ML20149F570
| ML20149F570 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 08/05/1994 |
| From: | Harrell P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV) |
| To: | |
| Shared Package | |
| ML20149F542 | List: |
| References | |
| 50-458-94-15, NUDOCS 9408110026 | |
| Download: ML20149F570 (25) | |
See also: IR 05000458/1994015
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APPENDIX B
U.S. NUCLEAR REGULATORY COMMISSION
REGION IV
Inspection Report:
50-458/94-15
Operating License:
Licensee:
Entergy Operations, Inc.
P.O. Box 220
St. Francisville, Louisiana 70775-0220
Facility Name: River Bend Station
Inspection At: St. Francisville, Louisiana
Inspection Conducted: June 5 through July 16, 1994
Inspectors:
W. F. Smith, Senior Resident Inspector
C. E. Sk ner Resident "nspector
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P.H. Harry
tf', Wo~ ject Branch C
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Inspection Summary
Areas Inspected: Routine, unannounced inspection of onsite response to
events, operational safety verification, maintenance and surveillance
observations, followup on corrective actions for violations, followup
maintenance, and review of licensee event reports (LERs).
Results:
Plant Operations
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The control room operators responded well to unexpected engineered safety
feature (ESF) actuations by taking timely corrective actions and implementing
the appropriate abnormal operating procedures (Section 2.1).
A violation was identified for the operation of the plant in a condition
prohibited by the Technical Specifications (TS). The mode selector switch was
taken out of the Shutdown position to perform a surveillance test, contrary to
a TS action statement. The cause was related to poor communications between
the Work Management Center (WMC) and the control room operators and was a
repeat occurrence (Section 2.3).
The operators performed effectively during the startup of the plant from the
refueling outage. Stringent controls were in effect to minimize distractions,
the startup procedure was carefully followed, and the operators exhibited
9408110026 940eos
ADOCK 05000458
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clear communications with each other and with supporting organizations. isood
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teamwork was demnstrated as the complex system configuration was established
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to allow filling of the reactor vessel level reference leg on Channel B
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(Section 3.1).
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The operators used poor judgement in securing power to the Division III
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battery charger in support of the bus outage in that they failed to consider
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the loads'on the battery and the effect they would have on the battery charger
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(Section 4.3).
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Maintenance
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A violation was identified for the failure to maintain an adequate instruction
for the replacement of a relay base.
Inattention to detail and a poor
technical review of work instructions resulted in an inadvertent Division I
balance of plant (B0P) isolation (Section 2.1.1).
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The only loss of shutdown cooling during this refueling outage occurred near
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the end of the outage when technicians were restoring the control systems that
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were bypassed to preclude a loss of shutdown cooling.
Insufficient
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precautions, coupled with cramped quarters, resulted in a blown fuse and an
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interruption of shutdown cooling for 18 minutes (Section 2.1.3).
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A violation was identified for the failure to maintain an adequate
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surveillance test procedure (STP), which resulted in the inadvertent actuation
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of the Division II standby service water (SSW) system (Section 2.1.4).
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Implementation of the licensee's inservice testing (IST) program improvement
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plan has revealed long-standing deficiencies in the program. The group
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assigned to perform this task demonstrated excellent attention to detail
(Section 2.2).
A violation was identified for failure to comply with a general maintenance
procedure controlling lifted leads.
Because of a lack of understanding of the
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requirements by the technicians and supervision, required independent
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verification of the restoration of lifted leads was not implemented
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(Section 4.1).
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Engineerino
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Installation of the feedwater heater nonreturn valve (NRV) backwards and on-
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the wrong side of the scavenging steam line was considered poor performance on
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the part of the engineering and construction disciplines (Section 2.4).
Engineering performance on corrective actions taken and evaluations performed,
on 31 of the 32 safety-significant condition reports (CR) selected by the
inspectors for review prior to startup, was good.
Failu e to utilize the
refueling outage to clean control room panels, when the need was identified
3 months prior to the start of the outage, was poor (Section 3.3).
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Engineering support on the replacement of the failed Division III battery war
responsive and technically sound (Section 4.3).
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The drywell bypass leakage test was successfully completed with results well
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within the acceptance criteria. However, the inspectors found that the test
engineers were working around procedure conflicts in lieu of correcting them
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(Section 5.1).
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Plant Support
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Housekeeping in the well-travelled areas was very good as the outage ended.
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Licensee management kept a good focus on maintaining plant housekeeping under
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control. The less traveled areas, such as the D Tunnel, drywell, residual
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heat removal (RHR) pump rooms, and the reactor core isolation cooling (RCIC)
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pump room, were in poor condition (Section 3.2).
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A violation was identified for failure to comply with radioactive material
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controls established by the licensee. As a result of insufficient caution and
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attention to detail by radiation workers, a pump part measuring 1000 millirem
per hour (mR/hr) was left in a contaminated area without being labeled.
Although licensee-identified, this violation was cited because of recent past
problems with the control of radioactive material (Section 3.4).
The licensee's prompt and thorough corrective actions to remove spilled
electrohydraulic control (EHC) fluid from the suppression pool were very good
and averted a major problem with possible organic contamination of the pool
(Section 3.5).
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Management Oversicht
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Management's resolve to complete all planned modification requests (MR) for
the refueling outage was considered a strength.
Except for one that did not
need to be implemented based on an inspection, the 64 scheduled modifications
were completed, plus an additional 20, for a total of 84 modifications. This
corrected a significant number of degraded plant conditions that previously
challenged the plant staff (Section 4.4).
Plant management's involvement in the day-to-day implementation of the outage,
the approach to startup, and the oversight of startup activities was effective
in bringing about productive outage results and a safe startup (General
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Observation).
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Summary of Inspection Findinas:
Violation 458/9415-01 was opened (Sections 2.1.1 and 2.1.4).
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Violation 458/9415-02 was opened (Section 2.3).
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Violation 458/9415-03 was opened (Section 3.4).
Violation 458/9415-04 was opened (Section 4.1).
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Violation 458/9305-01 was closed (Section 6.1).
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Violation 458/9305-02 was closed (Section 6.2).
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Inspection Followup Item 458/9305-03 was closed (Section 7).
LERs 458/94-014, 458/94-015, and 458/94-016 were closed (Section 8).
Attachment:
Persons Contacted and Exit Meeting
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DETAILS
1 PLANT STATUS
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At the beginning of this inspection period, the plant was shut down and in
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Operational Condition 5 (Refueling).
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The refueling outage started on April 16 and was originally scheduled to span
53 days.
Instead, the outage was extended to 82 days in order to accomplish
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all planned and emergent work. On July 1, 1994, the plant was started up and,
by July 6, the main generator was placed on the power grid, ending Refueling
Outage 5.
