ML20126B447
| ML20126B447 | |
| Person / Time | |
|---|---|
| Site: | Point Beach  |
| Issue date: | 12/08/1992 |
| From: | Jackiw I NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20126B431 | List: |
| References | |
| 50-266-92-23, 50-301-92-23, NUDOCS 9212220090 | |
| Download: ML20126B447 (17) | |
See also: IR 05000266/1992023
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Report No. 50-266/92023(DRP); 50-301/92023(DRP)
Docket No. 50-266; 50-301 License No. DPR-24; DPR-27
Licensee: Wisconsin Electric Company
231 West Michigan
Milwaukee, WI 53201
Facility Name: Point Beach Units 1 and 2
Inspection At: Two Rivers, Wisconsin
Dates: October 13 through November 22, 1992
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Inspectors: K. R. Jury
J. Gadzala
G. F. O'Dwyer
Approved By: / /24 * M Y 'f,2.
T.A. Jackiv,' Chief rate
Reactor Pr4jects Section 3A
Inspection Summary
Jnspection from October ~13 throuah November 22. 1992
(Recorts No. 50-266/92023(DRP): No. 50-301/92023(DRP)
Areas-Inspected: Routine, unannounced inspection by resident inspectors of
corrective actions on previous findings; plant operations; radiological-'
controls; maintenance and surveillance; emergency preparedness;. security;-
engineering and technical support; and safety assessment / quality verification.
Results: One violation of _NRC requirements was identified. An Executive
Summary Follows.
Plant Operations
On October 14, the Unit 1 " white" instrument bus inverter failed and caused a
plant transient due to loss of power to the reference- temperature circuit
(paragraph 3.a.).
Unit 2 completed a'52-day refueling outage (number 18) and was placed on line
November 18. Due to the additional steam generator tube plugging performed
during the outage, the unit is only able to achieve 98.7 percent power. At
9212220090 92120B
PDR- ADOCK 05000266
G PDR
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the end of the report period, reactor power was being maintained at 95 percent
due to reduced reactor coolant system flow rates (paragraph 3.b.).
A strength was identified in the pre-evolution briefings performed prior to
mid-loop operations, steam generator crevice flushing, and Unit 2 startup
(paragraphs 3.b.).
During Unit 2 refueling operations, effective communications were maintained
between the control room, the refueling level in containment, and spent fuel
pit personnel (paragraph 3.c.).
Maintenance / Surveillance
A violation was cited for a failuce to follow a surveillance procedure during
performance of a loss of voltage relay test on October 26, resulting in
deenergization of 4160 VAC safeguards bus 2A06 and 480 VAC safeguards bus 2B04
(paragraph 4.b.).
The gas turbine overhaul was completed and post maintenance testing was
conducted. The generator was load tested October 16, and post maintenance
testing was completed October 24 at which time G05 was declared back in
service. The temporary skid mounted diesel generator (G10) remains in place
pending completion of G05 reliability testing (paragraph 4.a.).
Emeraency Preparedness
An emergency pre,'aredness medical exercise was conducted November 20
(paragraph 5.).
Enaineerina and Technical Support
On October 20, the plant identified that one breaker affected by the Unit 2
non-safeguards equipment electrical lockout relay for 480 VAC safeguards bus
2B04 did not open as required during testing (paragraph 6.a.).
Two unit specific non-safety related 60 cell station batteries, ID-205 and
2D-205, were installed during the current outage to allow the plant to remove
non-safety loads from safety related station batteries 0-05 and D-06
(paragraph 4.b.).
Safety Assessment /0uality Verification
Outage risk assessment initiatives failed to recognize the potential impact of
performing a surveillance during reduced inventory conditions (paragraph
7.a.).
On November 20 the Nuclear Powet Otpartment announced a reorganization of the
corporate office (paragraph 7.b.).
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DETAILS
1. Persons Contacted-
G. J. Maxfield, Plant Manager
J. C. Reisenbuechler, Manager - Operations & Technical Support
T. J. Koehler, Manager - Maintenance & Engineering
N. L. Hoefert, Manager - Operations
- J. G. Schweitzer, Manager - Maintenance
W. B. Fromm, Sr. Project Engineer - Construction & Engineering
J, A. Palmer, Manager - Instrument & Controls
- W. J. Herrman, Manager - Technical Services
J. J. Bevelecqua, Manager - Health Physics
- J. F. Becka, Manager - Regulatory & Staff Services
- R. J. Chojnacki, Coordinator - Emergency Planning
- F. A. Flentje, Administrative Specialist
Other company employees were also contacted including members of the
technical and engineering staffs, and reactor and auxiliary operators.
