ML20126A503
| ML20126A503 | |
| Person / Time | |
|---|---|
| Site: | Wolf Creek  |
| Issue date: | 12/09/1992 |
| From: | Howell A NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20126A488 | List: |
| References | |
| 50-482-92-31, NUDOCS 9212210092 | |
| Download: ML20126A503 (29) | |
See also: IR 05000482/1992031
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f- APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
NRC Inspection Report: 50-482/92-31
Operating License No.: NPF-42
Docket No.: 50-482
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Licensee: Wolf Creek Nuclear OpeMing Corporation
P. O. Box 411
Burlington, Kansas 66839
Facility Name: Wolf Creek Generating Station
Inspection At: Coffey County, Burlington, Kansas
Inspection Conducted: October 11 through November 21, 1992
Inspectors: G. A. Pick, Senior Resident inspector
L. E. Myers, Resident Inspector
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Approved: M d Q. 12.l9f96
A. TQowell, Chief, ProjecQebon IF Date
Division orReR tor Projects
Inspection Summary
Areas Inspected: Routine, unannounced inspection including plant status,
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prompt onsite response to events, operational safety verification, maintenance
observations, surveillance observations, cold weather preparations, management
meeting, and followup.
Results:
o The licensee's overall response to the reactor trip was excellent.
However, during the response to the reactor trip, the inspectors
determined that operators did not use the repeat back technique in their
communications. Also, because operations personnel had not received
training on a change in the operation of the letdown radiation monitor,
they were suprised by the alarm entering the action range (Section 2).
e The licensee's implementation of their program to evaluate indeterminate
conditions was effectively implemented (Sections 3.3 and 3.6).
e The licensee's action to form a task team to identify a refueling water
storage tank low boron concentration condition was considered good.
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However, the inspectors identified several weaknesses in that licensee
personnel failed to inform operations personnel about the altered
configuration, failed to review similar situations, and failed to
consider all contributing causes. The licensee failed to-revise an
inadequate alarm response procedure until prompted by the inspectors,
which resulted in a violation. The licensee also had previous
opportunities to correct a deficiency with the refueling water storage
tank drain line. The inspectors considered this to be an additional
example resulting from past problems associated with the corrective
action program (Section 3.2),
e The licensee conducted an excellent medical emergency preparedness drill
(Section 3.7).
e Generally, the licensee conducted maintenance in a thorough, well
controlled manner (Section 4). However, the inspectors identified
potential weaknesses in work controls related to heavy loads in the
spent fuel pool. This issue will be tracked by an unresolved item
(Section 4.3). The inspectors determined that inadequate
postmaintenance testing prevented the licensee from identifying a
misadjusted rotor immediately following maintenance activities, which
resulted in a violation. Also, the maintenance instructions provided
incorrect guidance to the maintenance worker. The instructions were
incorrect because an error occurred while transferring data from one
design document to another. This deficiency resulted in a noncited
violation for inadequate control of design information (Section 3.6).
The failure of craft personnel to identify an obvious component
deficiency is a weakness (Section 4.2).
e The knowledge level and deliberateness of a nonlicensed operator during
operator rounds indicated that nonlicensed personnel were sensitized to
the importance of proper logtaking (Section 5.1).
e The licensee expended considerable effort to protect the plant against
the effects of cold weather. The licensee's sensitivity to the problems
associated with cold weather was demonstrated by their efforts to make
operable an auxiliary steam feedwater pump. The licensee had a very
good program to protect against cold weather (Section 6),
e A violation occurred because of operator inattention to detail, which is
a continuing problem. There was a los:: of charging flow and a decrease
in letdown flow for approximately 20 seconds because a licensed operator
failed to follow a procedure (Section 8).
Summary of Inspection Findings:
e Violation 482/9231-01 was opened (Section 3.2).
e Violation 482/9231-02 was opened (Section 3.6).
- Unresolved item 482/9231-03 was opened (Section 4.3).
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e Violation 482/9231-04 was opened (Section 8). l
- Unresolved Item 482/9228-01 was closed (Section 8).
Attachments:
e Attachment 1 Simplified Diagram of the Refueling Water Storage Tank
e Attachment 2 - Persons Contacted and Exit Meeting.
- Attachment 3 - List of Acronyms
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DETAILS
1 PLANT STATUS (71707)
At the beginning of the inspection period, the plant operated at 100 percent
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power. On November 10, 1992, the turbine tripped because of degraded grid ',
vol tage. Personnel at the Rose Hill substation, west of the plant, accidently l
shorted the secondary side of a 345 to 138 kilovolt transformer while
performing maintenance. Operators took the plant critical on November 11,
1992, and the unit achieved 100 percent power on November 13, 1992. At the
end of the inspection period, the plant was operating at 100 percent power. j
2 PROMPT ONSITE RESPONSE TO EVENTS (93702, 71707) l
2.1 Plant Trip
On November 10, 1992, at 11:05 a.m. the main generator tripped _because of
degraded grid voltage. The main generator trip caused a turbine trip that, by
design, caused the reactor trip. Subsequently, the_ licensee was notified that
troubleshooting activities at the Rose Hill substation created a line fault
that may have tripped the Wolf Creek Generating Station main generator.
Personnel working on a 345 to 138 kilovolt transformer inadvertently shorted
the 138 kilovolt side to ground. The licensee determined that 'a ground . fault
occurred when personnel made incidental contact between an overhead ground and
the energized portion of a 138 kilovolt transformer during implementation of a
clearance procedure. Annunciator 98C, " Response Spectrum OBE (Operating Basis
Earthquake) Exceeded," alarmed during the reactor trip. Following the seismic
alarm, the shift supervisor dispatched personnel to perform a plant walkdown,
including the containment, to look for equipment problems. At 2:10 p.m.,
chemistry reported that dose equivalent iodine (DEI) was measured to be
1.01 microcurie / milliliter (uCi/ml) of primary coolant, which exceeded the
Technical Specification (TS) limiting conditions for operation. -The
supervising operator promptly entered TS 3.4.8,'which required the primary
coolant to be sampled every 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> whenever the DEI exceeds 1.0 uCi/ml. The
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licensee entered Offnormal Procedure 0FN 00-006, Revision 1, "High Reactor
Coolant Activity," and verified the letdown flow rate to be 120-gallons per
minute as specified in the procedure. The licensee exited TS 3.4.8 and
Procedure 0FN 00-006 at 2:35 p.m. when DEI levels were meas ~ red at-
0.966 uCi/ml. The licensee conducted a walkdown of the switchyard, the main
generator exciter, and the main generator. -No problems were identified.
2.2 Posttrip Review and Shutdown Activities
Plant management conducted a meeting to determine: ~(1) the cause of the -
turbine trip, (2) the_ significance of anomalies or equipment failures,
(3) forced outage list work activities that must be completed prior to
starting the reactor, and (4) the approximate duration of the shutdown. The
licensee's forced outage work list identified two mandatory actions, which
involved replacing a failed rod control system power supply and performing a
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TS surveillance. The licensee replaced the rod control power supply restoring
the desired redundancy and completed TS required testing of the manual shunt
trip as committed when they received an emergency TS amendment on August 29,
1992 (refer to NRC Inspection Report 50-482/92-18).
The inspectors attended the posttrip review session conducted on November 10,
1992. Licensee personnel participating in the posttrip review had each
reviewed all the available information related to the plant trip. The plant-
walkdowns revealed no adverse equipment or pipe support conditions. Chemistry
personnel determined that under transient conditions with failed fuel. a spike
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in primary coolan, iodine activity, by a factor of 100, was not unusual-- From
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review of the electrical system design, instrumentation and control (l&C)
personnel determined that the Wolf Creek Generating Station switchyard
distance relaying was not designed to sense the line fault because it occurred
on'the secondary side of the offsite transformer. All safety-related and
nonsafety-re'ated equipment actuated as designed. The posttrip review team
classified the reactor trip as Condition I in accordance with
Procedure ADM 02-400, Revision 9, "Posttrip Reviews," and recommended that the
reactor be started once all mode restraints were satisfied.
