ML20035H605
| ML20035H605 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 04/29/1993 |
| From: | Gagliardo J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20035H601 | List: |
| References | |
| 50-458-93-05, 50-458-93-5, NUDOCS 9305060062 | |
| Download: ML20035H605 (24) | |
See also: IR 05000458/1993005
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-458/93-05
Operating License:
Licensee:
Gulf States Utilities
P.O. Box 220
St. Francisville, Louisiana 70775-0220
Facility Name:
River Bend Station
Inspection At:
St. Francisville, Louisiana
Inspection Conducted:
January 31 through March 13, 1993
Inspectors:
W. F. Smith, Senior Resident Inspector
D. P. Loveless, Resident Inspector
Approved:
J. () Gagliardo, Chief, Project Section C
Date
Inspection Summary
Areas Inspected:
Routine, unannounced inspection of plant status, onsite
response to events, operational safety verification, maintenance and
surveillance observations, followup on corrective actions for violations, and
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other followup.
Results:
The licensee's corrective actions to accelerate the reviews in an effort
to identify and correct any additional overlap problems with instrument
and control surveillance test procedures were appropriate (to the
circumstances, for the safety significance of the items found to date).
The licensee's sensitivity in monitoring off-gas radiation monitors and
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noting a trend, which resulted in the early identification of a fuel
leak, was excellent.
The licensee's efforts to carefully analyze the
problem and take appropriate steps to determine the location of the leak
without making it worse were excellent (Section 2.2).
The inspector considered the reduction in lighted control room
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annunciators to be noteworthy and indicative of management's efforts to
reduce outstanding work items in the control room (Section 3.I).
9305060062 930430
ADOCK 05000458
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A weakness was demonstrated in attention to detail when the operators
flooded the Residual Heat Removal (RHR) A pump room sump in an effort to
add water to clear a high/ low level alarm (Section 3.1).
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One violation was identified for failure to perform an adequate retest
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following maintenance of a safety-related solenoid operated instrument
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air valve (Section 4.3).
The operators' performance and documentation of the reactor jet pump
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operability test was excellent (Section 5.1).
One example of a violation was identified based on technical errors and
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an inappropriate application of ASME Code reference value tolerances.
Previously identified weaknesses continued to appear in the performance
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of pump and valve inservice testing by the operators (Section 5.2).
A second example of the above violation was identified because tank
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level versus time was used in lieu of the flow instrumc.nts required by
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ASME Code Section XI (Section 5.3).
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Summary of Inspection Findings:
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Violation 458/93005-1 was opened (Section 4.3).
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Violation 458/93005-2 was opened (Section 5.2).
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Inspector Followup Item 458/93005-3 was opened (Section 4.2).
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Two noncited violations were identified (Section 2.1 and 2.3).
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Violation 458/92009-1 was closed (Section 6.1).
Unresolved Item 458/92011-1 was closed (Section 7.1).
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Attachments:
Attachment 1 - Persons Contacted and Exit Meeting
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DETAILS
1 PLANT STATUS
At the beginning of this inspection period, the plant was operating at
100 percent power.
On February 10, 1993, power was reduced to approximately 70 percent to repack
a leaking gland on Feedwater Regulating Valve A, to accomplish the
deep / shallow reactor control rod exchange, and to perform the monthly turbine
control valve surveillance.
Power was restored to 100 percent on February 15.
On February 26, the licensee commenced lowering reactor power to 87 percent
for steam leak repairs and turbine testing.
With the moisture separator
reheaters out of service, the licensee slowed or stopped four packing leaks
and attempted to repair the leaking Nonreturn Valve lESS-NRV29B.
The repair
was unsuccessful, so the parts needed were assembled to repair the bonnet leak
later. The turbine valves were tested and reactor power was increased to
100 percent on the February 27th.
On the evening of March 2, the licensee lowered reactor power to 75 percent to
complete the repair of Valve lESS-NRV29B.
The bonnet leak was repaired to
leak tight, and then the reactor was returned to 100 percent power within
10 hours1.157407e-4 days <br />0.00278 hours <br />1.653439e-5 weeks <br />3.805e-6 months <br />, on March 3.
At the end of this inspection period, the plant was operating at 100 percent
power.
2 ONSITE RESPONSE TO EVENTS (93702)
2.1
Incomplete Logic System Functional Testinq
On February 12, 1993, the licensee identified a condition where the
surveillance test procedures (STPs), designated to implement the Technical Specification 4.3.5.2 surveillance requirement to perform a logic system
functional test (LSFT) of the reactor core isolation cooling (RCIC) system,
did not test the entire loop.
Briefly. Technical Specification 1.24 defines
an LSFT as a test of all logic components, from sensor through, and including.
the actuated device to verify operability.
The plant was operating at about 86 percent power at the time of discovery.
Condition Report 93-0083 was initiated to document the problem and to notify
the shift supervisor.
The shift supervisor promptly complied with the action
statements of Technical Specification 3.3.5 and declared RCIC inoperable,
effective as of the time of discovery.
Procedures STP-051-4226(4227), Revision 7 (8), "ECCS/RCIC sctuation ADS Trip
System A (B) Reactor Vessel Water Low, level 3 High, Level 8 Monthly Chfunct.
18 Month Chcal, and 18 Month LSFT," and STP-209-0601, Revision 5, "RC]C
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Initiation Functional," in combination, failed to test the entire loop by not
verifying continuity in the circuit wiring through certain relay contacts to
energize reactor vessel Water Level 8 Relay E51*K92.
If that continuity was
lost, the existing STPs would not have identified it.
In addition,
STP-209-0601 did not identify the fact that it overlapped STP-051-4226(4227)
to complete the LSFT for the RCIC actuation on reactor _ vessel Water Level 8.
As an interim solution to verify operability of RCIC, Work Order R059403 was
implemented to check the continuity of the above circuitry.
The results were
satisfactory and, within approximately 14 hours1.62037e-4 days <br />0.00389 hours <br />2.314815e-5 weeks <br />5.327e-6 months <br />, the RCIC Technical
Specification action statement was exited.
The licensee explained that the above problem was identified during a " Safety
System Functional Assessment" being conducted as a safety initiative by
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Quality Assurance.
The RCIC and low pressure core spray (LPCS) systems were
the subjects of the assessment, which was completed on February 18. An
additional issue identified by this review was related to the LPCS and low
pressure core injection (LPCI) Train A injection valve permissive logic.