- Denotes the personnel attending the management exit interview.
2. Corrective Action on Previous Inspection Findinns (92701) (92702)
a. LClosed) Violation (301/92014-01): Excessive Cooldown of the
On May 27, 1992, the technical specification cooldown rate of
100 F/hr (56 C/hr) was exceeded during performance of Refueling
Procedure RP-68, " Steam Generator Crevice Cleaning." The largest
cooldown over a one hour period was 141 F (78" C). Additionally,
the procedure did not prescribe adequate instructions to prevent
exceeding the maximum heatup and cooldown rates. -A civil penalty
was imposed for these violations.
An analysis was performed by the reactor vessel's vendor to
evaluate the effects of the cooldown transient. This analysis
calculated that the ratio of the crack initiation toughness to the
total stress intensity factor was 1.18. Since this ratio was
greater than 1.00, it was concluded that the structural integrity
of the vessel was assured and that acr7ptable margins of-safety
would be maintained during subsequent operations.
As corrective measures, the operators involved with this event
were disciplined and Procedure RP-6B was rewritten to provide
adequate guidance for conducting crevice cleaning. The changes
implemented for this evolution included: lowering the temperature
band at which steam generator cleaning is performed from 290-300 F
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(143-149 C) to 240-250 F (116-121 C); operating reactor coolant
i- pumps throughout the boiling period to make up for heat losses;
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maintaining component cooling water temperatures at elevated
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levels to minimize heat removal during the operation; assigning an
additional-licensed operator to plot heatup and cooldown rates and
a third senior reactor operator to supervise the entire evolution;
and precautions were added to the procedure to emphasize both the
administrative and technical specification cooldown and heatup
limits, and to clarify actions required if limits are exceeded. 1
Additionally, the licensee effectively implemented applicable
portions of procedure PBNP 3.4.19, " Infrequently Performed Tests
or Evolutions"'(see paragraph 3.b. for additional details).
The inspector reviewed the revised procedure _and observed steam
generator crevice cleaning performance utilizing the revised
process on November 13, during the Unit 2 refueling outage. Plant
management presence was noted during the evolution, reactor
coolant system temperatures were maintained within administrative
limits, and the evolution was strictly controlled. Further
concerns were not identified and this item is closed,
b. (Closed) Violation (301/92014-02): Deprivation of Required Decay
Heat Removal Capability
On November 10, 1991, all residual heat removal and reactor
coolant loops were secured while fuel was in the core and reactor '
coolant temperature was between 140 F and 350 F, contrary to
technical specification requirements. This violation occurred ,
during steam generator crevice cleaning when the pumps were I
secured to prevent excessive cooldown of the reactor coolant
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system.
The corrective actions discussed in item 2a. encompass this
violation as well as the violation discussed above. - As such, this
item is closed.
c. (Closed) Unresolved Item (266/92015-02): Instrument Cabinet
Seismic Mounting Adequacy
On-August 18, 1992, the plant discovered that Unit I analog.
instrumentation racks were not adequately seismically mounted.-
These racks were consequently declared inoperable, requiring entry
into a three-hour limiting condition for operation (LCO) as the
configuration was outside of the TS and plant design bases. The
company requested and was granted a temporary waiver of compliance. ,
from this LC0 for a period of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> to effect repairs on the R
cabinets without requiring the unit to be subjected.to a thermal ;
transient by shutting it down. '
-These cabinets were installed during initial plant construction
and their mounting configuration is not believed to have-changed
since that time. This condition was initially identified in late
June 1992, as part of a formal plant initiative. Plant
management's initial determination was that the existing hold down
clips were adequate to restrain the cabinets in the event of a
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safe shutdown earthquake (SSE). A detailed evaluation
subsequently determined that the clips were inadequate to restrain
the cabinets during an SSE.
The general adequacy of the licensee's seismic design was reviewed
by an NRC contractor preoperationally'as documented in Appendix D
of the NRC's Safety Evaluation of the Point Beach Nuclear Plant,
dated July 15, 1970. The review noted that some control room
cabinets were not bolted to the floor but did not identify the
seismic inadequacy of the design.