2.3 Plant Startup
The inspectors monitored the plant startup that occurred on November 11, 1992.
The shift supervisor briefed the crew, describing the overall sequence of
activities to take the reactor critical and the subsequent power increase.
The precautior.s and limitations of Procedure GEN 00-003, Revision 26, "llot
Standby to Minimum Load," were reviewed. During the approach to criticality
at a position of 45 steps on Control Bank 0, the digital rod position
indicator (DRPI) indicated that Control Rod D-12 had dropped. The reactor
operator immediately stopped the control rod withdrawal. The supervising
operator entered Offnormal Procedure 0FN 00-011, Revision 3, " Dropped or
Misaligned Rod, and Realignment," and TS 3.1.3.1 that specified, for an urgent
failure alarm in the rod control system, restore the inoperable rod to
The op9rators contacted I&C personnel so that an investigation could be
- - conducted. The shift supervisor directed the operators to reinsert the
control rods and reenter Mode 3, HOT STANDBY, until the technicians resolved
the rod control system problems. As the operator began inserting control
rods, Control Rod D-12 indicated 30 steps on the DRPI with Control Rod Bank D
at 39 steps on the demand counter; consequently, operators stopped the control
rod insertion. After the operators consulted with 1&C personnel and
determined no further problems would occur by further rod insertions, the
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operators continued the shutdown. As operators inserted the control rods,
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Control Rod D-12 traveled into the reactor core with the other Control Bank D
rods. When all Control Bank D rods were at 0' steps and Control' Bank C rods
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were at 115 steps, the supervising operator exited TS 3.1.3.1 because he was
confident that all rods were aligned. After all control rods were inserted,
the licensee entered Mode 3 and exited Procedure OFN 00-011.
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The !&C technicians determined the problem was within the DRPI= system. A
review of vendor documents revealed that the probable cause of _the indication
error was a signal cable, a magnetic indicating coll, or: a circuit-card. The
I&C technicians determined that above 30 steps the data encoder card for
Control Rod 0-12 in Data Cabinet B failed to translate the-voltage signal into
a digital signal. Subsequently, the technicians used a card tester verifying _ '
that the data encoder card was defective. After replacing the data encoder
card for Control Rod D-12, the technicians verified that the data encoder card
developed the appropriate digital signal over the entire range of control rod
movement.
After replacement of the DRPI data encoder card, the licensee recalculated a
new estimated critical boron concentration in preparation for a plant startup.
The reactor became critical at 110 steps on Control Bank D and a boron
concentration of 856 parts per mi_llion (ppm). The operators increased reactor
power to 30 percent then maintained a constant power level for 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> until
the secondary chemistry met specifications. The operators had adjusted the 1
power range nuclear instruments periodically during the power increase. On
November 13, 1992, at 99 percent reactor power by the nuclear instruments, the
operators stabilized the power increase and performed a calorimetric, primary
heat balance. By performing the calorimetric, the operators determined the
actual power level was 96 percent. After adjusting the nuclear instruments,
the operators increased power to 100 percent.
2.4 Assessment
The inspectors responded immediately to the control room. The inspectors
observed the licensed operators respond to the trip. Command and control was
excellent and communications among the reactor operators and supervising
operator were generally good; however, the inspectors noted that the operators
did not use the repeat-back technique while responding to the reactor-trip.
The shif t supervisor remained in the _ background, carefully observing the plant
-and the crew and maintaining an overview of the event response. The shift
crew appropriately responded to the event'in accordance with procedures. -The- -
inspectors noted that the call superintendent and other operations perronnel
had arrived in the control room-to provide support to the onduty crew. 'I&C
personnel had been contacted within the first 5 minutes and were examining the
exciter relays.
Management provided good oversight at the status' meeting that-was held
following the reactor trip. Personnel came prepared with: time estimates'for
equipment that required repair. The forced outage list was reviewed and the-
mandatory items, rod control system power supply and the manual reactor trip
shunt trip surveilltnce, were directed to be completed.
Personnel involved in the posttrip review represented a multidisciplined task
group as specified in Procedure ADM 02-400. The discussions regarding the-
sequence of events were thorough. The posttrip review group properly
classified- the trip as a Condition I because the cause was positively known
and all safety systems functioned properly. The licensee promptly reported
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the reactor trip to the NRC operations center and provided updates as new
information about the trip became available. The licensee will submit
Licensee Event Report 92-016 for this event.
The inspectors determined from discussions with 1&C personnel that the seismic
alarm was a momentary spike and was not representative of a seismic event.
The recorded magnitude of the event barely exceeded the alarm threshold and
was much lower than the previous seismic data associated with the noise events
in February and March 1992. The inspectors also reviewed the basis for the
momentary DEI spike. The licensee had a similar occurrence at the start of
Refuel 2 when they nanually scrammed the reactor while shutting down with some
failed fuel elements. The reviews of the anomalies were thorough. The
inspectors determined that the investigation of the DRPI system problems was
well planned and implemented.
The inspectors noted that the operators were surprised that the computer alarm
for the letdown system radiation monitor had saturated and alarmed. The
inspectors interviewed personnel and reviewed Procedure CHM 03-131,
Revision 0, " Failed fuel Monitor SJ RE01 Setpoint Adjustment." The procedure
was issued in September 1992 and provided a method to assure that the letdown
radiation monitor was more sensitive to reactor coolant activity. The
procedure allowed the monitor alarm setpoints to be varied rather than being
set at the previous, relatively high, constant values of 13.6 uCi/ml for the
alert setpoint and 136 uCi/ml for the alarm setpoiht. The procedure required
a 30-day average coolant activity to be determined. The alert setpoint for
the radiation monitor was set at 0.5 uti/ml above the 30-day average value,
and the alarm setpoint was set at 5.0 uCi/ml above the 30-day average. The
inspectors determined that the operators had not received training on the
changes to the alarm setpoint. During the screening prccess of design
changes, the licensee determined that this change was not significant enough
to warrant training. As a result, the operators did not expect the alarm.
The inspectors considered the lack of training because of the setpoint change
to be a weakness.
During the containment walkdown, quality control personnel identified a
1/16-inch d): meter boric acid crystal at spare Canopy Seal Penetration 25;
however, no active leakage was observed. Because there was no active leakage
and a previous vendor evaluation determined that a small amount of leakage was
acceptable, the licensee evaluated the discrepancy and determined that the
plant could be operated in this condition until Refuel VI. The spare canopy
seal weld had similar leakage identified following the previous forced
shutdown in February 1992. At that time, the licensee determined that the
leakage was not pressure boundary leakage because the connection was threaded
and seal welded to prevent backing off.
During the reactor startup, the inspectors noted that the licensed operators
performed the startup activities and required surveillances in accordance with
procedures. Excellent communications existed among the reactor operators and
the supervising operator. The supervising operator ensured his directions
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were understood. The shift supervisor quickly decided to shut down the
reactor and stop the approach to criticality when the DRPI problem occurred.
2.5 Conclusions
Operations personnel demonstrated excellent performance during both the plant
trip recovery and the startup evolutions. Plant management maintained
effective oversight during the forced outage. The inspectors determined that
control room personnel did not use repeat backs during communications;
however, no miscommunications were observed. The lack of operator training
for a setpoint change associated with the letdown system radiation monitor was
considered a weakness. The plant startup activities were conservative. The
licensee conducted thorough investigations into deficiencies identified during
the forced shutdown.