On July 10, the plant achieved full power operation; however, on July 11,
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power was reduced to 86 percent to allow isolation of a steam leak on the NRV
supplying steam to first-point Feedwater Heater A.
On July 12, power was
restored to 100 percent with the NRV isolated.
At the end of this inspection period, the plant was operating at 100 percent
power.
2 ONSITE RESPONSE TO EVENTS (93702,37551)
2.1
Inadvertent ESF Actuations
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2.1.1 Division I B0P Isolation
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On June 2,1994, during the replacement of Agastat Relay IB21H*K163 in the
reactor water cleanup system isolation circuitry, a Division I B0P isolation
occurred. The relay replacement was being performed in accordance with
Maintenance Work Order (MWO) E568208.
Maintenance personnel were in the process of changing the relay when they
noticed that the relay base was defective and would also require replacing.
The work package was returned to the technical specialist for a revision to
incorporate steps to replace the relay base. The revised job plan required
lifting the lead at Terminal B4, in control room Panel H13-P623, which
resulted in interrupting an interconnected neutral circuit for 14 relays,
4 status lights, and 4 meters.
Interrupting the neutral for the affected
equipment generated a Division I B0P containment isolation signal. All
systems that were in service functioned as required.
The operators entered Abnormal Operating Procedure A0P-0003, " Automatic
Isolations," to verify required actions were being taken to restore systems,
as required. All maintenance activities were suspended until the neutral
circuit could be restored and work could be performed without further
unplanned actuations,
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CR 94-0733 was written to determine the root cause of the isolation and to
develop corrective actions. The licensee determined that the revised work
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package was inadequate because it allowed the neutral circuit to be broken
when a jumper should have been installed. This was primarily caused by
inattention to detail on the part of the technical specialist planning the job
and subsequent inadequate reviews. Also, the contract personnel doing the
work were unfamiliar with the neutral circuit configurations at the River Bend
Station, which stressed the need for providing specific procedural guidance.
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The licensee's corrective actions included counselling the technical
specialist and briefing of all supervisors to stress the importance of
obtaining appropriate reviews. The licensee reported this event in
Failure to maintain an adequate procedure covering maintenance activities of
safety-related equipment is the first example of a violation of TS 6.8.I
(458/9415-01).
2.1.2 Division I B0P Isolation Signal
On June 6, 1994, while preparing to perform Procedure STP-058-4802, " Primary
Containment Isolation System Manual Initiation Switches Time Response Test,"
Revision 3B, a Division I B0P isolation signal was generated. Nearly all of
the Division I containment isolation valves and ventilation systems were out
of service for the outage or in preparation for the test; however, the
containment atmosphere monitoring system hydrogen analyzer automatically
started, thus completing part of the actuation logic. The licensee reported
this event to the NRC in LER 458/94-015.
The actuation occurred during installation of a patch cord between the chart
recorders required by the procedure. At that instant, control power
Fuse IB21H-F28A blew, causing a loss of power to the actuating relays. The
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fuse was replaced and the actuation logic was reset. After troubleshooting
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the recorder and finding no problems, the condition was repeated and the fuse
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did not blow. The test was then satisfactorily completed.
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On June 9, while performing the same test on Division II, as the instrument
and control technician moved some recorder wires, control power
Fuse IB21H-F28B blew.
Further troubleshooting revealed an Amphenol connector
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on the recorder with a loose wire, which was not apparent until the connector
was taken apart. The apparent cause was a failed solder joint. When the wire
was disturbed, it became grounded and blew the Divisions I and 11 fuses due to
overcurrent. After repairs and checking for other loose connections, the test
was satisfactorily completed.
The licensee's permanent corrective actions included inspecting other Amphenol
connectors for signs of metal fatigue and repairing or iel lacing them, as
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necessary. Also, the licensee indicated that they woulo uiscuss this event
with all electrical and instrument and control technicians to stress the need
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to inspect cables and connectors before installing test equipment on control
circuits. The inspectors considered the licensee's actions to be appropriate
to the circumstances.
2.1.3
Inadvertent Isolation of Division I Shutdown Cooling
On June 23, 1994, during the restoration of Temporary Procedure TP-94-0010,
" Shutdown Cooling Reliability During Refuel Outages," Revision 0, an isolation
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and subsequent trip of the Division I RHR pump occurred.
Division I RHR was
aligned in the shutdown cooling mode at the time of the isolation.
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temporary procedure specified steps to minimize the possibility of isolating
shutdown cooling by preventing isolation signals, to the RHR system, that
would not be valid during the refueling outage.
An instrument and control technician was removing an electrical jumper, in
accordance with Procedure TP-94-0010, when the technician received an
electrical shock.
Due to the reaction from the shock, the technician dropped
one end of the jumper and caused an electrical short circuit from the
energized jumper to the cabinet. The electrical short created an overcurrent
condition and blew Fuse IB21H-F76A, which resulted in the isolation and trip
of RHR Pump A.
The shock received by the technician was less than 120 volts
and no medical attention was required.
The operators entered Procedures A0P-0051, " Loss of Decay Heat Removal," and
A0P-0003. All systems functioned as designed. An MWO was initiated to
replace the blown fuse and the Division I RHR system was restored to the
shutdown cooling mode.
The RHR pump was isolated for 18 minutes, which
resulted in reactor coolant temperature increasing by 1.8aF.
The licensee entered this event into their corrective action program by
issuing CR 94-0830.
In the licensee's investigation of this event, the root
cause was identified as a personnel error. The procedure contained two
warnings in the Precautions and Limitations Section concerning the possibility
of an ESF actuation. Due to the technician's focused attention, he failed to
consider how close his fingers would be to the exposed jumper plug once it was
removed from the banana jack. Also, a contributing cause was the location of
the banana jack. The banana jack was in a cramped location and within
1/2 inch of the metal cabinet.
Corrective actions included engineering evaluations to change the breaker
configuration so that, when performing Procedure TP-94-0010, a loss of
shutdown cooling would be less likely and that the position of the banana
jacks could be changed so that the jumper location is further from the metal
cabinet. Also, the licensee indicated that they would discuss this event with
all instrument and control technicians and stress equipment and personnel
safety awareness when working on energized circuits.
Based on a review of
this event, the inspectors determined that the licensee's response to this
event was appropriate to the circumstances.
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2.1.4 Actuation of Division II SSW
On June 24, 1994, during remote shutdown systems testing, an inadvertent
reactor plant component cooling water (RPCCW) system low pressure signal was
generated, resulting in the initiation of the Division II SSW System.
The
test was being performed in accordance with Procedure STP-200-0602,
" Division II Remote Shutdown System Control Circuit Operability Test,"
Revision 7.
