ML20217B312
| ML20217B312 | |
| Person / Time | |
|---|---|
| Site: | Brunswick  |
| Issue date: | 02/11/1991 |
| From: | Christensen H, Prevatte R NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II) |
| To: | |
| Shared Package | |
| ML20217B269 | List: |
| References | |
| 50-324-91-01, 50-324-91-1, 50-325-91-01, 50-325-91-1, NUDOCS 9103120056 | |
| Download: ML20217B312 (21) | |
See also: IR 05000324/1991001
Text
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s Pto UNITED STATES
g ug'o, NUCLEAR REGULATORY COMMISSION
.I' ~* REGION H
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101 MARIETT A STREET.N.W.
ATLANT A, GEORGI A 30323
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Report No. 50-325/91-01 and 50-324/91-01
Licensee: Carolina Power and Light Company
P. O. Box 1551
Raleigh, NC 27602
Docket Nos. 50-325 and 50-324 License No. DPR-71 and DPR-62
Facility Name: Brunswick 1 and 2
Inspection Conducted: January 1 - 31, 1991
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Lead Inspector:
~R'.
/hB
L. Prevatte
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' Cate' Signed
Other Inspectors: W. Levis
D. J. Nelson
R. E. Carroll
Approved By: % 2/// [7/
'H. Christensen, Section Chief Date Signed
Reactor Projects Branrh 1
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, onsite review committee, onsite followup of events, onsite
response to events, in-office report review, action on previous inspection
findings, and meetings with local officials.
Results:
In the areas inspected, one apparent violation was identified for the failure
to follow procedures while calibrating a process computer point on the feedwater
control system. This resulted in work being accomplished with the unit at
100 percent power that should have been scheduled and accomrlished with the
unit in cold shutdown. This resulted in a plant trip a..a emergency core
cooling system accuation. This event demonstrated continuing weaknesses in the
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9103120056 910212
PDR ADOCK 0D000324
o PDR
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licensee's work control process. This _ event is similar to Violation
324/90-29-01 and 325,324/90-29-05, paragraph 4.a. In addition, a non-cited
violation -in the area of cold weather preparation was also identified,
paragraph 4.b.
A fuel bundle was dropped 127 inches while reloading the core. The licensee's
root cause investigation of this event was timely and effective, paragraph 7,
Unit 2 was operated at essentially 100 percent power until the Reactor trip on
Janua ry 25, 1991. After completion of the required restart items, the unit was
restarted on canuary 30, 1991. Unit I continued in a refueling outage. Core
reload was completed and the unit-is presently in the process of restoring
equipment to an operational status and preparing for the ILRT.
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REPORT DETAILS
'1. Persons Contacted
Licensee Employees
- K. Altman, Manager - Regulatory Compliance
F. Blackmon, Manager - Radwaste/ Fire Protection
- S. Callis, On-Site Licensing Engineer
T.,Cantebury, Manager - Unit 1. Mechanical Maintenance
- G. Cheatham, Manager - Environmental & Radiation Control
R. Creech, Manager - Unit 2 I&C Maintenance
- M. Foss, Supervisor, Regulatory Compliance
- J. Harness, General Manager - Brunswick Steam Electric Plant
W. Hatcher, Supervisor - Security
- R. Helme, Manager - Technical Support
J. Holder, Manager - Outage Management & Modifications (0M&M)
M. Jones, Acting Manager - Project Assessment
R. Kitchen, Manager - Unit 2 Mechanical Maintenance
B. Leonard, Manager - Training
J. Leviner,. Manager - Engineering Projects
- J. Moyer, Technical Assistant to Plant General Manager
- R. Oates, On-Site Licensing Engineer
B. Poteat, Administrative Assistant to Plant General Manager
R. Poulk, Manager - License Training
- C, Robertson, Shift Manager
J. Simon, Manager - Operations Unit 1
W. Simpson, Manager - Site Planning and Control
S. Smith, Manager - Unit 1 I&C Maintenance
- J.-Spencer, General Plant Manager - BSEP (Effective February 1, 1991)
- R. Starkey, Vice President - Brunswick Nuclear Project
R. Tart, Manager - Operations Unit 2
J. Titrington, Manager - Operations Staff
- R. Warden, Manager - Maintenance
- K. Williamson, Manager - Nuclear Engineering Department (Onsite)
B. Wilson, Manager - Nuclear Systems Engineering
Other licensee employees contacted included construction craftsmen,
engineers, technicians, operators, office personnel, and security force
members.
- Attended the exit interview
H. Christensen, Section Chief Division of Reactor Projects, was on site
January 14, 15 and 16, 1991, to tour the plant, meet with the resident
inspectors and plant management.
Acronyms and initialisms used in the report are listed in the last
paragraph.
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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, end 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 replacement 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.
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:
90-AQPT1 Overhaul of 1A Service Water Screen Wash Pump
91-AACX1 Refuel Bridge
91-AAZS2 Post Packing Adjustment Motor Current Checks for HPCI Valve
2-E41-F003
91-ABTT1 Unit 2 Recirculation Pump Discharge Valve B32-F031B Stem
Repair
Violations and deviations were not identified.
3. SurveillanceObservation(61726)
The inspectors observed surveillance testing required by Technical
Specifications. Through observation, interviews, and record review, the
1.nspectors verified that: tests conformed to Technical Specification
requirements; administrative controls were followed; personnel were
qualified; instrumentation was calibrated; and data was accurate and
complete. The inspectors independently verified selected test results and -
proper return to service of equipment.
