IR 05000373/1990003
| ML20042F334 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 04/30/1990 |
| From: | Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20042F331 | List: |
| References | |
| 50-373-90-03, 50-373-90-3, 50-374-90-03, 50-374-90-3, NUDOCS 9005080184 | |
| Download: ML20042F334 (15) | |
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U.S. NUCLEAR REGULATORY COMMISSION
REGION III
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Report Nos. 50-373/90003(DRP);50-374/90003(DRP)
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Docket Nos. 50-373; 50-374-License Nos. NPF-11; NPF-18 Licensee: Commonwealth Edison Company
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Post Office Box 767 Chicago, IL 60690 Facility Name: LaSalle-County Station, Units 1 and 2 i
Inspection At:
LaSalle Site, Marseilles,_ Illinois j
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Inspection Conducted: March 1 through April 23, 1990 Inspectors:
R. Lanksbury R. Kopriva
.D. Jones D
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Approved
l. Hinds, ief-c4.Se 90 l
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ctor Projects Section 1A Date
Inspection Summary Ins ection from March I through April 23,1990(ReportNos. 50-373/90003(DRP);
- 74/90003(DRP))
l Areas Inspected: Routine, unannounced safety inspection by the resident J!
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inspectors of licensee action on previously identified items; operational
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safety; surveillance; maintenance; _ licensee event reports followup; ESF system I
walkdown; training; security; radiological protection; report review; unit
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trip; design, design changes and modif.ications; safety assessment and quality
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verification; outages; and' emergency preparedness.
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Results: Of the fifteen areas inspected, no violations were identified.
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However, two unresolved items were identified. The unresolved items relate.to i
two instances in which.the Primary Containment Isolation-System (PCIS)- was ~
l actuated causing some primary containment isolation valves to close. 'During this inspection-period there were a total of three-instances of PCIS being-
actuated.
The inspectors are concerned with.the licensee's control of the
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large amount of electrical work occurring in the control room and how that may i
relate to the PCIS actuations. During this inspection period the licensee
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continued to experience problems with shutdown cooling isolating upon' system f
startup.
The licensee has made system modifications in an attempt to prevent the occurrence of these isolations but have not been successful to date. -New
modifications are currently planned by the licensee.
i During this inspection period Unit 1 experienced a scram from full power when I
a line insulator in the switchyard blew apart. The licensee is still I
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9005080184 900430 gDR ADOCK 0300
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continuing their invettigation of the root cause of the failure. This scram-represents the second scram in 1990 for the licensee (Unit 2 scramed February 6) and the second forced outage this year. The current Unit 2 outage appears to be going very well and is on schedule and approximetely 30% complete. No problems with contractors were noted during this inspection period, t
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DETAILS 1.
Persons Contacted
- G. J. Diederich, Manager, LaSalle Station C
- W. R. Huntington, Technical Superintendent"
- J. C. Renwick, Production Superintendent D. S. Berkman, Assistant Superintendent Wor _k Planning J. V. Schmeltz, Assistant Superintendent, Operations
- J. Walkington, Services Director
- T. A. Hammerich, Regulatory Assurance Supervisor W. E. Sheldon, Assistant Superintendent, Maintenance W. Betourne, Quality Assurance-Supervisor
- J. Roman,. Resident Engineer, Illinois Department of Nuclear Safety
- J. H. Atchley, Operating Engineer
- W. J. Marcis, Project Managenent Engineer
- S. Jerz, Quality Assurance Inspector
- Denotes personnel attending the exit interview on April 23, 1990.
Additional. licensee technical and administrative personnel were contacted by the inspectors during the course of the inspection.
2.
Licensee Action On Previously Identified Itemt (92701)
NRC Region III management has reviewed the existing open items for the LaSalle station and has determined that the following open item will be closed dainistratively due to the safety significance relative to emerging priority issues and to the age of the item.' The licensee is ti reminded that commitments directly relating to the open item are the
responsibility of the licensee and should'be met as committed.
NRC Region Ill will review I a n see actions by periodically sampling administratively closed items.
(Closed) Open item (374/86004-03):
Fire protection flow path valve cycling test procedure was revised to insure that adequate documentation exists to insure that valves are lubricated and cycled.-
3.
Operational Safety Verification (71707)
The inspectors observed control room operations, reviewed applicable-a.
logs, and conducted discussions with control room operators during the inspection period. The inspectors verified the operability of selected emergency systems, reviewed tagout records, and verified proper return to service of affected components. Tours of Unit I and 2 reactor, auxiliary, and turbine buildings were conducted to observe plant equipment conditions.
These tours-included checking
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for potential fire hazards, fluid' leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenance.
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The inspectors performed routine inspections _of the control room during off-shift and weekend periods; these included inspections-
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between the hours of 10:00 p.m. and 5:00 a.m..