Initiation of the Division II SSW system occurred when an operator closed
supply Valves CCP*MOV16B and MOV336, in accordance with the STP.
After
closing supply Valve CCP*MOV16B, a siphoning affect was created in the outlet
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piping, which lowered the pressure in the RPCCW header and caused the
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initiation.
The operators entered Procedures A0P-0053, "Initiatior of Standby Service
Water," and A0P-0003. All systems functioned as designed.
The RPCCW system
valve was reopened and the SSW system was returned to the normal standby
configuration. Both divisions of the SSW system were locked out the next time
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the test was performed and the arveillance was completed without any further
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problems.
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The root cause of the event was a procedural deficiency in that the pertinent
information required to prevent an ESF actuation was not included in the text
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of the procedure. The licensee's immediate corrective action was to revise
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the STP to include provisions for locking out the Division II SSW pumps and
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placing the Division II SSW system test switch in the " Test" position.
NRC Inspection Report 50-458/04-12 discusses an SSW system actuation that
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occurred due to an ambiguous caution statement in an IST surveillance.
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licensee's corrective actions included:
(1) revision of the affected
procedure to provide instructions for the prevention of an ESF actuation and
(2) a review of all IST procedures for ambiguous or misleading caution
statements.
The corrective actions were apparently too narrow in scope to
prevent recurrence of an ESF actuation. Therefore, the licensee expanded the
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review to include all 18-month surveillances that contain instructions for
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operating service water valves or components, to determine if similar
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procedural deficiencies exist. Also, the licensee stated that they planned to
form a three person team consisting of operations, engineering, and training
personnel to review the operating history and performance of the SSW system to
determine the need for additional cperator training, system modification, or
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additional procedural improvements to prevent additional ESF actuations.
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Failure to maintain an adequate procedure covering surveillance and test
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activities of safety-related equipment is the second example of a violation of
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TS 6.8.1 (458/9415-01).
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2.2 Licensee-Identified IST Program Deficiencies
In NRC Inspection Report 50-458/94-06, the cover letter expressed concern
that, in addition to the Notice of Violation, other NRC inspections had
previously identified deficiencies in the licensee's IST program. The
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licensee responded by referring to an IST Improvement Plan, which was
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initiated in February 1994. The plan included implementation of a
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verification and validation of the IST procedures, which, as of the end of
this inspection period, identified the issues discussed below.
Each of these
licensee-identified issues constituted past operation of the plant in a
condition prohibited by TS and, as such, are reportable pursuant to
10 CFR 50.73. The licensee indicated plans to report these, and any other
reportable IST deficiencies, in an LER, as required.
2.2.1
Improper Techniques Used in Testing Check Valves
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On June 17, 1994, the licensee discovered that IST procedures did not
adequately reficct the requirements of ASME Code Section XI,
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Subsection IWV-3520, for testing check valves in the RCIC, low pressure core
injection (LPCI), high pressure core spray, and low pressure core spray
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systems.
For example, when testing in the open direction without flow, the
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application of force or torque delivered to the disk from the mechanical
exerciser must not exceed 10 percent of the equivalent force represented by
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the minimum emergency condition pressure differential acting on the disk or
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200 percent of the actual observed force it took when the valve was new,
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whichever was less. These values were not properly specified as acceptance
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criteria in the applicable procedures. This deficiency and the final
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disposition of each valve was documented in CR 94-0816.
Permanent corrective
action included revising the applicable STPs.
The licensee performed appropriate testing and operability analyses prior to
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startup from the refueling outage.
For example, the RCIC check valves were
full flow tested, an LPCI check valve was full flow tested during dynamic
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signature testing of an upstream injection valve, and the other LPCI, high
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pressure core spray, and low pressure core spray check valves were determined
to be operable based on an analysis of the manual stroking data obtained.
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The inspectors reviewed the analysis, which consisted of calculating the lower
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of the two torque values described above and comparing that value with the
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actual torque applied to exercise the valves.
In each case, the actual torque
applied was less than the calculated torque.
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2.2.2 Failure to Include Required Check Valves in the IST Program
On June 23, 1994, the IST Verification Process Team identified that 30 check
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valves in the penetration valve leakage control system (PVLCS) piping
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installation and 6 check valves in the PVLCS compressor tubing installations
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were not being full flow tested in accordance with Generic Letter (GL) 89-04,
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" Guidance on Developing Acceptable Inservice Testing Programs," and ASME Code
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Section XI. This issue was documented by CR 94-0831.
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To verify operability, the licensee performed a sample disassembly and
inspection of a sample of similar valves in the system, as permitted by
GL 89-04, for the 30 piping check valves.
For the tubing check valves on the
compressor skids, all check valves were verified to be satisfactory by review
of preventive maintenance records.
The licensee also confirmed operability by
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successful completion of the PVLCS valve and system operability STPs.
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of the flow characteristics of the PVLCS, the licensee indicated an intent to
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submit an ASME Code relief request to the NRC relative to the check valves in
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the system. The inspectors considered the licensee's approach to be
appropriate.
On June 30, the IST Verification Process Team discovered that the standby
liquid control (SLC) system pump discharge check Valves C41*VF033A and VF033B
were never tested for the closing function as required by ASME Code,
Subsection IWV-3522, and GL 89-04. This was documented on CR 94-0857.
There was no way to test these valves for prompt closure on reverse flow
because the SLC pumps were positive displacement pumps.
The licensee
determined operability by performing radiography on both check valves to
verify that the valves were in the closed position with their respective pumps
secured. This action was acceptable, given the unique system configuration of
the SLC system. The licensee indicated an intent to change the IST program
accordingly.
2.2.3
Failure to Stroke Time Test the Main Steam Safety Relief Valves (SRV)
On July 14, 1994, the IST Verification Process Team discovered that the main
steam SRVs, though full stroke exercised after each refueling outage, which is
consistent with Valve Relief Request 22, stroke times were not specified in
the STP and, therefore, were not measured. ASME Code Subsection IWV-3413
requires the stroke time of all power-operated valves to be measured. This
information was typically used in the IST program to identify anomalies in
valve operation by comparing data with previous stroke times.
In this case,
trends of the stroke time were not available because the licensee removed and
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replaced the SRVs during each refueling outage.
The licensee indicated an intent to submit an ASME Code relief request to
obtain an exemption from the timing test.
The TS and the Updated Safety
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Analysis Report did not address any time limits for the SRVs to open in
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response to a demand from the automatic depressurization system.
The licensee
stated that Grand Gulf Nuclear Station, also a BWR-6, received an approved
relief request.
The inspectors considered this approach to be satisfactory on the basis that
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there would be no useful trending data developed.