The plant's corrective action for the mounting inadequacy
consisted of bolting angle irons to the base of the cabinets on
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the two long sides of each row. The angle irons were then bolted
to the concrete floor using concrete expansion anchors. Work was
completed within the 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> allowed by the temporary waiver.
The inspectors monitored installation of the new mounting brackets
and verified implementation of compensatory measures. Further
concerns were not identified and this item is closed.
d. (Closed) Unresolved Item (266/92004-02): Loss of Normal Boration
Flow Path
On January 20 and May 9,1992, two similar blockages occurred in
the normal boration flow paths for Unit I and Unit 2 respectively.
Heat tracing circuits in a section of piping were controlling
temperature below the normal setpoints and the boric acid.in these
sections crystallized. Heat lamps were used to return the boric
acid to solution and the heat tracing thermostats-were adjusted.
Insulation was also improved on these sections of piping. The
emergency boration flow path was verified to have remained
operable in all cases.
To ensure that additional flow blockages do not go undetected, a
weekly surveillance was added to require that boration' flow paths
be physically verified by a flow check.: The inspector reviewed
the plant's corrective actions and did not have additional
concerns. This item is closed.
e. (Closed) Unresolved Item (266/92004-03): Control of Axial Flux
Difference (AFD)
On August 16, 1990, and January 20, 1992, a turbine runback caused
AFD to appear to transcend its control band. Operators were not
able to return AFD to its control band within the required 15
minute interval based on plant process computer indication, even
though control board indications showed AFD returning to its
control band within 15 minutes. The reason for the disparity is
the approximately two minute delay time inherent in the' process
computer indication due to its time weighted algorithm for this
parameter.
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To correct this problem, a modification was installed in
September 1992 to update the computer software to increase the
sample frequency for AFD so the computer indication will not
substantially lag the actual AFD value. The revised calculation,
instead of using a one-minute average of nuclect instrument
readings and updating the display once per minute, now uses
current nuclear instrument readings and updates the display once
every four seconds. The technical specification basis regarding
AFD was changed to reflect the updated operation of the process
computer. The inspector revi'wed these changes and did not have
further concerns. This item is closed.
f. (Closed) Violation (266/92004-04): Inadequate Independent
Verification
A Unit 1 turbine runback was caused on January 20, 1992, by an
elet .rician inadvertently installing a jumper across two terminals
in the wrong breaker cubicle. Activities to verify that the
jumper installation conformed to procedural requirements were not
adequately performed. The personnel involved were counselled
regarding their actions and other maintenance electricians were
informed of this event.
To prevent recurrence, the plant revised the Point Beach " Writer's
Guide for Maintenance Procedures", to implement a concurrent
verification system. Information concerning human factors issues
was also expanded. Although the procedure used during this event
was determined to have been accurate, it was deemed that
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additional information on the specific location of the terminals
to be jumpered may have prevented the improper jumpering.
Consequently, the Writer's Guide was also revised to require that
a more detailed description of jumper locations be provided. The
inspector reviewed the Writer's Guide changes and did not have
further concerns. This item is closed.
3. Plant Ooerations (71707) (60710) (93702)
The inspectors evaluated licensee activities to confirm that the
facility was being operated safely and in conformance with regulatory
requirements. These activities were confirmed by direct observation,
facility tours, interviews and discussions with liceasee personnel and
management, verification of safety system status, and review of facility
records.
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l To verify equipment operability and compliance'with technical
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specifications (TS), the inspectors reviewed shift logs, Operations'
records, data' sheets, instrument traces, and records of equipment
mal functions . Through work observations and discussions with Operations
staff members, the inspectors- verified the staff was knowledgeable of
plant conditions, responded promptly and properly to alarms, adhered to
procedures and applicable administrative controls, was cognizant of in
progress surveillance and maintenance activities, and was aware of
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inoperable equipment status. The inspectors performed channel
verifications and reviewed component status and safety related
parameters to verify conformance with TS. Shift char.ges were observed,
verifying that system status continuity was maintained and that proper i
control room staffing existed. Access to the control room was
restricted and operations personnel carried out their assigned duties in.
an effective manner. The inspectors noted professionalism in most
facets of control room operation.
