ML20150B505
| ML20150B505 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 03/04/1988 |
| From: | Chamberlain D, Holler E, William Jones NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20150B491 | List: |
| References | |
| 50-458-88-01, 50-458-88-1, IEB-87-002, IEB-87-2, NUDOCS 8803170026 | |
| Download: ML20150B505 (12) | |
See also: IR 05000458/1988001
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APPENDIX B
U. S. NUCLEAR REGULATORY C0FNISSION
REGION IV
NRC Inspection Report:
50-458/88-01
Docket: 50-458
Licensee: Gulf States Utilities Company (GSU)
P. O. Box 220
St. Francisville, Louisiana 70775
Facility Name:
River Bend Station (RBS)
Inspection At: River Bend Station, St. Francisville, Louisiana
Inspection Conducted: January 1 through February 15, 1988
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Inspectors: E
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D. D." Chamberlain, Senior Resident Inspector
Date
Project Section C, Division of Reactor Projects
Y"$ $'bh
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B.V ones, Resident ::nspector
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Date
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Project Section C, Division of Reactor Projects
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Approved:
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E. J./1(oller, Chief, Project Section C
D'a t e/
Division of Reactor Projects
8803170026 880309
ADOCK 05000458
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Inspection Summary
Inspection Conducted January 1 through February 15, 1988
(Report 50-458/88-01)
Areas Inspected:
Routine, unannounced inspection of licensee action on
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previous inspection findings, NRC Bulletin 87-02, 10 CFR Part 21 Reports,
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surveillance test observation, maintenance observation, safety system
walkdown, and operational safety verification.
Results: Within the areas inspected, one violation was identified
(failure of timely follow-up review to verify corrective action completion,
paragraph 2).
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DETAILS
1.
Persons Contacted
D. L. Andrews, Director, Nuclear Training
. R. J. Backen, Supervisor, Operations Quality Assurance (QA)
C. L. Ballard, Supervisor, Projects
W. J. Beck, Supervisor, Reactor Engineering
- J. E. Booker, Manager, Oversight
J. L. Burton, Supervisor, Independent Safety Engineering Group
- E. M. Cargill, Supervisor, Radiation Programs
- J. W. Cook, Lead Environmental Analyst, Nuclear Licensing
- T. C. Crouse, Manager, QA
- J. C. Deddens, Senior Vice President River Bend Nuclear Group
D. R. Derbonne, Assistant Plant Manager, Maintenance
- L. A. England, Supervisor, Nuclear Licensing
P. E. Freehill, Outage Manager
A. O. Fredieu, Supervisor, Operations
P. D. Graham, Assistant Plant Manager, Operations
J. R. Hamilton, Director, Design Engineering
- G. K. Henry, Supervisor, Electrical Engineering
K. C. Hodges, Supervisor, Chemistry
- L. G. Johnson, Site Representative, Cajun
G. R. Kimmell, Director, Quality Services
- R. J. King, Supervisor, Nuclear Licensing
- A. D. Kowalczuk, Director, Oversight
J. W. Leavines, Director, Field Engineering
I. M. Malik, Supervisor, Quality Systems
J. H. McQuirter, Licensing Engineer
- V. J. Normand, Supervisor, Administrative Services
W. H. Odell, Manager, Administration
- T. F. Plunkett, Plant Manager
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M. F. Sankovich, Manager, Engineering
R. R. Smith, Engineer, Nuclear Licensing
- K. E. Suhrke, Manager, Project Management
- B. E. Tate, Supervisor, Project Scheduling
- R. J. Vachon, Senior Compliance Analyst
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R. G. West, Supervisor, General Maintenance
The NRC inspectors also interviewed additional licensee personnel during
the inspection period.
- Denotes those persons that attended the exit interview conducted on
February 19, 1988.
2.
Licensee Action on Previous Inspection Findings
a.
(Closed) Open Item (458/8632-01): Licensee implementation of power
line conditioner modifications and development of low voltage panel
load lists,
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This open item relates to the licensee efforts to correct a tripping
problem with Elgar power line conditioners (PLC).
The trip problem
occurred during electrical distribution system transients.
The PLC
are designed to provide a stable 120 volt AC power source for control
and indication circuits for both safety and nonsafety-related loads.
In addition to correcting the trip problem, the licensee instituted
an effort to provide low voltage distribution panel load lists.
The
licensee has completed design modifications to correct the trip
problem.
An electrical panel load list manual has been developed
which provides a general description of breaker loads and power loss
effects.
Also, low voltage electrical panels were labeled and power
distribution schedules were inserted in each panel.