In addition, the inspectors
observed the SRV stroking test, performed on July 2, and the SRVs operated
smoothly and responsively.
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2.3 Failure to Comply with TS Action Statement
On June 10, 1994, while the plant was in Operational Condition 5, the shift
supervisor discovered, during a routine review of TS action statements in
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effect, that the reactor mode switch was inappropriately in the "Startup/ Hot
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Standby" position when it should have been locked in the " Shutdown" position
as required by TS 3.3.1.b, Table 3.3.1-1, Action 9.
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The inspectors reviewed this concern to determine the causes and what actions
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were being taken by the licensee. On June 8, TS Action 9 was entered because
of scheduled replacement of Potter and Brumfield motor-driven rotary (MDR) and
Agastat relays in the control room. Work on three of the MDR relays rendered
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both divisions of the manual scram feature of the reactor protection
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system (RPS) inoperable.
There was a shift supervisor clearence in effect
against the withdraw button on reactor console Panel P-680, as an added
precaution to prevent inadvertent control rod withdrawal.
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On June 10, preparations were made in support of weekly nuclear instrument
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surveillance testing. The control room supervisor (CRS) consulted with the
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WMC supervisor to make sure Division II RPS was operable.
The response, in
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error, confirmed that the system was operable. The CRS then placed the mode
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switch in the "Startup\\ Hot Standby" position, as needed to support the nuclear
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instrument surveillance. However, the three relays affecting both divisions
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of RPS had not been postmaintenance tested, so Division II RPS was not
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Approximately 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> later, the shift supervisor discovered the error and
locked the mode switch in the Shutdown position. The three relays were
functionally tested a few hours later with satisfactory results, and TS
Action 9 w.~, exited. Nuclear instrument testing was resumed and completed.
The licensee reported this as operating in a condition prohibited by TS in
LER 458/94-016. The root cause of this incident was inadequate communications
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between the WMC supervisor and the CRS. A similar licensee-identified error
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occurred on May 9 during MDR relay replacements.
In this case, because of
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inadequate WMC reviews, a half scram was properly inserted, but then was
prematurely restored before the MDR relays were tested, which was in violation
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of TS 3.3.1.
The May 9th event was reported in LER 458/94-008. Also, a TS
violation was identified by an operator on March 22, when secondary
containment was breached because of miscommunications between the WMC and
workers. This was a noncited violation and was documented in NRC Inspection
Report 50-458/94-08.
Further, on January 11, the inspectors identified a
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failure to meet TS action requirements while working on a containment airlock
door. This was attributed, in part, to poor communications between the WMC
and maintenance personnel and was reported under LER 458/94-002.
It was also
the subject of a violation in NRC Inspection Report 50-458/93-31.
Even though communications between the WMC and interfacing organizations have
been numerous, when considering the volume of work items processed during the
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refueling outage, the level of performance necessary to prevent recurring
events, as described above, had not been achieved.
To preclude future events caused by WMC errors and miscommunications, the
licensee indicated plans to conduct an in-depth review of WMC performance,
with a focus on lessons learned from the refueling outage.
Failure to comply with the action requirements of TS 3.3.1.b is a violation.
This violation is being cited because of its repetitive nature, even though it
was licensee-identified within 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> and the condition was promptly
corrected (458/9415-02).
2.4 Turbine Extraction Steam NRV Installed Backwards
On July 11, 1994, the operators noted that first-point feedwater
Heater FWS-EIA was not heating properly and a steam leak existed in the
extraction steam supply line.
Power was reduced to 95 percent and attempts
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were made to remove the heater from service and isolate the leaking NRV.
Further investigation revealed that the NRV body gasket was leaking and the
NRV was installed backwards, preventing extraction and scavenging steam from
flowing to the feedwater heater.
The licensee also noted that the NRV was relocated to the wrong side of the
scavenging steam line that was connected to the high pressure steam side of
Moisture / Separator / Reheater A (MSR).
The purpose of the NRV was to prevent
residual energy from feeding into the high pressure turbine extraction line
during a turbine trip, thus helping prevent posttrip overspeeding. With the
NRV backward, this feature was defeated.
With the MSR scavenging steam line
now on the turbine side of the NRV, the energy in the high pressure steam side
of the MSR would not be blocked on a turbine trip.
During the refueling outage, eight NRVs were replaced, under MR 93-0080, with
a different design to eliminate leakage problems, which, in turn, had been
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contributing to radioactive gas problems in the turbine building during
previous fuel cycles.
The new design was a Type DRV-G nczzle check valve
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supplied by Enertech.
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Reactor power was further reduced to 86 percent and the HSRs were removed from
service so the scavenging steam line could be isolated.
The licensee established a Significant Event Response Team with representation
from the appropriate disciplines to sort out all of the design, operating, and
maintenance issues brought about by the nodification error and steam leak.
CRs 94-0898 and -0899 were issued to enter the problems into the licensee's
corrective action program.
On July 13, the MSRs were placed back in service and power was restored to
100 percent.
The NRV and steam scavenging piping from the MSR remained
isolated.
This ac+ ion maximized plant output to the grid, while at the same
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time kept the high pressure turbine extraction steam line isolated from the
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MSR and the NRV for posttrip overspeed protection.
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At the end of this inspection period, the licensee had not reached a decision
on how or when to correct the modification errors, because it will require a
plant shutdown. With the high pressure turbine extraction steam line isolated
from the MSR and NRV, the inspectors considered it safe to operate the plant
at full power.
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3 OPERATIONAL SAFETY VERIFICATION (71707,71750,37551)
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The objectives of this inspection were to ensure that the facility was being
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operated safely and in conformance with regulatory requirements and to ensure
that the licensee's management controls were effectively discharging the
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licensee's responsibilities for continued safe operation.
,
3.1 Control Room Observations
This inspection period covered the last month of the refueling outage plus the
startup and ascension to full power operations.
The inspectors observed
control room operations and spent several inspection hours observing the
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operators as they prepared to transition from an outage supporting role to an
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operational lead role.
The operators maintained an atmosphere of good command
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and control, with clear communications between the operators in the control
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room and with remote stations.
The startup evolution was partially observed by the inspectors on a sampling
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basis. The plant was placed in Operational Condition 2 (Startup), on July 1,
1994, and the reactor achieved criticality at 6:50 a.m.
Within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> of
criticality, Channel B of the narrow-range reactor vessel level trended upward
and deviated from Channels A and C by greater than 6 inches. The continuous
reference leg backfill system, not being fully tested yet, was not in full
service at the time.
It appeared that evacuation of the reactor vessel upon
opening the main steam isolation valves earlier may have been the cause.