Plant tours and perimeter walkdowns were conducted to verify equipment
operability, assess the general condition of plant equipment, and to
verify that radiological controls, fire protection controls, physical
protection controls, and equipment tag out procedures were properly
implemented,
a. Unit 1 Operational Sta.tg
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l The unit continued to operate at full power with the exception of
l power being briefly reduced to 75 percent on October 24 as a
l precautionary measure during installation of the new swing battery
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into the DC distribution system.
! On October 14, the " white" instrument bus inverter, IDYO3, failed.
This initiated a plant transient due to loss of power to the
reference temperature circuit, which caused control rods to drive
, in. Control operators promptly identified the cause of the
transient and responded by taking manual control of control rods
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and shifting " white" instrument busses to the swing inverter,
j DYOC. Transferring the affected bus to the swing inverter
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restored' instrument power and allowed operators to restore control
c systems to normal alignment. The plant is in the process of
installing automatic bus transfer devices to prevent inverter
failures from leading to major plant transients. The inspector
discussed this event with plant personnel and did not have further
Concerns.
! b. Unit 2 Operational Status
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The unit completed a 52-day refueling outage (number 18),
achievirq criticality on November 16. It was placed on line
November 18 and reached 98.7 percent power hvember 21. Due to
the additional steam generator tube plugging performed during the
outage the unit was only able to achieve 98.7 percent power with
all four turbine governor valves fully opened and Tavg at the
midpoint of the normal operating band. Equivalent tube plugging
levels for the Unit 2 steam generators were 12.9 percent for the A
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steam generator and 13.0 percent for the B steam generator. The-
l tube plugging also affected total reactor coolant system flow
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rate, which was determined to be 181,873 gpm at 95 percent power.
This is only 73 gpm above the minimum flow allowed by technical
specifications at rated power. Therefore power-was maintained at
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to 95 percent pending completion of engineering testing and
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analysis to verify flow rates and determine the minimum allowable
flow rates and the corresp9nding operating power level.
A strength was identified in the pre-evolution briefings performed
prior to mid-loop operations, steam generator crevice flushing,
and Unit 2 startup. These briefings were performed as part of
procedure PBNP 3.4.19, " Infrequently Performed Tests or
Evol utions . " The inspectors observed the pre-evolution briefings
and noted that they were sufficiently thorough and effective in
delineating the appropriate cautions, interfaces, expected plant
response, and operator actions. '
c. Refuelina activities
Effective communications were maintained between the control room,
the refueling level in containment, and spent fuel pit personnel
whenever changes in core geometry were taking place. On the
refueling floor, housekeeping was good and excellent control was
maintained to prevent loose objects from falling into the reactor .
vessel.
4. Maintenance / Surveillance Observation (62703) (61726)
a. Maintenance
The inspectors observed safety related maintenance activities on
systems and componerts to ascertain that these activities were
conducted in accordance with TS, approved procedures, and
appropriate industry codes and standards. The inspectors
determined that these activities did not violate LCOs and that
required redundant components were operable. The inspectors
verified that required administrative, material, testing,
radiological and fire prevention controls were adhered to.
Specifically, the inspectors observed / reviewed the following
maintenance activities:
- G05 gas turbine generator overhaul
The gas turbine overhaul was completed and post maintenance
testing was conducted. The generator was . load tested
October 16 and post maintenance testing completed October
24, at which time G05 was declared back in service.
Reliability testing to meet the station blackout rule was
then initiated, which includes twice per week starting and
loading of G05 until attainment of 95 percent reliability
can be demonstrated. The licensee's acceptance test program
consists of completion of-20 tests with two or fewer
failures as specified in Wisconsin Electric Company's letter
to the NRC dated July 23, 1992. The test program is
detailed in procedure PBNP 3.2.15, " Gas Turbine Generator
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(G-05) Reliability Program". The temporary skid mounted
diesel generator (G10) remains in place pending completion
of G05 reliability testing. See Inspection ~ Reports 50- '
266/92024; 50-301/92024 for additional details.
- G02 emergency diesel generator glycol heater replacement
The plant coordinated removal of G02 from service with
restoration of the G05 gas turbine generator and completion
of reduced inventory operation on Unit 2.