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logic was designed to allow the injection valves to open when called upon,
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only when reactor vessel pressure was at or below the lower design pressures
of the LPCS and LPCI systems. On February 19, the licensee found that the
logic was tested in the permissive state but was not tested to ensure that the
permissive contacts were open to prevent the injection valves from opening
(nonpermissive state) when reactor vessel pressure was above the permissive
setpoint. The licensee promptly declared the LPCS and LPCI Train A systems
inoperable in accordance with the plant Technical Specifications.
The
licensee then verified that LPCI Trains B and C had been properly tested in
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both the permissive and nonpermissive states and, therefore, a total loss of
function had not occurred.
The STPs were revised and a proper test on Train A
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was completed satisfactorily.
On February 20, the inspector reviewed the
completed test record and found no discrepancies.
The inspectors questioned what actions were being taken to ensure that similar
discrepancies did not exist in other safety-related instrument and control
loop test procedures.
In response, the licensee stated that, for the short
term, 32 points of overlap would be checked at random in other systems.
The licensee had already identified a need to develop a comprehensive matrix
which provided the relationship between STPs to ensure that continuity of
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testing and/or overlay was maintained. This information was to be used when
reviewing procedures.
The licensee also stated that the process of developing
the matrix would confirm overlap where needed and would reveal any
discrepancies, if they existed.
The licensee stated that work on the matrix
was scheduled to begin in May 1993, after another initiative was completed
which was to upgrade existing procedures in terms of human factors and
schedular interface.
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As of March 3, eight points of overlap were checked satisfactorily when the
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licensee discovered another error made between Revisions 8 and 9 of
STP-508-4202, "RPS/ Isolation Actuation Instrumentation Drywell Pressure-High,
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18 Month Chcal, 18 Month LSFT." Relay C71A*K4B actuation for Channel B high
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drywell pressure / primary containment isolation was inadvertently deleted
during the procedure revision process.
Channel B was, therefore, declared
inoperable by the operators on the basis that Technical Specification
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Surveillance Requirement 4.3.2.2 LSFT was not satisfied to verify operability.
The action statement in Technical Specification 3.3.2.b required the operators
to place Channel B in the tripped condition within I hour but, since that
would change the. coincidence logic for an isolation to one out of two once,
the operators opted to leave the channel active for no more than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.
Technical Specification 4,0.3 permits a delay in the action statements for up
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to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> to permit time to meet the missed surveillance requirement.
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The licensee demonstrated that Channel B had been successfully tested during
Refueling Outage 3 in accordance with Revision 8 of the above LSFT procedure
and, thus, there was confidence that the channel was functional.
Within a few
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hours the procedure was corrected, the test was satisfactorily performed on
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Channel B, and the Technical Specification action statement was exited.
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In view of their finding another LSFT overlap problem, the licensee informed
the inspector that they would expedite the matrix project to start immediately
(instead of in May 1993) to assist in seeking out any additional discrepancies
in the STPs. As of the end of this inspection period, 19 of the 32 points of
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overlap had been verified with no additional discrepancies.
The inspectors considered the licensee's identification of the above problem,
followed by the corrective actions described, to be a strength.
The licensee
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has informed the inspectors that these events will be reported to the NRC in
accordance with 10 CFR Part 50.73.
Failure to provide adequate procedures to implement Technical Specification
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surveillance requirements was a violation of Technical Specification 6.8.1.d.
Failure to verify operability of the RCIC actuation instrumentation at the
required surveillance internal was a violation of Technical Specification 3.3.5.
Failure to verify operability of the LPCS and LPCI
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Train A injection valve permissive logic in the nonpermissive status was a
violation of Technical Specification 3.3.3.
Failure to verify operability of
Channel B high drywell pressure / containment isolation was a violation of
Technical Specification 3.3.2.
In view of the satisfactory continuity checks
and surveillance testing which verified that the instrumentation was capable
of performing its intended safety function, the safety significance of the
specific discrepancies in the procedures was minimal. Therefore, this
licensee-identified violation is not being cited because the criteria
specified in Section VII.B of the Enforcement Policy were satisfied.
2.2 Reactor Fuel Integrity Failure
On February 25, 1993, the licensee identified a significant increase in the
off-gas pre-treatment release rate.
The Operations Supervisor had noted an
increase on the pre-treatment radiation monitor from approximately 400 mR/hr
to approximately 800 mR/hr over a 2-week period.
Chemistry was requested to
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evaluate the off-gas stream.
The analysis results showed an off-gas
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pretreatment release rate of approximately 15,000 microcuries/second, which
was greater than the nominal 4000 microcuries/second that had been indicated
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previously.
The licensee developed a fuel status assessment graph and determined that the
indicated increase in release rate did indicate a fuel cladding leak.
The
licensee took the following immediate actions:
Plant chemistry resampled and analyzed the off-gas pretreatment stream.
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This indicated a release rate of approximately 12,000 microcuries per
second.
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The system engineer verified that the off-gas pretreatment monitor
operational parameters were acceptable.
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The licensee obtained and analyzed a reactor coolant sample and
confirmed an increase in dose equivalent Iodine-131 of approximately
2.5 times nominal.
The licensee convened a meeting of the fuel integrity monitoring
committee (FIMC) to evaluate this data and make recommendations for
further actions to be taken.
The FIMC reviewed the fuel history for the past month.
Several major control
rod manipulations had been performed, including a deep / shallow control rod
exchange performed on February 10.
This manipulation exposed some fuel
bundles that had not been previously uncovered this cycle.
Under the guidance
of core analysis and reactor engineering, the operators inserted Group 9C
control rods from position 44 to 40 while collecting off-gas samples.
This
effort did not provide any conclusive data and failed to decrease the
pretreatment release rate.
The inspectors noted that there had been an increase in the amount of noble
gas in the turbine building.
However, no increase in posttreatment release
rate has been indicated.
The inspectors monitored the off-gas pretreatment
and posttreatment radiation monitors on an almost daily basis and noted the
chemistry sample results when taken.
No signs of additional significant fuel
leakage degradation were evident.
The FlMC continued to evaluate the problem in consultation with General
Electric, other plants with similar problems, and a consultant (the S. M.
Stolar Corporation) currently under contract with the Electric Power Research
Institute to address industry problems with fuel leakage.
As of the end of
this inspection period, the licensee had stated that they will probably
develop a flux tilting methodology to locate the leaking fuel pin so that fuel
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management will be able to minimize the power density and exposure of the leak
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to transients.
The inspection will continue to monitor and report on the
licensee's actions on this issue.
