IR 05000155/1987026
| ML20195K143 | |
| Person / Time | |
|---|---|
| Site: | Big Rock Point File:Consumers Energy icon.png |
| Issue date: | 01/25/1988 |
| From: | Guldemond W NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | Buckman F CONSUMERS ENERGY CO. (FORMERLY CONSUMERS POWER CO.) |
| References | |
| NUDOCS 8802020098 | |
| Download: ML20195K143 (2) | |
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Docket No. 50-155 Consumers Power Company ATTH: Dr. F.W. Buckman
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Senior Vice President Energy Supply 212 West Michigan Avenue Jackson, MI 49201 Gentlemen:
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This refers to the routine safety inspection conducted by Mr. Stephen Guthrie of this office on October 16, 1987 - December 14, 1987, of activities at Big
Rock Point Nuclear Plant authorized by NRC Operating License No. OPR-6 and to i
the discussion of our findings with Mr. C. R. Abel at the conclusion of the inspection.
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The enclosed copy of our inspection report identifies areas examined during the inspection. Within these areas, the inspection consisted of a selective examination of procedures and representative records, observations, and interviews with personnel.
No violations of NRC requirements were identified during the course of this inspection.
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In accordance with 10 CFR 2.790 of the Commission's regulations, a copy of this letter and the enclosed inspection report will be placed in the NRC Public Document Room.
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We will gladly discuss any questiens you have concerning this inspection.
Sincerely, l
Original signed by I. N. Jackiw/for
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W. G. Guldemond, Chief r
Reactor Project Branch 2
Enclosure:
Inspection Report
No. 50-155/87026(ORP)
See Attached Distribution
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Consumers Power Company
Distribution
REGION III==
Report No. 50-155/87026(DRP)
Docket No. 50-155
License No. OPR-6
Licensee:
Consumers Power Company
212 West Michigan Avenue
Jackson, MI 49201
Facility Name: Big Rock Point Nuclear Plant
Inspection At: Charlevoix, Michigan
Inspection Conducted: October 16, 1987 - December 14, 1987
Inspector:
S. Guthrie
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Approved By:
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P jects 5 ction 2C
Date
Inspection Summary
Inspection on October 16, 1987 - December 14, 1987 (Report No. 50-155/84-17(ORP))
Areas Inspected:
Routine, unannounced inspection conducted by the Senior
Resident Inspector of Operational Safety, Maintenance Operation, Surveillance
Operation, Reactor Trips, IE Bulletins, Management Meetings, Licensee Event
Report Followup, and Security.
Results: Of the nine areas inspected, no violations or deviations were
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identified.
No significant safety items were identified.
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DETAILS
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1.
Persons Contacted
T. Elward, Plant Superintendent
- G. Petitjean, Planning and Administrative Services Superintendent
- G. Withrow, Engineering Maintenance Superintendent
- R. Alexander, Technical Engineer
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- R. Abel, Production and Plant Performance Superintendent
L. Monshor, Quality Assurance Superintendent
D. Staton, Shift Supervisor
W. Trubilowicz, Operations Supervisor
- J. Beer, Chemistry / Health Physics Superintendent
D. Kelly, Maintenance Supervisor
D. Ball, Maintenance Supervisor
W. Blosh, Maintenance Engineer
M. Acker, Senior Engineer
J. Toskey, General Engineer
L. Darrah, Shift Supervisor
J. Ho,an, Shift Supervisor
R. Scheels, Shift Supervisor
J. Boss, Reactor Engineer
The inspector also contacted other licensee personnel in the Operations,
Maintenance, Radiation Protection and Technical Departments.
- Denotes those present at exit interview.
2.
Operational Safety Verification
The inspector observed control room operations, reviewed applicable legs
and conducted discussions with control room operators during the
inspection period. The inspector verified the operability of selected
emergency systems, reviewed tagout records and verified proper return to
service of affected components. Tours of the containment sphere and
turbine building were conducted to observe plant equipment conditions,
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including potential fire hazards, fluid leaks, and excessive vibrations
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and to verify that maintenance requests had been initiated for equipment
in need of maintenance. The inspector by observation and direct interview
verified that the physical security plan was being implemented in
accordance with the station security plan.
The inspector observed plant housekeeping / cleanliness conditions and
verified implementation of radiation protection controls.
