ML20057E742
| ML20057E742 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 10/01/1993 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20057E732 | List: |
| References | |
| 50-324-93-33, 50-325-93-33, NUDOCS 9310130107 | |
| Download: ML20057E742 (31) | |
See also: IR 05000324/1993033
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NUCLEAR REGULATORY COMMISSION
UNITED STATES
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REGION 11
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101 MARIETTA STREET, N.W., SUITE 2900
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ATLANTA, GEORGIA 303234199
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Report Nos.:
50-325/93-33 and 50-324/93-33
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: August 1 - September 3, 1993
Lead Inspector:
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R. LT Preva{Q, Sen'ior ResiderA Inspector
Daye/igned
Other Inspectors:
P. M. Byron, Resident Inspector
M. T. Janus, Resident Inspector
G. A. Harris, Project Engineer
y asnyk, Physical Security Inspector
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Approved By:.
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41."0. Christe'nsen, Chief
Dite Signed
Reactor Projects Section IA
Division of Reactor Projects
SUMMARY
Scope:
This routine safety inspection by the resident inspector involved the areas of
maintenance observation, surveillance observation, operational safety
verification, Three-Year Plan, Unit 1 outage / restart, onsite review committee,
Engineered Safety Feature System walkdown, action on previous inspection
findings, and review of licensee event reports, and Employee Concerns Program.
Results:
In the areas inspected, a violation was identified in the area of personnel
access control, paragraph 4.
A licensee identified non-cited violation was
identified in the area of incorrect valve installations on the diesel
generators, paragraph 2.
Additionally, weaknesses were identified in the
areas of procedural guidance for resetting gain adjustment factors (GAFs) on
average power range monitors, paragraph 4, and poor e rk planning and
coordination during air leakage testing on the main generator, paragraph 2.
Unit 1 - Remained in a forced outage that began April 21, 1992.
Unit 2 - Operated at 100% power for the reporting period.
9310130107 931001
ADOCK 05000324
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REPORT DETAILS
1.
Persons Contacted
Licensee Employees
- K. Ahern, Manager - Operations Supp1rt and Work Control
R. Anderson, Vice-President - Brunswick Nuclear Project
G. Barnes, Manager - Operations, Unit 1
E. Blackmon, Manager - Radwaste/ Fire Protection
M. Bradley, Manager - Brunswick Project Assessment
- H. Brown, Plant Manager - Unit 1 (Acting)
R. Godley, Supervisor - Regulatory Compliance
- R. Grazio, Manager - Nuclear Engineering Department
- J. Heffley, Manager - Maintenance, Unit 2
G. Hicks, Manager - Training
- C. Hinnant, Director of Site Operations
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P. Leslie, Manager - Security
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- J. Leviner, Manager - Nuclear Systems Engineer
- W. Levis, Manager - Regulatory Affairs
- R. Lopriore, Manager - Maintenance, Unit 1
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G. Miller, Manager - Technical Support
- C. Robertson, Manager - Environmental & Radiological Control
- J. Titrington, Manager - Operations, Unit 2
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.
- 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,
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
observed; adequate post-maintenance testing was performed; and
independent verification requirements were implemented. The inspectors
independently verified that selected equipment was properly returned to
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:
LPRM Cable Replacement
The inspector observed the troubleshooting activities associated with
the LPRM cable replacement modification PM 92-049. Work associated with
this modification involved the replacement of 124 coaxial cables, the
replacement of 16 LPRM detectors and changeout of under vessel hardline
cables with new hardline cables that were compatible with new
connectors. The LPRM cables required replacement due to degradation
that resulted in low insulation resistance values. The new cables were
designed to require minimal maintenance and are qualified for a 40 year
operating life.
After the new cables were installed, the cable connectors were left
uncovered and exposed to the drywell atmosphere. The high humidity in
the drywell atmosphere resulted in moisture collecting between the cable
wire core and insulator. The presence of moisture reduced the cable
insulation resistance below acceptable values. The licensee contacted
the cable and detector vendor and they both agreed that the low
resistance valves were caused by moisture intrusion.
It was then
decided that the moisture in each cable would be removed by heating and
vacuuming techniques.
Simultaneously, resistance readings were taken on
cable lengths between the control room cabinets and drywell penetration
and pedestal locations. The readings were compared against acceptable
values.
The licensee conducted the troubleshooting activities using OSPP-NE002,
Special Process Procedure, SRM, IRM, and LPRM Preinstallation and Post
Installation Testing, Rev. 3.
The procedure requires a nominal
resistance value of IXE10 ohms and a minimal resistance of IXE8 ohms.
In addition, values as low as IXE6 ohms are acceptable with system
engineer concurrence. At penetration QC6, fifteen of the seventeen
connectors were found to have lower than desired resistance readings
(i.e, IXE10 ohms).
It was believed that the damage was due to flexing
of the hardline cable during installation. The licensee plans to
replace the penetration during the next refueling outage.
The licensee concluded, after discussions with GE, that the resistance
readings for QC6 hardline cables were acceptable based on the margin
that exists in the LPRM calculations.
In addition, to the above
procedure, EER 90-0349 evaluated insulation resistance readings that
were lower than acceptance values. The EER stated that the IXE10 ohm
acceptance value was extremely conservative and that LPRM insulation
resistance values found to be greater than IXE9 ohms should be
considered acceptable. GE concurred with the conclusions of this EER
during a recent telecon with the licensee.
The inspector reviewed the
EER and considered it acceptable.
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The inspector, along with the system engineer, reviewed warehouse
storage conditions for the LPRM cables.
Recently, a cable was withdrawn
from its storage location and could not be used due t: moisture
intrusion. The system engineer accompanying the inspector noted that he
had earlier observed some cables stored in plastic bags which were not
sealed. The cables observed during this inspection were found sealed in
plastic to prevent air and moisture intrusion.
Preventive Maintenance on Diesel Generator No. 2
On August 3, DG No. 2 was taken out of service to perform the 18 month
preventive maintenance inspection, 0-MST-DG0500R, and other minor
inspections of maintenance activities. As stated in the previous
monthly inspection report (50-325,324/93-30), the diesel's main and
thrust bearings were examined for symptoms of frictional heating similar
to that observed on DG No. 1.
No discoloration was observed. A
boroscopic examination of the diesel's cylinders did not reveal any
damage. The examination did reveal some polishing in the 4R and 6R
cylinders.
On August 3, the licensee discovered that the newly installed 2-MUD-V101
jacket water head tank drain valve was installed in the reverse
direction as indicated by the flow arrow on the valve body. This item
was documented by the licensee in ACR 93-260.
Previous maintenance on DG No. I had found the jacket water temperature
control valve installed in the reverse direction. A review of this
second event found that the direct replacement instructions had required
the installation of two welded couplings % line with the valve.
The
licensee discovered that the craft perso.:.wl had used an unapproved
alternate installation method to reduce the number of welds by
eliminating the two couplings. These discrepancies were discovered and
corrected immediately by the licensee prior to declaring the diesel
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On August 3, during an investigation of lube oil flange leakage on DG
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No. 2 valve 2-LO-RV11, the licensee discovered that the engine driven
lube oil pump relief valve had been installed in the vertical instead of
horizontal position. The above valve was removed and reinstalled in the
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correct position. The system engineer performed an analysis to
determine the effect oc diesel engine operability of the misoriented
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relief valve. The analysis determined that the valve did not affect the
operability of the diesel engine.
The inspector reviewed and agreed
with this analysis. The relief valve had been in the incorrect position
since the previous diesel generator outage in June, 1993.
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While performing post maintenance housekeeping duties in the vicinity of
the DG No. 2 starting air system, workers heard air escaping from the
system. An investigation by maintenance personnel revealed that a cover
plate gasket on the control air filter had blown out. Discussions with
the diesel maintenance supervisor revealed that this event has occurred
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several times since the recent installation of the control air filter
modification.