This open item is closed.
b.
(0 pen) Open Item (458/8615-02):
Monitor licensee actions to correct
electrical drawing discrepancies on the standby gas treatment
system (SGTS) recirculation dampers.
In April 1986, the licensee identified discrepancies between the
electrical schematic drawings and the actual field wiring
configuration for the SGTS recirculation dampers.
Condition
report (CR) 86-0442 was issued on April 12, 1986, to affect
corrective action for the identified discrepancies.
Corrective
actions included operationally configuring the system with the
dampers closed during standby operation and verification of system
operability by surveillance testing.
Also, additional design
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documents were reviewed for similar errors and only six minor
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administrative discrepancies were found. Modification request
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(MR) 86-0642 was issued to correct the initial condition found.
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CR 86-0442 was closed with MR 86-064^ issued to correct the
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nonconforming field wiring condition. MR 86-0642 was issued on
April 19, 1986, but it was not released for field work until
January 7,1988. Although several plant outages occurred during 1986
and 1987, including the first refueling outage for 3 months in 1987,
this modification has not been implemented to correct the
nonconforming condition.
The licensee's quality assurance program
requires timely follow-up reviews by the appropriate department to
verify that specified corrective action has been properly
implemented.
The apparent lack of timely follow-up review to verify
completion of corrective action for CR 86-0442, which included
completion of MR 86-0642, was identified by the SRI as a potential
violation.
(458/8801-01)
This open item remains open.
3.
Licensee Action on f4RC Bulletin 87-02
This area of the inspection was conducted to review licensee actions
relative to fiRC Compliance Bulletin No. 87-02, "Fastener Testing to
Determine Conformance With Applicable Material Specifications." The
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purpose of this bulletin is to request that the licensee:
(a) review
their receipt inspection requirements and internal controls for fasteners;
and (b) independently determine, through testing, whether fasteners in
store at the facility meet required mechanical and chemical specification
requirements.
The licensee's program for receipt inspection requirements and internal
controls for fasteners is described in Quality Assurance Instruction
QAl-2.2, "QA Review of Procurement Documents and Identification of Receipt
Inspection Requirements," and Quality Control Instruction QCI-3.0,
"Receiving Inspection." The resident inspector verified that the
licensee's program for receipt inspection requirements for ASME fasteners,
as described in their response to NRC Compliar.ce Bulletin 87-02, is
reflected in the above two procedures.
The licensee has received the test results for the fasteners selected with
the participation of the resident inspector.
Seven of the selected
fasteners were found to be out of specification conditions.
The failures
occurred for both mechanical and chemical properties.
The licensee has
evaluated each of the failures and determined that no adverse impact on
safety-related components exists.
The basis for this evaluation is given
as an attachment to the licensee's response dated January 29, 1988.
A
copy of the response has been submitted to the Vendor Branch of Nuclear
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Reactor Regulation.
NRC Region IV actions associated with temparary
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instruction TI 2500/26 are complete.
No violations or deviations were identified in this a.ea of the
inspection.
4.
10 CFR Part 21 Reports
The resident inspectors were provided copies of selected 10 CFR Part 21
reports by NRC Region IV, which may be applicable to equipment or services
supplied to River Bend.
These reports were provided to the licensee, who
verified that the reports either had been or were being evaluated for
applicability at River Bend. Any reports that were not already entered
into the lir
le tracking system were immediately entered.
A listing of
reports by date, manufacturer, and subject is provided below:
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October 2,1987 - Borg Warner Corporation, Nuclear Valve
Division - Potential failure of fasteners between valve yoke and yoke
adapter.
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November 13, 1987 - Limitorque Corporation - SMB-00 motor operators
found with abrasion damage to the motor lead wires.
The resident inspectors will continue to provide copies of potentially
applicable 10 CFR Part 21 reports for licensee evaluation, and a follow up
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of licensee action on selected 10 CFR Part 21 reports will be conducted
during future NRC inspections.
No violations or deviations were identified in this area of the
inspection.
5.
Surveillance Test Observation
During this inspection period, the resident inspector observed the
performance of Surveillance Test Procedures STP-511-4504, "RPS/ Isolation
Actuation-MSLI-Main Steam Line Radiation-High Monthly Chfunct
(017-K6100)," and STP-309-0202, "Diesel Generator Division II Operability
Test." The results are documented below,
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STP-511-4504: This surveillance test procedure was performed on
January 16 and 17,1988, to meet the channel functional test
requirements for the main steam line isolation on high main steam
line radiation with the reactor in operational condition 1.