The inspectors witnessed / reviewed portions of the following ' test
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activities:
l 2MST-AM127M Suppression Pool Temperature Monitor Functional Test.
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2MST-APRM22Q APRM B and LPRM Group B Channel Calibration Functional Test
PT-02.6.6 Primary Containment Airlock Interlock Operability Check
PT-80.1 Reactor Hydrostatic Test
Violations and deviations were not identified.
4. Operational Safety Verification (71707)
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, discussions with personnel,
reviewing of records and-independent verification of safety system status.
- The= inspectors verified that control room manning requirements of 10 CFR
50.54 and the technical specifications were met. Control operator, shif t
supervisor, clearance, STA, daily and standing instructions, and
-jumper / bypass logs were reviewed to obtain information concerning
operating trends and out of service safety systems to ensure that there
. were no conflicts with Technical Specifications Limiting Conditions for
Operations. Direct observations of control room panels and instrumenta-
tion and recorder traces important to safety were conducted to verify
operability and that operating parameters were within Technical Specifica-
tion ' limits. The inspectors observed shift turnovers to verify that
system status continuity was maintained. The inspectors verified the
status of selected control room annunciators.
Operability of a selected Engineered Safety Feature division was verified
weekly by insuring that: each accessible valve in the flow path was in
its correct position; each power supply and breaker was closed for
j components that must activate upon initiation signal; the RHR subsystem
- cross-tie valve for each unit was closed with the power removed from the
L valve operator; there was no leakage of major components; there was proper
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lubrication and cooling water available; and conditions did not exist
, which could- prevent fulfillment of the system's functional requirements.
l 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 health physics
policies / procedures were followed. This included observation of HP
practices and a review of area surveys, radiation work permits, postings,
- and instrument calibration.
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The inspectors verified by general observations -that: the security
. organization was properly manned and security personnel were capable of
l performing their assigned functions; persons and packages were checked
prior to entry into the protected area; vehicles were properly authorized,
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-searched and escorted within the PA; persons within the PA displayed photo
identification badges; personnel in vital areas were author ned; effective
1 compensatory measures were employed when required; and security's response
to threats or alarms was adequate.
The inspectors also observed plant housekeeping controls, verified
position of certain containment isolation valves, checked clearances, and
verified the operability of onsite and offsite emergency power sources,
a. Unit 2 Scram
Unit 2 scrammed from 100 percent power on January 25, 1991. The
scram was due to a turbine trip which resulted from high reactor
water level ~. Water level had increased due to the FWLCS responding
to a loss of feedwater flow signal due to maintenance in progress.
With the FWLCS in three element control, tne loss of a feed flow
input was seen as a loss of a feed flow resulting in an increased
demand signal from the FWLCS to the feedwater pumps. The increased
feedwater flow caused reactor water level to increase to the high
level -setpoint for the turbine trip. This high icvel condition also
trips the feedwater pump turbines.
Subsequent to the trip, RCIC auto initiated and injected to restore
water level. HPCI auto initiated but did not inject due to the short
duration of 'the low level condition. The HPCI injection valve was
manually opened by the C0 to aid in restoring level. All safety
systems operated correctly during the trip. Initially, some
questions existed concerning the failure of SBGT to auto start.and
the ' Secondary Containment Isolation Dampers and RWCU to isolate.
Licensee review of calibration records for the trip-devices for these
components and ERFIS data showed that sufficient trip devices did not
, actuate to cause these occurrences. These instruments were set to
actuate between 117.6 inches and 117.8 inches. The lowest level
recorded on any channel was 116.6 inches. The technical
specification value is greater than or equal to 112 inches.
The-inspector was present in the control room throughout the event
and noted that operator performance following the trip was proper and
in accordance with procedures. Although the time duration of event
initiation to reactor scram was short, approximately 17 seconds, the
inspector noted that the operators did not recognize the cause of the
feedwater transient and took no actions to mitigate it. Similar
conditions were also noted in unit trips on August 16, 1990 and
October 12, 1990, which were caused by FWLCS malfunctions.
The feedwater transient was caused by the lifting of lead C32-A-18 in
panel H12-P612 which removed one feedwater flow input to the FWLCS.
This was dor.e in accordance with Step 7.1 of OPIC-CPU 001, Calibration
of an Analog Process Computer Point, Revision 12, which had been
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approved by the Unit 2 SCO a few minutes earlier. The SCO gave
permission and signed the WR/J0' to authorize the performance of the
calibration of the computer point based primarily on the Calibration
Summary Sheet, Attachment 13A of the procedure, which stated NONE
under the Required Plant Conditions Section. The NOTE which is
included at the top of the sumary sheet, states that the " Summary
Sheet is provided as an aid to the shift foreman and shall not be
substituted for the existing prerequisi'.as and precautions stated in
the procedure." Step 3.3.1 of the prerequisites of the procedure
stated that the unit be in cold shutdown or refuel to perform the
test.
