification operability and invalid
core flow data would have invalidated thermal limits calculations.
However, the licensee has concluded that this condition was created
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subsequent to the dual unit outage and most likely was caused in
conjunction with WR/JO 92-ASYDI, Determinate And Reterminate Cables And
Wires At Rack 2-H21-P009 To Support Instrument Rack Upgrade (Plant
Modification 92-071). The exact cause could not be determined. The
basis for the licensee's conclusion was data from surveillances
OPT-13.1, Reactor Recirculation Jet Pump Operability and OPT-50.5, Total
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Core Flow Calibration, during the operating period between the last
refueling outage and the current forced outage. Data from these
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surveillances indicates independent flow values for the two pumps.
The
inspector reviewed the documentation associated with the issue (ACR
93-092) and determined that the licensee's conclusion was reasonable.
The inspector also concluded that reasonable effort was expended in an
attempt to identify the exact cause.
In as much as the error was
discovered and corrected during the course of the licensee's normal
modification processes, this item is considered closed.
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(0 pen) 325,324/P2191-07, Cracking of Sulzer Bingham Recirculation Pump
Shafts. This item was previously addressed in Inspection Report
325,324/93-16.
The licensee provided the inspector a copy of the
contractor's report on the Structural Integrity Test performed on the
shafts of Unit 2 pumps. No indication of flaws in the shafts were
detected. This issue is considered satisfactory for Unit 2 restart, but
will remain open pending examination of the Unit 1 pump shafts.
11.
Review of Licensee Event Reports (92700)
(Closed) LER l-92-017, Incomplete Closure of ITE Type K-3000 Breaker
Contacts.
During the electrical maintenance inspection of
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February 22-26, 1993, the inspectors noted that the 4.16 kV essential
switchgear breakers may be susceptible to a lubrication hardening
failure mechanism. This issue was related to LER l-92-017 and CAL Item
B-1 (correct 480 VAC Emergency Bus Feeder Breaker Spring Tension).
In
the transmittal letter for Inspection Report 325,324/93-11, NRC
requested information from CP&L regarding the schedule for refurbishment
of the 4.16 kV essential breakers and justification for not completing
breaker refurbishment prior to plant restart.
NRC received the requested information via CP&L letter dated April 19,
1993 (CP&L No. file: B09-13510, serial: BSEP 93-0059). The letter
contained the licensee's commitment to complete essential 4.16 kV
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breaker refurbishment by December 1994. Additionally, the letter
provided justification for plant startup prior to completion of breaker
refurbishment.
The licensee's response was adequate. The concerns with
the 4.16 kV essential breaker refurbishment issue and CAL Item B-1 are
resolved.
(Closed) LER 2-91-06, Electrical Noise Induced During Routine RWCU
Surveillance Testing caused A Spurious Isolation Signal To Be Initiated
In The RWCU Leak Detection Logic Resulting In An Unplanned Engineered
Safety Feature Actuation.
I&C installed oxide varistors across HPCI AC
relays to help reduce the probability of occurrence of future spurious
RWCU (G31) system isolations. Also, RWCU system isolation valves are
now placed under clearance when MST-RWCU 22M, 22R and 32R are being
performed to eliminate unnecessary challenges to the PCIS/RWCU system.
The clearance requires temporarily opening the breakers for valves
G31-F001 and F004 after the valves have been closed and the RWCU system
has been removed from service. Unit 2 has been scheduled to have a
change-out of the existing Riley Model 86 temperature switches with
modern NUMAC hardware. This work will be completed during the next
Unit 2 refueling outage.
This . item is closed.