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2.3 Failure to Meet Reporting Reauirements
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On March 9,1993, the licensee's sewage treatment plant overflowed
approximately 5000 gallons to the storm drains.
This was caused by two
toilets overflowing the night before.
Typically, the sewage treatment plant
was unmanned at night, so the overflow condition was not discovered until the
attendants arrived at 6:30 a.m.
Samples were taken to assess potential permit
violations.
The Environmental Protection Agency and the Louisiana Department
of Environmental Quality were notified at about 10:30 a.m.
10 CFR Part 50.72(b)(2)vi requires a 4-hour report to the NRC of any event
related to protection of the environment for which a notification of other
90vernment agencies have been or will be made. This was also required by
Attachment 7 of River Bend Nuclear Procedure (RBNP) RBNP-004, Revision 8,
" Regulatory Reporting Requirements." The licensee made the report to the NRC
at 7:50 p.m., or about 5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br /> late, which was contrary to the above
timeliness requirement. The inspector identified this to the licensee, who
then committed to initiate a condition report, thus entering the problem into
the licensee's corrective action program.
Corrective actions to preclude a recurrence included adding a note to
Procedure ESP-9-009, " Conduct of National Pollutant Discharge Elimination
System Monitoring," which directed the environmental representative to remind
the shift supervisor of the 10 CFR Part 50.72 requirements when making reports
to other government agencies.
Also, appropriate operations personnel were to
be retrained on the licensee's policies and NRC requirements on timely
reporting.
In view of the minor safety significance of the issue, and the appropriateness
of the licensee's corrective action, this violation is not being cited because
the criteria specified in Section VII.B.(1) of the Enforcement Policy were
satisfied.
On March 11, the Louisiana Department of Environmental Quality was notified by
the licensee of a minor spill of 500 gallons of sodium hypochlorite solution
which was contained by a berm surrounding the tank.
The appropriate 10 CFR Part 50.72 notification of the NRC was made in approximately 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />.
2.4 Conclusion
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The licensee's corrective actions to accelerate the reviews in an effort to
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identify and correct any additional overlap problems with instrument and
control LSFT surveillance test procedures were appropriate (to the
circumstances, for the safety significance of the items found to date).
The licensee's sensitivity in monitoring off-gas radiation monitors and noting
a trend, which resulted in the early identification of a fuel leak, was
excellent. The licensee's efforts to carefully analyze the problem and take
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appropriate steps to determine the location of the leak without making it
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worse were excellent.
The licensee's subsequent actions remain to be
evaluated.
3 OPERATIONAL SAFETY VERIFICATION (71707)
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The objectives of this inspection were to ensure that this 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.
3.1 Control Room Observations
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During this inspection period, the inspector observed the indications of the
licensee's work to reduce the number of outstanding work items in the control
room. The inspector noted a significant reduction in the number of
outstanding maintenance work orders, and the number of lighted control room
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annunciators was reduced by approximately 38 percent from what the inspectors
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had been observing in recent months.
On March 8, 1993, while reviewing the reactor operators' Uog entries for the
previous night, the inspector noted that an LPCS injection line low pressure
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alarm had occurred when the operators attempted to add water to the RHR Pump A
room sump. The operators were attempting to clear a sump low level alarm that
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was annunciating. The inspector questioned the relationship between LPCS
injection line pressure and the method used to partially fill the sump and
found some weaknesses in the operators' performance.
Without the use of a procedure, the operators proceeded to drain water via the
RHR A heat exchanger Outlet Drain Valves E12*VF080A and -81A to bring the sump
level up.
When the low level alarm cleared, the operator opened the valves
rather than closing them. This placed excessive demand on the LPCS and RHR A
injection keep-filled pump and caused the low pressure alarm. Meanwhile, the
sump filled and overflowed to the pump room floor to approximately 1/8 inch
and tripped the sump high level alarm. The operators notified the
Radiological Protection Department. The pump room floor was already a
contaminated area, so there was no increase in contaminated areas.
The operators declared the LPCS system inoperable and entered Emergency
Operating Procedure E0P-0003, " Emergency Procedure - Secondary Containment and
Radiative Release Control," and reviewed the emergency implementing
procedures.
The entry condition was flooding of the sump (s) in the auxiliary
building.
No action was required beyond pumping down the sump, which they
successfully accomplished. They dispatched an operator to verify the
positions of the drain valves and he found them open. After shutting the
valves, conditions were restored to normal.
The operators performed
STP-205-0201, "LPCS Piping Water Fill and Valve Position Verification," and
declared the system operable.
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The inspector further questioned the licensee's process to maintain safety
system valve alignment integrity when procedures were not used to restore the
valves after an operation, and whether or not a procedure should have been
used in the first place.
Licensee representatives told the inspector that a
human performance study was under way to determine the root causes and that
the inspector would be informed of the results and corrective actions taken.
The inspector considered the operator's performance of the above evolution to
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be indicative of a weakness in attention to detail in that the operator did
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not implement the self-checking program.
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3.2 Plant Tours
On February 8, 1993, the inspector toured the river intake structure.
The
inspector observed that Makeup Water Pump 1A had an excessive amount of water
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spraying from its packing gland.
The water was accumulating in the basemant,
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and approximately 1 1/2 feet of water was on the floor.
The licensee had
setup an array of submersible pumps to' lift the water from the basement into
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drums and ultimately out of the building.
The inspector reviewed the equipment which remained under water as a result of
this condition.
The licensee stated that the only equipment under water was
the sump pumps, which were already out of service.
The inspector noted that
nonlicensed operators had accepted this condition because it had been a long-
standing problem.
By the end of the inspection period the licensee had
prepared a prompt modification request to install additional pumping capacity
to remove the water and keep the area dry.
Further evaluations were
continuing.
3.3 Security Observations
During the inspection period, the inspector reviewed the licensee's safeguards
contingency countermeasures Plant Security Procedure PSP-4-403, " Bomb Related
Events." The inspector determined that the licensee had met the requirements
of Generic Letter GL 89-07, " Power Reactor Safeguards Contingency Planning for
Surface Vehicle Bombs." All required materials and equipment were onsite and
maintained for usage if required for this contingency.
3.4 Nonoperators Operatina Equipment
On February 24, 1993, the inspector noted an operator log entry that stated
that a fire watch inadvertently caught his sleeve on, and changed position of,
the emergency shutdown switch for the Division I diesel generator.
The entry
indicated that the fire watch immediately reset the switch to the normal
position and contacted the main control room.