- Unplanned Maintenance Work Request (UMWR) 1559, " Replace N11
terminal strips"
Terminal Nll is associated with circuitry that ensures non-
safety related loads are shed from the safeguards buses
after a safety injection signal.
- MWR 925497, " Disassembly of Valve 2SI-825A"
Valve 2SI-825A, the refueling water storage tank (RWST)
outlet valve to the safety injection pumps, was disassembled
to allow insertion of a camera to boroscopically inspect the
Unit 2 common suction line between this valve and the RWST.
During insertion or withdrawal, the camera and its cabling
were not rotated to insure that all 360 degrees of the -
piping walls were being inspected. The inspectors discussed
this concern with the licensee and they confirmed the
boroscoping of this piping section was not adequate.
- RMP 153 (Revision 2), SI-853A Check Valve Inspection, Unit 2
RMP 161 (Revision 2), SI-853C Check Valve Inspection, Unit 2-
This procedure was performed to identify and correct the
cause of these Event-V valves failing leak testing. A mock-
up was built to provide maintenance technicians with
familiarity in valve-internals repair. Repairs were
coordinated and conducted well, resulting in all affected
valves passing subsequent leak tests,
b. Surveillt.nce
The inspectors observed certain safety related surveillance
activities on systems and' components to ascertain-that these
activities were conducted in accordance with license requirements.
For the surveillance test procedures listed below, the inspectors
determined that precautions and 1.COs were adhered to, the required
administrative approvals and tag-outs were obtained prior to test-
initiation, testing was accomplished by qualified personnel in
acccrdance with an approved test procedure, test instrumentation
was properly calibrated, the tests were completed at the required
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frequency, and that the tests conformed to TS requirements. Upon
test completion, the inspectors verified the recorded test data
was complete, accurate, and met TS requirements; test
discrepancies were properly documented and rectified; and that the
systems were properly returned to- service.
Specifically, the inspectors witnessed / reviewed selected portions
of the following test activities:
- RMP 74 (Revision 4) B Train Degraded and Loss of Voltage
Relay Test, Unit 2 (Monthly)_
During performance of this test on October 26, a maintenance
electrician did not open an isolation knife switch as
required by the procedure prior to depressir.g the relay test
button. This caused an undervoltage signal to be _
transmitted to 4160 VAC safeguards bus 2A06 and consequent ,
deenergization of that bus. The 480 VAC~ safeguards
bus 2B04, which is powered by bus 2A06, was also
deenergized. Emergency diesel generator G02 started as
required and energized bus 2A06.
RMP 74, step 3.2.1, directs that the knife switch cover be
removed, +he knife switch be opened, and a test point cover
be remov A caution statement preceding this step warns
that testing with the knife switch closed will trip the
associated bus power supply. Additionally, a similar
warning is printed adjacent to the relay test push button.
At this step, the electrician performing the test decided to
assist his helper by removing one cover while the helper
removed the other one. The electrician then initialed for
completion of that step without realizing.that the knife
switch had not been opened. This is a violation of
Technical Specification 15.6.8, which requires that=the
plant be operated and maintained in;accordance with approved
procedures (301/92023-01). Specific corrective actions--
regarding this violation had not_ been delineated by the end
of this inspection.
Unit 2 was in a reduced inventory condition at the time and
the 2P10B residual heat removal (RHR) pump was supplying
cooling water flow. Deenergization of bus 2004_resulted in
loss of power to this pump. Control operators _ responded by
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starting the 2P10A RHR pump and restoring cooling water flow
within one minute. After determining the cause of the-
safeguards bus loss, operators restored the electrical line-
up to normal and secured the emergency diesel. Additional
details surrounding this event are described in LER 92007
and paragraph 7.a.
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- RMP 203 (Revision 0) Station Battery 1(2)D-205
Performance Test
Station batteries10-205 and 20-205 are unit specific ne -
safety related 60 cell batteries that were installed i
the current outage. This allowed the plant to remove nu,
safety loads such as the main turbine emergency lube oil
pumps from safety related station batteries D-05 and D-06.
Reducing the loading profile on D-05 and D-06 increases
their design margin and thereby helps extend the life of the
station batteries to 20 years per IEEE Standard 485-1983,
"IEEE Recommended Practice for Sizing Large Lead Storage
Batteries for Generating Stations and Substations".