During the
inspection period, the inspector walked down the accessible portions of
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the Liquid Poison, Emergency Condenser, Reactor Depressurization, Post
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Incident, Core Spray and Containment Spray systems to verify operability,
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The inspector also witnessed portions of the radioactive waste system
controls associated with radwaste shipments and barreling.
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a.
On November 9 the licensee commenced a normal shutdown of the
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reactor to enter a scheduled outage of estimated four days duration
to repair Reactor Depressurization System (RDS) depressurization
valve top assemblies and repack RDS isolation valves. The facility
had operated for several weeks at approximately 0.6 gpm unidentified
leak rate, below the administrative limit of 0.8 requiring power
reduction and corrective measures.
Normal values for unidentified
leakage are approximately 0.3 gpm.
The unit was returned to service November 14 following a normal
startup.
Leak rate calculations performed at normal reactor
pressure and temperature following startup indicated RDS repairs had
been ineffective in reducing the unidentified leak rate. Unidentified
leak rate, which did not include that portion of RDS leakage which
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could be collected in specially constructed collection rigs mounted
on the RDS tail pipes, increased from 0.642 gpm on November 14
to 0.752 on November 20. During the shutdown a reactor scram
occurred. The event is discussed in Section 5 of this report,
b.
On November 22 following replacement of RDS depressurization valve
top assemblies on trains A and C, a startup was commenced. During
approach to criticality double notching was observed during withdrawal
on three different control rod drives and all drives were then fully
inserted in the reactor.
During normal rod drive withdrawal a relay
interrupts the withdrawal signal after a prescribed time interval,
thus limiting rod movement to one notch.
In this instance operators
observed the rod traveling two notches before settling into a new
position. An earlier instance of double notching on withdrawal
occurred during the November 14 startup but could not be duplicated
for investigation. The licensee investigated rod drive timing
relays and determined the timing relays were set within
specifications. During trouble shooting two additional drives
were observed double notching.
The licensee experimented with different reactor recirculation
pump discharge valve positions, and during testing identified
three additional double notching drives.
Testing results indicated
that because the rod drive water discharges to the suction of
recirculation pump No. 2, fully opening the pumps discharge valves
reduced the back pressure on the rod drive system, permitting faster
rod drive water flow and resultant faster rod travel time.
For
those drives with rate set valves adjusted to permit relatively fast
rod travel time of approximately 25 seconds, the increased rod drive
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flow rate caused the drive to travel past the first notch before the
timing relay could interrupt the operation.
The licensee retested
all drives and adjusted rate set valves as indicated by test results
conducted with recirculation pumps at full flow with the discharge
valve fully open. Normally, rod drive timing and any required
adjustments are performed during refueling outages with the reactor
head removed and recirculating pumps idle.
The licensee undertook
an evaluation of procedures controlling rod drive operation and
testing to determine the effects of testing at plant conditions not
representative of those seen at power operation.
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Rod drive diagnostic testing revealed two drives which exceeded
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Technical Specifications 5.2.2 (a)(IV).
The specification limits
the speed of control rod drives withdrawal to 23 seconds minimum
for continuous travel over the full length of the stroke.
Drive B-1 timing was 22.6 seconds and drive D-2 was found to be
21.7 seconds.
The increased flow of control rod drive water as
described above was the apparent explanation.
The reactor physic.s
package for the current cycle calculates that a free fall rod
withdrawal, which withdraws the rod from full in to full out in
0.60 seconds, does not exceed the maximum allowable deposited
enthalpy specified by the fuel vendor.
Because the 21.7 second
withdrawal time of drive D-1 is well within the limiting criteria
for the rod free fall accident, the licensee concluded no fuel
damage would have resulted had the drive been fully withdrawn in a
continuous motion.
During normal operation rods are withdrawn one
notch at a time.
The licensee adjusted both drives.
Drive B-1 was
adjusted to 30.5 seconds and drive D-2 was reset to 29.0 seconds as
tested with recirculation pumps at full flow with discharge valves
fully open.
Reactor startup was commenced at 1:00 a.m. November 23,
but was interrupted by a reactor scram at 2:47 a.m.
That scram is
described in Section 5.b of this report.
The reactor was
successfully restarted following repairs to nuclear instrumentation.
During the period November 23-25 the inspector interviewed operators
on several shifts to verify each operator was fully versed in the
observed control rod malfunction, the identified cause, and corrective
action.