The log entry and Condition Report 93-0097 did not indicate that the licensee
considered this to be a problem other than the switch in question being
vulnerable and needing a cover.
The inspector questioned the licensee's
policy on allowing individuals other than operations personnel to reset an
inadvertently changed state of a control.
The licensee amended the condition
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report that identified the vulnerability of the switch, the Plant Manager
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issued a memo to plant staff prohibiting such actions, and the licensee
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committed to added emphasis on this in General Employee Training. The
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inspector considered the licensee's response to be adequate.
3.5 Conclusions
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The inspector considered the reduction in lighted control room annunciators to
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be noteworthy and indicative of management's efforts to reduce outstanding
work items in the control room.
A weakness was demonstrated in attention to detail when the operators flooded
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the RHR A pump room sump in an effort to add water to. clear a high/ low level-
al arm. This resulted in entry into an emergency operating procedure.
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The continuous flooding of the river intake structure basement.was an example
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of operators accepting old problems.
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The licensee's' response was adequate regarding a firewatch'who caught his
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sleeve on a safety-related switch and immediately reset it without first
contacting the control room.
4 MONTHLY MAINTENANCE OBSERVATIONS (62703)
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The station maintenance activities addressed below were observed and
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documentation reviewed to ascertain that the activities were conducted in
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accordance with the licensee's approved maintenance programs, the Technical
Specifications, and NRC Regulations.
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4.1 Repair of Control Buildina Ventilation Chiller
On February 11, 1993, the inspector observed portions of.the work being
performed under Maintenance Work Order R174971. This work order was written
to remove and replace a seal weld on the Chiller 1HVK*CHLID~ condenser vent
piping that was installed prior to appropriate resolution of a quality control
inspection report as documented in Condition Report 93-0063.
The inspector determined that this work was acceptable under the Technical
Specifications and that the licensee was properly managing the equipment to
minimize the time the safety-related equipment was out of service. The work
plan was properly approved, and-the control operating foreman had authorized
.the work. Clearan e RB 1-93-6089-AA was developed and implemented to isolate,
-drain, and depressurize the system. The inspector noted that the' mechanical
foreman had verified and accepted the clearance boundary.
No evidence of
water was noted when the system was breached, which was indicative of proper
draining by the' operators.
The repairmen covered the surrounding equipment with fire resistant cloth's,
and a firewatch was posted with a fire extinguisher. The inspector reviewed
the hot work permit and verified that it was adequate to cover the job and
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prevent adverse impact on surrounding equipment.
In addition, a " Red Sheet"
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had been developed to minimize the impact of the job on plant safety equipment
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and to reduce the risk of a resultant engineered safety features actuation.
Before the work started the repairmen noted that the blind flange on the vent
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pipe'was still in place. Therefore, they could not verify that the system was
properly drained. A revision was issued to remove the blind flange prior to
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cutting. The inspector verified that the repairmen were qualified for the
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required functions to perform this work.
The inspector reviewed the work plan and determined that it was of good -
quality and _ provided the information necessary to perform the job.
The
repairmen cut the vent pipe and ground the-seal weld flush with the condenser
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shell. The pipe was then removed and the. internal threads inspected.
The
inspector viewed the threads and noted what appeared to _ be. a slight mac' ining
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mark across the crown of the threads at one location.
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The inspector questioned the licensee's use of a maintenance work order as the.
governing document instead of a-modification request when'the seal weld'was
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originally installed in the place of a threaded connection. The licensee
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informed the inspector that, given good quality threads as was determined by
visual inspection, the structural coupling of.the fitting was not changed. A
modification was defined by the licensee, in part, as a change in the fit,
form, or function of a component. This seal weld was only added to stop minor
leakage around the threads.
The vendor had verbally approved the seal weld,
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and the vendor _ drawings did not indicate the specifics of_the pipe connection.
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Therefore, the licensee determined that installing a seal weld to reduce
leakage was not a modification.
4.2 Conduct of Emergency Diesel Generator Preventive Maintenance
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On February 17, 1993, the inspector observed portions of the calibration check
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of various pressure switches associated with the instrumentation and controls
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of the Division II emergency diesel generator.
The work was accomplished in
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accordance with Maintenance Work Order P560783.
The technicians were required by the work order to lift several leads.
The
inspector observed that the technicians tagged, lifted, insulated, and
documented the lifted leads in accordance with Procedure GMP-0042,
Revision 7B, " Circuit Testing and Lifted Leads and Jumpers." During the
calibration checks the technicians used caution to ensure that they were
getting accurate setpoint data by noting repeatability.
The precision
pressure gauge used was in calibration.
The inspector noted that the work order was not specific on how to determine
the pressure switch changed state.
This appeared to be inappropriate to leave
to skill-of-the-craft, because most of the time spent was in determining
whether the switch change of state should be measured on spare contacts, if
available, or by voltage drop,. resistance, or current flow. The inspector-
questioned the foreman, who explained that these preventive maintenance
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activities may be done in conjunction with a variety of tagouts, and there may
or may not be voltage at the switch contacts.
Therefore, to avoid an
overprescriptive work order, it was typically left to the technicians to
decide.
A high impedance fluke digital multimeter was used, and it appeared
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to accommodate the trial and error process quite well.
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After the technicians finally determined what method to use to get an accurate
measurement, the calibration check was successfully completed.
Although the
methods used appeared to provide credible results, the inspector questioned
licensee management on the apparent lack of detailed planning for preventive
maintenance tasks which can be performed under a variety of conditions.
This
item will remain open to determine if a proper level of planning is provided
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to ensure that safety-related preventive maintenance tasks are performed
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acceptably under all plant conditions (Inspector Followup Item 458/93005-3).
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4.3 Repair of an Instrument Air S_ystem Solenoid Operated Valve
On February 22, the inspector observed the electrical portion of work
performed on Solenoid Operated Valve 11AS*S0V36A. This valve had failed a
stroke time test performed in accordance with Surveillance Test
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Procedure STP-122-6301, " Instrument Air Valve Operability Test." Mainteim,ce
Work Order R174694 was written to repair the valve.
The electricians were
qualified to perform this work as indicated by the training matrix. The
inspector noted that quality control hold points had been established and
appeared to be appropriate for the job.
The inspector verified that the redundant components were operable and that
the clearance alignment did not affect this operability.