3 OPERATIONAL SAFETY VERIFICATION (71707)
The objectives of this inspection were-to ensure that the facility was being
operated safely and in conformance with license and regulatory requirements
and that the licensee's management control systems were effectively
discharging the licensee's responsibilities for continued safe operation. The
inspectors monitored licensee activities related to: performance enhancement
program (PEP) employee survey results meeting, low boron concentration in the
refueling water storage tank (RWST), boron injection tank outlet isolation
valve - valve actuator maintenance, control room annunciators, fuel
reliability indicator (FRI), RWST suction valve - valve actuator maintenance,
and an emergency preparedness drill.
The methods used to perform this inspection included direct observation of
activities and equipment, control room operations, tours of the facility,
interviews and discussions with licensee personnel, independent verification
of safety-system status and TS limiting conditions for operation, corrective
actions, and review of facility records.
3.1 PEP Employee Survey Results Meetinq
On October 21, 1992, licensee management conducted meetings with all employees
to summarize the results of the PEP employee survey and present management's
response to tha survey. The survey was designed to identify issues and
concerns needing improvement. A third-party consultant and the PEP team
initiated the survey in July 1992.
The survey questionnaire was presented to all employees in August 1992. The
questionnaire included 106 questions designed to explore employee perceptions
about organizational groups and categories af functional areas, such
as: (1) management, (2) personnel policies, (3) communications, and
(4) procedures. Over 94 percent of the employees responded to the
questionnaire. The results were statistically analyzed for perceptions in and
among organizutional groups and in functional areas. Management incorporated
the employees survay results into the development of the PEP action plans.
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The inspectors attended one of the meetings. Licensee management explained
the PEP and communicated that changes would result as action plans were
developed and implemented.
3.2 Low Boron Concentration in RWST
On October 15,1992, at 12:14 p.m. the licensee entered f he action statements
for TS 3.1.2.6 and TS 3.5.5 after the RWST boron concentration was measured at
2151 ppm. TS 3.1.2.6 and TS 3.5.5 require that the boron concentration be
maintained between 2400 and 2500 ppm while in Modes 1, 2, 3, and 4. The
action statements require that with the RWST inoperable, restore the boron
concentration to within specifications in I hour or begin a controlled
shutdown. The licensee initiated preparations for a plant shutdown, initiated
preparations for requesting a Temporary Waiver of Compliance f-om NRC, and
requested chemistry to resample and analyze the boron concentr.. ion. After
chemistry personnel had increased the sample flush volume, they determined the
boron concentration to be 2403 ppm. Sebsequently, the licensee exited the TS
action statements.
The inspectors determined that the RWST high-level alarm annunciated in the
control room at 10:35 a.m. on October 15, 1992. The licensee-nominally
maintains the RWST level at 98 percent with the high-level alarm at
99 percent. The reactor operator responded to the alarm in accordance with
the procedure by requesting chemistry to sample the RWST and initiating steps
to lower the RWST level. The reactor operator dispatched a nonlicensed
operator to open Valve BN V017, RWST drain valve (refer to Attachment 1), to
lower the level and clear the alarm. The nonlicensed operator reported that
upon opening the valve no flow was observed, and the control room observed no
change in level. Concurrently, a chemistry technician sampled fre. the drain
line located upstream of Valve BN V017. The operators initiated letdown of
the RWST through the spent fuel pool cleanup system, an alternate draiu path,
to recover level. The high level alarm cleared at 12:38 p.m. The licensee
determined that there were no activities ongoing that could have caused water
to flow into the tank, thereby resulting in an RWST level increase.
Consequently, the licensee concluded that the high level alarm was spurious
and wcs generated because the true level was being maintained too close to the
setpoint.
Chemistry resampled the RWST at both the tank drain line and the 24-inch
header to the emergency core coeling system pumps. These results were 21s.
and 2443 ppm, respectively. Chemistry, after determining the piping
configuration of the RWST drain line, increased the flush volume at the sample
point from 2.5 to 20 gallons and obtained a sample with a concentration of
2403 ppm at 2:22 p.m. Anothcr samole obtained at 2:35 p.m. indicated that the
boron concentration was 2440 ppm. Chemistry personnel took additional samples
from the normal sample location and from the spent fuel pool clean-up
recirculation sample point. In addition, the results of previous weekly
analysis were reviewed. All results were approximately 2440 ppm which was
within the error of analysis. These data indicated that the RWST baron
concentration had bcen within sne ification the entire time.
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The normal sample point for determ_ining the RWST boron concentration is a
3/4-inch sample line attached to the 6-inch drain pipe. Downstream of the
sample point-is Valve BN V017. Next, the tank overflow pipe joins the drain
pipe between Valve BN V017 and Check Valve LF V034, RWST overflow to drain
system. After Check Valve LF V034, the drain pipe is routed to the waste
holdup tanks in the radwaste building. The licensee suspected that Check
Valve LF V034 was stuck closed so that when the nonlicensed operator opened
Valve BN V017, water in the overflow pipe backflowed into the sample-point
pipe volume.
On October 16, 1992, the licensee organized a task force of individuals from
nuclear safety engineering, systems engineering, operations, anel chemistry to-
investigate the circumstances leading to the event.
As a result of the initial investigation, the task force found:
a No water flowed into the RWST.
11 feet from the tank side, the sample flush volume was inadequate. The
task force initiated Reportability Evaluation Request 92-075 to ensure
the issue would be evaluated for reportability and initiated Performance
improvement _ Request CP 92-0704 to ensure all the corrective actions were
completed,
a Water with a boron concentration of 1700 ppm existed 'in the overflow-
line as determined by samnling the top of the full overflow pipe. The-
standing water supported the conclusion that Check Valve LF V034 was
stuck closed. The licensee determined that the borated water in the
overflow pipe was diluted by condensation.
- No source of water into the tank would cause overflow out the tank vent,
and the tank vent was adequately sized to-handle the inflow.
Consequently, the tank would not overpressurize.-
The task force initiated a work request (WR) to examine the operability of
Check Valve LF V034 and the insulating flange downstream of the check valve.
Also, the task force reviewed _ previous WRs that- indicated Check Valve LF V034
was sticking. In 1985 maintenance personnel determined that the check valve.
operated correctly but that an insulating flange may not have had the correct
configuration and did not permit flow. In 1988 the licensee administratively.
closed the WR without actually examining the downstream piping and the. .
insulating flange. The-inspectors considered ~the_ failure to' comp!ete the
previously scheduled work activity a significant_ weakness that contributed to
this event. The inspectors considered this to he'an additicaal example of-
past corrective action weaknesses (for which enforcemen'. action. has been
taken) that are now being resolved.
i As documented on the performance improvement request, chemistry changed
L Procedure CHM 01-080, Revision 4, " Sampling of the Refueling Water Storage
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Tank," to require a 20-gallon flush when sampling from the RWST drain line
sample point. The licensee determined this flush amount was necessary becaus'e
'the volume preceding the sample point was 8 volumes greater than originally
calculated. In addition, chemistry evaluated sampling flush methods for all
other tanks and found no discrepancies.
The licensee determined the the check valve operated properly and that the
drain line downstream of the check valve was full of water. The insulating
flange probably had a blank in the flange that _ existed since the original-
hydrostatic test of the line. When replacement gaskets for the flanged
connection are received, the pipe will be drained to confirm the blank in the '
insulating flange. ,
The inspectors concluded that the task force formed to investigate this everd
identified appropriate corrective actions. However, the inspectors noted that
the licensee had missed previous opportunities to correct the RWST drain line
configuration deficiencies.
The inspectors determined t'at the task force did not fully consider other
important aspects of the investigation. The need for operator training was
not investigated. The inspectors determined, through interviews, that
licensed operators lacked the knowledge that the RWST had no bladder. The
generic' issues were not explored. An in-depth review of other tanka to assure
that overflow drain lines were in the correct configuration was not conducted.