The inspector determined that operators performing startup
activities, while aware of instances of double notching of control
rods, were in some instances not aware of the effect of recirculation
pump discharge valve position on rod travel times.
The licensee,
when informed by the inspector, immediately placed a requirement in
the Daily Orders for operators to review the Deficiency Report
describing the event and its resolution.
The inspector noted that during the several startups and shutdowns
and scrams occurring during the period November 9-23, operators
consistently performed the evolutions and required responses in
accordance with procedural requirements and without operator error
or lapses in administrative control.
c.
On December 2 the inspector observed portions of the reactor shutdown
initiated in response to indications of steam leakage in the pipe
tunnel.
Immediately upon receipt of control room alarms from dew
cells located in the pipe tunnel and visual verification of steam
visible from the turbine deck operators commenced power reduction
to permit pipe tunnel entry for inspection.
Area radiation monitors
and sustained elevated offgas release rates were not observed because
of the prompt power reduction.
Inspection revealed through-the-wall
erosion in the shell of the low pressure side of the high pressure
feed heater.
Reactor power was further reduced to permit
nondestructive testing and repair of the defect. The reactor was
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maintained above 212 F and the shutdown cooling system was in
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operation during the maintenance period. Testing and corrective
maintenance is described in Section 3 of this report.
Upon completion of repair activity the reactor reached criticality
at 5:13 a.m. December 7 and the turbine was synchronized at 10:27 a.m.
During startup activities daily water chemistry sampling required by
Technical Specifications was delayed approximately two hours when'
calibration of feedwater instrumentation resulted in prohibition
of containment access.
No violations or deviations were identified in this area.
3.
Monthly Maintenance Observation
Station maintenance activities of safety related systems and components
listed below were observed / reviewed to ascertain that they were conducted
in accordance with approved procedures, regulatory guides and industry
codes or standards and in conformance with technical specifications.
The following items were considered during this review:
the limiting
conditions for operation were met while components or systems were
removed from service; approvals were obtained prior to initiating the
work; activities were accomplished using approved procedures and were
inspected as applicable; functional testing and/or calibrations were
performed prior to returning components or systems to service; quality
control records were maintained; activities were accomplished by
qualified personnel; parts and materials used were properly certified;
radiological controls were implemented; and, fire prevention controls
were implemented.
Work requests were reviewed to determine status of outstanding jobs and
to assure that priority is assigned to safety related equipment maintenance
which may affect system performance,
a.
On October 28 during a routine tour the inspector identified steam
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rising from the top assembly of B RDS depressurization valve,
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Investigation revealed steam escaping from a stud used to bolt
the top assembly to the body of the valve.
The licensee, as part
of repair activities on RDS valves during the outage commencing
November 9, performed cleaning and nondestructive testing of the
mating surfaces between the two valve components.
Leakage at the
stud was not observed following repairs.
b.
On November 9 and 10 the inspector observed disassembly and
inspection of RDS depressurization valves A and B following top
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assembly removal.
Based on direct observation and discussion with
licensee personnel the inspector determined that the seat had
visible cracks, the disc was visibly worn from being used as a
lapping tool during previous repairs, and discolorations in both
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disc and seat showed evidence of steam leakage. Original valve
design calls for seat angle to differ from disc angle, but long term
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use of the disc to lap the seat had resulted in nearly the same
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angle for both disc and seat.
The inspector questioned the use of
a stellite disc to lap a stellite seat and was informed by the
licensee that a cast iron lapping tool would be fabricated for
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future use. The inspector identified to the licensee a visiblo flat
spot or depression on the face of the B yalve's disc, but subsequent
blue checks during reassembly showed it to be outside the seating
area.
The inspector verified that the licensee had devised and implemented
an acceptable system for verifying correct reconnection of
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electrical leads on both valve coils as discussed in Section 4.a of
Report No. 155/87023.
c.
On November 10 the inspector observed testing of steam drum relief
valve serial Number A-5.
The single stage spring loaded relief
valve was removed from service for testing to satisfy a commitment
made by the licensee to verify the operability of steam drum relief
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valves following repeated occurrences of disc to seat adhesion that
resulted in as-found set points approximately 200 psi above
specification.
Incidents of unacceptable relief valve performance
and licensee corrective actions are detailed in Section 4.a of
Report No. 155/87011.