The inspector questioned the system engineer to determine if the correct
gasket was being used for the application. The system engineer was
unable to conclusively answer this question. The inspector then
reviewed the procurement process for the cover plate gasket. A parts
quality classification and commercial grade dedication evaluation report
was reviewed and the installed gasket was found to be correct for this
application. The licensee contacted the vendor who confirmed the
licensee's conclusions.
It was determined that the gasket had failed
because the cover plate had not been adequately torqued. An inspection
of this system also revealed that a gasket for check valve V-58 was
leaking.
This gasket was also replaced.
During an attempt to conduct the operability run, the diesel generator
would not start due to improper valve alignment of the control air
filters. The valves were realigned and the diesel started as required.
The inspector reviewed the clearance restoration instructions and found
that they were incorrect in that the restoration instructions had
required valves to be shut in both filter dryer trains. The inspector
verified that valve misalignment had occurred during system restoration
after the above gasket replacement.
The licensee reviewed the appropriate procedures used to perform the
diesel maintenance and clearance preparation tasks. The deficiencies
were identified and immediately corrected. Additionally, the licensee
convened special sessions of STAR refresher training to remind personnel
of the need to conduct activities that are important to safety in a
careful and accurate manner.
TS 6.8.1.a, requires that written procedures shall be established,
implemented and maintained covering activities such as maintenance and
clearances. The instructions for the installation of DG valves, 2-MUD-
V101, 2LO-RVll, and DG No. I jacket water temperature control valve, and
the DG No. 2 control air filter restoration instruction were inadequate.
The failure to have adequate valve installation and clearance
restoration instructions is a violation of TS 6.8.1.a.
This violation
will not be subject to enforcement action because it meets the criteria
specified in Section VII.B of the Enforcement Policy, NCV 93-33-02.
Nuclear Service Water System Leaks
The inspector, in Inspection Report 325,324/93-20, discussed a leak and
repairs on the Unit I nuclear service water system piping. The leak was
repaired and returned to service on July 30. After returning the system
to service, a new leak of approximately I dpm was identified on a six
inch welded flange approximately three feet after the vital header taps
off the main nuclear header. A temporary soft patch was placed over
this leak until permanent repairs could be accomplished.
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On August 13, an additional small leak, approximately 80 dpm, developed
in the 1 C conventional SW pump discharge line to the nuclear header
near the pump isolation valve. The licensee removed the Unit I nuclear
water system from service on August 26 and performed code repairs on
both of the above leaks. This work was completed and the system was
returned to service on August 31.
The inspector visually inspected each of the above leaks, the temporary
patch, and the repairs. A visual inspection was performed on the
repairs for the first leak which resulted in the replacement of a three
foot section of concrete lined carbon steel piping with copper nickel
piping. An inprocess inspection found that the defects had been removed
on the second leak and a code class weld repair had been performed. The
workmanship and quality of both efforts were examined and determined to
be satisfactory.
The inspector additionally performed a followup inspection on the
backfill over the piping repairs completed in July on the nuclear
service water system.
The efforts were satisfactorily completed without
problems.
Cracks in Core Support Shroud
The licensee previously identified cracks in the Unit I reactor vessel
core shroud in the heat affected zones of the H-3 and H-4 welds. This
was discussed in Inspection Report 325,324/93-30. The licensee took a
boat sample from each affected weld area to determine the initiating
cause. A Region II specialist was on site during the week of August 16
to review the UT data and the preliminary analysis of the boot sample.
The results of his inspection are contained in Inspection Report
325,324/93-34. The H-3 and H-4 weld boat samples were taken between
August 19 and 21. The boat samples were obtained by the electric
discharge machinery process and were 0.80 inches deep.
On August 24, GE informed the licensee that inspection of the H-3 boat
sample revealed that the crack passed all the way through the boat
sample. This finding invalidated the assumptions contained in the
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bounding analysis which the licensee had previously received because
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crack depth was found to be greater that 0.80 inches and exceeded the
0.40 inches obtained by UT examination.
On August 26, the licensee met with the NRC to discuss their recent
findings and revised plans to determine the crack depth. GE discussed
their analysis and the NRC questioned the validity of several
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assumptions used in the analysis. The NRC stated that a more
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substantive analysis would be required to justify plant restart and
operation. The licensee stated that they plan to use robotics to
perform further UT examinations.
The licensee has contracted with GE to build three devices similar to
the one used on the foreign BWR (KKM in Switzerland) described in GE
RICSIL 054. Two units will be used for data gathering and the third
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will be available as a spare. The licensee has contracted with KKM to
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obtain the service of a UT operator experienced in this procedure to
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perform the H-3 UT. The anticipated delivery for these machines is
September 15. The licensee anticipates that it will take approximately
ten days to setup, perform the UT examination, and evaluate the data.
The licensee plans to take an additional boat sample or samples as
needed to validate the UT results. They anticipate an extensive
analysis to support a justification for continued operation and have
developed a means of implementing a permanent repair. An overall outage
schedule delay of approximately four weeks is anticipated.
The inspector has observed and been involved in the above activities on
a daily basis and will continue to follow this issue and the licensee's
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actions until it is resolved, Inspector Followup Item:
IFI 325,324/
93-33-03.
Main Generator Seal Oil Leak
On August 17, an Air Leakage Test on the Unit 1 main generator was
performed using Administrative Instruction AI-117, Rev. O, Guidance for
Troubleshooting Safety Related Equipment. This test was part of a pre-
operational test of the main generator prior to unit startup. Test
instructions were written on a Troubleshooting Change Form (TCF)93-105
and approved by operations. The TCF was reviewed and discussed with
operations personnel, however a detailed pre-job briefing was not
performed.
In preparation for the test, valve and electrical lineups were completed
by operations personnel, temporary air valve, gauges were installed and
turbine lube oil and seal oil systems were started.
After informing the control room, maintenance personnel opened service
air valve 1-HC-b-03 to purge and pressurize the main generator. This
purging effort was to be maintained for approximately four hours.
During the purging effort the maintenance engineer noticed that the
sight glass for the hydrogen seal oil float trap was full. The engineer
became concerned because during previous testing, oil had backed up into
the hydrogen detraining section and had flooded the generator.
Because
of this concern, the maintenance engineer pressurized the generator to
operate the float trap. As air entered the generator the pressure began
to slowly increase.
Two maintenance personnel monitored sight glasses in low point drains
from the generator, exciter, and hydrogen detraining sections. The TCF
erroneously instructed maintenance to throttle close the float trap
bypass valve when the air pressure reached 10 psig.
The 10 psig value
was based on conversations with the vendor. At approximately 7 psig,
the engineer noticed that the sight glass was approximately half full
and steady. The maintenance crew did not take immediate action to
reduce pressure or close the float trap bypass valve because the sight
glass level was not decreasing. The pressurization of the generator was
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sufficient to force the oil into the air detraining section, out the
vent and onto the floor. This resulted in approximately 150 gallons of
oil spilling on the turbine building floors at elevations 55', 38' and
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20' and a small amount of oil seeping outside the turbine building at
ground elevation.
Subsequent investigation by the licensee revealed the TCF instructions
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required the float trap valve bypass (1-S0-H-05) to be manipulated by
the maintenance personnel to maintain oil level in the sight glass.
However, during this test, this valve was under clearance and the crew
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members were not authorized to manipulate the valve. Another
contributing factor to this event was the need to complete the test in
an expeditious manner due to the unavailability of travelling support
maintenance crew members to assist if problems were discovered as a
result of the test.
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The licensee is currently conducting a root cause analysis of the
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incident.
Investigations by the inspector revealed several deficiencies
in the conduct of this maintenance activity. These deficiencies
included inadequate communication between maintenance and operations
personnel, inaccurate procedural instructions, misinterpretation of
clearance procedure requirements, and inadequate scheduling and
coordination of work activities. The licensee is currently identifying
and implementing corrective actions to prevent a recurrence of this
event. The licensee documented this event in ACR 93-275. The above
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occurrence, though not safety-related, indicates a weakness in work
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planning, coordination and procedures. The inspector will review the
licensee's ACR and root cause analysis to determine the adequacy of
corrective actions for this item.