An information tag was piaced on the chemical and volume control system panel
near the boric acid tank controller used to fill the RWST. Operators
responding in accordance with the_ alarm procedure would be directed'to utilize
the overflow drain valve. However, until the drain lire blockage was
corrected, the RWST drain valve would not function, as designed, since =the
blockage was downstream of the valve. The licensee failed to initiate a
temporary change to the alarm procedure.
After the inspectors pointed out the deficiencies in the investigation, the
licensee reviewea training aspects of the event-and initiated =a review of
generic issues. Also, the licensee initiated and completed a- temporary change
to the_ alarm nrocedure. When the inspectors questioned the licensee
concerning other information tag weaknesses, the licensee stated that they
presently perform quarterly information tag audits. The licensee performs the
audits to verify that the information tag is needed and that-_the information
tag still provides the required information. Additionally, the -licensee
stated they will complete an audit of_ all outstanding information tags to
determine whether similar deficiencies _ exist. Alarm Procedure ALR 00-047E,
Revision 4, "RWST LEV HILO,"' Step 4.4.3 directs personnel to drain the RWST :
upon receipt of a high -level alarm by opening Valve BN V017. As described
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above, the pipe downstream was blocked and the drain path unavailable. The ,
failure to initiate.a temporary change to Procedure ALR 00-047E is' a violation
of TS 6.8.1.a (482/9231-01).
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3.3 Boron injection Tank Outlet Isolation Valve - Valve Actuator Maintenance
On October 28, 1992, while performing maintenance on Motor-0perated
Valve (MOV) EM HV8801B, boron injection tank outlet isolation, in accordance
with WR 50396-92 instructions, electricians identified a potentially
nonqualified torque switch and limit switch gear case. The torque switch was
manufactured from melamine (white) plastic material instead of the fibrite
(brown) plastic material, and the limit switch gear case was aluminum instead
of brass.
The licensee had recently issued Procedure MGE LT-008, Revision 0, " Routine
Electrical Limitorque Operator Maintenance," to provide upgraded instructions-
for routine preventive maintenance of MOVs. Procedure MGE LT-008, Step 4.10
specified that the torque switch should be fibrite and that the limit switch
gear case should be brass for environmentally qualified valves outside of
containment. Consequently, the electricians questioned the adequacy of the
internal components of the actuator.
The licensee entered Procedure KGP-1215, Revision 0, " Evaluation of
Nonconforming Condition of Installed Plant Equipment," that provided guidance
for evaluating indeterminate conditions. The licensee entered the procedure
to determine whether the valve was operable with the existing apparent
deficiencies. MOV EM HV8801B is a limit-closed valve and does not rely upon
the torque switch for motor control. The licensee determined from review of
their Motor Operated Valve Application Guide and Electric Power Research
Institute information that the use of an aluminum limit switch gear casing was
a concern, inside the containment only, because of the chemical reactions
between sodium hydroxide and aluminum. The licensee concluded that the
deficiencies would not have affected the ability of the valve to perform its
required safety functions.
As corrective action to eliminate future confusion, the licensee initiated a
procedure change service request that clarified the required environmental
conditions for aluminum versus brass limit switch gear boxes outside of
containment. The licensee's long-term plans included replacing the aluminum
limit switch gear boxes with brass as each valve is overhauled for the valves
located outside of containment. From review of the work package, the
inspectors determined that no other problems occurred during conduct of the
maintenance. The Valve Operations and Test Evaluation System test was
satisfactorily accomplished. The inspectors determined from discussions with
the licensee that the melamine torque switch was not a concern for this valve
because of shrinkage induced by radiation; however, this valve was susceptible
to roll-pin failures.
Upon receipt of a 10 CFR 21 report dated December 11, 1990, concerning SMB00
torque switch roll pin failures, the licensee initiated several Industry
Technical Information Program (ITIP) Items:
' Item 1513 required that engineering to evaluate the torque switches used
in conjunction with heavy spring packs.
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o Item 1514 required maintenance personnel to develop ~ a replacement
schedule.
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a Item 1515 required operations to develop guidance to minimize j
declutching of the actuator for the affected valves and required
verifying valve operability after declutching- the valve actuator.
The inspectors verified that operations had developed an information tag that
described actions to be taken when declutching the affected valves.
Maintenance personnel had developed a schedule to replace the melamine torque
switches susceptible to roll-pin failures by_the end of Refuel VI. Forty-six
out of 88 safety-related valves had their torque switches. replaced during
Refuel V. Similarly, 4 out of 16 nonsafety-related valves had their torque
switches replaced in Refuel V.
Plant Modification Request 3749 provided a disposition -for torque switches
with the affected roll pins located in the warehouse and in the field. The
affected torque switches located in the warehouse had been returned to the
vendor and refurbished. Some of the affected torque switches located in the
field were to be replaced during Refuel V or sat the first available-
opportunity. The disposition recommended that all remaining affected valves
have the torque switch replaced during Refuel VI.
3.4 Control Room Annunciators
On.0ctober 16, 1992, the Callaway Plant experienced a loss- of control-board
annunciators. On October 17, 1992, while' removing jumpers from field
multiplexor power supplies, the fuses on all four field multiplexors and other
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logic power supplies failed, The failed power-supplies resulted in a
significant number of the control panel antunciators- being illuminated. The
licensee thought only the illuminated annurciators were inoperable.
Subsequently,. the licensee determined that all annunciators were inoperable.
This condition existed for 56_ minutes until the fuses were replaced.
The _ inspectors questioned licensee personnel about whether the events at
Callaway could occur at Wolf Creek and what actions were being implemented.
The licensee informed the inspectors that thay were awaiting a root cause-to
be identified by the Callaway plant but that-they were. maintaining
communication with their counterparts. The licensee contacted the Callaway
plant and determined that fuses in the power supplies-located in the ~ control
room should be checked weekly. The weekly checks were _necessary to-ensure
that the power supply fuses had not failed since an inoperable power supply
would -prevent annunciators from alarming. Subsequently, the licensee
implemented a. requirement to periodically monitor the fuses in the power
supply panel to verify that the annunciators were operable.
The licensee developed a temporary-modification that provided indicating
lights behind the. control panel-that remained illuminated whenever the power
supplies were energized. The licensee added requirements to the control room
logs for monitoring the power supply status lights once every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. While
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implementing the temporary modification, the licensee removed the fuses one at
a time and photographed the main control board annunciators.- The-licensee
used the photographs to identify the annunciators illuminated upon a loss of
each power supply. The licensee highlighted the annunciator drawings- i
'
identifying all annunciators associated with each individual power supply that
would be inoperable upon loss of the power supply. The annunciator _ drawings-
were placed in the' control room to provide guidance to the operators upon a
loss of annunciators.
The inspectors determined that emergency preparedness personnel were
communicating with operations ;ersonnel and had initiated changes to-their
emergency action levels. The licensee's emergency action levels specified
that an alert should be declared upon a loss of all direct current (DC) power.
The inspectors determined that the affected emergency action level previously
specified "most or all annunciators or a loss of DC power;" however, the-
licensee changed the emergency action levels to eliminate the ambiguity of-
that phrase to prevent misinterpretation. At that time, the licensee believed
that their annunciator system could only be lost by a loss of all DC power.
Because of recent industry events, particularly the event at Callaway, the
licensee conducted a more detailed investigation into the annunciator system.