(Closed) LER 2-91-20, High Pressure Coolant Injection System Startup
Routine Surveillance Testing Finds Loose Components After A Refueling
Outage Rebuild. During a Unit 2 refueling outage, the HPCI turbine
steam supply valve (E41-F001) actuator had been rebuilt by a service
vendor. Apparently, the vendor did not properly tighten the valve's
limit switch assembly finger base during the rebuilding process. This
resulted in an erratic turbine speed feedback signal, which was observed
by the plant staff during a routine startup test. All other work
completed by the service vendor was inspected and evaluated for similar
conditions and none were found. Valve E41-F001 limit switch assembly
was tightened, the vendor was informed about the " loose" assembly, and
the procedure for the speed pickup gear assembly inspection (MI-10-517C)
was evaluated for inclusion of a check of the speed sensing gear set
screws for tightness. This item is closed.
(0 pen) LER 2-93-001, Containment Atmospheric Control (CAC) Radiation
Monitors Not Seismically Qualified.
Regulatory Guide 1.45, " Reactor
Coolant Pressure Boundary (RCPB) Leakage Detection Systems," dated May
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1973, states that leakage detection systems should be capable of
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performing their functions following seismic events that do not require
plant shutdown and the airborne particulate reactivity monitoring system
should remain functional when subjected to the Safe Shutdown Earthquake.
The licensee committed to provide a continuous monitor capable of
detecting particulates, halogens, and noble gases in Amendment 15 to the
FSAR (Section M4.18-1).
CAC monitors 1260, 1261, and 1262 were
installed to meet this requirement.
A review of the hist)ry of this issue revealed a pattern of inadequate
licensee reviews. The original SER, dated 1973, states that this-
equipment was in conformance with RG 1.45.
The licensee's A&E stated in
1974 that the equipment did not meet the requirements of RG 1.45.
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1975 internal memo states that the requirements of RG 1.45 are met and,
in 1977, the Technical Specifications were amended to read that the leak
detection systems were consistent with the requirements of RG 1.45.
Additional NRC correspondence between 1982 and 1989 references the
licensee's compliance with RG 1.45.
The licensee has no record of
committing to RG 1.45 and did not take exception to NP,C statements to
the contrary. The licensee reversed itself and in 1988 and 1989, in its
responses to GL 88-01, stated that the leak detection system was in
compliance with GL 88-01, which incorporates RG 1.45.
The licensee
further confuses the issue in 1.991 and 1992 by attempting to determine
the seismic qualification of the radiation monitors CAC 1260, 1261, and
1262.
The licensee recently determined through design documentation review
research that the monitors were not being controlled as Q-class. This
issue was presented to the PNSC (Item 92-037-0003) and, on July 6, 1992,
a FACTS items (No. 92B9175) was generated to determine if the CAC
monitors met the design requirements of RG 1.45.
NED determined that
the monitors did not meet seismic requirements and, on January 21, 1993,
ACR 93-033 was generated to identify this as a Technical Specification
,
operability concern. On February 22, 1993, LER 93-001 was issued to
report this condition.
The license investigated several options, including monitor replacement,
to satisfy the seismic requirements of RG 1.45.
Schedule constraints
eliminated the monitor replacement option and the licensee elected to
modify the existing equipment to meet the seismic design requirements.
The inspector attended several teleconferences between NED and site
,
personnel during which these issues were discussed. The licensee
elected to modify CAC 1260 and 1262 monitors since only two monitors are
required to satisfy the requirements of TS 3.3.5.3.
In addition, CAC
1260 and 1262 radiation monitors are located on the 20 foot elevation
while CAC 1261 monitor is located on the 50 foot elevation, which makes
them easier to modify to meet seismic requirements. The licensee was
able to verify that most of the equipment contained in the cabinets had
been previously seismically qualified but the complete assemblies had
'
not. NED determined that the sump level switches and some of the sump
!
flow instrumentation had to be tested.
Fourteen sump relays were
replaced and relocated. The licensee was able to demonstrate by
calculations that sufficient mixing occurred in the drywell. This
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resulted in modifying the sample suction configuration by removing the
isokinetic probes and terminating the suction tubing at the penetration.
This work was performed by Plant Modification, PM-93-009.7. The two
radiation monitor cabinets were structurally modified and detector
restraints were enhanced.
In addition, the sump flow transmitter stand
and cabinet XU-61, were structurally modified. The structural
modifications were accomplished by PM-91-041.