Reducing the loading profile on D-05 and D-06 is also
expected to obviate the need for battery service testing.
The plant's calculations show that performance discharge
tests alone will completely envelope the w)rst case duty
cycles for these batteries once the emergency lube oil pumps
have been removed from them. IEEE Standard 450, section
- i.2, allows a performance test to be used in lieu of a
st. ~ ice test when the performance test envelopes the service
test. Wisconsin Electric committed to install non-safety
batteries by December 31, 1992, in their letter to the NRC
dated September 11, 1992.
- Post modification stroke testing of Unit 2 main steam
isolation valves per IWP MR 91-210*A
- ORT 3 (Revision ~'i) Safety Injection Actuation with Loss
of Engineered Safeguards AC, Unit 2
- RMP 172 (Rev 0) Monitor Emergency Diesel Generator Fast
Start Voltage and Breaker Closure
This test was performed as a followup to ORT 3 (above) when
it was discovered that the G-01 emergency diesel ge.nerator
output breaker shut at a voltage of 2744 VAC. The minimum
specified voltage was 3744 VAC. One of two parallel speed
sensing relays in the output breaker closing circuit was
found to be actuating at too low an engine speed on the
diesel. The relay was adjusted and the test repeated
satisfactorily. The plant intends to temporarily increase
the periodicity of this annual test to evaluate any
potential drif t on the relay settings.
- TS-31 (Rev 13), High and Low Head Safety Injection Check
Valve Leakage Test (Cold Shutdown): Unit 2
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- 5. Emeraency Preparedness (71707)
An emergency preparedness medical exercise was conducted November 20.
The scenario involved a contaminated injured man requiring transport to-
an offsite hospital. The plant appropriately declared an Unusual Event
classification for this situation. The inspectors observed drill
conduct and significant concerns were not identified.
6. Enaineerina and Technical Support (71707) (37828) (71711)
The inspectors evaluated engineering and technical support activities to
determine their involvement and support of facility operations. This-
was accomplished during the course of routine evaluation of facility
events and concerns, through direct observation of activities, and
discussions with engineering personnel,
a. Electrical Lockout Relav Incorrect 1v Wired
On October 20, the plant found that the Unit 2 non-safeguards
equipment electrical lockout relay for 480 VAC bus 2004 was in the
tripped position. This relay is designed to strip nonessential
equipment from its associated electrical bus upon receipt of a
safety injection signal, to prevent overloading the emergency
diesel generator. Since Unit 2 was in a refueling outage at the
time, most of the equipment affected by this relay was already
shutdown. The trip of the lockout relay was believed to have been
. caused by inadvertent bumping of relay 2-SI21X by plant personnel
during as-built wire tracing of the safeguards relay racks. The
plant notified the NRC of this event as required.
One breaker affected by this relay did not open as required. This
breaker supplies motor control center MCC-821. The plant's
investigation of the failure of this breaker to open revealed that
the actuation signal wire leads-from_the lockout relay to the MCC-
B21 breaker were not connected. Therefore, the lockout relay was
incapable of tripping the MCC-B21 breaker. Based on the condition
of the electrical tape covering the wire lead terminations, the
plant believes that these wires were never connected during
original plant construction.
A review of wiring drawings and_ interviews with plant personnel
familiar with original plant construction, determined that MCC-821
had not always been powered from Unit 2 bus 2B04 (B train bus).
During Unit I construction, it became necessary to energize MCC-
B21 because it contained some minor loads required for Unit 1.
Since bus 2B04 had not yet been built, MCC-B21 was connected to
Unit 1 bus 1801 (A train bus). Later, during March 1970, its
power source was transferred to breaker "28C" in Unit 2 bus 2B04,
where it remains to date.
However, initial plans were apparently to transfer MCC-821 to
breaker "35A" in Unit 2 bus 2B03 (A train bus). This was
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evidenced by several terminals on the wiring being incorrectly
identified with the "35A" breaker prefix. The lockout relay
control switch terminal strip was labeled with the same "35A"
breaker prefix, as were the wire leads attached to it. The plant
theorizes that although the modification was subsequently changed
to transfer MCC-B21 to bus 2B04 vice 2003, the drawings and
installation procedure were not adequately revised. Consequently,
the wiring between the MCC-B21 breaker and its associated lockout
relay was never connected.