The
operability requirements are identified in Technical Specification (TS) 4.3.1.1 and 4.3.2.1, Tables 4.3.1.1-1.7
and 4.3.2.1.-l.2.b.
During the performance of the surveillance test,
the licensee found that the high radiation trip setpoint for
instrument D17-K6100 exceeded the TS allowable value of less than or
equal to 3.6 times full power operation radiation background. This
determination was based on the main steam line 100 percent power
radiation monitor background values established on January 8,1988,
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in licensee memorandum RPG-88-010.
The licensee periodically adjusts
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the calibration values to allow for changes in ionization chambers
and other system responses. The previous main steamline 100 percent
power monitor background values were established on April 27, 1987,
in memorandum RPG-87-160.
This was prior to the licensee beginning
power coastdown for the end of the first fuel cycle. The resident
inspector met with licensee personnel to discuss what. actions were
being taken to ensure that changes to the main steam line radiatior,
background monitors are promptly identified to assure the trip
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setpoints reflect the latest radiation monitor values and the
associated TS requirements. The licensee has initiated CR 88-0056 to
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review the incident and document their corrective action.
The
licensee's corrective action will be an open item (458/8801-02)
pending further review during a future NRC inspection,
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STP-309-0202: On February 11, 1988, at 12:40 a.m., CST, the licensee
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experienced a loss of preferred station transformer D.
Preferred
station transformer D was supplying the Division II safety-related
bus 1 ENS *SWG1B at the time of the event. This resulted in a
subsequent loss of offsite power to 1 ENS *SWG18.
The Division II
emergency diesel generator started on undervoltage on the bus and the
output breaker closed within 10 seconds to support the required
loads. At 2:42 a.m., CST, the licensee paralleled offsite power to
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1 ENS *SWG1B through normai station transformer C and the alternate
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supply breaker.
The diesel generator was then loaded between 3030
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and 3130kw for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> to meet the requirements of the surveillance -
test.
The start time and times to rate voltage and frequency were
determined through review of data points collected on the emergency
response information system (ERIS) computer. All of the associated
times were found to meet the requirements of TSs and the surveillance
test. A further discussion of this partial loss of offsite. event is
described in paragraph 8 of this report. A review of the
surveillance test data by the resident inspector revealed no problems
with using this diesel start to meet the diesel operability
requirements.
No violation or deviation was identified in this area of the
inspection.
6.
Maintenance Observation
On February 7,1988, with the reactor in operational condition 2, the
resident inspector observed maintenance activities for replacement of the
reactor core isolation cooling (RCIC) system isolation actuation
instrument, 1E31*N610A.
This instrument is required by TS 3.3.2 to be
operable whenever the reactor is in operational conditions 1, 2, or 3.
The instrument serves to close the RCIC steam supply line outboard
isolation valve, 1E51*MOVF064, en a residual heat removal (RHR) room, high
ambient temperature. The instrument was identified as inoperable during a
channel check required by surveillance test procedure STP-000-0001, "Daily
Operating Logs." The licensee initiated limited condition of operation
(LC0)-88-43 to identify the failed instrument and prevent entry into
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mode 1.
Prompt maintenance work order (PMW0) 56017 was initiated to
replace the instrument. The resident inspector verified through
observation and/or review of records that:
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the requirements of TS 3.3.2 were met;
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the required administrative approvals were obtained prior to
initiating work;
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controls for lifted leads and jumpers were followed;
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a quality control inspector observed the performance of the
maintenance activity as required for PMW0s; and
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the instrument was tested before being returned to service.
No violations or deviations were identified in this area of the
inspection.
7.
Safety System Walkdown
During this inspection period, the resident inspector performed a walkdown
of the main steam-positive leakage control system (MS-PLCS) with the plant
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in operational condition 1.
Two independent MS-PLCS divisions are
required by TS 3.6.].5 to be operable in operational conditions 1, 2,
and 3.
The MS-PLCS is used to seal between the inboard and outboard
mainstream isolation valves (MSIV) and between the outboard MSIV and the
main steam shutoff valves.
In the event of a loss of coolant accident,
the system is designed to maintain leakage from the containment within the
10 CFR Part 50 Appendix J Guidelines.
The MS-PLCS walkdown consisted of a
verification of accessible valve positions, instrument 11oeups and
electrical lineups.
The MS-PLCS valves which are located in the steam
tunnel will be verified in the required positions when plant operating
conditions permit. Review of the control board lineup dia not reveal any
conditions which would adversely affect MS-PLCS operability.
No violations or deviations were identified in this area of the
inspection.
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8.