The inspector
observed as the electricians lifted the power leads to the valve solenoid and
observed the placement of the clearance tags on the leads by operations. The
inspector noted that the electricians implemented a change to the work plan to
include placing a temporary jumper to prevent inadvertent loss of power to the
downstream loads. This was a positive initiative demonstrated by the
electricians to minimize the impact of the maintenance on the plant. The work
order was approved by the control operating foreman for work.
During the disassembly, the inspector noted that the reed switch stack that
provided position indication for the valve was removed to gain access to the
valve bonnet. The inspector observed the electricians mark the fittings on
the reed switches to help ensure that they were reinstalled in the same
position. The inspector also noted that one of the reed switches was loosened
from the stack in order to gain access to one of the terminal leads. This
reed switch was also marked for proper reinstallation.
On February 23, the inspector observed the maintenance repairmen as they
finished cutting the valve bonnet seal weld and removed the bonnet and valve
internal s . The repairmen utilized a special cutting machine that made a
machined cut of the seal weld, which simplified application of the new seal
weld and minimized undercutting of the valve body. The repairmen told the
inspector that they had developed the machine in house.
After the cut was
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completed, the bonnet came off the valve easily.
The inspector considered
their efforts to develop the machine to be a strength.
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The repairmen carefully transported the bonnet, stem, and disc assembly to a
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cleaner, well-lighted area in the shop to examine the parts for evidence of
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causes for the valve to fail the stroke timing test.
The inspector noted that
a maintenance engineer participated in the evaluation.
The soft sealing ring
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on the main disc was in excellent condition, but the pilot disc showed signs
of wear, so the engineer advised the repairmen to replace the pilot disc.
The
other moving parts were clean and free of nicks, scratches, or burrs, but the
valve position indication magnet had some steel filings on it, which
apparently came from the instrument air system.
The parts were cleaned and
reassembled in the valve.
Housekeeping efforts after job completion appeared
minimal. Metal chips were left around the base of the nearby accumulator.
Upon completion of the work, the inspector reviewed the work package and noted
that, after replacing the reed switch stack, the electricians were required to
make an adjustment of the reed switch positions.
Step 6 of the job plan
required the electrician to adjust the reed switches in accordance with the
vendor manual
This was performed by stroking the valve to the closed
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position and adjusting the reed switch to extinguish the green light on the
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main control room panel .
The only postmaintenance test performed was part of Surveillance Test
Procedure STP-122-6301, Revision 5B, " Instrument Air Valve Operability Test."
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This was a repeat of the valve stroke timing test required by the Inservice
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Testing Program.
The valve position indication device, adjusted during the
above maintenance activity, was not retested to verify that it was accurately
indicating valve position for the timing test and subsequent operations.
The
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inspectors also found that, although there was not a specific seat tightness
requirement for this valve in the inservice testing program, the valve was a
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boundary in the accumulator leakage test performed during the previous
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refueling in accordance with Procedure TSP-0029, Revision OA, " Control
Building Accumulator Test." By replacing the pilot disc, and breaching the
bonnet seal weld, the postmaintenance testing should also have included a
repeat of the accumulator leakage test or equivalent. The inspectors
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expressed concern that the valve was declared operable before completing an
adequate retest following maintenance.
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On March 3, the licensee amended Condition Report 93-0093 to address the
adequacy of retesting performed on Valve lIAS*SOV36A.
The system engineering
operability determination of March 4 indicated that the valve was radiographed
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to verify position indication.
This was done subsequent to the inspectors
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expressing concerns about the adequacy of retesting.
The operability
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determination stated the system was operable on the basis of the radiography
results, the wide design margins in the system, and that the upstream Check
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Valve lIAS*V515 was provided as the system boundary interface, not the
solenoid operated valve. While the system may perform its intended safety
function based on the wide design margins, allowing more leakage than may
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exist, the fact remained that the solenoid operated valves, not the check
valves, were the tested boundary when Procedure TSP-0029 was performed.
The licensee stated that both divisions of control room air conditioning would
be rendered inoperable if the test were performed. At this time, while at
power, the loss of this safety function would result in a Technical Specification 3.0.3 requirement to shut down the reactor.
Consequently, as of
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the end of this inspection period, the licensee was developing an analysis to
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show that Procedure TSP-0029 need not be repeated to verify operability of the
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valve.
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The inspectors reviewed postmaintenance testing program requirements and
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concluded that the failure to conduct the appropriate postmaintenance testing
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for the above example did not appear to be a programmatic weakness but
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appeared to be inadequate implementation.
The system engineer reviewed the
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completed work order over the telephone and did not realize that adjustments
were made on the position indicators.
The licensee's postmaintenance
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retesting program was well structured and the maintenance planning guidelines
for retesting appeared to ask the right questions for planning purposes.
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Failure to conduct an adequate retest following the above maintenance activity
performed on Valve llAS*S0V36A prior to declaring the component operable is a
violation of 10 CFR Part 50, Appendix B, Criterion XI, which states, in part,
that a test program shall be established to ensure that all testing required
to demonstrate that components will perform satisfactorily inservice is
identified and performed in accordance with written test procedures which
incorporate the requirements and acceptance limits contained in the applicable
design document (Violation 458/93005-1).
4.4 Repair of the Containment Purae Dampers
On February 26, the inspector observed portions of the repair of Containment
Purge Return Inboard Isolation Damper lHVR*AOD128, performed under Maintenance
Work Order R059414.
This damper, or valve, was suspected of leaking following
a failed local leak rate of its penetration.
On February 25, during a routine performance of Surveillance Test
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Procedure STP-403-3301, " Containment Purge System Isolation Valve Leakage
Test," the licensee had determined that the purge return line was leaking at a
rate of 4500 standard cubic centimeters per minute. The Technical
Specification limit is 1118 standard cubic centimeters per minute. Technical Specification 3.6.1.9.c requires that, with a primary containment purge
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exhaust isolation valve having a measured leakage rate greater than this
limit, the licensee must restore the inoperable valve to operable status
within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> or be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
The inspector reviewed Radiation Work Permit 93-0082 and verified that
appropriate radiological work practices were being maintained.
Contaminated
zones were set up prior to the system breach and a radiation protection
technician was present to take survey data. Additionally, the inspector
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verified that the security requirements were being met for breaching the
system. The work plan was properly approved for work, and the operators had-
entered the action statement for Technical Specification 3.6.1.9.c and were
complying with its requirements.
The mechanics were verified as qualified to perform the task.
The system was
properly tagged out.
Safety measures were taken to ensure personnel safety,
including the use of proper lifting devices and actions to block the disk open
during maintenance.