It
was required by TS to insert a half scram within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> and to take actions to
prevent all of the emergency core cooling and isolation logic from being
actuated from perturbations brought about by manually filling the reference
leg on the Channel B reactor vessel water level. This had to be done within
2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />, as required by TS.
Effective teamwork and coordination was demonstrated by the maintenance,
operations, and supporting personnel involved.
Within 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> of the level
deviation exceeding 6 inches, TS action statements were met, the crew was
briefed, the reference leg fill had commenced in accordance with established
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procedures, and the deviation alarm was cleared. The half scram was in effect
for just over 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> and then it was cleared.
As the startup progressed, the remaining at-pressure tests were satisfactorily
completed on the vessel level reference leg modification (MR 93-0034) and the
system was placed in service.
No final deviations or other anomalies were
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observed on the reactor vessel level instruments through the end of this
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inspection period.
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3.2 Plant Tours
The inspectors conducted tours of accessible areas of the plant, including
areas not normally accessible during plant operations such as the drywell,
condensate bays, and feedwater heater bays.
In general, the regularly used
areas continued to be well maintained.
Painting for ease of cleaning and for
equipment preservation was in progress throughout the outage.
In Tunnel D, an
area visited less frequently, the inspectors noted a scattering of broken
light bulbs, tools, pieces of paper, and other trash.
The inspectors found heavy gauge wire twisted and stretched between a cable
tray support and an 8-inch safety-related SSW pipe, 2 feet away, ostensibly
for supporting temporary lights during the outage. After some prompting of
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licensee management by the inspectors, CR 94-0873 was initiated to address
possible seismic qualification problems.
The inspectors will review the
closure disposition of the CR.
On June 27, 1994, the inspectors performed a final closure walkdown of the
drywell after the licensee had cleaned and inspected it. The drywell, in
general, was noted to be cleaner than for previous startups; however, the
inspectors found a 12- by 18-inch plastic bag floating in the suppression pool
behind the weir wall, along with several other wads of paper and tape. After
finding pens, an insulation clip, and other debris, the inspectors informed
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the licensee. The licensee reinspected the drywell and came out with 18 types
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of assorted items, including those found by the inspectors. CR 94-0847 was
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written to document the reinspection results.
[
On July 13, the inspectors toured the RHR and RCIC pump rooms. These were
designated high radiation areas and were locked to preclude unauthorized
access. The inspectors found damaged insulation, two safety-related valves
without labels attached, a handwheel adrift, remnants of grout and trash on
valves and ductwork, and a bolt missing from each of two motor-operated valve
covers. Anticontamination clothing was found scattered around the floor in
the RCIC pump room. The items identified by the inspectors, as discussed
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above, were promptly attended to by the licensee.
The licensee focused a significant amount of management attention on
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housekeeping throughout the outage and, overall, good results were achieved.
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The licensee assigned specific areas of the plant to various departments for
maintenance of high housekeeping standards, and the departments will be held
accountable for their respective areas in the future. The licensee
acknowledged that plant housekeeping was not up to expectations yet; however,
a senior management inspection will be conducted after the departments have
cleaned up the plant.
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3.3 CR Review
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During the refueling outage, the inspectors reviewed the licensee's CRs on a
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daily basis, with the objective of selecting those that involved potentially
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safety significant issues, to verify the CRs were appropriately dispositioned
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prior to startup from the refueling outage. CRs were generated by the
licensee's staff when a condition potentially (or actually) adverse to quality
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existed in order to enter the issue into the licensee's corrective action
program. The inspectors identified 32 CRs for followup.
In 29 cases, the
licensee's actions either corrected or appropriately resolved the condition
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and permanent corrective actions appeared to be adequate to prevent
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recurrence. The remaining three CRs are discussed below:
3.3.1
Discussion of CR 91-0107A
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Tears were found in the metal bellows of the Divisions I and II diesel
generator intake air expansion joints. This condition was originally
identified on March 21, 1991. Action was taken to replace the joints;
however, the new expansion joints supplied by Cooper Industries were too small
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to fit. After unsuccessful attempts to procure a joint that properly fit, the
original torn bellows was reinstalled during Refueling Outage 4 in 1992 and
<
evaluated as not affecting operability of the diesel generator.
During Refueling Outage 5, the licensee concluded that the tears are
acceptable as-is, with no further immediate corrective action required.
It
was determined that the tears were caused by repeated bending of the tabs when
disusembling the joints for inspection of the turbocharger during each
refueling outage. The inspectors did not consider this to be a safety
concern. For the long term, the licensee was considering a design change to
install rubber bellows.
This action appeared appropriate.
3.3.2 Discussion of CR 94-0029
Dust in control room back panels was identified by maintenance technicians on
January 1, 1994. The engineering disposition was sent to maintenance planning
on February 9 and it stated that the panels should be cleaned every refueling
outage starting with Refueling Outage 5.
Maintenance accepted the task on
April 15, the day before the plant was shut down for Refueling Outage 5;
however, the starting time for the task was changed to Refueling Outage 6.
Consequently, the panels did not get cleaned.
The inspectors noted, upon inspecting some of the panels, that a layer of dust
existed, but not to the extent that a safety issue might exist. The
inspectors considered it poor performance to implement panel cleaning when the
need was identified 3 months prior to the start of the outage.
3.3.3 Discussion of CR 94-0367
A Part 21 report was received regarding the potential shearing of torque
switch roll pins on certain Limitorque motor operators for valves.
This was
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identified on April 4, 1994. There were 93 valves in service at River Bend
Station that were potentially applicable.
The engineering disposition was
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that the valves were operable based on the fact that the potential for
shearing the roll pins only existed during the unseating phase of a stuck or
thermally bound valve.
In addition, a review of River Bend Station history
i
showed no documented failures of this type of valve.
The licensee stated that
all of the applicable valves, with a safety function to open, had a limit
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switch with contacts that bypassed the torque switch during the unseating
phase to the 90-95 percent open position.
Thus, the inspectors concluded
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that, if called upon to open, the valves would not fail to function because of
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a failed torque switch roll pin.
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3.4 Followup on Radioactive Material Handlino Event
On June 2,1994, at approximately 1 a.m., while cleaning up a radiation
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area / contamination zone in the machine shop, decontamination workers found a
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plastic bag that did not have a label or tag attached. The bag was reading
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1000 mR/hr deep dose equivalent on contact,
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Radiation Protection (RP) was immediately notified and an RP technician
surveyed the bag and attached a tag indicating that the dose rate from the bag
was 200 mR/hr at 12 inches. This was a problem because the bag was in a
posted radiation area when it should have been in a high radiation area. A
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high radiation area is required when the dose rate form radioactive material
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exceeds 100 mR/hr at 12 inches, as required by 10 CFR Part 20.