The licensee determined that a loss of a single breaker on-the PK 51 DC bus
could eliminate the ability of all annunciators to function. The oversight
could have resulted in licensed personnel failing to make an appropriate
emergency classification. 1
The licensee informed the inspectors that they had been reviewing their ;
annunciator design in response to ITIP Item 2069, Significant Event ,
Report 16-92: " Loss of Control Room Annunciators and Plant Monitoring
Computer System," which was assigned to their design engineering group and the
training department. Specific-licensee actions that were in process included
a review of the system design by system engineering and a review of Offnormal-
Procedure 0FN 00-029, " Loss of Nonvital 125 volt DC Bus PK01, PK02, PK03,-and
PK04," by operations personnel for adequacy. The licensee initiated Simulator
Modification Package 92-143 to accomplish the simulator modifications with a
required completion date of April 1, 1994. The inspectors determined from
interviews with the involved licensee personnel that changes were being made
to Procedure 0FN 00-029 to specifically address a loss of annunciation.
Although the licensee had-established a completion date of April-1994 for-
modeling the. simulator for a complete. loss of annunciators, the__ inspectors
determined from discussions with training personnel that the'_ simulator
modeling -should be completed by February 1993 because of the increased
sensitivity following the Callaway event. The Training Department will
discuss this event in Requalification Cycle 92-3 that will begin in
February 1993.
3.5 Failed Fuel Elements
The inspectors monitored the increase in the FRI parameter. Procedure
ADM 01-221, Revision 3, " Failed Fuel Action Plan," defined FRI and defined
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four action levels. The FRI is the steady state reactor coolant system
Iodine 131 activity corrected for the tramp uranium contribution and
normalized to a common purification rate. Tramp uranium is uranium particles
that remain on the outside of fuel elements following the manufacturing
process.
The licensee estimated, from review of chemistry parameters, that
approximately three to four fuel elements had pinhole cladding failures. The
first indication was an increase in the reactor coolant system gaseous
activity obtained from the ratio of Xenon 133 to Xenon 135. The licensee
entered FR1 Action level One on September 18, 1992, because of the increased
primary coolant gaseous activity, Upon entering action _ level one, the
licensee began evaluating data to determine the number and type of fuel
failures. The licensee initiated actions to review fabrication and design
records and initiated plans to perform fuel inspections during the refueling
outage.
3.6 RWST Suction Valve - Valve Actuator Maintenance
' On November 7,1992, as operators placed Residual Heat Removal (RHR) Pump B in
pull to lock while performing Procedure STS BN-201,- Revision 3 " Borated
Refueling Water Storage System Inservice Valve Test," the operators noted that
the engineered safety features status panel light for MOV BN HV88128, RWST to
RHR B suction, illuminated white and no alarm was received when they closed
the valve. The light extinguished upon the opening the valve.
Procedure STS BN-201 provided guidance for stroke time testing of valves that
are located in the flow path from the RWST to safety-related pumps. These
light indications occurred in a different order than expected; consequently,
the operator initiated WR 05598-92 so that technicians would investigate the
annunciator problem. The operators believed that the problem was with the
status panel light circuit; consequently, the operator did not consider that
the valve may be inoperable. The licensed operator demonstrated a good.
awareness of all control panel indications available.
'
On November 9, 1992, at 4:10 p.m., the shift supervisor declared RHR Pump B
inoperable because of the uncertainty of.the operability of MOV BN HV8812B
resulting from Limit Switch Rotor 3 being set 180 degrees from the required
position. The licensee entered TS 3,5.2 that allowed 72 nours to repair the-
valve or begin a controlled plant shutdown. The licensee initiated an
operability review for the valve operability in accordance with
Procedure KGP-1215. The licensee's operability evaluation docume'nted that the
Rotor 3 contacts included a' spare, the engineered safety features status panel
indicating light, the 'RWST 10-10 level test interlock circuitry, and the
interlock permissive for Valve BB PCV8702B, RHR Pump B. suction-from Reactor -
Coolant- System Loop 4 hot leg.
Valve BB PCV8702B is used when RHR Train B is placed in service for cooling
the reactor coolant system after the reactor is shutdown. With Limit Switch
Rotor 3 set incorrectly, Valve ~ BB PCV87028 would not receive a permissive
signal to open, as designed, when_ MOV BN HV8812B was closed. The failure of
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Valve BB PCV87028 to open resulted in the inability of the licensee to use RHR
Train B to remove decay heat whenever the reactor was shutdown. The licensee
determined that no automatic functions for MOV BN HV88128 were disabled;
therefore, the valve remained operable. The licensee had reviewed the
maintenance history for MOV BN HV8812A, RWST to RHR A suction, and the
licensee determined that no adjustments were made to MOV BN HV8812A.
Consequently, a common mode failure did not exist.
The licensee determined that the limit switch rotor position for Rotor 3 was
incorrectly specified as 6 percent FROM FULL OPEN. Further review determined
that upon transfer of data from the licensee's previous MOV Setpoint
Document WCHA-04 to the new MOV design configuration sheets located in
Document E-025-00007, a data transfer error occurred for MOV BN HV88128, Limit
Switch Rotor 3. The WCMA-04, Limit Switch Rotor 3 setting was specified as
6 percent FROM FULL CLOSED. The licensee's review determined the root cause j
was personnel oversight. The licensee identified several contributng causes.
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The first cause identified was the similarity in appearance of the "0" and the ;
"C" on the data sheets. Another contributing factor was most transfers were :
one-to-one; however, 9 of 153 valves did not follow the convention, including
this valve. A total of- 2300 pieces of data were transfered and verified.
Consequently, the licensee also attributed personnel error and inattention to
detail to the independent reviewer. Electricians referred to the E-025-0007
design configuration document for rotor settings as part of maintenance
activities that.specify setting limit-switch rotors. The licensee documented
this discrepancy on Performance Improvement Request NP 92-0741.
The inspectors determined that the inadequate E-025-00007 specification data
sheet resulted in maintenance work instructions that were inappropriate to the
circumstances. The licensee corrected the-af fected valve data specification -
sheet and identified other valve data sheets that were affected. Four of the
data sheets had data transposition errors related to rotor settings.- The
licensee reviewed maintenance activities related to each of the four valves
determining that the only valve worked was MOV BN HV88128. The failure to
have adequate instructions for the adjustment violated 10 CFR 50, Appendix-B,
Criterion III, because the licensee failed to ensure that design requirements'
were properly translated into work instructions. However, the violation will
not be cited because the criteria specified in paragraph VII.B.2 of the NRC
Enforcement Policy were satisfied.-- The licensee identified this deficiency
and evaluated the occurrence for reportability. The licensee promptly
reviewed other potentially affected valves for similar data transportation
errors. - The licensee reviewed their process, determining'that the appropriate
programmatic reviews had been conducted.
The licensee determined that M0V BN HV88128 rotors were reset during-
~
corrective maintenance conducted in September 1992 to repair the soft clutch
mechanism and replace the motor pinion gear in accordance with WR 04681-92
(refer to NRC Inspection Report 50-482/92-28, Section 3.2). While reviewing-
the work-activities accomplished under WR 04681-92 and licensee activities-
related to followup of the abnormal status panel indication, the inspectors
determined that corrective WR 04681-92 had required performance of
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Procedure STS BN-201, as a postmaintenance test. This inadequate
postmaintenance test was different from the issues raised in NRC Inspection-
Report 50-482/92-30 because the previous inadequate postmaintenance test was
related to planned preventive maintenance activities. The licensee's
corrective actiors described at the Enforcement Conference addressed review of
preventive maintenance work instructions. The inspectors reviewed .
Procedure STS BN-201 determining that the test did not require operators to
monitor the status panel indicating lights. Consequently, the operators did
not identify the offnormal status light indication during the postmaintenance
test activities.