,
On April 8,1993, the inspector walked down the Unit 2 CAC system with
the system and NED engineers. He inspected the modifications and
considered the work to be adequate. The Unit 2 CAC 1260 and 1262
monitor seismic modifications meet the requirements of RG 1.45 and are
acceptable for Unit 2 startup.
The inspector has concluded that, based on the duration of the issue and
the licensee's changing position, that each time this issue surfaced
they stated positions and/or made commitments without an adequate review
to substantiate that position. The licensee has, in the past year, been
,
cited for examples of inadequate reviews. This area was identified as
continuing to need management attention. This item was identified and
corrected by the licensee as a part of the Design Basis Reconstruction
Program. This LER remains open to track completion of Unit 1 items.
(0 pen) LER 1-92-016, Fire Seals Around Diesel Generator Pedestals. The
licensee, during construction, installed Rodofoam 300 as a seismic joint
filler in the gap between the diesel pedestal and the 23 foot elevation
diesel building floor.
It was used as a form to provide for the gap
between the pedestal and floor during the concrete pours. The licensee
later took credit for this seal as a fire barrier to meet the
requirements of 10 CFR 50, Appendix R; however, Rodofoam 300 had not
been tested and approved as a fire barrier and the licensee evaluated
its acceptability as a fire barrier in EER 85-0186. On April 2, 1992,
Technical Support was requested by site management to inspect the
Rodofoam seals. They determined the diesel front end seals were oil
soaked and that a faulty oil collection system had allowed the oil to
saturate the Rodofoam seal. The licensee declared the fire barrier
inoperable and initiated fire watches as a compensatory action. NED was
tasked to find a replacement seal, redesign the oil collecting system,
and develop a method to remove the installed Rodofoam.
NED investigated removing the installed seal by mechanical means or high
pressure water jet (hydrolasing). Hydrolasing was determined to be the
quickest and required minimal disassembly of DG accessories and
attachments. Mechanical removal would have required partial disassembly
of some DG accessories. Special Procedure 2-SP-92-048, Removal of
Diesel Generator No. 4 Pedestal Seal and Perimeter Angle, was developed
to remove the Rodofoam in the DG No. 4 pedestal gap.
Both methods of
removal were included in 2-SP-92-048. On July 9,1992, NED presented
their proposals to the PNSC. The PNSC recommended that DG No. 4 be used
as a pilot project to demonstrate the effectiveness and feasibility of
using the high pressure water jet method to remove the installed
Rodofoam from the DG pedestals. The inspector observed the hydrolasing
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in DG No. 4 and noted that the licensee adequately shielded cable trays
with 20 gauge aluminum sheet metal covers and Herculite. The areas
,
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around the diesel skid at the t'op of the pedestal were covered with
Herculite and mop heads were used as water absorbers. The hydrolasing
was performed from underneath the 23 foot elevation floor _ around the
perimeter of the pedestal. Water was not observed spraying on equipment
,
and the inspector observed that the process was adequately controlled.
'
The crews were able to clean up the water and prevent excessive
accumulation on the floors.
Steel was installed around the perimeter of
,
the pedestal to protect the Rodofoam from contaminants.
The removal of
,
the DG No. 4 Rodofoam seal was completed on November 10, 1992.
,
(
Plant Modification PM-92-090, Diesel Generator Pedestal Seals, was
issued February 27, 1993. The modification includes the removal of the
t
Rodofoam seal on DG Nos.1, 2, and 3, the installation of an approved
three hour fire barrier, and the modification of the oil collection
system on all four DGs. Dow-Corning RTV Silicone Foam was used as the
'
fire seal and installed to a minimum depth of 12 inches. Dow-Corning
.
RTV Silicone Elastonomer was used to protect the fire seal from
contaminants. This is the same material used to protect the drywell
liner plate at the Unit 2 base mat (Inspection Report 325,324/93-02).