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Surveillance Observation (61726)
The inspectors observed surveillance testing required by Technical
Specifications. Through observation, interviews, and record review the
inspectors verified that: tests conformed to Technical Specification
requirements; administrative controls were followed; personnel were
qualified; instrumentation was calibrated; and data was accurate and
compl ete. The inspectors independently verified selected test results
and proper return to service of equipment.
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The inspectors witnessed / reviewed portions of the following test
activities:
2-MST-RWCU 22M
RWCU High Differential Flow Trip Unit Channel
Calibration
2-PT-24 1-2
Service Water Pump and Discharge Valve
Operability Test
2-MST-RHR 26M
Residual Heat Removal / Core Spray Low Reactor
Pressure Permissive Trip Unit Channel
Calibration
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The inspector noted that procedures were available and used during the
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above tests. Maintenance personnel also appeared to be knowledgeable on
all aspects of the observed tests.
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Violations and deviations 'were not identified.
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Operational Safety Verification (71707)
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The inspectors verified that Unit 1.and Unit 2 were operated in
compliance with Technical Specifications and other regulatory-
requirements by direct observations of. activities, facility-tours,
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discussions with personnel, reviewing of records and independent
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 jumper / bypass logs were reviewed to obtain information
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concerning operating trends and out of service safety systems to ensure
that there were no conflicts with Technical Specification Limiting
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Conditions for Operations.
Direct observations of control room panels
and instrumentation and recorded traces important to safety were
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conducted to verify operability and that operating parameters were
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within Technical Specification limits. The inspectors observed shift
turnovers to verify that system status continuity was maintained. The
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inspectors also verified the status of selected control room
Operability of a selected Engineered Safety Feature division was
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verified weekly by ensuring that:
each accessible valve in the flow
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path was in its correct position; each power supply and breaker was
closed for components that must activate upon initiation signal; the RHR
subsystem cross-tie valve for each unit was closed with the power
removed from the valve operator; there was not leakage of major
components; there was proper lubrication and cooling water available;
and conditions did not exist which could prevent fulfillment of the
system's functional requirements.
Instrumentation essential to system
actuation or performance was verified operable by observing on-scale
indication and proper instrument valve lineup, if accessible.
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
and escorted within the PA; persons within the PA displayed photo
identification badges; personnel in vital areas were authorized;
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effective compensatory measures were employed when required; and
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.
Alternate Safe Shutdown Drill
An Alternate Safe Shutdown (ASSD) drill was conducted on the morning of
August 19. The drill was observed by the licensee, individuals from the
Nuclear Assessment Department (NAD), and a regional and resident
inspector. The drill was conducted to evaluate the ability of operators
to safely shutdown the plant using 0-ASSD-02 Alternate Safe Shutdown
Procedure, Rev. 12. The drill scenario required operators to simulate
an evacuation of the control room due to a fire.
The inspector observed the operators performing the functions of shift
supervisor, reactor building operator, and remote shutdown panel
operator.
In addition, two drill evaluators were observed and
evaluated. The inspector noted that only one evaluator had been
assigned to evaluate two operators. At the beginning of the drill this
did not provide adequate coverage since both operators were performing
actions rapidly and simultaneously as dictated by the drill scenario.
The inspector and the evaluators experienced some difficulty following
drill evolutions due to infrequent briefings provided by the operators
and the inability to listen to sound-powered phone conversations between
operators positioned at various stations throughout the plant.
At times the inspector observed an operator perform steps in the
procedure without waiting for adequate feedback from evaluators. The
evaluators did not consistently provided feedback to the operators to
simulate plant response to the operators' actions.
For example, the
ASSD procedure required operators to cooldown the plant by opening
safety relief valves, but evaluators were observed giving incorrect
plant responses to changes in reactor water level and reactor pressure.
The inspector also observed that an evaluator was not present while an
operator completed a procedural step to secure shutdown cooling. The
inspector verified that the operator completed the step successfully.
The drill, while realistic, did not contain faults or equipment
malfunctions to create abnormal conditions requiring the shift
supervisor to demonstrate problem solving, decision making and exercise
command and control skills or the ability to reestablish communications.
Inclusion of these faults would have enabled evaluators to better assess
the crew's ability to safely shutdown the plant under changing
conditions. However; the inspector noted that the shift supervisor
demonstrated good command and control throughout the drill. The
licensee informed the inspector that the ASSD job performance measures,
which are use to evaluate an operator's ability to perform a significant
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operational or safety task, contain faults and malfunctions. The
resident inspector concluded that the drill was conducted adequately and
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that the operators demonstrated the ability to shutdown and cooldown the
plant.
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Hurricane Preparedness
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The inspector previously identified, in Inspection Report 325,324/93-27,
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a weakness in the licensee's review of Lessons Learned from Hurricane
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Andrew. The licensee re-addressed this issue by reviewing the major
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items, concerns, and structures in the Turkey Point report and
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determining their applicability to Brunswick. They then developed plans
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and compensatory measures to address these items. The inspector
reviewed the licensee's revised procedures and concluded that they
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addressed the potential hurricane effects on non-safety structures,
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equipment, and buildings important to the operation of the plant. The
licensee's initial efforts on this issue as reported in the previous
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monthly inspection report was not considered thorough.
However, after
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discussing the issue with the licensee in detail, their reassessment and
response was considered aggressive.
In addition, an INP0 assist visit
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which focused on hurricane preparedness was held the week of August
23rd, and included participation by members of the Turkey Point EP
staff. The licensee stated that the visit was very beneficial.
Several
supporting procedures are in the process of, or are scheduled to be
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revised based on the results of this visit.
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On August 26, during the INP0 assist visit, an emergency preparedness
exercise was conducted using a hurricane scenario. The inspector
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observed portions of this exercise and noted that the drill progressed
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smoothly with good communications and response actions by all team
members. The inspector also noted that some difficulties and confusion
existed over when to call in relief team members and suspend all outside
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activities. These deficiencies were also identified by the licensee and
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will be formally proceduralized in the future revisions of the
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procedure. The licensee concluded that the drill was a good test of the
revised procedures and plan to incorporate lessons from this drill and
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the observations of INPO team members into a planned revision of the
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hurricane preparedness procedures.
On August 30, 1993, the licensee had an opportunity to put into practice
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some of the lessons learned in hurricane preparedness when Hurricane
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Emily approached the general vicinity. The site was placed under a
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hurricane watch on August 29. The inspector reviewed the licensee's
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Emergency Response Plan and Procedures to insure that they were
preparing for the imminent approach of Hurricane Emily. At that time,
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the hurricane was approximately 350 miles from the site.
The licensee
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implemented their plan with Administrative Instruction AI-68, Brunswick
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Nuclear Plant Response to Severe Weather Warnings, Revision 9, and
Abnormal Operating Procedure A0P-13.0, Operation During Hurricane, Flood
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Conditions, Tornado, or Earthquake, Revision 11. The inspectors
observed all licensee preparations made for the storm and found them to
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be satisfactory. Outside equipment was tied down or removed if it had
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the potential to become a missile or overturn and damage other
equipment. Teams were established for Control Room, Plant, TSC, and OSC
manning if required. The inspector performed site-wide inspections and
attended the licensee's preparation and status meetings to ensure that
the site was being prepared for the storm. The inspector performed
operational tests of the NRC cellular telephone and HF radio system on
August 30. As a precautionary measure, Region II dispatched a four
wheel drive vehicle with three support personnel to the site at 11:00 AM
on August 30. Region II manned the Emergency Response Center at the
Atlanta Regional office at 4:00 PM and the site was manned for around-
the-clock coverage with two resident inspectors. On the morning of
August 31, all indications were that Hurricane Emily would pass to the
East of the site and approximately 100 miles out to sea on a NNW track.
At that time, a decision was made to send the Regional Response
personnel to the Surry Plant in Virginia.
The storm passed the area and
hit the North Carolina coast near Cape Hatteras late on August 31. The
hurricane watch was terminated at 11:00 am on August 31.