The failure to notice the improper light status following the maintenance
activities resulted in Train B shutdown cooling being inoperable for
approximately 55 days, from September 17 through November 9, 1992. Throughout
this period, the plant was in Modes 1 through 3. Consequently, the ability to
remove decay heat was not required to be operable. The licensee's maintenance
program requirements were specified, in part, by Procedure ADM 01-057,
Revision 25, " Work Request," Attachment 8. The attachment provided guidance
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and expectations for the performance of postmaintenance testing. In
particular, Attachment 8, Step-2.A, specified that postmaintenance testing is
used to verify that the maintenance w:e performed correctly, the equipment
performs its intended function, and that a new deficiency has not been
created. The inspectors-determined that the postmaintenance test instructions
were not appropriate to the circumstances as required by Procedures
ADM 01-057. This is a violation (482/9231-02) because the-postmaintenance
test failed to assure that the limit switch rotors were properly adjusted.
3.7 Emergency Preparedness Drill
On November 20, 1992, the licensee conducted a medical emergency with
contamination emergency preparedness drill. The drill was well designed and
exercised all groups involved. The scenario placed-a' worker in a contaminated
area (in protective clothing) in the auxiliary building who responded to the-
emergency evacuation alarm by clearing the area. The individual panicked and:
exited through a turbine building stairwell (a clean area) and, subsequently,
fell down the stairs which resulted in a simulated serious injury. The
inspectors observed portions of the drill and attended the critique following '
the drill.
'
The critique was well performed and included free and open discussions of the
lessons learned in command and control, communications, health physics
boundary problems in an unexpected circumstance, and medical treatment.
Lessons learned will be incorporated into training and further exercises are
planned to assure resolution of observed problems.
3.8 Conclusions
Licensee PEP activities continued, and the licensee reported the results of-
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the employee survey to the employees.
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The use of a task group to perform a root cause investigation into the
apparent RWST level increase and the inadequate sampling methodology was a -
positive licensee resporise to an event. The root cause and immediate
corrective action determinations were good;- however, the overall result of the-
investigation was diminished because personnel did not consider the generic
implications by reviewing the other tank configurations.for similar
deficiencies and since the operators were not properly notified of the drain
line configuration. The task group did not evaluate other tontributing
causes. The inspectors also concluded that the licensee.had previous-
opportunities to correct a problem with the RWST drain line and considered
this an additional example resulting from corrective action program
weaknesses.
Licensee maintenance personnel identified potential MOV operability issues.
Personnel promptly completed the operability evaluations.
The licensee's review of how the loss of annunciator event at Callaway
affected Wolf Creek Generating Station was good.
The licensee's evaluation of the fuel clad failures was thorough.
A noncited violation was identified because a weakness in design controls
resulted in inadequate maintenance instructions. The inspectors identified a
violation' because the licensee 'had conicted an inadequate postmaintenance
test. The postmaintenance test failed to identify that an error was
introduced during performance of an MOV maintenance activity.
The licensee conducted an excellent medical emergency drill and critique.
4 MAINTENANCE OBSERVATIONS (62703)
The purpose of inspections in this area was to ascertain that maintenance
activities on safety-related systems and components were conducted .in
accordance with approved procedures and TS. Methods used in this inspecticn
included direct observations of maintenance' activities _ and review of records.
4.1 Safetv-Related Batter _v and Battery Charger Maintenance
In response to several failures during the past year associated with the-NK 23-
safety-related battuy charger, the inspectors reviewed the maintenance
history of the battery chargers and the batteries, discussed the history with'
the electrical maintenance engineer responsible for the DC bus components,-and ,
observed battery maintenance activities.
There have been two failures of the NK 23 charger amplifier and firing boards,,
in November 1991 and, again, in June 1992 (refer to NRC Inspection-
Report 50-482/92-08). The failure of the amplifier and firing. boards caused
voltage fluctuations on the DC bus. Historically, there_was one other failure
of amplifier and firing boards, which affected the NK 24 charger, since the
battery chargers were installed.
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The licensee returned the amplifier and firing boards to the vendor for
evaluation of the failure mechanism. The vendor determined both boards
operated satisfactorily after initial troubleshooting and after being-
subjected to a_100-hour operational test. However, the vendor communicated
that the float potentiometer, a varianle resistor in the circuit but not on
the firing board, could have caused the appearance of a failure. The float
potentiometer can change resistance characteristics because of heat
degradation. The licensee discussed this problem with other utilities and
determined that industry experiences were mixed. The licensee incorporated
into their charger maintenance activities inspecting, adjusting, and, if
necessary, replacing the float potentiometer if further altage fluctuations
occur.
Intermittent bettery monitoring alarms on the NK 13 battery monitor has been a
long-standing problem that the licensee has pursued for resolution.- The
battery monitor compares the total battery voltage of 135 volt DC to the
voltage created by each half of the battery cells. The setpoint has a very
low tolerance range of i 0.01 volt DC. Four battery cells located on the same
side of the NK 13 battery were determined to have low voltage but were within
specifications. The low voltage condition of the cells has maintained the
voltage very close to the low voltage setpoint of the battery monitor but
above the TS limits. The vendor suggested that the electrolyte levels could
be adjusted by transferring electrolyte from high to low specific gravity
celle to equalize the voltage on both halves of the battery. The licensee
implemented this procedure four times without success.
To resolve this issue, the licensee decided that charging the cells
individually, or up to four cells in series, could increase the cell voltage.
A procedure was developed, reviewed, and approved by the Plant Safety Review
Committee for the activity. The inspectors observed portions of WR 02164-92.
The WR included the use of Procedure MPE BA-013, Revision 0, " Charging
Individual Battery Cells," and special work instructions. The inspectors
found that the WR provided good instructions for_-the performance of the
i activity, with precautions for proper isolation of the battery charger from
the safety-related battery. The inspectors determined from discussions with-
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licensee personnel that the cell charging was not fully successful.- The craft
personnel were knowledgeable of the task and followed the WR,
Another long-standing problem, since 1985, has been the corrosion of the cell
terminal posts. The individual battery cells utilize a soft seal, an_0-ring,
between flat washers and seal nuts at the battery posts. Electrolyte vapor
has leaked from the seals, which corrodes the terminal post and terminals.
When initially identified, the licensee and vendor could not determine an
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effective solution, consequently, the licensee aggre sively developed a
,
program to-inspect the batteries for corrosion. The licensee perforr:s visual
inspections weekly and quarterly. If the visual inspection reveals-corrosion,
the terminal resistance is checked prior to and following cleaning activities.
The battery post and terminal is cleaned and covered with_a protective grease.
During the last refueling outage, the licensee completely disassembled and
cleaned the batteries. There was no indication of corrosion in the seal area
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that could cause the cell cover to crack and break. The licensee determined
the soft post seal design prevented cracking of the battery cover. The vendor
suggested using an epoxy seal in the 0-ring area. However, the licensee ruled '
out that recommendation because a buildup of corrosion could cause battery
cover cracking if a hard seal was present. The licensee is considering
replacement of the batteries before the end of life because of the corrosion
problem. The licensee maintains a historical and trending program to monitor
bo~.h the charger and battery problems. The inspectors, in addition to
co nducting the above evaluation, reviewed and observed portions of the battery
inspections.
The inspectors concluded the licensee addressed the problems with battery
chargers very well and in sufficient depth. The activities associated with
the battery corrosion and the low voltage condition of some battery calls by
the licensee is commendable. Tho history and trending program of the Class IE
DC bus and associated equipment was excellent.
4.2 RHR Train B Maintenance
During the RHR Train B maintenance outage, the inspectors observed the
implementation of:
o WR 52303-92, RHR B Pump Motor Oil Sampling, on November 4, 1992, and
o WR 52306-92, RHR B Room Cooler Maintenance and Inspection, on
November 4, 1992.