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The bag was removed and placed in the proper parts box, which was located in a
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Subsequently, it was determined that the hardware was a
contaminated reactor water cleanup pump seal that was missing and assumed to
have been scrapped in error. The on-shift RP foreman was notified and he
obtained statements from the people involved in the event; however, he did not
perform a backup survey, nor did he inform his management until they arrived
on site at their regular time the next morning. This was viewed as poor
judgement on the foreman's part, in view of past escalated enforcement on
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similar issues.
The bag was surveyed again after RP management was briefed, but the dose rate
was no more than 50 mR/hr at 12 inches.
This was confirmed with another
survey meter.
The licensee concluded that the 200 mR/hr reading that was
obtained earlier was probably caused by the RP technician taking the readings
too close to the bag. At approximately 4 1/2 inches, a 200 mR/hr reading was
obtainable.
The 50 mR/hr dose rate at 12 inches resolved the problem of the bag being in a
radiation area, because it was less than 100 mR/hr at 12 inches. However, the
bag should have been labeled.
Section 6.1.2 of Radiation Section
Procedure RSP-0213, " Control and Handling of Radioactive Materials,"
Revision 7, required material left inside a posted contamination area to be
tagged or labeled when the material dose rate equaled or exceeded 100 mR/hr
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deep dose equivalent on contact. Failure to comply with the requirements of
Procedure RSP-0213 is a violation (458/9415-03).
The licensee could not establish a specific cause for the plastic bag being in
the hot machine shop contamination zone. This zone was an enclosed area used
for the decontamination and cleaning of parts from the reactor water cleanup
pump. While the parts were being processed, the area was posted as a high
radiation area / contamination zone. On May 31, RP technicians surveyed and
stored the pump parts in a separate high radiation area, surveyed the
disassembly / cleaning area, and downgraded it to a radiation area.
The survey report indicated an 80 mR/hr dose rate on a bend of the exhaust
hose used during decontamination activities, which appeared reasonable at the
time.
Subsequent to finding the parts bag containing the missing seal, the
hose surveyed at 10 mR/hr. The licensee speculated that the part fell into
the hose while pump parts were being decontaminated and, therefore, was not
seen by the RP technician when he downgraded the area to a radiation area.
The licensee further speculated that, while moving the exhaust hose on June 2,
the seal rolled out of the hose onto the floor.
As an immediate corrective action, the licensee surveyed the remainder of the
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hot machine shop and found no other misplaced radioactive material.
The
radwaste, auxiliary, turbine, and reactor (including the drywell) buildings
were searched for bags containing radioactive material that were not
appropriately labeled and none were found.
For permanent corrective action, the licensee indicated that they were
contacting other nuclear plants for input on the best methods and practices
for bagging and labeling material in high radiation areas while in use. They
stated that they were considering better controls and housekeeping practices
when dealing with highly radioactive parts.
The licensee also stated that,
during safety meetings, the current criteria for bagging and labeling
radioactive material would be discussed.
3.5 EHC Fluid Spill in Suppression Pool
On June 16, 1994, wher the reactor recirculation hydraulic power Unit B pump
was started, EHC fluid was sprayed on the 141-foot elevation down through the
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ll4-foot elevation into the suppression pool.
The pump was secured and the
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affected area was roped off and treated as a contamination zone. An action
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plan was developed by the chemistry department to prevent the spread of the
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EHC fluid and to cican up the affected areas.
The licensee began the cleanup
process immediately for the 141- and 114-foot elevations and the surface of
the suppression pool.
EHC fluid that had settled to the bottom of the
suppression pool was cleaned up by utilizing divers.
The licensee's prompt response to the event enabled them to contain the EHC
fluid to a small area in the reactor building and, using the experience of
other nuclear plants that have had similar events, helped to aid in their
cleanup efforts.
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4 MAINTENANCE OBSERVATIONS (62703,37551)
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During this inspection period, the inspectors observed portions of the
maintenance activities listed below. The observations included a review of
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the MW0s and other related documents for adequacy, worker adherence to
procedure, proper tagouts, TS compliance, quality controls, radiological
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controls, observation of work and/or retesting, and appropriateness of retest
requirements.
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MWO Number
Description
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C306902
Replacement of Relay K-1 associated with
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modification of lower containment airlock
system
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R210298
Investigation and rework of a mechanical
seal on the control room building chilled
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water Pump HVK*PIB after it failed the
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postmaintenance test
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The inspectors found no significant strengths or weaknesses during the
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observations, except as noted below-
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4.1 Comments on MWO C306902
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On June 29, 1994, the inspectors reviewed the work package to confirm that all
of the steps for the replacement of Relay K-1 were completed as stated in the
work package. The inspectors identified a step in the work package that was
not followed. The step stated that General Maintenance Procedure GMP-0042,
" Circuit Testing and Lifted Leads and Jumpers," Revision 7B, and
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Drawing 219.711-056-45 were to be used to install the new relay.
Step 6.7 of
Procedure GMP-0042 required independent verification of all lifted leads on
restoration. Step 8.4.9 further stated that the independent verifier shall
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remove each lifted lead tag upon completion of each individual verification.
The inspectors observed the individual performing the work landing the leads
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and removing the lifted-lead tags during the restoration process. No
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independent verification was performed.
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After discussions with the plant modification and construction supervisor, who
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was overseeing the work activity, it became apparent to the inspectors that
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the supervisor did not understand the requirements of Procedure GMP-0042. The
inspectors expressed concern about the technicians and their supervisor's lack
of knowledge on the requirements of Procedure GMP-0042 to licensee management.
The licensee agreed that Procedure GHP-0042 required independent verification
and stated that the supervisor and the technicians involved would be counseled
and trained on the requirements of Procedure GMP-0042.
They were also
considering a revision of Procedure GMP-0042 to more cleariy state independent
verification requirements.
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Failure to perform independent verification on lifted leads as required by
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Procedure GMP-0042 is a violation of TS 6.8.1 (458/9415-04).
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4.2 Comments on MWO R210298
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The inspectors noted areas of weakness in the implementation of this
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maintenance activity. The technicians did not appear to be utilizing the MWO
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instructions in an appropriate manner. At one point, the inspector observed a
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technician questioning how to reassemble the chilled water pump until his
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supervisor directed his attention to the MWO, which contained the needed
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instructions. The prerequisite steps requiring verification of plant
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conditions prior to commencing the work were not signed off.
The technician
signed the steps, when they were pointed out by the inspectors, on the basis
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that he previously verified the conditions.
The technician was signing off
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several steps at a time instead of each step as it was performed.