Valve No. A-5, one of six installed on the steam drum as
primary plant overpressure protection, has a specified setpoint
of 1535 psig +/- 15 psig. Testing was performed using compressed
nitrogen and at ambient temperature in accordance with Surveillance
TR-28 Testing of Steam Drum Relief Valves. As-found lift pressure
was 1484.6 psig, 50.4 psig below set point and 35.4 psig below
tolerance. A second test established repeatability at 1488.1 psig.
The adhesion of disc to seat which resulted in elevated lift
pressures during tests earlier in 1987 was not in evidence.
During the test the inspector questioned the procedural requirement
of Surveillance TR-28 to reposition the nozzle blow down ring from
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position 18 to position 2 prior to the as-found test.
The technical
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justification of the long standing practice could not be established
by the licensee.
The licensee maintained that the valve manufacturer
concurred with the adjustment. The inspector provided the licensee
with data from LER 83-74 (valves failed to meet "as found" acceptance
criteria) describing the Palisades Plant's experience with main steam
relief valve as-found setpoints above the specified limit. The
licensee attributed the palisades malfunction to adjustments made to
each valve's blowdown ring prior to as-found testing.
The Palisades
procedure was revised to eliminate the requirement for blowdown ring
adjustment.
To address the inspector's concern the licensee on November 11
performed two additional lift tests on Valve No. A-5 in an effort to
demonstrate that blowdown ring position has no effect on set point.
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The first lift was made with the blowdown ring at position 2 and
results were consistent witn the tests performed November 10.
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second test was conducted with the blowdown ring at its normally
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installed position number 18 and resulted in no appreciable
difference in lift points. The inspector questioned the validity of
any engineering judgements made on the basis of these additional
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lift because (1) the tests did not determine the as-found condition
of the valve, (2) seat leakage through the valve's disc and seat was
observed at a pressure well below the lift point, indicating the
repeated testing had prevented reestablishment of the disc to seat
seal typical of the as-found valve condition, and (3) the valve body
had cooled significantly from the previous day's testing.
On November 11 the Plant Review Committee convened to assess the
safety significance of the low setpoint found on valve A-5.
The PRC
concluded that the 1484.6 psig setpoint would not impede operation
of the emergency condenser, which operates at 100 psig above reactor
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pressure of 1335 psig and approximately 100 psig below steam drum
relief valve setpoints. The liquid poison system, which operates on
siphon effect was expected to operate normally. A relief valve with
a low setpoint thit might stick in the open position represents a
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loss of coolant accident that is an analyzed accident condition
against which the plant is protected. Applicable industry codes do
not address setpoint test results below the setpoint. As a
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conservative measure to verify the disc to seat adhesion phenomenon
was not in evidence the licensee elected to remove and test a second
steam drum relief.
Valve No. A-4 was tested using Surveillance TR-28
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with the blowdown ring in position 2.
The valve has a specified
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lift point of 1585 +/- 15 psig and lifted on the as-found test at
1581.9 psig.
A review by the inspector and Region III concluded that the disc to
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seat adhesion was not in evidence and that the low relief valve
setpoint did not impose an undue safety hazard while installed in
the plant. The testing of at least one additional relief valve
during the upcoming refueling outage in approximately 90' days will
be observed to determine if the low setpoint on valve A-5 was an
isolated incident or is represeritative of a programmatic deficiency
in the licensee's testing or setpoint calibration methodology. The
licensee committed to resolve the apparent conflict between Palisades
and Big Rock procedures that address position of the blowdown ring
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and its effect on valve setpoint.
The licensee is considered to
have met all commitments made to the staff concerning relief valve
testing arising from the concerns over disc to seat adhesion and
resultant high relief valve setpoints.
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d.
The HP feed heater is a single pass U tube heat exchanger with high
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pressure feed water on the tube side and low pressure extraction
steam on the shell side.
Extraction steam is drawn off the turbine
and at full power is approximately 185 psig.
The heat exchanger is
constructed with an internal steam deflector to prevent direct
impingement of steam on the U-tubes. The licensee performed
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nondestructive testing and constructed ultrasound maps of the
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heat exchanger's shell in both of the locations where the internal
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deflector would cause the steam to erode the shell's interior
surface.
Dye penetrant testing was performed in the area of
the erosion to verify the defect had not developed into a
structural crack.
