ML20029D112
| ML20029D112 | |
| Person / Time | |
|---|---|
| Site: | Cooper  |
| Issue date: | 04/29/1994 |
| From: | Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20029D109 | List: |
| References | |
| 50-298-94-03, 50-298-94-3, NUDOCS 9405040046 | |
| Download: ML20029D112 (17) | |
See also: IR 05000298/1994003
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-298/94-03
License: DPR-46
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Licensee: Nebraska Public Power District
P.O. Box 499
Columbus, Nebraska
Facility Name: Cooper Nuclear Station (CNS)
Inspection.At:
Brownville, Nebraska
Inspection Conducted: January 2 through' February'12, 1994,
Inspectors:
R. A. Kopriva, Senior Resident Inspector
W. C. Walker, Resident Inspector
E. E. Collins, Project Engineer
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Approved-
. E.
agliardo, Chief, Project Section C
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ivis@ionofReactorProjects
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Inspection Summar_Y
Areas Inspected:
Routine, unannounced inspection of onsite response to
events, operational safety verification, maintenance observations and
surveillance observations, followup on corrective' actions for violations, and
onsite review of licensee event reports.
Results:
An unexpected actuation of an engineered safety feature during the high
pressure core injection (HPCI) surveillance-indicated procedure problems
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which were not identified as discrepancies-in previous surveillances.
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The recently developed questioning attitude by operators resulted in the
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concern finally being identified (Section 2.1).
The review of several maintenance procedures indicated a lack of
recognition by maintenance personnel concerning procedural requirements
and inadequate implementation of a procedure (Section 3.2.1).
The efforts of maintenance personnel to evaluate alternatives and prejob
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planning for repair of a reactor equipment cooling valve were a noted
strength (Section 4.1).
9405040046 940429
ADOCK 05000298
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Surveillance activities identified a discrepancy in a procedure which
was a strength, but the surveillance should have been stopped and
reviewed when the discrepancy was first observed (Section 5).
The licensee had identified that manual primary containment isolation
valves were not uniquely identified and controlled as a result of the
event documented in Licensee Event Report (LER)93-012, but the licensee
had not yet implemented, at the time of the inspection, the corrective
action to address this issue.
Inspectors identified additional examples
of manual primary containment isolation valves that were not being
controlled by approved station procedures (Section 7.2).
The use of a single, unlocked, manual valve for the containment function
is an unresolved item. Two examples of single valves that did not meet
the design intent were identified.
'ieveral examples where a single,
unlocked valve was used for the containment function were identified
(Section 7.2).
Summary of Inspection Findings:
Unresolved Item 298/9403-01 was opened (Section 7.2).
Violation 298/9403-02 was opened (Section 7.2).
Violation 298/9325-01 was closed (Section 6.1).
Violation 298/9219-03 was closed (Section 6.2).
LER 298/93-016 was closed (Section 7.1).
LER 298/93-012 was closed (Section 7.2).
LER 298/93-011 was closed (Section 7.3).
Attachments:
Persons Contacted and Exit Meeting
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DETAILS
1 PLANT STATUS
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At the beginning of the inspection period, the plant was operating at
100 percent power.
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On January 21, 1994, the licensee initiated a load reduction to approximately
69 percent power as part of the licensee's efforts for fuel conservation.
During the power reduction, the licensee was able to complete its scheduled
turbine testing and to complete maintenance on the Condensate Booster Pump B
oil system.
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Contrcl rod adjustments were also performed prior to increasing power.
Full
power operation was restored on January 24.
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2 ONSITE RESPONSE TO EVENTS (93702)
2.1 HPCI Valve Operability
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On January 19, 1994, during the performance of Surveillance Procedure 6.3.3.2,
"High Pressure Core Injection Valve Operability Test," the pump's minimum flow
Valve HPCI-M0V-M025 unexpectedly stroked open. The control room operators
were stroking open and closed the pump's Valves HPCI-M0V-M019 and -M020, which
are injection valves, when Valve -M025 opened.
Valve -M025 is designed to
open on pump low flow of less than or equal to 400 gpm and a pump discharge
pressure of greater than or equal to 125 psig. Valve -M025 was not expected
to move during the surveillance test.
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The resident inspectors became aware of the concern on January 20, when the
licensee was preparing to make an Emergency Notifications System telephone
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call to the NRC inspectors informing them of the valve actuation, which was
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classified as an unexpected actuation of an Engineered Safety Features
component.
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The inspectors discussed the event with plant management and the system
engineers to obtain an understanding of the valve actuation.
Initially, the
engineers were uncertain as to the root cause of the problem. Maintenance
Work Request (MWR) 94-0289 and special instructions were generated to
troubleshoot the discrepancy.