The licensee's maintenance procedures require that the maintenance
foreman review work packages generated by the maintenance planners
and have the work scheduled through SWFCG if he determines that the
work can be. performed with assigned manpower and existing plant
conditions. SWFCG reviews the submission of these requests, resolves
conflicts between the different work groups and establishes the
schedule for the performance of maintenance activities. During the
review for the work planned for the week of January 20, the involved
maintenance foreman submitted 5 preventive maintenance routes to
SWFCG to be performed. SWFCG specifically questioned the feasibility
of performing 3 of the tests with the unit at power. Upon review by
the foreman, he concluded that two of the tests could not be
performed but that the third, performance of OPIC-CPU 001, could be
accomplished with the unit running. He based his conclusion on
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reviewing the procedure's summary sheets. SWFCG did not review the
work package themselves nor cause an ACR to be generated when they
determined that 2 of the tests could not be performed at power.
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Two I&C technicians performed procedure OPIC-CPU 001. Neither noted
the -prerequisite specifying the required plant shutdown -conditions
even though one technician signed the step immediately preceding the
step which indicated that they had permission to begin the
calibration. In-fact, the prerequisite which stated the required
plant conditions was the only prerequisite in the procedure.
l The inspector reviewed the WR/JO which indicated this work needed to
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be performed. A due date of December 24, 1990 is shown with an
overdue date of May 5,1991. The frequency is stated as every 18
months. Plant operating mode was lef t blank. 0MMM-004, Preventive
Maintenance, Revision 3, Section 5.3, states that, when a preventive
maintenance route is initiated and a frequency of 18 months is
assigned, the route should be reviewed to determine if it is
refueling outage related. If so, a frequency of "R0" should be
assigned. In addition, Section 5.3.4.2.1 states that the planner may
enter the plant operation mode (1-5) or leave the field blank. Mode 5
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should be used for PM routes with -a "R0" or other outage related
frequency. The Unit I rcute, which performs this same procedure,
specifies "R0" for required frequency. These routes were developed
prior- to the implementation of OMMM-004. Subsequent to its
implementation in July,1988, only the Unit I route was updated to
reflect the latest requirements.
Two SR0s, the Unit 2 SCO and SF, also signed the WR/JO which finally
allowed this work to begin. They did not review the prerequisites of
the test but relied upon the summary sheet and the fact that the work
was scheduled by SWFCG.
There were many potential barriers which should have prevented this
event. Although the glaring weaknesses involve the 1&C technicians
and their foreman, other work groups demonstrated deficiencies. The
maintenance planning organization, maintenance procedure writers,
SWFCG, and finally the licensed operators on shif t all had the
opportunity to recognize the error in performing this calibration at
power.
As.a result of the Unit 2 scram on August 19, 1990 and the trip of an
RPS bus on Unit 1 on August 22, 1990, the licensee instituted several
measures to correct work control weaknesse>. These measures, which
were discussed in response to violations dated October 17, 1990 and
December 28, 1990, included the stoppage of work, institution of pre
and post-job briefings, training of appropriate personnel, discussing
these events and performing " Reducing Human Error Training." In the
case of the event on January 25, 1991, a pre-job briefing was held
with the foreman and 2 technicians. This brief did not review the
prerequisites of the procedure. In addition, the two technicians and
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the foreman had received " Reducing Human Error" training. Two
i individuals, including the foreman, received this training on
December 3,1990. The other technician received the training on
November 15, 1990.
The failure to follow procedure 0PIC-CPU 001 with respect to not
- ' satisfying the prerequisites of the procedure is a Violation
l Failure to Meet Procedure Prerequisites, (324/90-01-01). The
i inspector recognizes that the willfulness and falsification issues
L which surfaced in the August 19, 1990 trip are not present in this
l case. However, the same issue, that is, the f ailure to adequately
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control maintenance work in the plant existed in the August 19, 1990
and August 22, 1990 events and occurred again on January 25, 19s1.
Since the corrective actions which were in place for the previous
violations could have reasonably been expected to prevent the
occurrence of this violation, the violation is characterized as a
similar violation.
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b. On Jannry 23, 1991, when the outside temperature reached a low of 22
degrees F, the inspector noted that protective measures to shelter
and supply of supplementary heating were not provided for the diesel
fire pump fuel tank. Section 5.0, Note 15 of 01-43, Freeze
Protection and Cold Weather Bill, Revision 6, states that the fire
pump fuel oil tank requires sheltering and supplementary heating at
25 degrees F to maintain operability. Item 9 of Attachment 2 of this
procedure requires the outside auxiliary operator contact maintenance
who will provide portable heating and windbreaks for the diesel fire
pump tank. In addition, the outside A0 is to ensure that the
temperature of the tank area remains greater than 23 degrees F.
On this particular occasion, the outside auxiliary operator notified
maintenance to take the appropriate actions at 25 degrees F.
However, maintenance was not equipped to respond quickly and did not
understand the urgency of these measures. Consequently, these
measures were not in place several hours later when the inspector
toured the area. Subsequently, the licensee has staged windbreaks
and provided heating for the area.
During this time period, the motor driven fire pump was operable.
Therefore, the safety significance of this event is minor. However,
it displays several weaknesses. Temperatures had been predicted to
be . in the low 20's that evening, yet prior planning had not been
accomplished to ensure that the diesel fire pump fuel oil tank would
be protected. Instead, the licensee's staff waited until the
established temperature to take action and then found out that they
could not respond quickly. Operations did not followup and
maintenance did not inform operations that these actions would not be
completed expeditiously. The failure to inmplement their freeze
protection procedures is a Violation: Failure to Implement Freeze
Protection Procedures, (325,324/91-01-02). However, this NRC
identified violation is not being cited because criteria specified in
Section V.A. of the NRC Enforcement Policy were satisfied.