Operational Safety Verification
The resident inspectors observed operational activities throughout the
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inspection period and closely monitored operational events.
Control room
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activities and conduct were generally observed to be well controlled.
Proper control room staffing was maintained and access to the control room
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operational areas was controlled.
Selected shift turnover meetings werc
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observed and it was found that information concerning plant status was
being covered in each of these meetings.
System walkdowns of the "A,"
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"B,"
and "C" low pressure coolant injection systems were conducted to
verify major flow path alignments for operabil1ty. Also, a detailed
system walkdown of the main steam positive leakage control system was
conducted and the results are documented in paragraph 7 of this report.
Plant tours were conducted, and overall plant cleanliness was good.
General radiation protection practices were observed and no problems were
noted. Personnel exiting the radiation control area were observed and
radiation monitors were being properly utilized to check for
contamination.
In addition to the routine observation of security activities by the
resident inspectors, the resident inspector participated in the security
Regulatory Effectiveness Review (RER) conductea during this inspection
period. The RER was performed by NRC personnel and members of the Army
Special Forces.
The resident inspector provided comments to the RER team leader for
inclusion in the NRC assessment of the security program at River Bend
Station as appropriate.
Plant perimeter walkdowns were conducted and
personnel entry and exit from the protected area were observed and no
problems were noted.
The resident inspectors also reviewed licensee actions on operational
events and potential problems.
The results of reviews of selected items
are described below:
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Annulus Radiation Monitors
On January 6,1988, the licensee discovered the cooling water supply
valves (3042 and 3043) isolated to the annulus radiation monitors
(RE11A&B).
The valves were immediately opened and CR 88-0011 was
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issued for investigation and corrective action.
Subsequent
investigation by the licensee revealed that these valves were
included within the boundary of a clearance issued during the
refueling outage.
The clearance was issued to allow cleaning of the
cooling water lines that had plugged. The actual work performed
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included replacement of a section of the piping which included the
valves that were later found isolated. Apparently these valves were
replaced and the maintenance mechanics left them closed on
December 10, 1987. The clearance was released on December 13, 1987,
but only the boundary valves included in the clearance were reopened.
The post maintenance testing performed was only an operational leak
test and no verificaticn of flow was performed.
The subject valves
were then found closed by an operator during his routine rounds on
January 6,1988. The valve alignments for these radiation monitors
had been performed prior to issuance of the clearance and the
clearance restoration should have restored the valves to the proper
position. The licensee has evaluated tha root cause of this problem
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to be inadequate controls to verify proper position of valves located
within t'e boundaries of a clearance.
The licensee also performed a
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detailed engineering evaluation of the safety significance of the
isolation of cooling water to the annulus radiation monitors.
The
evaluation confirms that cooling water is not required for these
monitors to perform their intended safety function.
It was also
determined that the annulus exhaust radiation monitors are not
necessary to initiate the standby gas treatment system since
redundant and diverse actuation signals are provided by high drywell
pressure and low reactor water level. Licensee corrective actions
for this, problem included:
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a review of other modification activities performed during the
refueling outage for similar problems;
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addition of a hold point on all mechanical job plans by the
maintenance planner for operations to verify final position of
all manual valves affected during the performance of maintenance
activities; and
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revision to Administrative Procedure ADM-0027, "Protective
Tagging" to require that' all valves located within the boundary
of a clearance to be restored when the clearance is restored.
The resident inspectors have monitored licensee actions on this
problem.
No NRC violation will be issued because the licensee
identified the problem and took prompt and extensive corrective
action. Also, the isolation of these valves had no impact on sate
operation of River Bend.
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b.
During the performance of surveillance test STP-052-3301 for control
rod drive operability on January 26, 1988, the licensee discovered
that the scram discharge volume drain valve IC11*A0V011 would not
fully close.
This valve is an air operated valve which fails open on
loss of air pressure.
The valve is in series with another automatic
valve on the scram discharge volume drain line. Both valves are
normally open and receive a close signal during a reactor SCRAM.
When the SCRAM is reset both valves open to allow the scram discharge
volume to drain. The failure of either one or both of these valves
to close would not prevent a reactor SCRAM from occurring. The
licensee initiated CR 88-0086 to investigate the cause of the valve
not fully closing.
Subsequent investigation by the licensee revealed
that a manual handwheel used to jack the air operated valve to the
closed position was partially closed. A similar valve 1C11*A0V010 on
the scram discharge volume vent line was also.found to have the same
condition. The licensee immediately positioned the manual handwheels
for both valves to allow free movement of the valves.