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U2 Non-conservative Settina of APRM Gain Ad.iustment Factors
In conjunction with the Brunswick power up-rate project, the
licensee conducted a sodium tracer injection test on July 2, to
determine the calibration constants for the main steam flow
elements. The meter differential for the main steam flow elements
had not been revised since the initial calibration, and the
current value was believed to be inaccurate due to wear on the
nozzle plate over the past 15 years. The sodium tracer test data
was to be used to determine the feedwater flow rate.
The new
feedwater flow rate was then to be used to determine new
calibration constants for the main steam flow elements. This
would ensure that feedwater flow indication and main steam flow
indications were in agreement.
The testing and analysis was conducted by GE. The Unit 2 testing
was conducted on July 2, with the unit operating at 100% indicated
power. The unit remained operating at 100% indicated power until
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July 14, when preliminary test results were released by GE. The
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preliminary results indicated a non-conservative inaccuracy in
feedwater flow of 1.094%. This inaccuracy corresponded to an
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increase in core thermal power of approximately 1.08%.
In
response to these results, the licensee initiated a reduction in
power from 2436 MWth to 2405 MWth, which corresponds to an actual
reactor power of less than 100% indicated. As a result of the
reduction in power, a new core thermal power reading of 2409 MWth
now corresponds to 100% power. An administrative limit of 2405
was chosen until the plant process computer could be changed to
incorporate the new information based on the test results.
Standing Instruction (SI)93-166 was established to ensure that
core thermal power would be limited to less than or equal to an
indicated 2405 MWth. The plant continued operation in this manner
until the appropriate changes to the process computer were made on
August 5.
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On August 5, while in the process of implementing the corrections
to the plant process computer, the licensee discovered that they
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had operated with non-conservative Average Power Range Monitor
(APRM) Gain Adjustment Factor (GAF) settings since the power
reduction 23 days earlier on July 14.
During the implementation
of the change in data points for the process computer, it was
discovered that the APRM GAFs had not been adjusted to correspond
with the new thermal power limit of 2409 MWth as the equivalent to
100% reactor power.
The GAF values in use were still based on the
old thermal power limit of 2436 MWth which was no longer valid.
During the time in question, while the unit operated with the APRM
GAF settings, the error went unnoticed by plant operators,
corporate maintenance engineers, plant nuclear engineers. During
this period, operators performed the required daily periodic test,
PT 1.11, Core Performance Parameter Check. The purpose of this
test is to obtain basic core parameters required by Technical
Specifications (TS) and to calibrate the APRM channels to read
greater than or equal to actual core thermal power. This test
required the operators to obtain a P1 edit of the process computer
program. The P1 edit provides the operator with a current listing
of various monitored parameters and safety limit setpoints. The
display also provides the operators with proper settings for the
APRM GAFs. The plant process computer generates these APRM GAF
settings based on a calculation using the plant's license thermal
power limit (reference value) of 2436 MWth. The test required the
operators to only verify that at least two APRM GAF settings are
less than or equal to 1.00.
The event occurred because plant personnel failed to recognize
that other parameters, such as APRM GAF setpoints, are effected by
changes to the core thermal power limit.
It was also noted that
plant procedures do not address or provide a methodology to
prevent this problem. The licensee corrected this item and issued
Standing Instruction SI 93-172 which limits thermal power to 99.5%
until the feedwater flow instrumentation can be calibrated. The
licensee also documented this issue in Adverse Condition Report
(ACR) B-93-261. The resolution of the ACR will identify the root
cause of the problem and provide corrective action to prevent
reoccurrence.
The inspector will follow up on the ACR to ensure
that the issue is properly addressed.
The item is identified as a weakness in attention to detail.
The licensee has identified that the failure to adjust the APRM
GAFs did not adversely affect the APRM setpoints input to the RPS.
The licensee has determined that the APRM setpoints were still
within TS allowable limits. The inspector independently verified
that the APRM trip setpoints were within TS tolerances.
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Access Control
During review of the licensee's security event logs, adverse condition
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reports, and discussion with licensee security personnel, several
concerns were discovered in the area of personnel access control. These
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concerns are discussed below.
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On August 2,1993, a member of the security force returned from medical
leave which started on June 17, 1993, a total of 47 days. Although the
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officer's badge was placed in " lost" status, blocking it from being
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used, a security supervisor erroneously reinstated the badge into the
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security computer. This was done despite the fact that the officer had
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not completed required chemical testing. The officer entered the
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protected area at 7:55 am until another security force member discovered
the error and the officer was removed from the protected area at
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8:34 am.
CP&L Screening Practices and Procedures 107, Screening For Level 1
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Employment, Reinstatement, dated April 22, 1993, requires completion of
chemical testing and review of the individual's activities by a
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supervisor for absences greater then 30 days. Contrary to the above,
the individual did not complete chemical testing until approximately
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11:30 am, three hours after entry into the protected area; and a
required summary of activities form was not completed until the
following day.
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This is somewhat mitigated in that this individual's spouse is also a
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security officer, and the individual met with security management
personnel approximately three times during the period of the abse ?
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The individual remained in the random drug testing pool, but wac not
selected for random testing.
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10 CFR 73.71(c)(1) requires these types of events to be logged within 24
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hours of their occurrence. The licensee did not log this event until
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after NRC inspectors discussed the event with members of the security
staff.
In a previous event, badge P2284 was issued 63 days after pre-access
drug screening which is required within 60 days. This was due to
personnel error which was discovered during a Quality Assurance Audit
and was properly logged.
4
This failure to properly control access to the protected area based on
requirements of 10 CFR Part 26, The Fitness For Duty Rule, failure to
adhere to the licensee's procedure, and failure to log the event in a
timely fashion is a violation of regulatory requirements. This is a
Violation: Failure to Control Plant Access (325,324/93-33-01).
Two additional events were identified which did not place the licensee
in violation but allowed the potential for violation and required
corrective action.
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On July 7,1993, a security force member failed Ceneral Employee
Training and had his badge placed in lost status at 1136 hours0.0131 days <br />0.316 hours <br />0.00188 weeks <br />4.32248e-4 months <br />. Without
the knowledge of licensee security personnel, the security contract
force chief utilized this officer at the vehicle access gate, exterior
to the protected area. This post is manned by two security force
members, one armed, one unarmed. This officer acted as the armed
officer,. but was not considered a member of the response team. On
July 12, 1993, licensee security personnel became aware of the situation
and the officer was removed from the post. During his time on duty, the
officer's security training had not expired, no violation took place.
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The licensee reviewed computer records which showed the officer's badge
in lost status. On July 12, 1993, the officer passed the GET training
and the badge was reactivated. Licensee security staff and contractor
management personnel agreed that poor judgement was exhibited by the
contractor security chief, who had a disciplinary letter placed in his
file. Security contractor personnel were advised to contact licensee
personnel for guidance in non-routine situations.
Licensee Adverse Condition Report B-93-217 dated July 9, 1993, discusses
a situation where an individual's badge was placed in lost status due to
expiration of GET training. After completing training, the individual
attempted to enter the protected area but his badge was still
deactivated. The access control officer electronically unlocked the
turnstile and allowed access into the protected area. The officer
immediately noted the error due to the advisory on the computer screen
at the entry post and removed the individual from the protected area.
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Although no violation took place, the officer demonstrated poor
judgement.
The licensee has implemented several corrective measures to address the
types of problems discussed above.
In order to identify individuals
with the potential for being away from a continued observation program
for more then 30 days, or individuals who require chemical testing the
licensee has implemented a program to suspend access on badges that have
not been used within 30 days. A "do not issue" tag is placed on the
badge and the badge is deactivated in the security computer.
In order
to have the badge reactivated the employee must have a form completed
which shows that an ascertaining of activities has been accomplished by
the supervisor. Additionally, the employee must complete chemical
testing if required.
One violation and no deviations were identified.
5.
Three-Year Plan
The inspector reviewed the licensee's monthly management report for
July,1993. The significant accomplishments for the month of July
included implementation of the procedure for preparation, review,
approval, and performance of post modification tests; development of a
formal training program for procedure control; completion of final
evaluations for additional site facilities; and completion and submittal
of a proposed site staffing plan.