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The inspectors followed the licensee's actions on determining the cause of the
actuation. The licensee installed a pressure gauge on a test connection for
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the HPCI system and noted a stagnant system pressure of 70 psig which is as
expected by the keep-fill system. The operators closed Valve -M020 and
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recorded a pressure of 100 psig.
Pump Valve -M019 was then opened and a
system pressure of 140 psig was noted. When Valve -M019 was again closed, the
pressure increased to 150 psig. At this point Valve -M020 was reopened, which
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caused Valve -H025 to open, and pressure dropped to essentially 0 psig,
initiating the start of the auxiliary condensate (keep-fill) pump.
The system engineers explained the results of the test.
During the sequence
of events, the pipe section between Valves -M019 and -M020 became pressurized
to 150 psig from the normal system pressure of the keep-fill pump.and the
valve stroking. When Valve -M020 was then opened, a pressure wave propagated
down the line and was picked up by the pressure sensor for Valve -M025. The
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minimum flow valve logic sensed a no-flow condition with a discharge pipe
pressure of more than 125 psig, which satisfied the opening logic for
Valve -M025, which then opened.
The inspectors had originally questioned the engineers concerning the
potential for back leakage from Control Valve CV-29CV, which could have caused
the increased pressure. The engineers responded that the pressure recorded
while performing the special instructions was not leakage by Valve CV-29CV and
the check valve. The pressure present in the pipe between Valves -M019'and
-M020 when they were both closed was not abnormal and, when the valves were
placed in.this configuration per Surveillance Procedure (SP) 6.3.3.2, the
normal _and expected response of Valve -M025 would be to open. A Temporary.
Procedure Change Notice and Procedure Change Notice to.SP 6.3.3.2 were issued
which caution operators to expect Valve -M025 to open and, if it does open, to
proceed with closing it, thereby preventing the recording of this normal
response as a discrepant condition.
The inspectors questioned the licensee about system configurations which could
cause similar occurrences. The licensee indicated that the valve operability
procedure for residual heat removal (6.3.5.2), reactor core isolation
cooling (RCIC) (6.3.6.2), and core spray (CS) systems (6.3.4.2) have been
reviewed for similar configuration. The RCIC system logic and valve operating
procedure is similar to the HPCI system in that the minimum flow valve is
controlled by flow and pressure inputs. A caution for possible minimum flow
valve operation should be considered for SP 6.3.4.2 for the RCIC system.
Minimum flow valve operation during CS and residual heat removal motor-
operated valve (MOV) surveillance testing is not expected because their
respective minimum flow valves are not controlled by pump discharge pressure',
they are controlled by flow rate logic only.
The licensee appeared to have investigated the'cause for the engineered safety
features actuation adequately. There were two concerns identified with the
event. The first was, why had this expected condition not been addressed in
the procedure, and why had the operators not questioned it during past
surveillances.
Licensee representatives indicated that this was identified at
this time because of the new questioning attitude of the employees.
The second concern is that the resident inspectors were not informed of the
engineered safety features actuation until the licensee was about to make an
emergency notification system call. There were no log book entries
identifying a surveillance concern or discrepancy. This concern was discussed
with the licensee.
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2.2 10 CFR Part 21 Reportable Condition
During the report period, the resident inspectors reviewed a 10 CFR Part 21
Reportable Condition which had been issued from General Electric Company on
December 3, 1993.
In 1975, General Electric Company had installed reactor protection system
scram status indicating lights on a BWR/4 control room panel to show when
power was available to scram pilot valve solenoids.
To protect against a hot
short condition, the current limiting isolation resistors for the status
indicating lights were to have been enclosed inside of their respective scram
contractor boxes.
In 1993, it had been discovered that the current limiting isolation resistors
were not located in their respective scram contractor b
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or any separation
enclosure, as required by the plant design. The 10 CFR Part 21 report
indicated that, if a hot short across the terminals of the isolation resistors
were to occur, in conjunction with a transient event, the resulting condition
would not jeopardize the safe shutdown of the plant, but it could be expected
that the minimum critical power ratio safety limit might be exceeded.
The inspectors discussed the concern with licensee management and engineers.
The engineers indicated that they had previous knowledge of the concern
identified in 10 CFR Part 21 report and had investigated the concern.
Their
conclusions were that CNS did not have the particular concern pertaining to a
hot short condition of the current limiting isolation resistors.
The inspectors were shown the style of isolation resistor used at CNS and
inspected the scram indicating lights installed at the plant. The isolation
(current limiting) resistor used at CNS is an integral part of the reactor
protection system scram status light, greatly reducing the potential of a hot
short condition. Also, the scram indicator lights were enclosed within a
protective box, further reducing the potential for an accidental hot short.
2.3 CS Minimum Flow Valve Actuation
The inspectors were informed that on February 1, 1994, during the performance
of SP 6.3.4.2, " Core Spray M0V Valve Operability," while stroking open
Valve M026B which is the Test Loop B return valve, Valve CS-M0V-M05B, the
Pump B minimum flow valve, stroked closed and immediately reopened.