The seat and 0-ring were replaced with new materials.
The inspector noted that the mechanics identified that the root cause of the
leakage was the failure of the 0-ring at the seam and that the seam had been
placed in an area that was under higher stress than other areas of the 0-ring.
This was not documented in the maintenance work order, even though
Procedure ADM-0023, Revision 10, " Conduct of Maintenance," recommended workers
to do so.
Failure to document information about the failure mode, which would
provide for a more effective maintenance procedure in the future, was viewed
as a missed opportunity to improve maintenance.
The valve was retested in accordance with Surveillance Test
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Procedures STP-403-3301 and STP-403-6302, " Containment HVAC Valve Operability
Test," and was found satisfactory. This work and retesting was performed
within the 24-hour time frame allowed by Technical Specifications.
The
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overall response to the failed penetration valve leakrate test was considered
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very good by the inspectors.
4.5 Review of the Licensee's Response to Degrading Recirculation Pump Seals
On December 8, 1992, the plant was shut down and cooled to ambient conditions
for Planned Outage 92-04 to replace the mechanical seal on Reactor
Recirculation Pump B.
The first stage of the two-stage seal had degraded.
This was just 2 months into operation after having replaced both Seals A and B
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during Refueling Outage 4.
River Bend Station has Sulzer-Bingham pumps with
Bingham Model 750A seal arrangements.
Upon disassembling the degraded seal, the licensee.found that excessive
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quantities of Dow Corning high vacuum grease had been applied to all of the
rubber 0-rings.
In particular, the 0-ring that provides a seal for the
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movable, spring-loaded mechanical seal face was damaged and a black rubber and
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grease sludge was found on the sleeve against which the part seals.
The licensee determined, with assistance from a Bingham representative and a
Canadian seal expert from Atomic Energy of Canada, Limited that, although the
seal was properly assembled before installation, excessive grease was applied
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to the 0-rings, partly because it was difficult to apply a thin, even film
while wearing anticontamination clothing.
The seal operated properly until
some of the excess grease was drawn to the seal face with time, temperature,
flow, and vibration.
This dramatically changed tne operating characteristic
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of the seal since it was designed to be lubricated only by a thin film of
water. As a result, the seal operated with an unevenly wetted film of grease,
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which might have caused greater than normal " whirling" motion of the rotating
carbide seal as it tracked the stationary seal face.
This sinusoidal whirling
motion (up and down) caused abnormal movement and wear of the 0-ring seal,
thus depositing the black sludge on the sleeve mentioned above.
The licensee decided to replace both Seals A and B based partly on the generic
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root cause identified.
The 0-rings in the replacement seals were
prelubricated with a thin film of General Electric Versalube, which was said
to have better lubricating characteristics.
Therefore, less lubricant was
required.
This was done on the recommendation of Atomic Energy of Canada,
Limited.
In order to further prevent excessive lubrication of the 0-rings, the licensee
stated they will change their procedures to prelubricate new 0-rings before
entering a radiologically controlled contamination zone, where it becomes
necessary to wear anticontamination gloves.
On December 16, the plant was restored to full power operation. Within a few
days, interstage seal pressure began to slowly increase, indicating
degradation of the first stage seals again.
Seal A increased from
approximately 550 psig to approximately 620 psig over approximately a 30-day
period. From mid-January 1993 to the end of this inspection period, the
inspectors noted a gradual increase from 620 psig to 640 psig.
Seal B, on the
other hand, remained around 560 psig for approximately 1 month and then_ has
steadily degraded to approximately 800 psig as of the end of this inspection
period. Seal B appeared to be steadily degrading.
All other parameters associated with the seals have been normal. These
include overall seal leakage and various temperatures, except that Seal B had
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some temperatures steadily running about 10 degrees higher than Seal A.
The
inspectors had been monitoring seal performance concurrent with the licensee
and had no concerns about the licensee's approach to not take action unless
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there were radical changes in leak rates.
On March 8, the licensee made a presentation to the inspectors to discuss
recirculation pump seal history and the licensee's plans to correct the causes
of seal failures at River Bend Station.
Since 1986, the licensee had
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encountered seal degradation on frequent occasions. Twice in 1989, once in
1991, and again in 1992 they were forced to shut down because of seal
failures.
The licensee had been consulting with Sulzer-Bingham and Atomic Energy of
Canada, limited to determine the root causes or contributors to seal failures
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in terms of design, manufacturing, maintenance, and operational concerns and
for the next seal replacement indicated plans to take actions to counteract
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the causes and. concerns found.
For Refueling Outage 5, the licensee has indicated that they will probably
replace the seals with Bingham Mode 750C, which is an improved version of the
currently installed Model 750A. They have parts on order to utilize
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Model 750C attributes in the event the present seals require replacement prior
to the refueling outage.
For the long term, the licensee indicated plans to request proposals for new
seal designs, evaluate the proposals, and implement one for Refueling Outage 6
or 7.
The inspectors will continue to monitor seal performance and keep abreast of
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the licensee's actions on the matter.
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4.6 Conclusions
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The maintenance activities observed on the control building ventilation
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chiller, the Division II emergency diesel generator, and containment purge
dampers, met regulatory requirements and reflected good performance and
management oversight.
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One inspector followup item was opened to determine if a proper level of
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planning is provided to ensure that safety-related preventive maintenance
tasks are performed acceptably under all plant conditions.
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A violation was identified for failure to perform an adequate retest following
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maintenance of solenoid operated Valve 11AS*S0V36A. This was not a reflection
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of a weak postmaintenance program but appeared to be inadequate
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implementation.
The electricians and repairmen performed well and care was
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taken to do a high quality job. The licensee demonstrated good initiative by
developing a special machine for cutting the seal weld.
Housekeeping after
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the job was complete was marginal and not up to plant management's
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expectations.
The licensee is continuing to research the causes of recirculation pump seal
failures at River Bend Station. An interim replacement seal package has been
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ordered for the rework of the seal packages.
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5 BIMONTHLY SURVEILLANCE OBSERVATIONS (61726)
The inspectors observed the surveillance testing of safety-related systems and
components addressed below to verify that the activities were being performed
in accordance with the licensee's approved programs and the Technical
Specifications.
5.1
Reactor Jet Pump Operability Test
On February 9, 1993, the inspector observed portions of STP-053-3001,
Revision 4A, " Jet Pump Operability Test."
Prior to making the observation,
the inspector reviewed the procedure and found it to be free from technical
and typographical errors.