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Step 8.1.6.1.D.(1) of Administrative Procedure ADM-0023, " Conduct of
Maintenance," Revision 12, required that steps be signed or initialed as the
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steps were performed, but in Step 8.1.2.7, the technician was allowed the
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flexibility to decide whether or not to have the arocedure in hand based on.
the individual's qualifications and experience, t1e routine or repetitive
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nature of the activity, the importance of the activity, and the complexity of
the activity. These conflicting and vague requirements appeared to be sending
mixed messages to maintenance personnel.
The concern about the technician not being familiar with the MWO was brought
to the attention of maintenance management, who acknowledged the weakness and
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stated that they would reinforce their expectations to the technician
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involved.
In addition, the licensee stated that a review of
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Procedure ADM-0023 would be performed to determine what clarification between
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the two steps discussed above would be required.
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4.3 Review of Maintenance and Engineering Actions to Correct a Failed
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Division III Battery
On June 4, 1994, the Division III safety-related Battery 1E22*S001 BAT failed
the 6-month performance discharge test. TS 4.8.2.1.e has an acceptance
criteria that requires the battery capacity to be at least 80 percent of the
manufacturer's rating when subjected to a performance discharge test. The
results obtained by the licensee were 65 percent, which was unexpected.
CR 94-0743 was initiated to enter the problem into the licensee's corrective
action program.
The battery was last replaced, in December 1987, because the original battery
,
had abnormally low cell voltage during an equalizing charge. The new battery
discharge tested at only 93 percent. This was considered marginally low,
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because TS 4.8.2.1.f requires the frequency of testing to be increased from
once every 60 months to once every 18 months when the battery capacity is
below 90 percent of the manufacturer's rating. The licensee expected the
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capacity to improve before degrading any further due to the characteristics of
lead-acid batteries and, therefore, accepted the test results.
The licensee's system engineers reviewed the history of the battery to
determine the cause of the test failure.
They determined that a combination
of problems contributed to the failure.
Battery Cell 22, although having met
i
previous surveillance test acceptance criteria, failed during the discharge
test and Cell 24 was marginally weak.
This was coupled with an inadvertent,
2-day discharge of the battery on May 17, 1994, when the operators deenergized
the Division III electrical busses in support of the refueling outage. This
removed power from the Division III battery charger, leaving some of the
direct current loads on the battery. The operators did not recognize the
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significance of those loads until nearly 2 days later, when the Division III
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instrument (Topaz) inverter began to cycle off.
By that time, battery bus
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voltage had deteriorated to 108 volts. The operators then removed the
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remaining loads. The battery was subsequently charged in preparation for the
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performance discharge test; however, battery voltage dropped to 117 volts
during the first minute of the discharge test, which led the engineers to
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believe that the battery was damaged and required replacement.
The licensee obtained 17 jars (51 of 60 cells) from the Tennessee Valley
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Authority that had seen 2 years service at the Browns Ferry facility. The
batteries were located in a warehouse at the Sequoyah Nuclear Power Plant and
had been on a trickle charge for about 9 months.
Three jars containing the
best 9 cells were selected from the River Bend Station battery and they were
installed with the 17 jars from the Sequoyah Nuclear Power Plant warehouse.
An equalizing charge was completed and then a performance discharge test was
satisfactorily conducted on June 12. The inspectors reviewed the completed
test results and noted that all acceptance criteria were met. The battery
capacity was 105.9 percent of the manufacturer's rating, which met the
licensee's expectations.
The licensee's engineering support on this issue was responsive and
appropriate to the circumstances.
The inspectors considered that the
operators used poor judgement in leaving the remaining direct current loads on
the Division III battery without analyzing the magnitude of the loads and
knowing when the battery charger would be restored to service.
System
Operating Procedure S0P-0049, "125 VDC System," Revision 7, left it to the
operators to decide whether or not to secure the loads when removing the
battery charger from service.
On July 10, the system engineer initiated CR 94-0896 to identify that the
Division III battery was on the bus without a battery charger.
The
recommended corrective action was to add a precaution to Procedure 50P-0049 to
minimize the time any station battery is on the bus without a charger. The
licensee confirmed that this would be done.
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4.4 Performance of Scheduled Modifications Durina Refuelino Outage 5
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Periodically, the inspectors monitored the licensee's performance on
accomplishment of scheduled modifications as the refueling outage progressed.
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In view of the numerous degraded conditions identified by the licensee and the
NRC in the past, licensee management established an approach that would ensure
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that the planned tasks were accomplished.
Schedule pressure was diminished
and sufficient time was made available to work the projects to completion.
At the beginning of the outage, on April 16, 1994, the licensee had scheduled
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64 modifications to be implemented.
As of July 6, at the end of the outage,
only one was cancelled and that modification involved the replacement of a
cracked penetration bellows inside the guard pipe tunnel.
Inspection showed
no crack growth since Refueling Outage 4 and the licensee determined it was
not necessary to replace them during Refueling Outage 5.
Twenty modifications
were added during the course of the refueling outage for a net completion of
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84 modifications.
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5 SURVEILLANCE OBSERVATIONS (61726,37551)
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The inspectors observed the performance of portions of the surveillances
listed below. The observations included a review of the procedures for
technical adequacy, conformance to the TS and limiting conditions for
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operation, verification of test instrument calibration, observation of all or
part of the actual surveillance, removal and return to service of the system
or component, and review of the data for acceptability based upon the
acceptance criteria.
Procedure Number
Description
STP-057-3603
Drywell Bypass Leakage Rate Test
STP-202-0602
Stroke Test of Main Steam Safety Relief
Valves using Automatic Depressurization
System
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STP-309-0601
Division I Emergency Core Cooling System
Test
STP-110-0101
Turbine Overspeed Protection Operability
Test
The inspectors found no significant strengths or weaknesses during the
observations, except as noted below:
5.1 Comments on Procedure STP-057-3603
On June 21, 1994, the inspectors attended the briefing held in the control
room, reviewed the procedure for adequacy, observed portions of the test in
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progress, and reviewed the completed data.
The briefing met the requirements
of the infrequently performed procedure checklist delineated in Attachment 10
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of Procedure STP-057-3603.
The procedure was revised on June 18 and was structured to pressurize the
drywell using either the installed service air system or temporary air
compressors. However, the procedure was unclear on what valves to throttle in
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controlling drywell pressure and pressurization rate. Step 7.4 gave a choice
of three valves but, because temporary air compressors were used,
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Attachment 11 required a fourth specific valve, which conflicted with
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Step 7.4.
Instead of correcting the procedure on the outset, the test
engineers worked around the procedure conflicts by struggling to meet both
requirements.