Two violations and no deviations were identified.
5, Onsite. Review Committee (40700)
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
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regarding quorum membership, review process, frequency and personnel
qualifications. Meeting minutes were reviewed to confirm that
decisions / recommendations were reflected in the minutes and followup of
corrective actions was completed.
. Violations and deviations were not identified.
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6. Onsite Followup of Events (92700)
The below listed events were reviewed to verify that the information
provided met NRC reporting requirements. The verification included
adequacy of event description and corrective action taken or planned,
existence of potential generic problems and the relative safety
significance of the event. Onsite inspections were performed and
concluded that necessary corrective actions have been taken in accordance
with existing requirements, license conditions and commitments, unless
otherwise stated.
a. (CLOSED) . LER 1-89-04, Unplanned Auto Isolation of Reactor Water
Cleanup System Inlet Outboard Isolation Valve G31-F004 Due to
Spurious Actuation of Steam Leak Detection Instrumentation. This
unexpected partial Group 3 PCIS isolation was due to inadequate
clearance research. The steam leak detection temperature modules are
known to be susceptible to spurious trips upon being energized. The
distribution panel that supplies the affected temperature module was
being re-energized at the time of the actuation. The Group 3
isolation was not expected because operators did not thoroughly
research the system drawings to determine all isolations that could
occur. A HPCI isolation signal was expected but HPCI was already
isolated. Therefore, no actuations were anticipated. The Group 3
isolation would not have been prevented - only anticipated - had
thorough research been conducted. Since this event and numerous
other clearance problems, the licensee has improved the clearance
process such that events of this type have been minimized.
b. (CLOSED) LER 1-89-19, Failure of the Service Water System to Meet
Design Requirement. This report documented the failure of the
service water system to meet the requirements for system hydraulic
capability, cross-tie leakage and the motor reliability. This item
was discussed in the NRC Diagnostic Team inspection conducted in
April and May 1989, and was the subject of an enforcement conference
held in the Region II office. A Notice of Violation 89-34-47 was
issued as a result of the above action. This violation and the
licensee's actions taken to resolve this issue were disnussed in
l detail and the violation was closed in Report No. 325,324/90-52.
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Based on the information contained in that report, this item is also
closed.
c. (CLOSED) LER 1-89-21, Inadvertent Divisi7n 1 LOCA Initiation During
Test Perfo.mance as a Result of Miscommunication and Failure to
Verify Voltage. This event occurred during the performance of an MST
when .an I&C technician placed test lead on an incorrect terminal to
take a resistance measurement without verifying the absence of
vol tage. This resulted in the initiation of an inadvertent LOCA
initiation signal. All systems performed as designed. After
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verification that an event did not exist, the signal was reset. The
licensee has determined the root cause of this event and has provided
counselling and training to the involved technicians. This subject
was also discussed with the remaining technicians during scheduled
maintenance real time training. The applicable test procedures were
. revised to delete the resistance measurement that was being taken
when the event occurred since an evaluation has determined that it is
not a required step.
d. (CLOSED) LER 1-89-24, Failure to Test Seventeen Primary Containment
Isolatior. Valves Per Technical Specification 4.6.1.1.a, Due to Failure
to Recognize Testing Applicability. The root cause of this event was
a weakness in the design basis documentation that did not identify
all of the design criteria, Technical Specifications and affected
procedures for the above valves. A Regulatory Compliance TS
Interpretation 85-01 was issued in 1985 that identified PCIS valves
as those valves that require LLRT and-did not include valves that
fall under other criteria. The design engineer who iscued these
modifications to be installed on the above valves placed blame on the
interpretation and not adequately researching these components to
verify whether or not testing was a requirement. The licensee has
updated the PT for valve testing to include the missing valves. A
Design Deficiency Report (DDR) was initiated and routed' to all NED
personnel to insure that they understand this issue and to prevent
recurrence. The DDR has been entered into the design feedback
system. One of the valves was deleted from the list when it was
removed as a temporary repair and was not placed back on the list
when the valve was replaced under the direct replacement program. It
, appears that, on this event, operations . failed to review this DR
package and revise the necessary documentation. Operations had been
provided training on this event and applicable procedure changes have
been initiated to improve and strengthen the direct replacement
program,- These changes appear to be adequate to resolve this item
and prevent repetition.
e. (CLOSED) LER 1-89-25, Failure to Fulfill Surveillance Requirements
of Technical Specification 4.11.2.1. This event involved the loss of-
ability to sample the stack radiation release due to a frozen sample
line during extreme cold weather conditions. This had resulted from
a lack of insulation on a three foot section of line where they exist
in the stack. An investigation determined that this condition had
existed since initial installation. Drawings indicate that this line
should have been heat traced but was not. The licensee took
compensatory measures during this event to monitor all input into the
stack. This and other routine monitoring would have identified
unacceptable releases at that time. The uninsulated sample line has
been repaired and an E&RC evaluation determined that no 10 CFR 20 or
10 CFR 50 limits were exceeded during this event.
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f. (CLOSED) LER 1-89-26, Loss of E3 Bus While Deenergizing Bus 2D for
Scheduled Maintenance. Due to past difficulties in performing this
evolution, operations and the system engineer had developed
handwritten instructions on how to perform this task. These written
instructions were not explicitly followed since the SR0 performing
the evolution disagreed with the instructions. During the event, the
DC logic did not perform as designed. An investigation determined
that the Engine Room Manual Control Relay B (EMCR-B) had its normal
contact arrangement reversed (normally open vice closed). This
contact is located in the " Loss of Emergency Bus Diesel Start Relay"
circuit of the ECCS logic. In conjunction with the Control Room
Manual Control Relay (CMCR), EMCR-B serves to block a DG auto start
when the master / slave breakers are opened and the DG is operating in
the Control Room Manual or Engine Room Manual Mode. The reversed
contact in the DC logic did not play an active role in the event.