The' turbulence resulting from the deflected
steam eroded the shell side metal from the inside, reducing it from
a nominal 0.562 inch thickness to as little as 0.047 - 0.097 inches
in the area adjacent to the defect.
The licensee welded the eroded area and constructed a patch from
0.25 inch steel rolled to the contour of the 30 inch diameter of the
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heat exchanger's shell.
The patch was sized to cover the areas on
both sides of the shell where ultrasound tests indicated wall
thinning, and was welded directly to the shell material. Attempts
were made to inspect the heater's interior for corrosion and
structural damage using a baroscope, but the restrictive contours of
the internal deflector prevented access. Wall thicknesses were
verified in the area of the only other deflector in the HP feed
heater and were also verified in the areas of possible erosion on
the low and intermediate pressure feed heaters. The licensee
expects to perform major repairs to the HP feed heater and
extraction line during the 1988 refueling outage.
Prior to startup December 7 the licensee unsuccessfully attempted to
hydrostatically pressure test the heat exchanger's shell side.
Several leaking valves prevented reaching test pressure. Visual
inspections of the repaired area were conducted during startup. A
humidity indicator with remote read out and a chart recorder was
installed in the area of the repairs to detect minor leakage.
The
licensee was sensitive to the need for limited personnel access
to the heat exchanger, which is located in the locked pipe tunnel
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not normally accessible during operation except for weekly
inspections.
No violations or deviations were identified in this area.
4.
Surveillance Observation
a.
On November 13 the inspector observed performance of
Surveillance TV-07, Control Rod Drive Scram Test from Notch 23.
The surveillance, which is performed prior to startup to verify
the ability of each control rod to scram from the full out position,
was successfully completed in accordance with procedural requirements.
b.
On November 13 the inspector observed from the control room the
performance of Surveillance T90-12, Reactor Depressurization System
(RDS) Valve Test.
The surveillance involves pressurization of
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portions of RDS piping to normal plant pressure (1335 psig) with
compressed nitrogen and actuation of the RDS depressurization valve
from the control room. A strip recorder verifies depressurization
of the test pressure when the valve is actuated.
The test was
successfully completed in accordance with procedural requirements.,
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c.
The inspector on November 17 reviewed the licensee's preparations
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for cold weather.
The inspector observed preparations which had
been completed and documented on the licensee's cold weather check
off sheet in the screen house, diesel generator room, sphere
ventilation shed and turbine building.
The inspector reviewed
maintenance orders issued to repair inoperable air louvers in the
turbine room,
d.
On November 25 the inspector observed performance of monthly
surveillance T30-22, ECCS Valve Test.
The surveillance verifies the
operability of four core spray valves.
The test was performed in
accordance with procedural requirements.
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5.
a.
On November 9, approximately three hours into a normal shutdown and
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with the reactor subcritical at approximately 15 x 10-3 per cent
power, the reactor tripped on a spurious upscale /downscale signal.
The trip occurred during downscaling of the three picoammeter
channels. With picoammeter No. I downscale with a downscale alarm
inserted, channel No. 3 was downscaled. A spurious high flux signal
caused the trip signal.
The susceptability of reactor trips from
spurious upscale /downscale signals with their origin in picoammeter
circuitry is a long known operating characteristic of the facility
associated with electrical noise at very low power levels. All
partially withdrawn control rods inserted fully and all systems
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functioned normally.
The licensee made the required notifications.
b.
On November 23 at 2:47 a.m. the reactor tripped during approach to
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criticality. With the reactor slightly subcritical operators
observed fluctuations in intermediate range channel 5 period
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indications ranging from +30 seconds to -100 seconds.
The second
intermediate range channel displayed no such fluctuation, and with
reactor power sufficient to register in the lower ranges of power
range instrumentation, operators observed no power level oscillations.
While ender observation by operators the reactor tripped on short
period. All systems functioned normally and the required
notifications were completed.
Cause of tne erratic indication was
determined to be electronic failure of channel 5 nuclear
instrumentation. The circuitry was replaced and tested and restart
commenced at approximately 1:00 p.m. November 23.
No violations or deviations were identified in this area.
6.