It was
noted from the plant management information system data that when Valve M026B
was stroked open, the pump discharge line pressure decreased and the discharge
line flow as read by PMIS Point N001, indicated a flow rate of approximately
1461 gpm, although Core Spray Pump B was not operating. Valve -M058 is a
normally open valve with position logic controlled by the Core Spray Pump B
discharge flow rate. The logic is designed to have the valve close on a
sensed flow rate greater than 1200 gpm.
The licensee performed portions of the surveillance test in an attempt to
recreate the actuation of Valve -M05B.
Valve -M0268 was stroked again,
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and Valve -M05B did not close on this attempt. Core Spray Loop B was declared
inoperable. The inspectors questioned the licensee as to whether this
actuation had been identified during past performances of the surveillance.
The licensee indicated that this was not expected nor did they recall any
previous actuations.
The licensee pursued the cause of the valve actuation
and their investigation revealed that the Core Spray Loop B flow
instrumentation had been calibrated per SP 6.2.2.4.1 earlier in the day on
February 1.
Further troubleshooting, including stroking of Valve -M0268,
could not recreate the actuation of Valve -M05B.
Review of the work item
history revealed numerous problems attributed to air in the flow indication
instruments and sensing lines.
Review of the electrical circuitry indicated
no factors that would produce this type of indication.
The licensee continued searching for resolution of the valve actuation.
The
licensee proceeded to back-flush the flow instrumentation after the event.
The licensee was unable to recreate the scenario nor were they able to
specifically identify a root cause.
On February 11, Valve -M026 was again stroked, with no resulting actuation of
Valve -M05B. The licensee concluded that, since the flow instrumentation
which provides the initiation logic for Valve CS-M0V-M058 had been calibrated
just prior to performing SP 6.3.4.2, and the fact that the problem could not
be recreated, indicated that the unexpected initiation of Valve -M05B was
caused by spurious operation of the flow sensor.
Licensee representatives
stated that a small air-bubble introduced or removed in the instrument sensing
lines during calibration could have produced the type of flow indication
identified when the discharge line was rapidly depressurized to initiate
Valve -M05B closure.
2.4 Conclusions
Operator performance during plant events was good.
However, the failure to
inform the resident inspectors in a timely manner of ongoing events and the
failure to log surveillance discrepancies indicates that continued improvement
is needed in this area.
The licensee had knowledge of a Part 21 concern applicable to the control
panel and had aggressively inrpected the configuration at CNS which confirmed
the fact that the Part 21 concern was not applicable to CNS.
The licensee had
concluded their investigation prior to the inspectors' inquiring about the
concern.
3 OPERATIONAL SAFETY VERIFICATION (71707)
The objectives of this inspection were to ensure that the CNS facility was
being operated safely and in conformance with regulatory requirements and to
ensure that the licensee's management controls were effectively discharging
the licensee's responsibilities for continued safe operation.
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3.1 Control Room Observations
The inspectors observed operations in the control room during normal and
backshift hours on a sampling basis.
The inspectors noted that the shift
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supervisors have taken a more active, aggressive role in controlling and
managing the control room and plant work activities.
Communications and repeat backs in the control room and throughout the plant
continued to improve.
The licensee indicated that they were continuing their
efforts in this area.
3.2 Plant Tours
The licensee was continuing their efforts to improve the housekeeping
condition of the plant, and the overall appearance of the plant was good.
3.2.1 Review of Maintenance Procedures
On January 11, 1994, the inspectors observed work which was in progress under
MWR 94-0094 to repair leaking Service Water Valves SW-A0V-851AV and SW-A0V-
853AV. The inspectors noted that maintenance personnel had used a 1/4-inch
nylon rope to tie off two pieces of equipment.
The nylon rope was draped over
a 3-inch reactor equipment cooling pipe and tied off on the yoke of a reactor
equipment cooling valve.
The inspector questioned the maintenance supervisor
concerning the acceptability of this practice and whether a rigging / loading
analysis had been performed. The licensee had not performed an analysis to
verify that the equipment supported by the nylon rope and piping would have no
adverse impact on the pipe and valve. Maintenance Procedure (MP) 7.0.3.1,
" Control of Lift: Less Than or Equal to 1000 Pounds," Revision 0, provides
guidance on this type of rigging.
Based on the inspectors' review of the
procedure, it appeared that the licensee should have completed Step 7.7.2,
which would have provided a justification for not implementing rigging
controls. This justification was to be signed by an engineer and a
supervisor.