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Overall,17 action steps and project phases were completed during July.
Three initiatives were completed early and four late activities were
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also completed. Completion of five initiative actions and two project
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phases were delayed. _The design and installation of the non-segregated
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bus modification was delayed due to equipment failures during laboratory
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testing. The initiative addressing an interim modification process was
delayed because it was expanded to include all minor modifications. The
root cause analysis overview training was delayed to accommodate the
addition of new supervisors that will result from recent organizational
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changes. Review of the overall status showed that 27 initiatives and 65
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projects are currently in progress.
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The licensee, in a letter to the Regional Administrator dated August 27,
1993, noted that a revision of the three year. plan was underway and
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noted that the submittal planned for September,1993, would be delayed
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until December, 1993.
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In the inspector's July inspection report (325,324/93-30),.it was noted
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that the plans for the Work Control Center and Hands on Training Center
had been approved and were in the bid process. The inspector was
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informed in early August that corporate management had placed these
projects on hold and was having an outside consultant conduct an
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additional review of these plans. :The inspector will continue to follow'
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these and other three year projects as they progress.
6.
Unit 1 Outage / Restart
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(Closed) D-1 STSI Items
The licensee has committed to have all the Unit 1 STSI items, with the
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exception of the 26 STSI items associated with.the service water pumps
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and related hardware, completed. prior to restart. These items will be
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completed during the scheduled pump replacement. This project will be
completed by November 1994. On. June 30, 1993, 1038 STSI items were
required to.be completed prior to restart. The licensee had completed
787 of these at the end of the inspection period and plans to complete
the remaining 251 items by September 10.
Based on the licensee's
efforts and the remaining items being scheduled, this item is closed for
Unit 1.
(0 pen) Reduction in Unit 1 Corrective Maintenance Backlog
The following are the corrective maintenance backlog categories, goal,
and status as of August 31 and progress in the past month:
Indication
Goal
Status 8/31
Chanae In
Past Month
Focus systems
<650
480
-31
(on line WR/J0s)
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Indication
Goal
Status 8/31
Change In
Past Month
(cont'd)
Focus Systems
<80
216
-141
(Priority 1-4
WR/J0s)
Other Systems
<80
121
-70
(Priority 1-4
WR/J0s)
Control Room
<5
37
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Operator Work
<25
65
-34
Arounds
Permanent
0
0
0
Caution Tags
STSI Items
<26
251
-277
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Temporary Mods
<20
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A review of the above items indicates that good progress has been made
over the past month. The licensee currently has 1404 WR/J0s scheduled
to be completed prior to Unit I restart. The WR/J0s work off rate
averaged approximately 46 items per day for the past month. During the
same time period, approximately 7 items were added per day. At the
current work off rate, it is anticipated that these items should be
completed about October 1, 1993. This appears to be an achievable goal
since the curre:)t schedule shows all work complete on September 28. The
inspector will continue to track this item until restart.
License _e Scif-Assessment for Unit 1 Restart
The licensee Nuclear Assessment Department planned to conduct a two
phase assessment of Unit I readiness for restart.
Phase I of this
assessment was conducted from August 23 through August 27. The Phase II
assessment will focus on 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> control room observations and will be
conducted during startup and power ascension up to 100% reactor power.
The Phase I assessment team consisted of 13 CP&L personnel, 2
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consultants,1 INPO individual and an employee of another utility.
The
assessment focused on the areas of operations, maintenance, E&RC, and
Engineering / Technical Support. Special emphasis was placed on
determining the adequacy of management involvement, coaching and
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communications, lessons learned from the startup of Unit 2, backlog
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reduction, corrective action effectiveness, the attitude and morale of
station personnel, the use and effectiveness of the integrated schedule,
plant material condition and housekeeping, and startup readiness.
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The inspector held informal discussions with members of the assessment
team and attended two team meetings and the assessment debrief to plant
management on August 27, 1993. The assessment identified that plant
equipment and personnel were ready for restart after the following items
were completed:
integrated startup plan submitted to the NRC on November 30, 1992
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e commitments to NRC contained in CP&L letter to NRC dated July 23,
1992 are met (CIP)
e PN31 reviews for Unit 1
Unit I restart targets identified in the June 9, 1993 meeting with
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the NRC are met for WR/J0s on focus systems, corrective
maintenance, temporary modifications, control room annunciators,
permanent caution tags, and STSIs
elements for Unit I startup and power ascension needed for rod
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pull are met
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The team did identify a potential issue involving a lack of CP&L
presence and control over refueling floor activities. They also noted
that even though significant progress had been made, additional
improvement was still needed in the area of work control and scheduling.
They additionally noted that added emphasis by NED was needed in design
ownership and configuration management. Overall, the team stated that
significant plant work improvement had been made in process, people, and
equipment readiness since Unit 2 restart.
The inspector reviewed the
assessment and, based on plant observations and evaluations, has reached
a similar conclusion. The inspector will continue to follow, review,
and evaluate Phase II of the NAD assessment during Unit I restart.
(Closed) NRC Bulletin 93-02, Debris Plugging of Emergency Core Cooling
,
Suction Strainers. This bulletin, issued on May 11, 1993, identified a
previously unrecognized potential contributor to a loss of net positive
suction head for Emergency Core Cooling System (ECCS) following a Loss-
of Coolant Accident (LOCA). The bulletin requested that licensees
identify any fibrous filter material not designed to withstand a LOCA
installed inside primary containment, take immediate compensatory
measures required to ensure functional capability of the ECCS, and take
prompt action to remove any such material.
Licensees were requested to
respond in writing within thirty days stating whether these actions had
been or would be completed. The licensee's response to NRC Bulletin 93-
02 was addressed in a letter to NRR dated June 10, 1993.
In this
letter, the licensee stated that they had completed the requested
actions, that fibrous filter material not designed to withstand the
effects of a LOCA are not installed or stored inside of primary
containment during power operation, and that a primary containment
walkdown prior to closure following major outages is performed to ensure
that non-designed equipment / materials are removed or stored in a safe
manner. This licensee response has been reviewed by NRR and was
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acknowledged in an August 6, 1993, letter. The NRR letter states that,
based on a review of the submitted material, the licensee's actions are
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considered complete.
Additionally, the inspector recently witnessed the licensee's ECCS
suction strainer inspection in the Unit I torus. Divers did not find
any indications of debris plugging or strainer degradation. The
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inspector also reviewed Administrative Instruction AI-127, Drywell
Inspection and Closecut, Revision 1, and verified that it includes steps
requiring the removal of temporary filters prior to drywell closure.
The inspectors routinely perform a pre-closure drywell and torus
walkdown following each outage to verify all extraneous, non-qualified
material (i.e. fibrous filter material) used for the outage has been
removed prior to unit start up.
M ed on a review of the licensee
response, the recent strainer ingection results, and the above
mentioned procedure, this issue is considered losed.
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(Closed) Hardened Wet Well Vent - Unit 1
The design for the Hardened Wetwell Vent system to be installed at the
Brunswick site in response to NRC Generic Letter 89-16 was previously
discussed in NRC Inspection Report 325,324/92-37. The design was
installed and tested on Unit 2 prior to the unit's restart in April of
this year. The inspection related activities associated with Unit 2 are
discussed in NRC Inspection Report 325,324/93-10.
The installation of the Unit 1 Hardened Wetwell Vent system,
including all piping components and rupture disks, was completed
on July 20. The tie to the non-interruptable air line was
completed on July 23 with installation of the vent line being
completed in several stages. The piping components for the system
were assembled in sections, and each section was hydrostatically
tested for leakage prior to being installed in the system.
Following final assembly of the various sections of vent line, the
entire vent line was tested with low pressure air to verify the
mechanical joint tightness and the pressure integrity of the final
installed vent line. This test was completed on July 23.
The inspector reviewed the design package and the as-built
drawings and followed the installation activities as they were
completed.