It was an excellent procedure and was well
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structured from a human factors standpoint.
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The inspector independently verified all of the data taken, including jet pump
differential pressure percentages, core flow, recirculation pump drive flows,
and flow control valve positions, and found no disparities.
All calculations
were correct, the data plots were correctly entered, and all steps were
appropriately signed off.
The operators' performance of this surveillance test was excellent.
5.2 Inservice Testing of Control Room Chilled Water Pump
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On February 10, 1993, the inspector observed portions of the inservice testing
of Control Room Air Conditioning Chilled Water Pump IHVK*PIB.
The test was
performed in accordance with STP-410-6312, Revision 0, Change Notice 93-0027,
" Control Bldg Chilled Water System Quarterly Pump and Valve Operability Test
Div II."
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The resident inspectors had a particular interest in this test, because
weaknesses were identified during the conduct of a similar test on a
Division I control building air conditioning system pump on January 14.
Details of the inspectors' concerns are documented in NRC Inspection
Report 50-458/92-35.
In response to those concerns, the licensee performed
another review and changed the above surveillance test procedure prior to
performance on February 10.
Although they indicated an intent to walk down
the new inservice test procedures prior to performance, if possible, a
walkdown was not performed for the above procedure.
During performance of the operability test on Chilled Water Pump 1HVK*PIB, the
operators were unable to obtain acceptable results.
After setting the pump
differential pressure at the reference value required by the procedure, the
measured flow was above the unacceptable range specified by the ASME Code,
Section XI.
The pump was declared inoperable as required by the procedure.
As of the end of this inspection period, the pump remained in an inoperable
status pending an engineering resolution.
On March 4, Pump IHVK*PIC in the
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redundant division was declared inoperable for similar reasons, and it remains
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inoperable as of the end of the inspection period. There was a 100 percent
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capacity duplicate pump in each division that was operable; therefore, no
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Technical Specification action statements were in effect. However, the
inspector expressed concern to the licensee that control room air conditioning
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outages could reach a level, as it has in the past, where a Technical
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Specification 3.0.3 shutdown could occur.
The inspector performed a detailed review of the revised procedure and found
the following deficiencies:
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Precaution 5.9 stated in part that, if the pump was determined to be in
the alert range based on a high differential pressure, it may be assumed
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to be caused by instrument inaccuracy. This was an incorrect statement,
because this procedure established the differential pressure at the
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reference value.
Therefore, the pump could only go into the alert range
based on pump flow,
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Section 7.2, Note 2, required pump differential pressure to be read on
the permanently installed indicator, if calibrated and functional .
Section 7.4.18 required it to be read on the temporary test gauge.
These two sections were in conflict.
Section 7.4.4 required the test gauge to be mounted at the same
elevation as the permanently installed discharge pressure gauge.
In
order to get valid pump differential pressure with test gauges, this
gauge should have been mounted at the same elevation as the pump suction
test gauge to preclude the need for compensating for elevation
differences. On February 10, the test gauge was mounted as stated in
Section 7.4.4; however, both test gauges were at approximately the same
elevation, due to the good judgement demonstrated by the operators.
Data Sheet 2, Line 7.4.21, provided an acceptance range for differential
pressure.
Because this was the reference value providing a range of
values was in violation of the ASME Code, Section IWP-3100.
This
deficiency was exacerbated by the fact that there was an asterisk
referencing a note that stated, "This range is not test acceptance
criteria, it is included only to assure repeatability of test data.
If
the range cannot be met, that test is still valid if other data are
within acceptance range." To the inspector, that meant any value of
differential pressure would be acceptable as long as the other values
were acceptable. This could have been one of the contributing causes of
inconsistent data each time the pumps were tested.
The inspector found
a similar note in other pump operability inservice testing procedures,
i.e., for the three emergency diesel generator fuel oil transfer pumps.
Data Sheet 3 was changed to eliminate the above asterisk referenced note
for Pump PID.
However, an acceptance range, alert range, and
unacceptable range as shown in ASME Code Table IWP-3100-2 was added to
the reference value for pump differential.
This is in violation of the
ASME Code, Section IWP-3100. It was not appropriate to apply these
ranges to the test input reference value.
Based on the above deficiencies, the surveillance procedure was technically
inadequate to satisfy the requirements of Technical Specification 4.0.5 and
is, therefore, the first example of a violation of Technical Specification 6.8.1.d, which requires written procedures to be maintained to
cover surveillance and test activities of safety-related equipment
(Violation 458/93003-2).
The licensee stated that only two of the inservice testing procedures for
pumps had inappropriate ranges applied to the input reference valves and that
one was changed.
As of the end of this inspection period, the other was in
the process of being changed.
The licensee also committed to walk down all
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future inservice testing procedures for pumps that were amended for
operations' use as a result of the transfer responsibility from engineering to
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perform the tests.
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5.3 Review of Pump and Valve Program
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During this inspection period, the inspector reviewed the February 1, 1993,
issue of Revision 6 to the River Bend Station Inservice Testing Plan, "First
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Ten Year Inspection Interval." The revision was submitted to the NRC for
review; however, the licensee stated it was implemented as written.
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The primary purpose.of this review was to gain a better understanding of the
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program in view of the problems discussed in Section 5.2 above.
The program
appeared well structured, and .it provided a clear and understandable
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description'of the program; however, several questions.and concerns were
surfaced as listed below. The inspectors met with key licensee personnel
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involved'with the program and discussed these issues:
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Section 2.3.2 referred to use of a multimeter ( 2 percent accuracy) in
certain cases where. installed flow instruments provide a voltage signal
only. ASME Code Section XI, paragraph IWP-4600 requires the entire loop'
to be 2 percent accurate pursuant to paragraph IWP.-4110. The inspector
was' concerned that only the accuracy of the multimeter was being
addressed.
The licensee responded that "(
2 percent _ accuracy)" applied to the
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entire loop, and that'most multimeters used at River Bend Station are
1 0.1 percent accurate or better.
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When testing the emergency diesel generator fuel oil' transfer pumps,
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STP-309-6301(2)(3), " Division I (II)(III)-Diesel Generator ISI Pump
Operability Test," required flow to be measured using the day tank level
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instrument output versus time. This was in conflict with ASME Code
Section XI, paragraph IWP-4600, which requires flow rate to be measured
using a rate or quantity meter installed in the pump test circuit.
This
is a second example of a violation of Technical Specifications 4.0.5 and
6.8.1.d (Violation 458/93005-2).