The deviation from the normal sequence was that the auto start
circuit for DG 3 was initiated by opening the master / slave breaker
instead of an undervoltage or Bus E3, The remaining logic performed
as designed. An investigation into the reversed cartridge was not
able tc reveal when this occurred. A review of the 3 remaining DGs
did not reveal a similar problem. The EMCR-B relay was corrected
under WR/JO 89-BBHEl. The primary cause of this event was not having
an adequately approved procedure for this task. The existing
procedure did not -address running loads and the handwritten
instructions confused the SRO. In addition, the reversed cartridge
allowed a different signal to be inputed to the DC logic than was
normally expected. Specific procedural guidance for removing
rotating -loads from an E bus prior to opening the master / slave
breakers when switching power from the normal- feed to the DG have
been developed and implemented. The inspector reviewed the plant
electrical system Operating Procedure OP-50, Revision 28 for Unit 2
and Revision 15 for Unit 1, to ensure that this action had been
completed,
g. (CLOSED) LER l-90-09, Required Surveillance Not Performed on Unit I
and.2 E11-F013A and E11-F0138 PCIS V?lves. During the performance of
PT-2.2.4a, Primary Containment Integrity Verification, Containment
External, it was determined that the requirements of TS 4.6.1.la were
not being met for the above valves. These valves do not get an
automatic isolation signal and were not being verified closed every
31 days as required by TS. This was not being done since the valves
were not listed in the above PT. The safety significance of this
event was minimal since the location of these valves is normally
below the water level in the suppression pool which would provide a
water seal. The procedure has been modified to list the above
valves. The inspector reviewed the. revised procedure and the
licensee's other corrective actions taken as a result of the above
event and determined that they appear adequate to prevent repetition.
This item is therefore closed.
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h. (CLOSED) LER 2-89-03, RWCU Group Ill isolation During Performance of
HPCI MST. The inadvertent RWCU isolation was caused by a technician
lifting the wrong lead from a scan module located in panel H12-614.
The mistake was attributed to the congestion of the wiring in the
back of the cabinet and the fact that the modules are not labelled in
the back of the panel . The licensee has developed and installed a
map on the back of the cabinet to assist the technician in locating
the correct module. The -inspector has observed, through direct
observation,.that the maps are installed for both units and have been
useful to the technicians when they perform surveillance tests in
these panels.
i. (CLOSED) LER 2-89-05, HPCI Declared Inoperable Due to a Limitorque
Corporation Software Error. A software error with the Motor Actuator
Characterizer (MAC) diagnostic equipment supplied by Limitorque
resulted in closing torque switch settings for the SMB-3 actuator to
be approximately 800 foot-pounds higher than actual. This
discrepancy was found by the licensee in concert with limitorque
while troubleshooting one of the licensee's SMB-3 actuators at
Limitorque's test facility. At the time of discovery, Unit I was in
a refueling outage and Unit 2 was operating.
The licensae's evaluation determined that this condition rendered the
Unit 2 HPCI injection valve inoperable since the MAC equipment had
previously been used to set the torque switch for this actuator.
Other SMB-3 actuators had either not had their torque switches set
usinc +he MAC equipment or the licensee put in place appropriate
compenstory measures to ensure that the valves could perform their
function. The Unit 2 HPCI injection valve torque switch setting was
adjusted to the correct value during a power reduction several days
later. Subsequent to this event, the licensee has received new
software from Limitorque correcting the discrepancy. The problem was
determined to be unique to the SMB-3. Affected valves have been
properly adjusted using this new software,
j. (CLGitb) 1.ER 2-89-13, . Failure of the HPCI Auxiliary Oil Pump Seal .
The inspectors reviewed the licensee's material- evaluation of the
failed seal. Examination showed that the adhesive joining the
elastomer and the metal had f ailed. Chemical analysis further
revealed that the failed adhesive was chemically different from the
good adhesive. This difference could be attributed to the seal being
constructed with an off specification adhesive or degradation from
service due to high temperatures or incompatibility with the pump
media. The licensee found no evidence that high temperatures
occurred during the operation of the system. Adhesive material was
also demonstrated to be compatible with the pump media. The root
cause of this failure was, therefore, not established. General
l
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12
Electric recommended retaining the same seal material as it has been
used successfully at many other facitities. If additional failures
occur, further actions will be considered.
k. (CLOSED) LER 2-89-14, Failure of the Drywell to Drywell Head Flange
Outer Seal During Local Leak Rate Testing. The licensee performed a
material analysis of the failed gasket at their Harris E&E Center.
The analysis showed that the gasket failed due to a combination of
high drywell temperatures and the use of Nickel Never-Seez as a
gasket lubricant. The licensee implemented ventilation modifications
last refueling outage to reduce drywell temperatures. These
modifications have been effective in lowering drywell temperatures.