The inspectors also noted that Section 8.10.1.3 of MP 7.0.4, " Conduct of
Maintenance," Revision 0, states, in part, "a review group shall be
established to periodically field observe the implementation of MWRs." The
group is to be composed of one representative from the mechanical, electrical,
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instrument and control (I&C), and weld shops. The procedure specifies that
the maintenance supervisor shall select one corrective maintenance and one
preventive maintenance activity for each shop representative to field observe
for each shop. The inspectors requested a summary of the observations
performed by the maintenance group and received four observations for 1993.
It appears that this program is not being properly implemented.
The
inspectors discussed the two examples above with the maintenance manager and
the engineering manager.
Based on the discussions, it appeared that an error
in judgement was made by the maintenance supervisor and mechanics in not
recognizing that any rigging activity being performed in the reactor building
requires a rigging analysis.
The rigging procedure was reviewed and the
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inspectors discussed the adequacy of the procedure with the maintenance
engineer.
The procedure appeared to be acceptable as written, but indicates
lack of recognition by maintenance personnel of requirements in a maintenance
procedure.
The example of the field observation program not being properly implemented
appeared to result from a breakdown in management direction and poor
communication of expectations for performance, requiring accountability of
assigned activities as they relate to periodic review of maintenance
activities. The inspectors discussed this with the maintenance manager and
were informed that these activities would begin to take place immediately as
specified in the procedure.
3.2.2
Fuel Pool Activities
On February 1, the inspectors observed the receipt of a transportation cask
for removal of two control blades. The cask, which weighed approximately
45,000 pounds, was transferred by crane from the first floor 903-foot
elevation of the reactor building to the refueling floor 1001-foot elevation.
The licensee personnel demonstrated good work practices during the lifting of
the cask. The crane operator was in constant communication with the
maintenance technician on the first floor during the lifting operation. After
the cask was placed on the 1001-foot level, it was washed off in preparation
for lowering into the spent fuel pcol for loading of the two control rod
blades. The licensee's health physics personnel were present at all times
during performance of activities on the refuel floor. The licensee was using
Special Work Permit (SWP)94-118 for entrance into and out of the work area.
Inside the SWP area the health physics staff had established another roped-off
area with step-off pad.
The inspectors questioned the health physics
technician concerning this additional area which was inside the contaminated
area but did not have an SWP.
The area inside the SWP area was roped-off as a
prudent measure to try to limit the spread of contamination on the refuel
floor. However, during the inspectors' observation, one contract individual
crossed through the additional roped-off area and then exited with potentially
contaminated boots. The additional controlled area appeared to be a good
radiological practice to reduce spread of contamination, but it appeared that
the contractors performing the work were somewhat confused on how to perform
work inside this additional roped-off area.
3.2.3
Reactor Eauipment Cooli_nq Heat Exchanger Cleaning
On February 1, the inspectors observed the outlet water box of the Reactor
Equipment Cooling (REC) B Heat Exchanger. The licensee determined that some
pitting existed and several areas were below minimal wall thickness and
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required weld buildup. The inspectors reviewed MWR 94-0438 under which the
ultrasonic testing, weld buildup, and radiographing of the weld areas was
performed.
The inspectors discussed and reviewed the radiographs with the
licensee, and no abnormalities were found.
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During the next scheduled refueling or maintenance outage, the licensee plans
to sandblast the heat exchanger, ultrasonic-test areas for minimum wall
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thickness, perform weld buildup if necessary, and coat the inner surface of
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the heat exchangers with epoxy, to decrease the potential for pitting and
erosion / corrosion.
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3.2.4 High Vibration on CS System
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On February 10, the inspectors observed the performance of SP 6.3.4.1, "CS
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Test Mode Surveillance Operation." A fastener from the flange on Core Spray -
Restricting Orifice - 29A located on the CS test return line had vibrated
loose from the flange and was found on the floor.
The licensee initiated
Deficiency Report 94-048 to document this discovery. After discovery of the
fastener which had vibrated loose, the licensee reviewed potential actions
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which could be initiated for systems with high vibration. Maintenance Work
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Requests 94-0460 and 94-0516 were initiated with special instructions to
increase the torquing on the flange fasteners on both CS Systems A and B.
The
licensee also decided to run CS Systems A and B to obtain additional vibration
readings which could be used by the engineering design group to determine if
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additional pipe supports were needed on the CS system.
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During observation of the CS B run, the inspectors noted a loose conduit
connection on Valve CS-MOV-26.
A Deficiency Report 94-118 was initiated by
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the licensee to document this discovery. The inspectors noted that CS
System B was on an increased inservice test frequency for vibration.
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inspectors observed the maintenance technicians collecting vibration readings
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for the piping downstream of Valve CS-M0V-26.
It appeared that vibration was
highest downstream of CS-MOV-?6.
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3.4 Security Observations
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The inspectors observed various aspects of the licensee's security program.