Following the installation of the system, the
inspector reviewed the system design and conducted a walkdown of
the installed vent line system with the modification engineer
verifying that the installed system was built in accordance with
requirements specified in the design package. During the
walkdown, the engineer pointed out some of the differences between
the system installed on Unit I and that which was previously
installed on Unit 2.
These changes in the installed piping were
minor in nature and primarily consisted of the addition of a valve
in the nitrogen supply line to the two Containment Atmospheric
Control (CAC) valves that are part of the system. The addition of
this valve allowed for the pressure and leakage testing of this
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line to be completed in sections, rather than one entire run. The
benefits of such an addition were based on the experience gained
in testing the installed design on Unit 2.
As part of the design review effort, the inspector reviewed the
data from tests that were performed on the ventline system. This
included pre-installation and post-installation piping and system
tests. No discrepancies or deficiencies were identified. The
licensee has not completed the following tests: AT-1A, CAC V216
and CAC V7 Valve Operation and Logic Test; AT-10, Hardened Wetwell
Vent Radiation Monitor Operational Test; AT-3, Local Leak Rate
Test 1-CAC-V216; and AT-40, Nitrogen System Hardened Wetwell Vent
Valve Operational Test. The inspector will follow and review the
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results of these tests. The inspector also reviewed the
procedural changes associated with this modification. For Unit 1,
there were 32 document changes associated with the installation,
operation and testing. The inspector reviewed this list of
document changes and noted that of the 32 changes, only 9 were
required to be completed prior to declaring the system operable.
The licensee had completed and approved eight of the nine required
changes necessary for system operability. A final change to
Operating Procedure OP 46, Instrument and Service Air System has
been written and reviewed, but has not been approved. The
inspector, as part of the routine inspection plan, will follow the
licensee's efforts in the completion of these activities.
The inspector verified that the plant modification / design
information for the Hardened Wetwell Vent has been incorporated
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into the plant simulator and operation of the system is currently
included in the training program.
Based on the above, this item
is closed.
Violations and deviations were not identified.
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7.
Onsite Review Committee (40500)
The inspectors attended selected Plant Nuclear Safety Committee meetings
conducted during the period. The inspectors verified that the meetings
were conducted in accordance with Technical Specification requirements
regarding quorum membership, review process, frequency and personnel
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qualifications. Meeting minutes were reviewed to confirm that decisions
and recommendations were reflected in the minutes and followup of
corrective actions were completed.
There were no concerns identified relative to the PNSC meetings
attended. The resolution of safety issues presented during these
meetings was considered to be acceptable.
8.
Engineered Safety Feature System Walkdown (71710)
The inspector conducted a detailed walkdown of Unit 2 Loop A core spray
system. The core spray system protects the reactor core by directly
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spraying cooling water on top of the fuel assemblies from sparger rings
located just above the reactor core. This action removes decay and
residual heat from the core and thus maintains cladding temperatures and
oxidation within acceptable limits.
The inspector did not observe any significant material condition
deficiencies. The valve lineup procedure, when compared with the as-
found configuration and applicable drawings, did not reveal any
discrepancies. No system caintenance discrepancies were noted.
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Observed leaks were properly captured and routed to drains. All
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significant components were properly labelled and identifiable. All
control board and local instrumentation were indicating properly. No
discrepancies were observed with the electrical lineup of the system.
No discrepancies were identified with the support systems needed to
ensure operability (i.e., electrical, ventilation, etc.).
Violations and deviations were not identified.
9.
Action on Previous Inspection Findings (92701) (92702)
(Closed) IFI 325/93-10-07, Followup on Potential Disc and Stem
Separation on Valves 1-Ell-F017 A and B.
In a 1989 LER, the licensee
had identified the occurrence of a disc to stem separation on the RHR
outboard low pressure coolant injection valve 2-Ell-F017A. This had
occurred due to inadequate engagement of the disc to stem locking pin.
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This Unit 2 valve was repaired in 1989.
In 1992, the licensee
identified a noise emanating from the Unit 1,1-E11-F017B valve that
indicated disc to stem separation. The licensee opened and inspected
this valve and found that valve disc to stem separation had also
occurred. This was due to an inadequate tack weld on the locking pin,
caused by the lack of adequate material being applied close enough to
the locking pin to prevent it from backing out due to vibration.
Based
on the above, the inspector expressed concern about the adequacy of the
)
weld on 1-Ell-F017A and 2-Ell-F017 A and B since the same welding
procedure was used to prevent the locking pin from backing out and
causing disc to stem separations. The licensee interviewed the welders
who performed these tasks and on each of the above valves. The welders
stated that they had " puddled" the weld material as close to the locking
pin as physically possible and that they clearly understood the purpose
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of the tack weld.
The licensee has determined that a major contribution to this event was
that this valve was not designed for but was being used to throttle RHR
flow to maintain acceptable cooldown rates. The vibration created by
this throttling had caused the locking pin to loosen and back out. The
licensee has replaced the RHR 03 and RHR 24 valves with globe valves in
both RHR loops for Unit I and plans to perform the same modification on
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Unit 2 during the next outage. After these modifications, the RHR 03
and RHR 24 valves will be used to throttle flow and the RHR 17 valve
will be maintained in its normal open position. Under this condition,
the vibration would not be present and the above failure potential would
be considerably reduced. The pin location in the valve does not allow
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visibility under X-ray conditions.
Since disassembly of this valve
would require a significant amount of work and personnel radiation
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exposure, the licensee has decided not to open the valve for visual
inspection. The inspector accepted the licensee's evaluation and
conclusions for this item. Based on the above, this item is closed.
(Closed) IFI 325,324/90-07-01, ECCS Analog Trip Unit Power Source
Upgrade.
PM 82-030 and 82-031 were implemented in 1985 and 1983,
respectively, as a means of preventing spurious ECCS actuations. To
further increase system reliability, two additional modifications, PM
85-020 and 85-021, were planned. These modifications were proposed due
to the remote possibility that problems could re-occur with the battery
out of service and the battery charger re-energizing automatically as
part of a diesel start and load.
In addition, the licensee conducted an
analysis to show that the probability of this condition was extremely
remote and that previously installed modifications and procedures were
in place to prevent spurious ECCS actuations. After an examination of
the problem by NED, the project has been canceled based on the low
probability of the initiating event and the low marginal contribution to
plant safety. The inspector agreed with this conclusion. This item is
considered closed.
(Closed) Violation 325,324/92-35-02, Inadequate Procedures With Regard
to Clearance Process. This violaticn involved the failure of a
clearance to communicate the loss of reactor water level instrumentation
to the control operators. The event occurred when a clearance was
implemented to permit the installation of the digital feedwater
modification. The reactor water level control system and the level
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strip chart recorder were deenergized by this clearance. This recorder
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provided the input to the high flow level annunciator on the RTGB. This
deleted the only alarm available to the operators.
The clearance did
not provide for any temporary alarm and did not contain any steps to
inform the operators that no alarm was available. Since the test
function of the annunciator was still operable and no tag was on the
annunciator window, all operators were not aware that this function had
been lost. This was a contributing factor to an event that involved
excessive drain down of the reactor vessel water level. The licensee
corrective actions were to install a temporary alarm, revise the
applicable procedure OP-17, Residual Heat Removal System Operating
Procedure, Revision 47, to require a second operator monitor RPV level
changes, and issue a standing instruction to require that two operators
monitor critical activities such as lowering reactor water level.
In
addition, the licensee has proposed a plant betterment project that will
provide for ERFIS alarms of reactor water level and temperature at
shutdown conditions.
NED has been assigned responsibility to develop
this change. A review of the modification process by the licensee
determined that adequate guidance is included for plant conditions. A
memo from the engineering supervisor to all NED personnel reiterated the
need to follow the established guidelines. The licensee, as stated in
their response to this item, implemented an outage Risk Management
Procedure BSP-56, Revision 0, on March 5, 1993. The inspector, through
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documentation review and discussions with licensee personnel, verified
that all stated corrective actions for this item have been completed.