'In addition, the licensee has revised their refueling procedures to
use Dow Corning High Vacuum Grease as the lubricant for the drywell
head gasket. The inspector verified, through review of
documentation, that the appropriate procedure changes were made.
1. (CLOSED) LER 2-89-15, PCIS/SDC Suction Valve, 2-E11-F008, Isolated
After Action Taken to Preclude the' Isolation. Corrective action for
this event included individual counseling, procedural enhancements
and training for all operations personnel. The inspector reviewed
the procedure changes and verified they adequately addressed the
identified discrepancies. However, the inspector noted that 4 other
surveillance test procedures, which test similar features and cause
the same isolations, were not updated. Procedure revision requests
had been submitted to update these procedures but no completion date
was provided. The licensee has since stated that these procedures
will be revised prior to their next scheduled use. In addition, an
ACR was generated to address the fact that the licensee considered
their corrective actions for this event complete when, in fact, they
were not.
L m. (CLOSED) LER 2-89-16, Unexpected Isolation of 2-G31-F004 Valve
During SP-89-51 Due to inadequate Clearance Review. This event
occurred during the performance of DG-3 Emergency Bus Energization
! Response Time Test. The procedure called for the removal of the RWCU
l filter demineralizers for service during the test. The shift foreman
L decided not to remove the RWCU system from service because the
l
filters had recently been precoated and the holding pump would lose
i power during the momentary loss of E3 power. This would prevent the
filter resin from being maintained on the septa and require the
filters to be backwashed and precoated. A shift foreman clearance
was used to open the breaker to Division 1 RWCU inboard isolation
vah e 2-G31-F001. However, the operations staff failed to realize
that the non-regenerative heat exchanger outlet temperature high
isolation signal (a non-engineered safety feature -(ESF) isolation
which causes the outboard isolation valve 2-G31-F004 to close), was
also powered from a Division 1 source. Therefore, when power was
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lost, the F004 valve closed. This incident was the result of a
failure of operations personnel to adequately review the associated
logic drawings. The inspectors verified that the licensee's
,
corrective actions provided counseling of the personnel involved.
The inspectors also reviewed the attendance records and lesson plan
for the Real Time training provided to operations personnel on the
event.
Violations and deviations were not identified.
7. Prompt Onsite Response to Events - Dropped Fuel Bundle (93702)
On January 2,1991, an irradiated fuel bundle was dropped approximately
ten feet into the Unit 1 core. It was being lowered into its assigned
position in the core matrix at the time ano came to rest in its normal
position. No significant damage was immediately evident and no gas
release was observed. The licensee took proper precautionary actions and
evacuated refueling floor personnel. Reactor coolant and airborne samples
verified no release had occurred.
The licensee initiated a SIIT investigation. The cause of the problem was
determined to be due to a pre-existing fuel handling grapple installation
error that caused the grapple to fail open instead of closed upon loss of
the refuel bridge control power. The grapple consists of two interlocking
"J" hooks that open and close via the action of air operated pistons. A
solenoid valve routes pressurized air to tha pistons to either open or
close the grapple depending on either energizing or de-energizing the
solenoid. . The power for the solenoid is controlled by a simple two
position on/off switch labeled "open" and "close" corresponding to the
grapple position. The solenoid, air supply, and grapple are supposed to
be configured such that the grapple is open when the solenoid is
.
energized. Thus, upon loss of power, the grapple will fail to the safe
closed position. The investigation revealed that the grapple failed open
upon loss of power. This was due to the supply lines between the solenoid
v61ve and the grapple pistons being crossed. Likewise, the control switch
was reversed such that when positioned to "close", the solenoid was
energized instead of de-energized. The result of the two reversals
allowed the grapple to operate normally, i.e., the grapple opened and
closed correctly according to the control switch position, but upon loss
. of power -to the solenoid, the grapple failed open. This problem was
'
masked in the past by the interlocking double "J" design that prevents the
grapple from opening whenever a fuel bundle or other load is .being
suspended.
At the time the fuel bundle was dropped, the following sequence of events
occurred. Af ter initial alignment of the fuel bundle within the core
matrix, the bridge operator increased the lowering speed of the hoist to
maximum. Approximately two feet of the way into the core (corresponding
to the top of the control blade), the bundle encountered some interference
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i
with surrounding components which momentarily unloaded the grapple and ;
actuated the hoist's " slack cable" protective feature which caused the
hoist to stop. The delay in stopping the hoist and momentum of the
grapple allowed the interlocking double "J" hook to become disengaged from
the fuel bundle bail. Due to the sudden stop from maximum speed, the
hoist overload protective feature inadvertently acutated causing the
bridge -control power to de-energize. This de-energized the grapple
solenoid and the grapple f ailed open. The bundle handle was now clear of
the grapple._ The interference r2 straining the bundle cleared and the
bundle fell to its final position.
The licensee's investigation revealed the grapple configuration error.
The error was easily corrected by interchanging the air hoses and
reversing the open/ closed control switch. The licensee could not
determine when the error occurred and postulated that it has always
existed. The Unit 2 grapple was tested and found to be correct. The
refuel bridge interlocks and hoist are required to be tested by TS 4.9.1.2.a and b and 4.9.6 prior to movement of control rods or fuel
assemblies within the reactor pressure vessel. Toese tests are
implemented by PT-18.1, Refueling Position Interlock Check. The inspector
verified that the PT performs all TS required testing. TS do not require
that the fail-safe feature of the fuel handling grapple be tested.