Personnel and packages entering the protected area were observed to be
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properly searched. Vehicles were properly controlled or escorted within the
protected area. Designated vehicles parked and unattended within the
protected area were found to be locked and their keys removed.
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routinely toured the protected area perimeter and found it to be maintained at
an excellent level.
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3.5 Radiation Protection Activities
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The inspectors verified that selected activities of the licensee's
radiological protection program were properly implemented.
Radiation and
contaminated areas were properly posted and generally well controlled.
Health
physics personnel were observed routinely touring the controlled areas.
3.6 Conclusions
Maintenance personnel and procedures continue to need management's attention
to assure that the procedures are being implemented adequately and personnel
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are following the procedures.
Failure to control two manual containment
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valves indicated the need for more positive controls on manual valves designed
for containment isolation purposes.
4 MAINTENANCE OBSERVATIONS (62703)
4.1 Replacement of Reactor Eauipment Cooling Valve
On January 14, 1994, the inspectors observed maintenance troubleshooting of
reactor equipment cooling valve (REC-A0V-TCV-451) under MWR 93-4128. The
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system engineer was also present during the troubleshooting activities. .The
valve was cycled five times and it appeared that the valve was binding in the
valve seat. After discussions with the engineering supervisor and. maintenance
supervisor, a decision was reached by licensee personnel.to replace the valve.
On January 26, the inspectors observed reinstallation of Service Water Inlet
Valve SW-A0V-TCV-4518. The maintenance mechanics were authorized to perform
work under MWR 94-0180 which was at the job site.
The mechanics also had a
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copy of the vendor manual and referred to it when clarification was required,
concerning the crushing of the newly installed flexitallic gaskets. All
signatures were present as required on the MWR and the inspectors reviewed the
comments concerning the as-found condition of the valve. During the removal
of the valve, which was located on top of the torus, a rigging evaluation was
required. This evaluation was present at the work site and attached to the
work package.
In the process of removing the valve, it was necessary to
provide additional rigging pick points prior to proceeding with the. valve
removal. Design Engineering was consulted to provide approval for the
additional rigging. The inspectors discussed with the mechanics the torquing
requirements that were contained in the vendor manual for compressing of the
flexitallic gaskets since no requirements were specific in the work package.
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The mechanics had reviewed the vendor manual and determined that no vendor
requirements were specified for torquing and compressing of. the flexitallic
The inspectors questioned the maintenance mechanics concerning radiological
hazards in the area. The mechanics were aware of the dose rates in the area,
and specific areas which had elevated dose rates were labeled. A radiological
survey was performed prior to the work effort by a health physics technician.
The inspectors also discussed the training requirements for the mechanics
performing the work and verified their qualifications through review of
mechanical maintenance training records.
The inspectors observed that the
maintenance mechanics were working on the top of the torus without.any type of
safety harness to prevent falling off the side of the torus. The MP did not
require the use of a safety harness, however, it appeared that some type of
safety restraint would have been prudent.
The inspectors observed the
satisfactory postmaintenance testing of the valve.
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4.2 Conclusion
The workmanship involved in the replacement of Reactor Equipment Cooling
Valve SW-A0V-TCV-451B was good. The licensee evaluated the alternatives for
repairing the valve and exercised good prejob planning to schedule the
cleaning of the REC B heat exchanger concurrent with the replacement of the
valve.
5 SURVEILLANCE OBSERVATIONS (61726)
5.1 CS Surveillance
On January 11, 1994, the licensee performed SP 6.2.2.4.2, "CS Loops A
and B Pump Time Delay Calibration and Functional / Functional Test,"
Revision 27. The purpose of this surveillance is to verify the operability of
the CS pumps' time delay logic which allows for sequential loading of the
diesel generators when normal station power is unavailable.
During
performance of the surveillance at Step 8.1.13, the control room operator was
uncertain of the status of Indicator Light 14A-DS20A on Panel 9-3 which
verifies the CS pump stop signal is sealed in (illuminated). At the time of
the surveillance, the control room operator did not stop the surveillance and
inform the I&C technicians in the auxiliary relay room of the potential
discrepancy. After the surveillance was completed the control room operator
discussed what was believed to be a discrepancy in the surveillance with the
shifts supervisor, shift technical advisor, and system engineer. The shift
supervisor initiated Operability Determinate 94-005 to ascertain if CS logic
was in accordance with design. The surveillance was signed off as
ratisfactory with a discrepancy noted. The operability determination verified
the CS system was operable and engineering decided to troubleshoot the CS
logic system using MWR 94-0114. The request allowed the technicians to review
the surveillance as specified in the procedure with stopping points to allow
an electrical maintenance technician to measure voltages across certain
relays, to assure no loose connections were evident.
Upon reperformance of
the test, no discrepancy could be found. The seal-in lamp for the pump
functioned as specified in the procedure.