(Closed) URI 325,324/93-27-02, Inadequate Surveillance Procedure and
Post Modification Testing. This item is discussed in detail in Report
No. 50-325,324/93-30 and was identified as a non-cited violation
50-325,324/93-30-01.
(0 pen) VIO 325,324/93-27-03, Failure to follow procedures for
controlling excessive overtime.
This item was closed in error in
Inspection Report 50-325,324/93-30, and is reopened.
10.
Review of Licensee Event Reports (92700)
(Closed) LER 1-92-26, RPS Actuation on Low Reactor Water Level. On
October 2,1992, Unit I was in cold shutdown for a maintenance outage
with the RWCU out of service and the RHR system Loop B in shutdown
cooling. Reactor water level was being controlled by allowing the
control rod drive system cooling water flow to increase level to
approximately 240 inches above the core and then reducing reactor level
to 200 inches by rejecting level to the radwaste system. The normal
reactor water level hi/lo annunciator was out of service due to
installation of the modification of digital feedwater control.
The reactor operator began lowering reactor water level. During the
course of the drain down, he began to read a trip report. The reactor
operator did not monitor reactor water level that had decreased to the
trip setpoints for tre reactor protection system. The RPS actuation
resulted in primary containment isolation system group isolations 2
(drywell floor and equipment drain valves), 6 (primary containment
atmospheric valves), and 8 (shutdown cooling). The loss of shutdown
cooling resulted in a minimal increase in reactor water temperature.
The licensee conducted a root cause analysis of the event and
implemented corrective action for the identified weaknesses. The direct
cause of the event was the inattention of the reactor operator during
the performance of a critical license activity.
A Site Incident Investigation Team (SIIT) investigation was initiated by
the licensee. Their investigation concluded that the root cause was a
lack of clear management standards governing conduct of control room
activities and the control and sequencing of outage projects. A number
of recommendations were proposed by this team.
Operations reviewed its policy of holding shift information briefings
during watch standing periods and to more clearly define what types of
information are appropriate for such briefings. As a result, a room
outside the control room proper has been designated for pre-job
briefings, reactive meetings, etc.
In addition, a memo has been
generated that better describes the content and conduct of shift
information briefings. The inspector reviewed the memo and found it
provided adequate guidance.
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Two violations were issued under NOV 92-35-02. The corrective action
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for these violations were reviewed. One of these violations is closed
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in this report in paragraph 9.
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The licensee initiated EWR-9089 to provide alarms for reactor water
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level and reactor temperature that can be adjusted to alarm depending on
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what the desired level and temperature would be during the outage. _The
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licensee discovered that its ERFIS system has this capability. This
betterment modification has been proposed to be in operation by December
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of 1993.
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The licensee has developed and approved BSP-56, BNP Outage Risk
Management, Revision 0.
This procedure was the product of the
licensee's effort to better manage and assess the risk of certain work
activities during outage conditions. The inspector reviewed the
procedure and found that its instructions were adequate. As stated
above, the lack of a hi/lo annunciator was a result of the modification
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on the digital feedwater control system. . A procedure was developed to
ensure that the system conditions are appropriate prior to the
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installation of the modification. The licensee has developed
Modification Administration Procedure, MAP-006, Modification Acceptance
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Test Preparation, Review, Approval, and Performance. This procedure
contains prerequisites that address plant and system initial conditions
prior to installing and testing a new plant modification. The
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operations procedure for plant modification review, Operations Review of
Plant Modifications, Direct Replacement Packages, Technical
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Specification Changes and Procedure Changes as a result of Technical
Specification Changes, Revision 15, currently has requirements included
that ensure that the design documents state what plant conditions are
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required for modification installation.
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A memorandum to all control room operators was issued that described
those parameters (i.e. reactor power, reactor water level...) that the
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reactor operators may not affect without giving prior notice to the unit
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SRO. The memorandum also reiterated that the unit SR0 must be in
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control of and direct all control room activities. The memorandum was
incorporated into 01-01, Operating Principals and Philosophy, Volume 7,
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Revision 049. The inspector verified that the instructions were
adequate and had been incorporated into the proce6ere.
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A control room activity study was conducted in January and February
1993, to identify work control and maintenance activities that distract
from operations oversight ability. The study provided reccmmendations
in work control, command and control, professional conduct, control room
equipment, control room noise distractions and other recommendations. A
major finding in the study identified the need to lessen the
administrative burden of the SCO. This was accomplished by relocating
those work activities to a work control center. On-going observation of
control room activities by resident and regional inspectors has shown
this to be an effective method of reducing the administrative burden of
the SCO.
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While attempting to recover from a loss of shutdown cooling, the 1-Ell-
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F017B LPCI Outboard Injection Valve, failed to reopen. ~A component
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failure analysis was performed by Technical Support to determine the
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reason for the failure of the valve. The failure analysis revealed that
actuator failure was caused by the disintegration of the nylon gear
inserts in the motor drive intermediate pinion and shaft assembly. Work
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requests were written to disassemble, clean, inspect, and repair this
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valve and other high speed SMB-5T actuators. A preventive maintenance
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request was submnted to have the nylon gear inserts replaced every four
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fuel cycles.
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(Closed) LER l-92-11 Primary Conta'inment Monitoring System Inoperable
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Due to Relay Failure. On April 6,1992, a partial-Group 6 isolation
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occurred that resalted in the inoperability of ali of the primary
containment atmosphere radiation monitors and the Division I primary
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containment hydrogen / oxygen analyzer.
Inoperability of the primary
containment atmospheric radiation monitors was a condition outside of
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that addressed in TS 3.4.3.1, Reactor Coolant Leakage / Leakage Detection
Systems. Consequently TS 3.0.3 was invoked requiring Unit I to be
placed in Hot Shutdown within six hours and cold shutdown within the
following thirty hours. The cause of the event was the failure of the
normally energized 1-CAC-3B relay coil due to aging. The 115V-AC relay
model number CR120A was manufactured by General Electric. The licensee
replaced the failed relay and conducted a comprehensive study using
Nuclear Plant Reliability Data System, Operating Experience reports,
EDBS, drawings, and maintenance history to determine failure causes and
useful life periods. As of this writing, 54 relays have been replaced
in Unit 2 (March, 1993) and 39 in Unit 1.
Four remaining relays are
scheduled for installation prior to the Unit I startup. A preventive
maintenance route has been written to replace other relays on a
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scheduled frequency. This LER is considered closed.
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(Closed) LER l-93-005, Standby Gas Treatment (SBGT) Design Has Resulted
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in Throttle Valve Logic Allowing Flow Beyond Technical Specification
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Limits. On February 14, 1993, testing of the Unit 1 SBGT using Special
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Procedure 1-SP-93-014, " Flow Throttling of SBGT Filter Trains," found
that unthrottled flow of a single train would exceed the TS rated flow
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limit of 3300 cfm. The as found flow for IA SBGT was 4050 cfm and
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IB SBGT was 3950 cfm. The licensee determined that with the excess
flow, the heater was inadequate to roduce the humidity to 70 percent.
ACR 93-014 was written to document this problem.
Analyses were performed to investigate the effects of the higher flow
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rates.
It was determined that the SBGT can be safely operated up to
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4200 cfm without violating its design basis functions. The analysis
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also determined that the minimum heater capacity to reduce humidity to
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70 percent was 16.7 kw under normal voltage conditions. This ensures
that the TS value of 15.2 kw would be achieved under degraded voltage
conditions. This is documented in EER 93-0327.
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The licensee had a vendor perform a test on Iodine-131 removal
efficiency determination of absorbent samples for SBGT 1A.
Results of
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analysis and testing confirmed that the system as installed will provide
the required absorber efficier.cy at the higher flow rate. This analysis
was documented in a March 6, 1993, NUCON Report No. 13CP154/21.
Calculation BNP-E-8.031, Revision 0, determined that SBGT heater output
under degraded conditions is 17.8 kw. Calculation OSBGT-0006,
Revision 0, determined that a heat addition of 16.7 kw is required to
lower the relative humidity from 100 to 70 percent for 4200 cfm SBGT
fl ow.