The fire seal and protective seal were installed on DG No. 4 on
i
March 19, 1993, and WR/JO 92-AZPNI implemented this effort. .The
!'
licensee had originally planned to complete the remaining three units
!
after Unit 2 was on line. They had determined that this task could be
accomplished with the DGs operable. The NRC raised a concern about the
advisability of removing the installed seal with high pressure water on
Licensee management concurred with the concern and
'
directed that the Rodofoam would be removed by April 16. The effort was
completed on April 18.. The inspector observed the hydrolasing of DG
Nos. 2 and 3 and noted that additional spray shields had been installed
,
on the 23 foot elevation. The inspector observed selected portions of
these efforts and found them to be adequately and effectively
controlled.
The inspector reviewed the procedures, 2-SP-92-048 and PM 92-048
,
developed for this project, and determined that they were technically
,
adequate. The inspector noted in Section 1 of PM 92-048 that the basic
i
function of the seals is to seismically isolate the DG pedestal from the
structural floor system at elevation 23 feet and serve as a three hour
,
rated fire barrier. Discussions with NED structural engineers and
i
review of the safety analysis revealed that the gap was the seismic
l
isolator and the seal was not used to perform this function. The sole
'
purpose of the barrier is a fire seal and it had to be fabricated from a
material less rigid than Rodofoam to maintain the gap as the seismic
'
isol ator. The licensee will re.-review PM 92-048 and plan to issue a
field change clarifying the functions of the seal.
The inspector has determined that the absence of a pedestal seal .in DG
Nos. 1, 2, and 3 does not affect Unit 2 startup since the licensee has
!
provided adequate fire protection compensatory measures. The licensee
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25
currently plans to start installation activities on the new sealant
material in early May and finish in mid June. The remaining activities
associated with oil collection pan modifications and epoxy coating
activities are scheduled to be completed by September 1, 1993.
12.
Exit Interview (30703)
.
t
The inspection scope and findings were summarized on April 30, 1993 with
those persons indicated in paragraph 1.
The inspectors described the
areas inspected and discussed in detail the inspection findings listed
below and in the summary.
Dissenting comments were not received from
the licensee.
Proprietary information is not contained in this report.
Item Number
D'escription/ Reference Paraaraoh
325,324/93-19-01
Violation - Inattention to detail on Clearances
and Control Board Walkdowns, paragraph 5.
13.
Acronyms and Initialisms
A&E
Architect and Engineer
ACR
Adverse Condition Report
AMMS
Automated Maintenance Management System
A0
Auxiliary Operator
Alternate Safe Shutdown
BNP
Brunswick Nuclear Plant
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Containment Atmospheric Control
Confirmation of Action Letter
Carolina Power & Light Company
'
Diesel Generator
E&RC
Environmental & Radiation Control
Estimated Critical Position
Engineering Evaluation Report
Engineered Safety Feature
Engineering Work Request
FACTS
Facility Automated Commitment Tracking System
Final Safety Analysis Report
i
GL
Generic Letter
Health Physics
High Pressure Coolant Injection
,
Heating Ventilation and Air Conditioning
Instrun.entation and Control
LC0
Limiting Condition for Operation
LER
Licensee Event Report
i
Loss of Coolant Accident
Motor Generator
NAD
Nuclear Assessment Department
i
1
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NED
Nuclear Engineering Department
NRC
Nuclear Regulatory Commission
NRCS
Nuclear Records Control System
NSOC
Nuclear Safety Oversight Committee
Nuclear Safety Review Committee
OM&M
Outage Management & Modification
Operational Readiness Assessment Team
Protected Area
Primary Containment Isolation System
Preventive Maintenance
PNSC
Plant Nuclear Safety Committee
Procedure Revision Request
Reactor Core Isolation Cooling
Reactor Coolant Pressure Boundary
Regulatory Guide
RIGB
Reactor Turbine Gauge Board
Standby Gas Treatment
Safety Evaluation Report
Service Information Letter
Source Range Monitor
SR0
Senior Reactor Operator
Shift Supervisor
United Engineering
WR/JO
Work Request / Job Order
.