During the performance of WRs 52303-92 and 52304 32 by electricians in the
RHR B pump room, the inspectors noticed a flexible connector disconnected
between the fixed conduit and flexible conduit for the bearia oil temperature
that was routed to the top of the RHR pump motor. The maintenance workers did
not notice nor document the dis. nnected conduit. The inspectors informed the
electrician's supervisor of the loose connector after review of the completed
WRs. The electrical supervisor agreed that the workman's porceptions of their
responsibility was narrow since only equipment required u be repaired was
considered. The supervisor agreed th.t the workman should take a broader view
of the utilization of environmental discrepancy sheet while in a work area and
stated that th h expectation would be communicated in shift meetings. The
licensee prompt b initiated a WR to have the connector repaired. The
inspectors con:idered the electricians' failure to identify this discrepancy
to be a weakneu
4.3 Gate Seal Inspection and Replacement in the Spent Fuel Pool
On November 5, 1992, the licensee began inspection activities on the gate seal
for the cask lording pool and the fuel transfer canal gates. In order to
inspect the gates, the gates were lifted off the storage location and moved to
a locatior, where the divcrs could safely examine the seals. While relocating
the fuel transfer canal gate, a quality assurance auditor raised a concern
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that the gate may have been over spent fuel elements. 1he licensee stopped
the work activities after placing the gate in a safe condition. The licensee
initiated a reportability evaluation request to determine reportability and an
investigation to determine the circumstances surrounding this issue. This
issue was significant because it may have been a violation of TS 3.9.7, which
states that loads in excess of 2250 pounds shall be prohibited from travel
over fuel assemblies in the spent fuel pool. The licensee replanned and
successfully completed the work after resolving the method of movement of the
gate so that it would not travel over fuel assemblies. The inspectors
observed the movement of the cask loading pool gate but not the movement of
the fuel transfer canal gate. Radiological controls in place for the diver's
work were exec 11ent. The licensee did not complete the reportability
evaluation nor their investigation before the- report period ended. The
inspectors noted that work planning and control related to this issue may be
inadequate. This item will remain unresolved (482/9231-03) pending further
NRC inspection.
4.4 Safety-injection Accumulator level Indication
4
The inspectors reviewed WRs associated with the Safety injection Accumulator
Tank B level indication. On October 12, 1992, the level indication failed
high, and the licensee initiated WR 05300-92 to troubleshoot EP L10952, Safety
injection Accumulator Tank B level transmitter. The transmitter failed when
moisture penetrated the flexible conduit and entered into the transmitter from -
a Containment Cooler B drain pan water leak. During troubleshooting, the I&C
technicians examined the other accumulator level and pressure transmitter
conduits for similar conditions, with no problems being identified. The-
itcensee initiated WR 05335-92 to install a moisture seal at the flexible
conduit connector to prevent moisture intrusion after replacing the
transmitter. The transmitter wiring connections-are not environmentally
qualified. The licensee is considering installing moisture seals on the other
accumulator flexibic connectors during the next outage. The inspectors
determined that the licensee immediately examined the failure for generic
issues.
4.5 Steam Generator Blowdown Tank Drain Line Weld Repairs
On November 18, 1992, a pinhole steam leak occurred in the 8-inch steam
generator blowdown tank drain line to the heater drain tank. The leak--
occurred on the drain pipe directly opposite of a 3-inch penetration from the
- startup feedwater pump recirculation line. The startup feedwater pump *
recirculation line has an orifice installed upstream of the recirculation
penetration. The itcensee concluded that the impingement of the flow from the
orifice eroded the drain pipe opposite of the orifice. Ultrasonic examination
revealed that the indication was 1/2 inch in diameter with a pinhole _ :
penetrating t he pipe. Since the leak was not._able to be isolated, the
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-licensee encapsulated the line surrounding the pinhole leak. The inspectors
reviewed the WR, observed portions of the work activities, discussed the
results of the ultrasonic examination with the test engineers, and discussed -
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the issue with the engineer responsible for the erosion / corrosion program. ,
The inspectors concluded the licensee had adequately assessed and offcctively i
resolved the leak. l
4.6 Miscellaneous Maintenance Activities
The inspectors observed the following work activities:
a WR 50403-92, Safety Injection Train 8 Discharge Accumulator injection
Valve - Motor Operated Valve EH HV88218, on October 14, 1992, I
o WR 52202-92, Safety injection Pump B 011 Change, on October 14, 1992,
a WR 52395-92, Safety injection Pump B Breaker, Preventive Haintenance
inspection, on October 14, 1992, and
a WR 00243-92, Safety injection Pump B Breaker, Replace Prop Spring, on
October 14, 1992.
The craft personnel performed the maintenance activities in accordance with
detailed work instructions that were appropriate to the work conducted. The
craft were experienced and knowledgeable. The inspectors determined that work
was stopped when an instruction was not clear. Maintenance equipment and test
instr uments were within calibration. Personnel adhered to the radiation work
permit-instructions, where applicable, for protective clothes and other
radiation worker practices.
4.7 Conclusions-
The licenseo maintenance practices relative to the safety-related batteries
was commendable. Craft personnel performing specific maintenance in the RHR B-
room did not identify and document a loose connector; the inspectors 1
considered the failure to identify the component deficiency to be a weakness.
The inspectors identified an unresolved item because licensee work controls
for loads over spent fuel may have resulted in a TS violation. The licensee
effectively repaired a failed level transmitter and a' pinhole leak created by
erosion.
5 SURVEILLANCE OBSERVATIONS (61726)
The purpose of this inspection was to ascertain whether surveillance of
safety-significant systems and components was being conducted in accordance
with TS and approved procedures.
5.1 Operator Daily Loos
In October 1992 the inspectors accompanied a nonlicensed operator on his
rounds in the auxiliary building. The nonlicensed operator utilized
Procedure CKL ZL-001, Revision 16, " Auxiliary Building Log and Daily Reading-
Sheets." The inspectors determined that the nonlicensed operator was:-
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(1) knowledgeable and aware of the plant conditions, (2) cautious and
deliberate during the rounds, took appropriate readings, checked equipment for
levels, touched pump bearings for excessive heat buildup, and observed each
area for leaks or spills, and (3) key carded into each door, as required.
5.2 Shutdown Margin Determination
On November ll, 1992, the inspectors observed reactor engineers perform
Procedure STS RE-004, Revision 11. " Shutdown Margin Determination," as
required during the reactor startup. The inspectors determined that the
reactor engineers performing the surveillance were knowledgeable about the
procedure requirements. The licensee had a software program on a personal
computer that required specific inputs such as the time since the shutdown,
power level prior to shutdown, and the current baron concentration. After
inputing the parameters, the program provided an estimate of the shutdown
margin. The procedure was performed at various intervals while the plant was
in Mode 3, with all data meeting specifications.
5.3 Conclusions
lhe knowledge level and deliberations of a nonlicensed operator during
operator rounds indicated that nonlicensed personnel were sensitized to the
importance of proper logtaking.
6 COLD WEATHER PREPARATION (71714)
The inspectors conducted this inspection to evaluate the effectiveness of
licensee actions to protect plant equipment during extremely cold weather.
6.1 Licensee Preparations
The inspectors verified that Procedure S1N Gp-001, Revision 9, " Plant
Winterization," provided detailed guidance for implementing cold weather
protection. The procedure provided cautions for ensuring area space heaters
and heat tracing for the tanks operated properly. The procedure specified
that upon unavailability of the auxiliary steam system, the outside tanks were
required to be placed on recirculation. Procedure ADM 02-030, Revision 12,
" Reading Sheets and Shif t Rounds Instructions," provided general guidance for
operators conducting rounds to monitor heat trace circuits.
The inspectors independently verified that the plant heating steam system
supplies to various safety-related air supply units were operable. The
inspectors verified that the power supplied to selected heat trace circuits
was properly lined up. The inspectors compared a listing of required
winterization preventive maintenance' activities to completed preventive
maintenance activities to ensure work was being implemented,
The inspectors verified that: the licensee's cold weather checklists were
properly completed; maintenance activities were implemented to assure that
heat tracing, space heaters, and thermostats operated properly; required cold
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weather inspections were completed; alarm response procedures provided
adequate guidance for responding to freeze ')rotection alarms; and fire
protection systems were monitored. !