The valve
lineup for this system only required placing these valves in service
and with no mention of the manual handwheels. The licensee has
revised the valve lineup to require the manual handwheels to be
rotated to the full clockwise position and locked in place.
The
licensee is continuing investigation of this problem for action to
prevent recurrence.
The resident inspectors will continue to monitor
licensee actions,
c.
Division II Preferred Power
On February 11, 1988, with the plant at 10 percent power, preferred
station service transformers RTX-XSRIB and 10 tripped off line
causing a loss of power to the Division II emergency bus. This
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equates to the loss of 1 of 2 offsite power sources.
The Division II
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emergency diesel generator auto started and supplied power to the
Division II emergency bus as per design.
The licensee entered a
72-hour shutdown limiting condition fo^ operation as required by TSs
while the cause for the trip was investigated.
The cause of the trip
was determined to be a bad grounding transformer on the 1B preferred
station service transformer. The ID transformer was then returned to
service to supply offsite power to Division II emergency bus before
the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> were expended. The grounding transfonner on the
IB preferred station service transformer has been replaced and normal
electrical lineups restored. The licensee is continuing the
investigation for the cause of the grounding transformer failure.
The resident inspectors will continue to monitor licensee actions,
d.
Reactor Shutdowns
During this inspection period, there were two unplanned reactor
shutdowns and one planned reactor shutdown. The details of these
events are discussed below:
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Alternate Rod Insertion SCRAM: On January 10, 1988, with the
plant at 100 percent power, a reactor SCRAM occurred during the
performance of surveillance test procedure STP-051-4269 on the
alternate rod insertion system.
The alternate rod
insertion (ARI) system was added during the recent refueling
outage as an anticipated transient without a scram (ATWAS).
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feature.
This surveillance test was required to be performed on
a monthly basis and it had been performed at least one other
time. During perforn.ance of the test, technicians incorrectly
lifted wiring from "TB6" terminals 4 and 5 instead of from
"TB0006" terminals 4 and 5.
These terminal blocks were both
located in the saroe electrical panel.
Lifting of the incorrect
wiring resulted in breaking the common ground circuit for two
trip units which initiated the ARI reactor shutdown.
Licensee
corre:tive actions for this event included shop training of
technicians.on the event, revising of ATWAS procedures to more
clearly define the correct terminal board locations, and marking
of control room ATWAS panels with caution signs to note
potential for a reactor SCRAM by lifting one electrical lead.
The licensee has also initiated engineering action requests to
evaluate changes to the AT11AS wiring so that the comon wiring
configuration does not affect multiple trip units.
The resident
inspectors will continue to monitor licensee actions in this
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area.
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Reactor High Pressure SCRAM:
On January 28, 1988, with the
plant at 100 percent power, a reactor SCRAM occurred from
reactor high pressure. The reactor high pressure condition
occurred from a main turbine runback because of a high stator
cooling water temperature signal.
Subsequent investigation by
the licensee revealed that a piece of linkage on a stator
cooling water temperature controller had broken. This caused
the control valve to go full open and bypass the generator
stator coolers. The stator water temperature increased to the
turbine runback setpoint of 178*F.
The operators could not drop
reactor power fast enough to account for the reduced turbine
load and reactor pressure increased to the SCRAM initiation.
The licensee determined that the temperature controller had
failed because of excessive vibration at the mounted location.
The controller has been relocated to a vibration free location
and the temperature switch for turbine runback initiation has
also been relocated. The licensee also installed a mechanical
stop on the temperature control valve so that the stator coolers
will never be fully bypassed. The stator coofing water
temperature alarm has also been lowered by 10 to allow
operators more response time for future events of this nature.
The licensee actions for this event are considered responsive
and thorough.
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Manual Reactor SCRAM:
On February 6,1988, the licensee
initiated a manual reactor SCRAM with the plant at 13 percent
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power.
The main turbine was being taken off line in order to
repair a main generator exciter coupling.
had developed a lubrication leakage.
During the main turbine
coastdown a high vibration condition developed and the shift
supervisor decided to b*eak condenser vacuum and initiate a
manual SCRAM. The exciter coupling was repaired and-a plant
restart was conducted on February 7,1988.
No vibration
problems were encountered with the main turbine during the plant
restart. The licensee speculates that operating the turbine
unloaded during the coastdown caused hot spots along.the turbine
shaft and subsequently caused the high vibration condition.
The
licensee is continuing to investigate the problem.
No violations or deviations were identified in this area of
inspection,
9.
Exit Interview
An exit interview was conducted with licensee representatives (Identified
in paragraph 1).
During this interview, the senior resident inspector
reviewed the scope and findings of the inspection.
,