The inspectors discussed with the
system engineer and electrical engineer how this discrepancy as-found in the
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first surveillance would now be documented. The engineers believed the
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procedure possibly needed to be more clear at Step 8.1.13 in that an
explanation could be written explaining when the indicating light should come
on and go off.
The inspectors questioned the engineers on how this
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discrepancy would be documented.
It did not appear that the engineers were
clear on what would be the best method for documenting the discrepancy.
However, the control room operator had already written Deficiency
Report 94-022.
The inspector discussed the procedure with the I&C technicians and learned
that another discrepancy existed which the I&C personnel would address.
This
related to Step 8.1.9 which requires an electronic counter to be connected to
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Panel 9-32 in the auxiliary relay room to check the time delay of the relay.
The procedure did not require the electronic counter to be removed from
Panel 9-32, which should be done at Step 8.1.12.
The inspectors found the control room operators' questioning of the
surveillance procedure to be good.
However, it appears the surveillance
should have been stopped when the discrepancy was first observed. Also, the
determination by the I&C technicians that the procedure was not entirely
accurate was good. The inspector noted that the engineers appeared uncertain
on how to appropriately document the above activities using the corrective
action program.
5.2 Conclusions
Surveillance activities identified a discrepancy in a procedure.
However, the
reactor operator did not inform anyone of a potential discrepancy in the
surveillance procedure until the surveillance was completed.
6 FOLLOWUP ON CORRECTIVE ACTIONS FOR VIOLATIONS (92702)
6.1
(Closed) Violation 298/93025-01:
Alarm Procedure Was Not Established and
Maintained For a Safety System Alarm
This violation documented that Alarm Procedure 2.3.2.22 did not appropriately
specify the operator actions to be taken when the alarm was received during
the high pressure coolant system surveillance testing.
To correct the causes of this violation, the licensee issued two Temporary
Procedure Change Notices,93-303 and 93-306, clarifying operator actions
should the "HPCI Turbine Inlet Drain Pot High Level" alarm come in during
surveillance on the HPCI system or if the alarm stays in after securing the
HPCI system. The inspector reviewed the temporary procedure changes and
verified completion of the procedure enhancements.
6.2
(Closed) Violation 298/92019-03:
Failure to identify and Correct the
Presence of Temporary Startup Strainers in the CS System
This violation was subsequently the subject of Special NRC Inspection
50-298/93-06 and the subject of escalated enforcement actions,
,
Violations 298/93006-01 and -02.
Violation 298/92019-03 is closed.
7 ONSITE REVIEW 0F LERs
(92700)
7.1
(Closed)
LER 93-016:
Design Change Installation Deficiency Control Room
Emergency Bypass System
This LER documents a condition that could have prevented the fulfillment of a
safety function of a system needed to mitigate the consequences of an
accident. During a design change implementation, an on-the-spot change was
issued. An error by craft personnel in lifting and sparing out the two cables
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specified in the Operations Support Center was committed. . In addition, no
quality control verification was specified in the design change instructions
to ensure the proper cables were lifted.
Bned on the above errors the control room ventilation (HVAC) system did not
isolate and transfer to the emergency bypass mode of operation during the
surveillance test of the control room ventilation system radiation monitor.
Had standard design installation procedures such as implementation of quality
control been incorporated into the Operations Support Center, this event might
have been prevented.
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The inspectors reviewed the documentation which incorporated this LER into
contractor craft training.
In addition, the inspectors verified that industry
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events training for engineering, operations, and station management personnel
who prepare, review, and approve Operations Support Center procedures, was
conducted.
7.2 (Closed LER 93-012: Violation of Primary Containment Integrity Due to
Operation of a 3/4-Inch Vent Valve Durina CS Surveillance Testina
On April 14, 1993, the licensee concluded that opening Valve CS-V-55 when
primary containment integrity was required was not in accordance with the
Technical Specifications. The primary containment integrity definition
required that all manually operated valves not required to be open during
accident conditions be closed.
Valve CS-V-55 was a 3/4-inch manual vent valve
located in the CS test return line, unisolable from the primary containment.
In June 1992, the monthly surveillance test procedure had been revised to open
the valve, attach a vacuum pump, and verify that the system piping had been
completely filled and vented after surveillance testing.
During monthly
surveillance testing from about June 1992 until March 1993, the licensee had
opened Valve CS-V-55 for short periods when primary containment integrity was
required. This event was identified by the licensee's Safety Review and
Assessment Board Safety Evaluation Sub-Committee during a review of
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10 CFR 50.59 evaluations that were done for procedure changes.
The licensee changed Procedure 6.3.4.1, "CS Test Mode Surveillance Operation,"
to prevent opening Valve CS-V-55 unless the plant was in a mode where primary
containment integrity was not required.
Inspectors reviewed Revision 33 and
verified that the procedure prohibited opening Valve CS-V-55 if primary
containment integrity was required.