The licensee responded that they would submit a relief request.
Pump Request for Relief 4, submitted in January 1993 and not yet
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approved, requested relief from the paragraph IWP-4120 requirement to
provide a test instrument whose range is at or less than three' times the
reference valve.
The basis for this relief. appeared weak.
The standard
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gauges available at River Bend Station are not in the required ranges,
and idle and running suction ~ pressures were different enough to~ require
two gauges.
The licensee agreed that the requirements probably could be met.
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Pump Request for Relief 4 also requested a 10 percent deviation
tolerance for the paragraph IWP-4120 requirements, so that if a gauge is
within 10 percent of the required full scale range it would be
acceptable. The inspector asked for the basis of the 10 percent
deviation.
The licensee responded by stating that 10 percent was arbitrary and that
they did not know how many problems it might solve in selecting gauges.
The inspector suggested that the licensee determine what is really
needed.
The licensee stated that they would.
5.4 Conclusions
The rperators' performance and documentation of the reactor jet pump
oprobility test was excellent in that the procedure was meticulously and
dLi'tratily implemented.
Weaknesses continued to appear in the performance of pcmp and valve inservice
testing by the operators. Despite concerns communicated by the inspectors
during the previous inspection period, revised procedures still had problems.
One example of a violation was identified based on technical errors and an
inappropriate application of ASME Code reference value tolerances.
A second example of the above violation was identified during a review of the
inservice testing program in that level instruments and a stop watch were
substituted for the flow instruments required by the ASME Code,Section XI,
without an NRC approved relief request.
6 FOLLOWUP 0F CORRECTIVE ACTIONS FOR A VIOLATION (92702)
6.1
(Closed) Violation 458/92009-1:
Untimely Evaluation for Applicability
and Reportability of Potentially Reportable Conditions
This violation involved approximately 47 NRC Information Notices and
18 potentially reportable conditions at River Bend Station for which
information responses from responsible department heads were neither provided
to Nuclear Licensing nor alternative response due dates established.
Due
dates were exceeded by 30 days to 2 years. The violation was of concern
because of the potential created, by untimely reviews of external information,
for defective equipment to remain in service for extended periods.
The licensee completed the backlog of unanswered requests for information by
issuing a bimonthly memorandum containing a listing of all potentially
reportable condition reports and industry and regulatory documents requiring a
response to nuclear licensing. The inspector reviewed the March 5, 1993,
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issue of the listing and found only six issues delinquent, all 1 month or
less.
Those items that were potentially reportable conditions were
highlighted by the initiation of a condition report, which requires a
reportability and operability determination and receives appropriate
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management attentions and assures timely evaluation and dispositioning. The
inspector reviewed RBNP-030, Revision 1, " Initiation and processing of
Condition Reports." Controls were in place to ensure that an appropriate
response date, referred to as " severity level," were assigned, and the
established date could not be revised without Plant Manager approval.
The inspector also reviewed RBNP-026, Revision 2, " Evaluating Potentially
Reportable Condition Pursuant to 10 CFR 21."
This procedure was reviewed in
August 1992 and clearly assigned responsibilities and implemented requirements
to ensure the timely disposition of issues and to delineate the correct
processing of potential 10 CFR Part 21 issues that may need reporting by the
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licensee.
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The inspector concluded that the corrective actions described by the licensee
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were implemented in an appropriate manner and that potentially reportable
condition evaluations appeared to be under controls that were designed to
prevent a recurrence of this violation.
7 FOLLOWUP (92701)
7.1
(Closed) Unresolved Item 458/92011-1:
Delays in the initiation of 'a
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po_tentially reportable condition (PRC) report
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On November 28, 1990, Condition Report 90-1194 was documented, identifying a
cracked weld on the combustion air adapter of the Division 11 standby diesel
generator.
By November 29, the condition was dispositioned as potentially
reportable under 10 CFR Part 21.
Licensee procedures required a PRC form to
be initiated upon receipt of notification of a PRC, and then the reportability
determination was to be completed within 30 calendar days from the time the
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PRC was identified. The PRC form was not initiated for the above condition
until February 7,1992, and then the reportability evaluation was completed by
March 5, 1992.
In NRC Inspection Report 50-458/92-21, this unresolved item was addressed
again.
The inspector determined that the licensee's procedures did not
adequately control the timely issuance of PRC forms such that the
10 CFR Part 21 requirement to complete the evaluation within 60 days would be
met.
The inspector also noted that there were other similar examples of
untimely reportability determinations at River Bend Station.
Enforcement action was not taken in the above inspection report because a
Notice of Violation was cited in NRC Inspection Report 50-458/92-09 for the
same problem, but this unresolved item was left open pending completion of the
corrective actions for Violation 458/92009-1.
The corrective actions were
completed as described in the closure of Violation 458/92009-1 described in
Section 6.1 of this inspection report.
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ATTACHMENT 1
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1 PERSONS CONTACTED
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1.1 Licensee Personnel
D. L. Andrews, Director, Quality Assurance
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J. E. Booker, Manager, Nuclear Industry Relations
l
R. L. Biggs, Supervisor, Quality Control
l
J. B. Blakley, Acting Assistant Plant Manager, System Engineering
i
J. A. Clark, Foreman, Control Operating
i
J. W. Cook, Senior Technical Specialist
W. L. Curran, Cajun Site Representative
R. C. Daley, ISEG
D. R. Derbonr.e, Assistant Plant Manager, Operations Radwaste & Chemistry
A. O. Fredieu, Supervisor, Maintenance Services
P. E. Freehill, Assistant Plant Manager - Outage Management
l
D. P. Galle, Member, RBS Nuclear Safety Advisory Committee
l
P. D. Graham, Vice President, River Bend Nuclear Group
l
J. R. Hamilton, Manager-Engineering
l
T. M. Hoffman, Supervisor, Civil / Structural Design
G. R. Kimmell, General Maintenance Supervisor
'
D. N. Lorfing, Supervisor, Nuclear Licensing
I. M. Malik, Supervisor, Operations Quality Assurance
W. H. Odell, Director, Radiological Programs
S. R. Radebaugh, Assistant Plant Manager, Maintenance
J. P. Schippert, Plant Manager
J. E. Spivey, Jr., Senior, Quality Engineer
M. A. Stein, Director, Design Engineering
K. E. Suhrke, General Manager, Engineering and Administration
J. E. Venable, Operations Supervisor
S. L. Woody, Director, Nuclear Station Security
The personnel listed above 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 March 17, 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.