However, PT-18.1, Section 7.5.9 checks that a test eight does not
disengage when the grapple power is de-energized, but tl2 interlocking "J"
hooks prevent the grapple from opening, thereby, rei fering the test
ineffective for checking the fail closed feature. The licensee determined
that the hoist brake safety features also were 1ot correctly tested by the
PT. The hoist has an electric and mechanical b*ake. The PT tests these
concurrently. Therefore, if one was not functioning, the other would mask
the failure. The licensee revised their procedures and tested the brakes
individually prior to recovery of the dropped bundle. Both performed
-correctly.
The licensee developed Special Procedure SP-91-001, Inspection of Unit 1
Core Cell 10-15 Following Drop of Fuel Bundle LYG612, for inspection of
the affected fuel cell, the dropped bundle, and adjacent areas. Nc
significant damage was detected. The dropped bundle was removed to t1e
spent fuel pool and an appropriate fuel shuffle utilizing a previous
burned bundle as a replacement, was perfomed.
'
Other action was taken to address the control power loss due to
'
inadvertent actuation of the hoist overload protective feature. The
result was that the maximum lowering speed of the hoist has been
temporarily reduced from approximately 20 feet per minute to approximately
14 feet per minute. This has reduced the frequency of inadvertent control
power loss until the actual cause can be determined. The licensee's
investigation has been hampered by poor refueling bridge drawings and
configuration documentation.
l
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L
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15
Further inspection of long term corrective actions will be conducted
pending receipt of the Licensee Event Report.
Violations and deviations were not identified.
.8. In-Office Report Review (90712)
a. (CLOSED) Violation 325,324/89-20-07, Failure to Hold Quarterly
Corporate Nuclear Safety Review Board (CNSRB) Meetings As Specified
in Brunswick Improvement Program (BIP), Item VI-5. As the BIP was
required to be implemented by Confirmatory Order EA-82-106, the
subject violation was cited because the quarterly CNSRB meetings were
discontinued without prior NRC notification / approval. The intended
CNSRB function of- providing independent assessment of potential
safety concerns at CP&L nuclear plants is now captured -by CP&L's
recently implemented Nuclear Assessment Program (Integrated Action
Plan item E5). Based on this and the licensee's November 20, 1989
response, which adequately addressed the failure to maintain in place
regulatory comitments made to the NRC, this item is considered
closed.
9. Action on Previous Inspection Findings (92701) (92702)
a. (CLOSED) Violation 325/89-05-01, Failure to Follow Equipment
Clearance Procedure. This incident involved the failure to establish
adequate clearance for work activities on F010 and F014 valves on the
Standby Liquid Control System. The valves used to isolate this work
did not take into consideration that both the above valves would be
manipulated during the maintenance activity which was permitted by
the established procedure. _The . manipulation of the above valves
resulted in partial draining of the SLC tank. The licensee's
corrective action on the above included establishment of a Clearance
Center staffed by licensed reactor operations personnel and
additional training to operations and maintenance personnel on
procedural revisions made to strengthen the tagging process. The
inspectors reviewed the changes made to the Equipment Clearance
Procedure AI-58-under Revision 29 dated July 7, 1989, and the lesson
plans and attendance sheets for the training conducted for operations
and maintenance personnel on the revised procedure. The Clearance
Center, which was established in 1989, had led to an improvement in
the clearances issued and a marked reduction in clearance errors,
b. -(CLOSED) Violation 325,324/89-20-04, ONS Not independent During Post
Trip Reviews. This violation involved the assignment of an 0NS
member as the team leader of a Site Incident Investigation Team. As
SIIT team leader he was required to sign off on functions that he was
also required by TS 6.2.3.2 to provide independent oversight over.
The licensee corrective action to resolve this item included revision
of Regulatory Compliance Instruction, Site Event Investigation
Process, RCI-06.6, on November 22, 1989, to ensure that ONS are not
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16
assigned any functions on SIITs. A TS interpretation was also issued
to clarify the duties,- responsibility and independence of this
organization. A review of selected Silts since this event indicates
that this problem has been corrected.
c. (CLOSED) Violation 324/89-20-06, Inadenuate G earance, and Violation
3?S/89-44-01, failure to Follow Al-58 for Drawing Research. Both of
the above violations involved a lack of attention to detail in
researching drawings to ensure the adequacy of clearances, in both
the above cases, plant safety equipment was rendered inoperable due
to these errors. The inspector reviewed the licensee's corrective
actions on the above items. These included the establishment of a
task force to study the overall problems associated with clearances
and repetitive errors in this area. The results of this task force's
findings have led to upgrades in Al-58 and the establishment of a
dedicated Clearance Center. This center provides for duplicate and
independent reviews of clearance requests. This center is staffed by
senior licensed operators and has been in operation for approximately
one year. Although some errors have been identified in this new
process, it appears to have led to significant improvement in this
area. Based on the progress to date, these violations are closed.
However, the overall effectiveness of this center and the other
cleararce program improvements will be evaluated further under IAP
item E-2.
Violations and deviations were not identified.