This error was never discovered during testing for two reasons,
first, the breaker supplying MCC-B21 is also designed to open on
undervoltage. Second, an additional wiring error resulted in a
lockout contact for load breakers in bus 2B03, being connected to
the MCC-821 control circuit. Thus, whenever loads were stripped
from bus 2B03 on a safety injection signal, this additional wiring
connection would cause MCC-821 to strip from bus 2B04.
Testing of bus stripping functions was performed-in two phases.
In the first phase, a safety injection signal is actuated
coincident with a loss of power to the safeguards busses. Since
the breaker supplying MCC-B21 is also designed to open on
undervoltage, this breaker opened during this phase of the test on
the undervoltage signal, even though it did not receive the safety
injection signal. Because the breaker opened, the test was
considered successful. Another phase of the test is initiated by
only inserting a safety injection signal. However, both safety
injection train signals are inserted simultaneously. According to
intended design, the A train signal strips loads from 2B03 while
the B train signal strips 2B04. Although, unbeknownst to
operators, the B train signal did not strip MCC-821-from 2B04,
actuation of the lockout relay for bus 2B03 by the A train safety
injection signal, caused MCC-D21 to be shed from 2B04. The net
result was that all required loads were stripped and the test
appeared successful,
Since the purpose of the load stripping function is to protect the
emergency diesel generators (EDGs) from beirg overloaded, an
evaluation was performed on the safety significance of the
existent wiring configurations. This evaluation determined that
multiple coincident events would be required to overload an EDG.
A postulated scenario that would create such a condition would
require that- the Unit 2 B train safeguards !:usses were initially
being powered by their EDG without a prior loss of offsite power.
This prerequisite ensures that.MCC-B21 is not previously stripped
on loss of offsite power due to its undervoltage relay actuating.
If during such a condition, an actuation of safety injection
occurred where only the B train safety injection signal
functioned, MCC-B21 would not be stripped and the EDG could be
overloaded (during normal operation, MCC-B21 draws between 150 and
200 amps). The diesel would subsequently restart'and could then
be manually loaded as necessary by the operator.
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_ After this wiring discrepancy was identified, the plant removed
the extraneous wire connecting the 2B03 lockout relay with the
MCC-B21 control circuit. Wire terminations were then made up from
the 2B04 lockout relay to the MCC-B21 breaker trip contact. A
subsequent test of load stripping functions (ORT-3) was completed
satisfactorily on October 31. The inspector discussed this event
with plant management and observed testing of the load stripping
functions. This is an unresolved item 266/92023 pending a review
of the licensee's updated LER.
b. Installation and Testina of Modifications
The inspectors observed onsite activities and hardware associated
with the installation of selected plant modifications to ascertain
that modification activities are in conformance with requirements.
Selected portions of the following modifications were reviewed:
- lWP 92-144*A, "CCW LW-63 and LW-64 Replacement to be
Performed During U2R18, Unit 2"
7. Safety Assessment /0uality Verification (40500) (90712) (92700)
a. Outa.ge Risk Assessment
During the Unit 2 refueling outage the licensee performed an
ongoing risk assessment of plant conditions (see IR 90018). As
part of this assessment, the licensee reviews scheduled and
emergent work's impact on the overall change of risk associated
with existing plant conditions. Monthly surveillance test RMP 074
was scheduled for Unit 1 on October 26. Although this test is not
required while shutdown, Unit 2's test was scheduled to coincide
with Unit 1 test performance to keep the test schedule for both
units in parallel. Unit 2 was in reduced inventory on that date,
and this test involves testing the 4160 VAC and 480 VAC safeguards
busses. Therefore, outage risk assessment would normally prohibit
test performance in this plant configuration. Due to the Unit 2
test being scheduled on an emergent basis (i.e. not identified as
a scheduled item in the initial Outage Safety Review), this
surveillance was not recognized as having adverse risk impact. As
discussed in paragraph 4.b., a personnel error during this test
resulted in a loss of one train's safeguards busses normal power
supply. The inspectors discussed this issue with management and
concluded it was an isolated occurrence. Additionally, the
licensee is reviewing emergent work controls for outage periods
with respect to risk.