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After the pressure stabilization period was met, the test engineer immediately
commenced plotting the pressure against time before other potential sources of
pressure were isolated and vented. This was compensated for by taking
readings longer than the required I hour but, had there been a marginal leak
rate combined with a leaking air source, the test results could have been
misleading in the nonconservative direction.
As it turned out, upon reviewing
the completed test data, the test results were well within the TS acceptance
criteria of less than or equal to 0.1 square foot in that drywell bypass
leakage was 0.0105 square foot.
The licensee stated that they would clarify the procedures to eliminate the
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need to work around conflicting steps, in time to support the next test during
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the next refueling outage.
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o FOLLOWUP OF CORRECTIVE ACTIONS FOR VIOLATIONS (92902)
6.1
(Closed) Violation 458/9305-01:
Failure to Conduct Postmaintenance Test
Following maintenance on the control building instrument air solenoid-operated
Valve IAS*S0V36A, the licensee failed to perform a postmaintenance test to
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verify that the leakage integrity of the valve was adequate and the position
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indication was correct.
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In response to this violation, the licensee checked the valve position and
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verified there was no leakage. The licensee committed to revise the
maintenance planning guidelines if any postmaintenance tests were identified
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during a review of procedures. Also, the test method used to determine
leakage through Valve IAS*S0V36A(B) would be specified in
Procedure STP-122-6301, " Instrument Air Valve Operability Test."
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The inspectors reviewed the maintenance planning guidelines and
Procedure STP-122-6301 and found that the licensee had adequately revised
these documents to address the causes of this violation inJ to prevent
recurrence.
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6.2
(Closed) Violation 458/9305-02:
Inadeauate IST Procedures
This violation involved two examples where IST surveillance procedures were
not properly established or maintained in that they contained instructions
that were in conflict with the ASME Code. The first example allowed an
acceptable pump differential pressure to be over a range of 93 to 102 percent
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of the reference value, instead of equaling the reference value as required.
In the second example, the procedure allowed the operators to measure pump
flow rate on the fuel oil transfer pumps using the day tank level and a stop
watch, when the ASME Code requirements specified the use of a rate or quantity
meter.
To address the first example, the licensee revised the pump data sheets for
all IST procedures to clarify that the reference value was to be used for
system resistance only. The inspectors verified that this action had been
completed by reviewing all of the current IST procedures that contained pump
data sheets. The second example was addressed by requesting, and subsequently
receiving, an NRC-approveo relief request to use the day tank level and a stop
watch to meet the requiicments of ASME Code. The inspectors reviewed the
approved relief request and noted it was consistent with the licensee's
procedural requirements.
7 FOLLOWUP-MAINTENANCE (92902)
7.1
(Closed) Inspection Followup Item 458/9305-03:
Verification of Proper
Planning for Preventive Maintenance
The inspectors noted that the work order for preventive maintenance of various
pressure switches associated with the instrumentation and controls of the
Division II emergency diesel generator was not specific on how to determine if
the pressure switches changed state.
Much of the time was spent determining
whether the change of state of the switch should be measured using spare
contacts, voltage drop, resistance, or current flow.
The inspectors held discussions with the licensee's maintenance management on
whether a proper level of detail in planning was provided to ensure that
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safety-related preventive maintenance tasks were performed acceptably under
all plant conditions.
The licensee stated that the preventive maintenance job
plan could be written to give, for example, specific contacts and meter
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settings to perform the task.
This would decrease the flexibility involved in
scheduling work and could increase the outage time for that particular
equipment. During system outages, as many items as possible were worked in
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parallel in order to minimize safety system unavailability.
The licensee
further stated that, in order to provide specific instructions, the job plan
would have to provide for specific system lineups or plant conditions, thus
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limiting when the preventive maintenance task could be performed.
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The licensee's expectations were for the technicians to research the drawings
and current plant conditions that could affect the preventive maintenance to
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determine which contacts and meter settings could be used.
They took the
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position that drawing research as well as techniques used to check the
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contracts (e.g., the use of a digital multimeter) were fundamental skills that
all qualified technicians processed.
The inspectors noted that the approach utilized by the licensee for conducting
preventive maintenance tasks appeared to be appropriate.
8 ONSITE REVIEW OF LERs
(92700)
8.1 1 Closed) LER 458/94-014: Actuation of Multiple Division I Containment
isolation Valves Due to inadeauate Review of a Job Plan Change
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This event and the actions taken by the licensee are discussed in
Section 2.1.1 of this inspection report.
Based on the review of the event,
this LER is closed.
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8.2 (Closed) LER 458/94-015:
ESF Actuation Caused by Pin Failure in Test
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Eauipment Patch Cord
This event and the actions taken by the licensee are discussed in
Section 2.1.2 of this inspection report.
Based on the review of the event,
this LER is closed.
8.3 (Closed) LER 458/94-016:
Reactor Mode Switch Positioned for Testina With
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Reauired System inoperable Due to Communication Error
This event and the actions taken by the licensee are discussed in Section 2.3
of this inspection report.
Based on the review of the event, this LER is
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closed.
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ATTACHMENT
1 PERSONS CONTACTED
1.1
Licensee Personnel
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R. J. Alexander, Manager, Project Management
R. L. Biggs, Supervisor, Quality Systems
0. P. Bulich, Manager, Licensing
R. T. Davey, Manager, Electrical /I&C
W. S. Day, Cajun Site Representative
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J. R. Douet, Director, Plant Projects and Support
E. C. Ewing, Manager, Maintenance
J. J. Fisicaro, Director, Nuclear Safety
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P. E. Freehill, Manager, Plant Modification and Construction
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T. W. Gates, Supervisor, Licensing
K. J. Giadrosich, Manager, Quality Assurance
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W. C. Hardy, Supervisor, Radiation Control
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J. Holmes, Superintendent, Chemistry
H. B. Hutchens, Superintendent Plant Security
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M. A. Krupa, Manager, System Engineering
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T. R. Leonard, Director, Engineering
L. G. Lewis, Manager, Training
D. N. Lorfing, Supervisor, Licensing
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J. F. Mead, Supervisor, Engineering
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W. H. Odell, Superintendent, Radiation Control
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M. B. Sellman, General Manager, Plant Operations
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J. P. Schippert, Technical Assistant
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W. J. Trudell, Superintendent, Operations
The above personnel attended the exit meeting.
In addition to the personnel
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listed above, the inspectors contacted other personnel during this inspection
period.
2 EXIT MEETING
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An exit meeting was conducted on July 20, 1994.
During this meeting, the
inspectors reviewed the scope and findings of the report. The licensee
acknowledged the inspection findings documented in this report. The licensee
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did not identify as proprietary any information provided to, or reviewed by,
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the inspectors.
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