Management Meeting
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On October 21 the licensee participated in a management meeting with
members of the Region III staff in Glen Ellyn. During the meeting the
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licensee discussed the implementation of the trial Enhanced Performance
Incentive Program implemented approximately 18 months ago to provide
reduced site Quality Assurance department involvement with selected site
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departments who have demonstrated exemplary performance in meeting
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quality assurance requirements.
The licensee reviewed the program
philosophy and requirements, described the audits, surveillances, and
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inspections performed during the trial period, and proposed the
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formalizedcontinuationoftheprogramthroughachangeintheTopical
Report (CPC-2A). The staff concurred in the licensee s plan to continue
the program for the one site department now participating pending review
of the proposed CPC-ZA changes.
The licensee presently has no additional
candidates for the reduced involvement program.
7.
Licensee Event Reports Followup
Through direct observations, discussions with licensee personnel, and
review of records, the following event reports were reviewed to determine
that reportability requirements were fulfilled, immediate corrective
action was accomplished, and corrective action to prevent recurrence had
been accomplished in accordance with technical specifications.
By letter dated November 12 the licensee submitted Licensee Security
Event Report (BRP-87-01.5), Vital Area Barrier Breach, required by
10 CFR73.71(c). Contents of the report contain safeguards information
exempt from public disclosure in accordance with 10 CFR73.21(c). The
event is the subject of Inspection Report No. 155/87021(DRSS) and was
discussed with the licensee at an enforcement conference in Region III
on October 21, 1987.
The LER is considered closed.
By letter dated November 13 the licensee submitted Revision 3 to
LER 87-003, Inoperable Primary System Safety Valves. The LER was
submitted as an informational update to report the results of safety
valve testing conducted November 10-11. The update documented that test
results showed no evidence of disc to seat adhesion that earlier had
resulted in lif t points above specification. These elevated lift points
were the subject of the original LER submittal. A detailed description
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of the November 10-11 testing is presented in Section 4.c of this report.
The LER and Revision 3 are considered closed.
By letter dated December 1 the licensee submitted LER 87-011, Reactor
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Trip-Spurious Upscale /Downscale trip. The reactor trip occurred
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November 9 during a shutdown to perform RAS top assembly replacement.
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The event is described in Section 6.a of this report.
The LER is
considered closed.
8.
Security
a.
On December 8 the inspector observed a site employee enter the site
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with a sheathed knife normally used in outdoor sports. The inspector
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questioned the need to bring into the protected area a device which
was not a work related tool and which could be perceived as a weapon.
Interviews with several security officers revealed an inconsistency
among officers regarding the admissibility of knives of that
description. The licensee elected to prohibit the knife's entry
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and, at the ir.spector's request, committed to develop a prohibited
items list and provida clear instructions to security officers on
what items are prohibited from the site,
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b.
On December 9 the inspector observed through the window in the door
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to the Central Alarm Station (CAS) the security supervisor on watch
to have the appearance of inattentiveness.
Specifically, the interior
lights had been switched off, the supervisor _was in a fully reclined
position in his chair -with his feet up on the panel, and for a period
of several seconds his eyes were observed to be closed. The inspector
informed licensee management.
The supervisor was interviewed by the
licensee and counselled on the importance of professional conduct
and the appearance of attentiveness at all times. The licensee
committed to develop and implement a policy which clearly conveys to
security personnel staffing alarm stations expectations for
appropriate behavior to ensure attentiveness while on duty.
9.
Bulletins
As required by I.E.Bulletin 87-02, Fastener Testing to Determine
Conformance With Applicable Material Specifications, the inspector
participated with the licensee in the selection of 20 samples of safety
and non-safety related fasteners from current stock.
Nuts were included
for all fasteners selected.
The inspector noted that because the
licensee's procurement practices result in nearly all fasteners being
purchased as safety grade stock, only seven of the ten required non-safety
samples available on site. Using guidance from the Staff's Tethnical
contact, the inspector requested that the licensee obtain an additional
three samples of safety grade fasteners to satisfy the requirement
for 20 samples.
10.
Exit Interview
The inspector met with licensee representatives (denoted in Paragraph 1)
throughout the month and at the conclusion of the inspection period and
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summarized the scope and findings of the inspection activities.
The
licensee acknowledged these findings.
The inspectcr also discussed the
likely informational content of the inspection report with regard to
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documents or processes reviewed by the inspector during the inspection.
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The licensee did not identify any such documents or processes as
proprietary.
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