The inspections were conducted to assess overall crew performance and, specifically,_
control room operator attentiveness during night shifts. The inspectors also reviewed the licensee's administrative controls regarding " Conduct of Operations" and interviewed the_ licensee's security personnel, shift supervisors and operators to determine if
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shift personnel were notified of the inspectors' arrivals onsite
during off-shifts.
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The inspectors determined that both licensed and non-licensed i
operators were attentive to their duties, and that the inspectors'
arrivals on site appeared to have been unannounced. The licensee
as. implemented appropriate administrative controls related to the conduct of operations. -These include proce1ures which specify fitness for duty and operator attentiveness, c.
On March 17,1990, at 6:51 p.m., the B loop of shutdown cooling automatically isolated on high suction flow when the B Residual Heat Removal (RHR) pump was started. As a result of.the isolation the B RHR pump tripped. At the time of tha event, the licensee was cooling the reactor down by steaming to the condenser and reactor coolant temperature was approximately 310 degrees F.
The licensee hari also just completed pre-warming the RHR B loop in accordance with LOP-RH-07, SDC Startup and Operation. At 8:17 p.m., the licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Emergency Notification System (ENS) Notification for actuation of an Engineered Safety Feature l
(ESF).
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Subsequent to the isolation, the licensee performed a walkdown of
- j the suction and discharge piping to verify t?.at no leaks existed and
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that, therefore, the actuation signal was spurious. At 9:17 p.m.
the licensee momentarily bypassed the Division 2 high suction flow isolation in accordance with LOP-RH-07 and.successfully.' restarted the B RHR pump. At 9:18 p.m. the B RHR loop was placed into the j
shutdown cooling mode.
l The licensee believes the cause of the spurious 1 solation signal was due to excessive differential pressure (dP) fluctuations at the Division 2 chutdown cooling high suction flow isolation switch
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(2C31-N012BA) during the initial pump startup.
The problem with RHR, in the shutdown cooling mode, isolating upon initial pump startup has occurred in the past.
In response to the last time this occurred on Unit 2 (reference LER 374/89-005-00), the licensee installed pulsation dampers on the instrument line for the high suction flow isolation switches.
The licensee believes that these are limiting the magnitude of the fluctuations to some degree but not enough to prevent the trip point from being reached.
The licensee has approved a modification for each' unit (M01-1-90-005 andM01-2-90-005) to replace the existing isolation relays with time delay relays that would provide a 1 second delay in the processing of an isolation signal on high suction flow, h
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On April 11,1990, at 12:16 a.m. (CST), Unit 2 received a Division 1
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primary containment isolation signal and' actuation.
The A loop of
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the Primary Containment Chilled Water (VP) system outboard isolation valves and the outboard Reactor Building Closed Cooling Water (RBCCW) system isolation valves closer' in response to the isolation signals. Other valve closures did noc o ccur because the isolation signals were defeated by jumpers instoed for a temporary system change. At the time of the event Unit 2 was shutdown and defueled as part of a 12 week refueling / modification outage.
I The licensee's investigation of the cause of the isolation signal l
revealed that it occurred when Circuit Breaker (CB) 7 at DC
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distribution panel 211-Y was opened. Opening CB 7 resulted in a loss of DC control power to the Division 1 Primary Containment Isolation System (PCIS) logic. CB 7 was being opened in accordance
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with an Out-of-Service f005) (2-63B-90) that was b'eing(hung)in f
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preparation for Unit 2 Reactor Core Isoiation' Cooling-RCIC work.
The licensee's investigation found that CB 7 at DC distribution panel 211-Y did not feed RCIC but only fed the Division.1 PCIS logic. They. also found that the Key Diagram (IE-2-4000FB), an Operator Aid, posted at the breaker location was also in error in that it indicated that the breaker fed the PCIS panel 2PA133 as well as a valve-(2E51-C002) in the RCIC system.
At 2:15 a.m. the licensee reclosed CB 7 and reset the isolation
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The A VP loop was restarted and the outboard RBCCW valves l
i that had closed were reopened. At 3:15 a.m., the licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS notification of t% ESF nctuation.
k The inspectors were not able to complete the evaluation of this
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event curing the inspection period. Completion of this event will j
be tracked as an Unresolved Item (374/90003-01).
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On April 12, 1990, at 3:31 a.m. (CST), Unit 2 received a Division 2
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PCIS isolation signal. As in the April 11 event, only some valves
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closed in response to the signal, except in.this case they were the
inboard isolation valves.
The isolation signal occurred when the
operator transferred the 2B Reactor Protection System (RPS) power I
supply from its alternate source back to-the normal preferred
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source.
The licensee reset the isolation signal =and reopened the isolation valves that had closed.
At 5:36 a.m. the' licensee made j
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the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS notification of the ESF actuation ~.
The licensee's investigation of the event revealed that 00S 2-621-90 had been previously hung to allow the rotation of a Division 2 PCIS l
testswitch(S800).