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Nonconformance Report 93-076 root cause analysis identified the causes for the
event to be personnel miscue in that those who performed the 10 CFR 50.59
review did not recognize that opening Valve CS-V-55 violated primary
containment integrity, and that no programmatic method existed to identify
manual containment isolation valves whose operation would jeopardize primary
containment integrity.
As corrective action, the licensee reviewed the circumstances associated with
the procedure change and 10 CFR 50.59 evaluation with all technical staff,
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operations staff, and Station Operations Review Committee personnel.
The
licensee also planned to develop and implement a method to uniquely identify
manual containment isolation valves, but this action was not completed at the
time of the inspection.
Licensee personnel stated that the planned completion
date of this action was March 18, 1994.
Inspectors walked down the CS system and observed that, for both core spray
subsystems, there were single manual vent valves (Valves CS-V-54 and -55)
between the test return valves and the containment. The valves were not
locked and were not uniquely identified as primary containment isolation
valves.
For Valve CS-V-55, a plug was observed, and licensee representatives
stated that a plug was installed for Valve CS-V-54.
The process and
instrumentation diagram (P&ID) for the CS system, Drawing 2045, showed one
valve and no pipe cap or plug.
Inspectors walked down accessible portions of other systems that penetrated
the primary containment and found several additional examples of single manual
containment isolation valves.
These were Valves PC-V-506 and -507, torus
drain connection (no pipe caps or plugs), Valves RW-V-254 and -258, drywell
equipment and floor sump pump discharges (no pipe caps or plugs), and
Valve RHR-V-145, torus pool cooling return line to torus (pipe plug
installed) .
In addition, from review of the residual heat removal system
P&ID, Drawing 2040, inspectors found several examples of a single manual
containment isolation valve (Valves RHR-V-143, -144, and -146).
In each
example, the valves were not locked and were not identified as primary
containment isolation valves, although the valves performed that function.
The licensee did not control the installation of pipe caps or plugs, and was
not consistent in identifying the caps or plugs on P& ids.
Some caps were
shown on the P&ID and some were not.
Updated Safety Analysis Report (USAR) Chapter V, Section 2.3.5, " Primary
Containment Isolation Valves," classified process line isolation valves as:
Class A valves that communicated directly with the reactor vessel and
penetrated the primary containment; Class B valves that did not directly
communicate with the reactor vessel, but penetrated the primary containment
and communicated with the primary containment free space; and Class C valves
that penetrated the primary containment but did not communicate directly with
the reactor vessel, with the primary containment free space, or with the
environs.
Class A required two valves, Class B required two valves, and
Class C required one valve.
Except for check valves, this discussion required
valves to either automatically close or have remote operation from the control
room. This discussion only addressed process valves and did not address vent,
drain, or test connection manual valves; however, the licensee used it as a
basis for their classification of manual vent, drain, and test connection
valves.
Inspectors questioned the acceptability of a single, unlocked, manual valve
for containment isolation.
Licensee representatives indicated that there was
not a requirement for CNS to lock manual containment isolation valves, since
the plant was licensed before the current general design criteria.
USAR,
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Appendix F, described CNS' design considering the draft general design
criteria published in June 1967. USAR, Appendix F, Section 2.7.3, evaluated
CNS' design considering draft Criterion 53, " Containment Isolation Valves" as
"All lines which penetrate the primary containment anu which communicate with
the reactor vessel or the primary containment free space are provided with at
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lest two isolation valves (or equivalent) in series." Draft Criterion 53
stated " Penetrations that require closure for the containment function shall
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be protected by redundant valving and associated apparatus."
For Valves CS-V-54, CS-V-55, RW-V-254, RW-V-258, PC-V-506, PC-V-507,
RHR-V-145, and RHR-V-146, licensee representatives stated that one unlocked
valve was acceptable since these process lines did not communicate with the
reactor vessel or the free air space.
For Valves RHR-V-143 and -144, which did communicate with the containment free
space (located on the torus spray line), licensee representatives stated that
these valves were not within the containment design basis.
The torus spray
line was a Class B penetration, and two valves were required. The licensee
documented this configuration in Deficiency Report 94-107, dated
February 8, 1994, and performed an operability determination for the as-found
condition. The licensee concluded that the configuration was operable, taking
credit for the pipe plugs as the second boundary.
This operability
determination was not completed by the end of the inspection period and,
consequently, was not reviewed as part of this inspection.
Inspectors asked if the single valve configuration for Valves CS-V-54 and -55
was the original design.
Licensee representatives were unable to answer this
question definitively since they had not yet completed the design
reconstitution for the primary containment system; however, they did find that
Drawing 2045, Revisions 1 and 2 showed two valves.