6.2 Auxiliary Steam System Activities
The licensee began implementing cold weather protection preparations in
August 1992 when they conducted an auxiliary steam boiler train outage to
ensure the auxiliary steam boiler and the various auxiliary steam system pumps
operated properly. - Detween August 3 and October 24, 1992, the licensee
replaced ) ump shafts for the auxiliary steam feedwater aumps on four occasions
because tie pump shafts had seized during operation. T1e licensee believed a
stress riser occurred because the interior threads in the pump shaft that held
the pump impeller bolt were bored too far into the hole. Following the second
shaft failuro, vendor personnel observed the disassembly and reassembly of the
auxiliary steam feedwater pump, verifying that all critical measurements met
specifications and that the > ump was properly reassembled. The licensee
modified the shaft after a tiird failure. The new pump shaft was threaded.
with the impeller attached by a nut. The auxiliary steam feedwater pump with
the redesigned shaft o)erated for 4 days prior to failing when the pump shaft
seized. The licensee .1ad investigated several potential causes for the shaft
cracking; however, the licensee could not determine the cause of the numerous
recent failures.
Following the initial failure on September 4, 1992, the licensee researched
the possibility of obtaining new parts. The licensee. determined that their
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model of auxiliary steam feedwater pump was not manufactured as a unit but
spare parts could be manufactured. Ilowever, the parts were fabricated as
customized parts with at least a 6-week lead time._ The licensee began
reviewing other pump designs so that they could lower the part procurement
lead time and reduce the expense. The system engineers determined that the
piping would require modification for a different pump and began developing a
plant modification. After the new shaft design failed on October 20, 1992,
the licensee expedited procuring new pumps and prepared Plant Modification
Request 4465, " Auxiliary Steam feedwater Pump Replacement," to modify the pipe
configuration.
The licensee changed the pumps and modified the piping configuration in
accordance with Plant Modification Request 04465. The licensee installed the
Train A auxiliary steam feedwater pump on October 24, 1992, and placed the
auxiliary steam system in service on October 25, 1992. The Train B auxiliary
steam feedwater pump was installed on October 29, 1992. Throughout the period
that the pumps were out of service, the licensee placed the water storage
unks on recirculation to prevent any chance of freezing.
-6.3 Conclusions
The licensee expended considerable effort to protect the )lant against the
effects of cold weather. The licensee's sensitivity to tie problems
associated with cold weather was demonstrated by their efforts to make
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operable an auxiliary steam feedwater pump. The licensee had a very good
program to protect against cold weather.
7 MANAGEMENT MEETING (30702)
On October ll3,1992, a public meeting between NRC-and the Wolf Creek Nuclear
Operating Corporation was conducted in the Region IV NRC office to discuss the
licensee's Management Action Plan and the development and implementation of
the PEP. The meeting provided a brief summary of the number of Management
Action Plan items that will be incorporated into the PEP and the number of
action items that will undergo closure as defined by the Management Action
_
Plan. The meeting provided beneficial uformation about both programs.
The presentation on the PEP program provided a history of the program
development to date and an overview of upcoming program milestones. The
program resulted from third party reviews conducted at the request of the
owner companies. The. consultant aided the PEP team in developing the program
from interviews with plant management and a review of assessments conducted by
NRC and other reviewing organizations. After initial development of the
program action plan areas of emphasis, an employee survey was conducted.- The
PEP action plans should be completely developed by the end of the first
ouarter of 1993.
8 FOLLOWUP (92700)
8.1 (Closed) Unresolved item 482/9228-01: Loss of Charaina and letdown Flows
On October 1,1992, while an operator transferred from Centrifugal Charging
Pump (CCP) A.to the positive displacement pump (PDP), charging flow stopped
and letdos;n flow decreased on two occasions for approximately 20.and
27 seconds, respectively. The initial loss 'of flow occurred when a licensed
operator failed to close the PDP recirculation valve in accordance with the
procedure. The second . loss of flow was postulated to be caused by hydrogen '
gas leaving solution on' the suction side of the ?DP and collecting in the
pulsation damper. At the en' of toe last inspection period, the inspectors
questioned the licensee as to whetter the gas bubble could have gas-bound the
CCPs.
Procedure SYS BG-201, Revision 15. " Shifting Between Positive Displacement and
Centrifugal Charging Pumps," provided instructions in step 4.2.6 to close the
PDP recirculation valve, M0V BG HV8109. While transferring from CCP A to the
'
PDP on October 1, 1992, a licensed operator failed to close MOV BG HV8109 as
i specified, which resulted in decreased letdown flow and a loss of charging
, flow. The failure to follow the procedure is a violation of TS 6.8.1.a
l (482/9231-04). This procedural violation was caused by I1 censed operator
j inattention to detail.
i
During this inspection period, the inspectors reviewed the licensee's '
calculations for head loss in the suction piping from the volume control tank
to the PDP and the CCPs. The licensee's calculations demonstrated that the
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- gas could not leave solution on the suction side of the pumps. Since the gas
could not leave solution,'there was no possibility of binding the CCPs. At :
'
the end of the inspection period, the licensee stated they would provide an
engineering evaluation by December 14, 1992, that described the most probable-
cause of the second PDP loss of flow. The licensee believed that the hydrogen l'
might have been formed in the PDP pump cylinders, since the licensee had
previously experienced cylinder spring failures created by hydrogen
embrittlement.
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ATTACHMENT 2
1 PERSONS CONTACTED
P. D. Adam, Supervisor, Reactor Engineering
R. S. Benedict, Manager, Quality Control
A. B. Clason, Supervisor, Maintenance Engineering
R. D. Flannigan, Manager, Nuclear Safety Engineering
D. E. Gerroits, Manager, Instrumentation and Control ,
N. W. Gioadley, Manager, Equipment Engineering
R. W. Holloway, Manager, Maintenance and Modifications
L. W. Holloway, Supervisor, System Engineering
D. Jacobs, Supervisor, Mechanical Maintenance
R. K. Lewis, Supervisor, Results Engineering
W. M. Lindsay, Manager, Quality Assurance
R. L. Logsdon, Manager, Chemistry
J. D. Lutz, Regulatory Compliance Engineer
0. L. Haynard, Vice President, Plant Operations
K. J. Moles, Manager, Regulatory Services
T. S. Morrill, Manager, Radiation Protection
D. G. Moseby, Supervisor, Operations
F. T. Rhodes, Vice President, Engineering
T. L. Riley, Supervisor, Regulatory Compliance
D. B. Smith, Marager, Modifications
C. M. Sprout, Manager, System Engineering
J. D. Stamm, Manager, Plant Design Engineering
H. L. Stubby, Supervisor, Technical Training
5. G. Wideman, Supervisor Licensing
M. G. Williams, Manager, Plant Support
B. D. Withers, President and Chief Executive Officer
The above licensee personnel attended the exit meeting, in addition to the
personnel listed above, the inspectors contacted other personnel during this
inspection period.
2 EXIT MEETING
An exit meeting was conducted on November 25, 1992. During this meeting, the
inspectors reviewed the scope and findings of the report. The licensee did
not identify as proprietary any information provided to, or reviewed by, the
inspectors.
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ATTACHMENT 3
LIST OF ACRONYMS
CCP centrifugal charging pump
DC direct current
DEI dose equivalent iodine
DRPI digital rod position indication
FRI fuel reliability indicator
I&C instrumentation and controls
ITIP Industry Technical Information Program
MOV motor operated valve
PDP positive displacement pump
PEP Performance Enhancement Program
ppm parts per million -
RWST refueling water storage tank
IS Technical Specifications
uti/ml microcurie per milliliter
WR work request
_