10. Information Meetings With Local Officials (94600)
The inspectors and the project section chief met with and explained the
'
NRC's' mission and inspection program at the Brunswick Plant to local
officials. Meetings were held with the Mayor of Boiling Spring Lakes on
January 10, the City Managers of Long Beach and Southport and the Acting
Brunswick County Manager and Emergency Management Coordinator on January ,
16 - the Manager of Bald Head Island on January 17, the County Manager and
Director of Emergency Preparedness for New Hanover County and the Manager
of Carolina Beach and the Mayor Pro Tempore of Kure Beach on January 29,
1992. The Mayor for the town of Caswell Beach was contacted but was not
available for a meeting at the present time. The Mayor of Youpon Beach
presently works at the Brunswick Plant and indicated that he was fully
aware of the NRC's mission and role at the Brunswick Plant. The above
towns and two counties comprise all areas within a 10 mile radius of the
plant. The above personnel appeared to be very appreciative of the visits
and were provided with - telephone contact numbers for the resident
inspec tors,-- The Region 11 Section and Branch Chiefs -and the NRC
Headquarters Emergency Response Center.
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17
Local Fublic Docun ent Room
The inspector visited the LPDR for Brunswick which is located at the
University of North Carolina - Wilmington Randall Library. The inspector
found the available documentation to be neatly arranged and properly
categorized according to NRC instructions. Library personnel were
knowledgeable and helpful. The inspector was hble to access recently
issued Brunswick-related documentation from microfiche. All documents
issued since July 1990, are in microfiche form.- The inspector noted that
the files are arranged in broad categories. Within categories,
documentation is filed basco on issuance to the LPDR, not necessarily on
the date of the documentation. This results in the search for a
particular document to be burdensome. For example. the inspector sought a
particular 1989 Resident inspector report by number. This could be
located only-by having the knowledge of the approximate date that it may
_
have been issued in microfiche form. A random search of the microfiche
accession list in the approximate time period was necessary to locate the
appropriate report number. The inspector concluded that the method of
categorizing makes the information virtually unretrievable without some
prior knowledge of the' docummts available, e.g., an individual cannot
easily access all inspection reports for a given year or SALP cycle.
The inspector located a hard copy version of outdated Brunswick custom
Technical Specifications. A search for the curret.t TS was unsuccessful.
A call to the LPDR hotline in Washington rev6aled that no complete
compilation of current TS is maintained, rather, trA4vidual TS amendments
are randomly filed in the broad " licensing" category. The TS in this
form, if the individual amendments could be located, are unusable. The
only compiled document maintained in its current form is the FSAR. The
inspector concluded that, although the pertinent documentation appeared to
be present, the filing system and accessibility is not user friendly and
,
is, therefore, of very limited use to the public.
11. ExitInterview-(30703)
The inspection scope and findings were summarized on Janrny 31, 1991,
with those persons indicated in paragraph 1. The inspect rs described the
areas inspected and discussed in detail the inspection ' fndings listed
below. Dissenting comments were not received f rom 'le licensee.
Proprietary information is not contained in this report,
item Number Description / Reference Paragraph
324/90-01-01 VIOLATION - Failure.to Meet Procedure
Prerequisites, paragraph 4.a.
325,324/90-01-02 NON-CITED V10LATi"1 - Failure to Implement Freeze
Protection Pro :aures, paragraph 4.b.
,
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-.--w- . --,,--w , r,- , . w-- %-,.-..-,----r,- ,w-,ym. , ,. - ,-
,
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4
i 12. Acronyms and Initialisms
ACR Adverse Condition Report
AI Administrative Instruction
A0 Auxiliary Operator
APRM Average Power Range Monitor
BSEP Brunswick Steam Electric Plant
CMCR Control Room Manual Control Relay
CNSRB Corporate Nuclear Safety Review Board
CO Control Operator
DC Direct Current ~
DDR Design Deficiency Report
DG Diesel Generator
DR- Direct Replacement
E&E Energy & Environment
ECCS Emergency Core Cooling System
EMCR Engine Room Manual Control Relay .
ERFIS_ Emergency Response Facility Information System
_
ESF Engineered Safety Feature
F Degrees Fahrenheit
FWLCS Feedwater Level Control System
HP- Health Physics
HPCI High Pressure Coolant Injection
IAP Integrated Action Plan
1&C Instrumentation and Control
I E. NRC Office of Inspection and Enforcement
IEEE International Electrical & Electronic Engineers
IFI. Inspector Followup Item ,
IPBS Integrated Planning, Budgeting and Scheduling
LER Licensee Event Report
LLRT Local Leak Rate Test
LOCA Loss.of Coolant Accident
LPDR Local Public Document Room
LPRM Local Power Range Monitor- '
MAC Motor Actuator Characterizer
MST Maintenance Surveillance Test
NED Nuclear Engineering Department
NRC Nuclear Regulatory Commission
01 -Operating Instruction
ONS Onsite Nuclear Safety
0P Operating Procedure
PA Protected Area
PCIS Primary Containment Isolation System
PM Plant Modification
PNSC -Plant Nuclear Safety Committee
PT Periodic Test
QA Quality Assurance
QC. Quality Control
,
(
)
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19
RCI Regulatory Compliance Instruction
RCIC Reactor Core isolation Cooling
R0 Refueling Outage
SBGT Standby Gas Treatment
SCO- Senior Control Operator
SDC Shut Down Cooling
SF Shift Foreman
SIIT Site Incident Investigation Team
SP Special Procedure
SRG Senior Reactor Operator
STA Shift Technical Advisor
SWFCG Site Work Force Control Group
TS Technical Specification
URI Unresolved item
WR/JO Work Request / Job Order
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