This drawing was changed
to reflect the one-valve as-built condition by Drawing Change Notice 77-459,
which was approved on June 14, 1977. This change was made to make the P&ID
match the piping isometric drawings and the actual field configuration, which
was only one valve.
No evaluation of the single versus double vent valve
configuration could be found.
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Inspectors also found that P&ID Drawing 2028 showed two manual vent valves
where, in the field, only single Valve RW-V-254 was installed.
Inspectors identified several examples where only one manual valve was used to
provide containment isolation.
In each case, the manual containment isolation
valves were not identified as containment isolation valves and the valves were
not locked.
It appeareo', from the original P& ids, that the original design
provided for two valves. and draft General Design Criterion 53 implied that
redundant valves should be provided for the containment function.
Licensee
personnel stated that redundant valves were only required for lines that
communicated directly with the free air space or the reactor vessel.
The use
of a single manual valve for the containment function is an unresolved item
(298/9403-01) pending additional NRC review.
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Inspectors reviewed the valve line-up procedures and verified that
Valves RHR-V-143, -144, -145, -146, RW-V-254, -258, and CS-V-54, and -55 were
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controlled by approved procedures requiring the valves to be verified in the
closed position. Valves PC-V-506 and -507, however, were not controlled by
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procedure.
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Inspectors reviewed the safety evaluation for Design Change 90-036, which
installed Valves PC-V-506 and -507 during the last refueling outage.
The
,
licensee eventually planned to add new instrument lines, but Design
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Change 90-036 only installed the root valves on the torus.
The completion of
the instrument lines was to be done at a later date. The safety evaluation
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concluded that the possibility of operator error to open the valves was not
increased by the design change because the new instrume..t taps will be capped,
,
preventing suppression pool water loss.
Inspectors found that the valve caps
were not installed and that the valves were not controlled by procedure.
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licensee personnel installed the pipe caps before the end of the inspection
period.
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10 CFR Part 50, Appendix B, Criterion V, " Instructions, Procedures, and
Drawings," states, in part, " Activities affecting quality shall be prescribed
,
by documented instructions, procedures, or drawings, of a type appropriate to
the circumstances and shall be accomplished in accordance with these
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instructions, procedures, or drawings. The control of primary containment
isolation valve position is an activity affecting quality.
Inspectors
concluded that the failure to control the position of manual primary
containment isolation Valves PC-V-506 and -507 in an approved procedure is a
4
violation (298/9403-02) of the regulatory requirements stated above.
7.3 (Closed) LER 93-011:
Secondary Containment Surveillance Methodology
Failed to Identify Leakage Path Between Secondary Containment and the
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Radwaste Building
The events documented in the LER were reviewed in detail in NRC Inspection
Report 50-298/93-17, discussed in an enforcement conference, and the subject
of subsequent escalated enforcement actions.
The licensee's corrective
actions are being tracked under Violation 298/93017-01.
7.4 Conclusions
The licensee had identified that manual primary containment isolation valves
were not uniquely identified and controlled as a result of the event
documented in LER 93-012, but had not implemented corrective action, at the
time of the inspection, to address this issue.
Inspectors identified
additional examples of manual primary containment isolation valves that were
not controlled in approved station procedures.
The use of a single, unlocked, manual valve for the containment function is an
unresolved item.
Two examples of single valves that did not meet the design
intent were identified.
Several examples where a single, unlocked valve was
used for the containment function were identified.
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ATTACHMENT
,
1 PERSONS CONTACTED
1.1 Licensee Personnel
R. L. Beilke, Acting Radiological Manager
L. E. Bray, Regulatory Compliance Specialist
S. L. Bray, Quality Assessment Supervisor
R. Brungardt, Operations Manager
J. W. Dutton, Nuclear Training Manager
C. M. Estes, Corrective Actions Program Overview Group (CAP 0G)
R. L. Gardner, Plant Manager
G. R. Horn, Vice President, Nuclear
J. E. Lynch, Plant Engineering Manager
E. M. Mace, Senior Manager Site Support
J. M. Meacham, Senior Nuclear Division Manager of Safety Assessment
D. R. Overbeck, Purchasing and Materials & Supervisor
R. X. Sanchez, CAP 0G
M. E. Unruh, Maintenance Manager
D. A. Whitman, Division Manager of Nuclear Support
V. L. Wolstenholm, Division Manager of Quality Assurance
1.2 NRC Personnel
R. A. Kopriva, Senior Resident Inspector
W. C. Walker, Resident Inspector
C. J. Paulk, Reactor Inspector
The personnel listed above attended the exit meeting.
In addition to the
personnel listed above, the inspectors contacted other licensee personnel
during this inspection period.
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2 EXIT MEETING
An exit meeting was conducted on February 16, 1994.
During this meeting, the
inspectors reviewed the scope and findings of this report. The licensee did
not identify as proprietary any information provided to, or reviewed by, the
inspectors.
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