b. Licensee Event Report (LER) Review
The inspectors reviewed LERs submitted to the NRC to verify that
the details were clearly reported, including accuracy of the
description and corrective action taken. The inspector determined
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whether further information was required, whether generic
implications were indicated, and whether the event warranted
onsite follow up. The following LERs were reviewed and closed:
266/92-008-00 Reactor Trip Following Closure of Main Steam
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Isolation Valve IMS-2018
This report discusses the reactor trip on October 5, 1992, caused
by inadvertent closure of IMS-2018, the Unit 1 A steam generator
main steam isolation valve, during the performance of quarterly
surveillance testing. Details are contained in Inspection Report
266/92018; 301/92018. The faulty solenoid valve was replaced and
tested satisfactorily. Both MSIVs were then tested prior to-
startup. The inspector observed the solenoid valve replacement
and selected corrective actions for the identified equipment
anomalies.
301/92-002-00 Radioactive Waste Disposal' System Component
Cooling Water Isolation Valves Outside Design
Basis
This report discusses the discovery of component cooling water
system (CCW) isolation valves LW-63 and LW-64 in a condition
outside of the plant's design basis. Valves LW-63 and LW-64 were
discovered to not be capable of providing the appropriate
interface between the Seismic Class 1 and Seismic Class III
portions of the CCW system, as specified in the Point Beach Final
Safety Analysis Report. This issue and the status of
classification of the CCW system as safety related remain
unresolved as stated in Inspection Report 266/92018; 301/92018.
Corrective action will ~ be tracked via the unresolved item.
301/92-003-00 One Train of Containment Spray Inoperable Due to
>- Foreign Material
301/92-003-01 One Train of Containment Spray Inoperable Due to
Foreign Material
This report describes an event which occurred on September 18
during performance of the containment spray system leakage test.
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The Unit 2 train A containment spray pump was rendered inoperable
due to a foreign material exclusion plug blocking the containment
spray pump suction. The plug had likely been left in the' piping
during installation of a full flow test line modification.
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Details are contained in Inspection Report 266/92018; 301/92018.
An enforcement conference was' held on this incident on November 6
and resolution of this item is pending the outcome of the
enforcement action.
301/92-004-00 Manual Reactor Trip During Hot Control Rod Drop
Testing
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This report discusses a manual trip which was initiated during
performance of Reactor Engineering Surveillance Procedure RESP
1.1, " Rod Control System: Rod Drop Testing." Details are
contained in' Inspection Report 266/92018; 301/92018. A lack of
clear communication was the principal cause of this event. Plant
management also recognized a procedural weakness _and initiated a
revision to the test procedure to insert a note alerting operators 4
to expected equipment response during the test. The inspector i
interviewed personnel involved in this test, reviewed the test
procedure, and did not have further concerns.
301/92-005-00 Steam Generator Tube Degradation
This report provides the results of the steam generator eddy
current testing performed during the most recent Unit 2 outage.
36 degraded tubes were found in the A steam generator and 49_in
the B steam generator. All of these tubes were subsequently
plugged. Growth rate of tube indications averages 4-5 percent per
year. The 800 psid leak test revealed four explosive plugs with
excessive leakage. These four explosive plugs were removed and
replaced with mechanical plugs. The inspection did not reveal
other unusual conditions in either steam generator,
c. Manaaer's Supervisory Staff Meetina
The inspector observed several sessions of the Manager's
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Supervisory Staff. Issues discussed included operability testing
of the emergency diesel generators, Quality Assurance audits of
supervisory staff meetings, technical specification change
requests, Licensee Event Reports, and safety related
classification of the component cooling water system.
d. Corocrate Manaaement Reoraanization
On November 20 the Nuclear Power Department announced a
reorganization of the corporate office. In addition to the
creation of an Assistant to the Vice: President, the following ,
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sections in the corporate office have new managers effective
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November 20, 1992: Engineering; Regulatory Services; Planning, '
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Systems and Support; and Quality Assurance. The inspectors ~
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discussed these changes with senior corporate management.
8. Exit Interview ,
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A verbal summary of preliminary findings was provided to the Wisconsin
Electric representatives denoted in Section 1 on November 23, at the
conclusion of the inspection. Written inspection material was not
provided to company personnel:during the inspection.
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The likely informational content of the inspection report with regard to-
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documents or processes reviewed during the inspection was also=
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discussed. Wisconsin Electric management did not identify any documents
or processes that were reported on as proprietary.
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