The inspector reviewed the above documents and determined that they were
adequate. The licensee increased the heater output by changing the
wiring configuration from a delta to a wye wiring scheme. This was
accomplished by Plant Modifications92-105 and 92-106. The licensee has
determined that the as found condition would meet the unit design
requirements.
In addition, the inlet valves were adjusted to provide
throttling. This was accomplished by stops and the adjustment of limit
switches.
The inspector's review of the listed documents verifies that the
licensee completed the listed corrective actions and this item is
closed.
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11.
Employee Concerns Program
The inspector reviewed the licensee's employee concern Quality Check
program which was created to provide employees an alternate path from
their supervisor and normal line management to express safety concerns
or allegations. As part of this inspection, the inspector reviewed the
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program implementing procedure and discussed the program / process with
the site Quality Check Representative.
Survey reports of Quality Check
activities were also reviewed.
See attachment for questions addressed
during this inspection.
The licensee had established several methods for submission of employee
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concerns which included employee interviews, telephone, or by submission
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Quality Check
of Quality Check Report (QCR) forms in one of several,litidentiality of
Station lockboxes. The inspector was informed that co
the submitter was maintained. The Manager - Quality Check was
responsible for reviewing the QCRs and identifying nuclear safety issues
or other matters requiring management attention.
Employee concerns were
classified in one of three categories
Nuclear Safety issues or
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lassification of a " Case" which
technical / quality issues received
required an investigation and s a fe of action. Other concerns, such
as personnel issues, resulted i
clw sfication of Management
Information Items (MIIs) or Not ~
.,f Information. Only Cases and MIIs
required a formal response from line management. After review by the
Manager - Quality Check, the concern was then transferred to Quality
Check forms and routed to assigned evaluators / investigators.
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12.
Exit Interview (30703)
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The inspection scope and findings were summarized on September 3, 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 Paraaraoh
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93-33-01
Violation: Failure to Control Plant Access,
paragraph 4.
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93-33-02
NCV: Inadequate maintenance procedures,
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paragraph 2.
93-33-03
IFI:
Followup on core shroud activities,
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paragraph 2.
13.
Acronyms and Initialisms
ACR
Adverse Condition Report
Average Power Range Monitor
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Alternate Safe Shutdown Drill
BNP
Brunswick Nuclear Project
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Boiling Water Reactor
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Containment Atmospheric Control
Carolina Power & Light Company
Diesel Generator
Drips Per Minute
E&RC
Environmental & Radiation Control
EDBS
Engineering Data Base System
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ERFIS
Emergency Response Facility Information System
Engineering Work Request
GAF
Gain Adjustment Factor
General Electric Company
General Employee Training
HF
High Frequency
Health Physics
INP0
Institute of Nuclear Power Operations
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LER
Licensee Event Report
Loss of Coolant Accident
Low Pressure Coolant Injection
Local Power Range Monitor
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NAD
Nuclear Assessment Department
NED
Nuclear Engineering Department
Notice of Violation-
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NRC
Nuclear Regulatory Commission
Nuclear Reactor Regulation
Operations Support Center
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Protected Area
Plant Modification
PNSC
Plant Nuclear Safety Committee
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Pounds Per Square Inch Gauge
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Periodic Test
Quality Control
Rapid Information Communication Service Info. Letter
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Reactor Turbine Gauge Board
Standby Gas Treatment
SCO
Senior Control Operator
Standing Instruction
SIIT
Site Incident Investigation Team
SR0
Senior Reactor Operator
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STSI
Short Term Structural Integrity
Troubleshooting Change Form
TS
Technical Specification
Ultrasonic Testing
WR/JO
Work Request / Job Order
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Attachment 1
EMPLOYEE CONCERNS PROGRAMS
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PLANT NAME: Brunswick
LICENSEE: CP&L
DOCKET f: 50-325.50-324
NOTE: Please indicate yes or no as applicable and add comments in the space
provided.
A.
PROGRAM:
1.
Does the licensee have an employee concerns program? Yes
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2.
Has NRC inspected the program? No. Originally scheduled for
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Sept. 7 but deferred. Manager of Quality Check informally
discusses current issues with the Senior Resident Inspector on a
monthly basis.
B.
SCOPE: (Indicate all that apply.)
1.
Is it for:
a. Technical? Yes
b. Administrative? Yes
c. Personnel issues? Yes
2.
Does it cover safety as well as non-safety issues? Yes
3.
Is it designed for:
a. Nuclear safety? Yes
b. Personal safety? Yes
c. Personnel issues - including union grievances? Yes
4.
Does the program apply to all licensee employees? Yes
5.
Contractors? Yes
6.
Does the licensee require its contractors and their subs to have a
similar program? No
7.
Does the licensee conduct an exit interview upon terminating
employees asking if they have any safety concerns? Yes.
Part of
BSP-37, Employee Checkout Instructions.
C.
INDEPENDENCE:
1.
What is the title of the person in charge? Manager, Quality Check
2.
To whom do they report? Manager, Nuclear Assessment Department
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3.
Are they independent of line management? Yes
4.
Does the ECP use third party consultants? Uses outside
departments within CP&L corporate and currently has a program
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assessment being performed by outside consultant however it does
not normally use outside consultants as part of the program
5.
How is a concern about a manager or vice president followed up? A
review of the concern is conducted by the next level of
management. Concerns directed against the Manager, Nuclear
Assessment Department are immediately forwarded to Senior _Vice
President, Nuclear Generation Group.
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D.
RESOURCES:
1.
What is the size of the staff devoted to this program? Four. One
manager and three site representatives.
2.
What are ECP staff qualifications (technical training,
interviewing training, investigator training, other)?
Interviewing training including OJT. Experienced QA/QC personnel
in this position.
E. REFERRALS:
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1.
Who has followup on concerns (ECP staff, line management, other)?
Concern is identified, reviewed and classified by ECP staff
members and then forwarded to line management personnel for
investigation and resolution.
F. CONFIDENTIALITY:
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1.
Are the reports confidential? Yes
2.
To whom is the identity of the alleger made known (senior
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management, ECP staff, line canagement, other)? Senior management
and ECP staff
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3.
Can employees:
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a. be anonymous? Yes
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b. report by phone? Yes
G. FEEDBACK:
1.
Is feedback given to the alleger upon completion of the followup?
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Yes. Verbal communication of results/ resolution.
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2.
Does program reward good ideas? Yes. Good ideas are rewarded
with a letter of appreciation from the President or Chief
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Operating Officer.
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3.
Who, or at what level, makes the final decision of resolution?
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Manager, Quality Check
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4.
Are the resolutions of anonymous concerns disseminated? No, only
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to submitter.
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H. EFFECTIVENESS:
1.
How does the licensee measure the effectiveness of the program?
The licensee has no formal measure of program effectiveness.
2.
Are concerns:
a. Trended? Yes. Monthly status of number received and total
YTD; semi-annual report to senior management.
b. Used? Yes
3.
In the last three years how many concerns were raised? 107
Of the concerns raised, how many were closed? 106
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What percentage were substantiated? The licensee does not
substantiate concerns.
4.
How are followup techniques used to measure effectiveness (random
survey, interviews,other)? A random survey conducted by senior
management.
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5.
How frequently are internal audits of the ECP conducted and by
whom? Internal audits are very infrequent; only one in the very
beginning of the program.
I. ADNINISTRATION/ TRAINING:
1.
Is ECP prescribed by a procedure? Yes
2.
How are employees, as well as contractors, made aware of this
program (training, newsletter, bulletin board, other)? Initial-
GET training, bulletin boards, ECP boxes located throughout the
plant, posters, and brochures.
ADDITIONAL COMMENTS:
(Including characteristics which make the program
especially effective, if any.)
The inspector reviewed the licensee's program procedures, the CP&L Nuclear
Projects Quality Check Program and BSP-37 Brunswick Site Procedure Employee
Checkout Instructions, and has verified that the licensee meets the intent of
the program. Currently, BSP-37 is undergoing revision to clarify and formally
proceduralize parts of the program as it is currently implemented.
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