This switch had originally been installed upside down and was being rotated to make it conform with the other test switches. 005 2-621-90 lifted several leads which produced a 1/2 Division 2 PCIS signal. This status was not annunciated in the i
control room and was, therefore, unknown to the operators. When the 2B RPS power supply was transferred, the momentary loss of power to the reactor water level 2 trip switches generated another 1/2 Division 2 PCIS signal per plant design.
This completed the necessary signal to cause the isolations.
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On April 21, ~1990, at 5:25 a.m. (CST)}ike the previous two events, Unit.2 again received a Division 2 PCIS isolation signal.
Un the velves that closed were all reactor recirculation A loop Hydraulic Power Unit (HPU) isolation valves (2B33-F338A, 2833-F340A, 2B33-F342A, and 2B33-F344A). No other valves closed because they were already in the closed position or had a temporary system change in place that prevented closure.
The licensee reset the isolation signal and reopened the isolation valves.
The licensee's initial review of 005's in place did not reveal.the cause of the isolation.
As in the April.12 event, the licensee was in the process of transferring the RPS power supply from its alternate source back to its normal preferred source, except in this case it was the 2A RPS but instead of the 28 RPS bus.
At 7:00 a.m., the licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> notification for the ESF actuution.
The licensee subsequently found that a Division 2 PCIS test switch (S800) was in the TEST position instead of the NORM position. With the test switch-in this position, a 1/2 Division 2 PCIS signal was produced. When the.2A RPS power supply was transferred, the i
momentary loss of power to the reactor water level 2 trip switches
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generated another 1/2 Division 2 PCIS signal per plant design.
This completed the necessary signal to cause the isolations.
The inspectors were not able to complete the evaluation of this event during the inspection period. Completion of this event will betrackedasanUnresolvedItem(374/90003-02).
No violations or deviations were identified in this area, however, two unresolved items were identified.
4.
MonthlySurveillanceObservation(61726]
The inspectors observed surveillance testing, including required
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Technical Specifications surveillance testing, and verified for I
actual activities observed that testing was performed in accordance
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with adecuate procedures. The inspectors also verified that test instrumentation was calibrated, that Limiting Conditions for
Operation were met. that removal and restoration of the affected j
components were accomplished and that test results conformed with
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Technical Specification and procedure requirements. Additionally,
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the inspectors ensured that the-test results were reviewed by
personnel other then the individual directing the test, and that any deficiencies identified during the testing were properly reviewed
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and resolved by appropriate management personnel.
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The inspectors witnessed portions of the following test activities:
LES-GM-126 Unit 1 Generator and Alterex Collector Ring Inspection, Brush Replacement and Insulation Resistance Measurement.
LES-PT-207 Unit 2 CRD Charging Water Header Pressure Time Delay
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Relay Calibration and Functional Test LIS-NB-418 Unit 2 Reactor Vessel Low Pressure LPCS/LPCI Inspection Yalve Permissive Functional Test
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LOS-CS-Q1 Secondary Containment Damper Operability Test b.
On March 20, 1990, at approximately 9:12 a.m. (CST), the licensee i
made a 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS phone notification pertaining to Unit 2 exceeding a Technical Specification requirement for the maximum allowable
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leakage rate at the calculated peak containment internal pressure
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(0.6 La). The exceeding of the 0.6 La requirement is based on the results to date of as-found data from local leak rate tests being )
performed.
Unit 2 had been shutdown for four days of a twelve (12 week refueling / modification nutage. The licensee is. continuing to perform local leak rate tes'
in other containment isolation valves.
The licensee plans to repali ihose valves.that do not pass their
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local leak rate tests.
No violations or deviations were identified in this 6rea.
S.
Monthly Maintenance Observation (62703)
Station maintenance activities of systems and components listed below, including safety-related systems, were observed / reviewed to ascertain that they were conducted in accordance with approved procedures, regulatory guides and industry codes or standards and in conformance with
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Technical Specifications.
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The following items were considered during this review:
the Limiting Conditions for Operation were met while components or systems were removed from service; approvals were obtained prior to initiating the work; activities were accomplished using approved procedures and were inspected as applicable; functional testing and/or calibrations were
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performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemented.
Work requests were reviewed to determine status of
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outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performance.
Portions of the following maintenance items were observed during the inspection period:
Unit 1 RBCCW Heat Exchanger Weld Repair Unit 2 reactor Building Ventilation Damper 2VR05YA Repair No violations or deviations were identified in this area.
6.
Licensee Event Report Followup (90712, 92700)
Through direct observations, discussions with licensee personnel, and review of records, the following event reports were reviewed to determine that reportability requirements were fulfilled, imediate corrective i
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action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical _ Specifications.
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The following reports of nonroutine events were reviewed by the a.
inspectors.
Based on this review it was determined that the events
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were of minor safety significance, did not represent program deficiencies, were properly reported, and were properly compensated for. These reports are closed:
373/89013-01 Primary Containment Isolation During Instrument Surveillance Testing Due to Procedural Deficiency 373/90002-00 1A Diesel Generator Governor Low on 011 Due to Oil Leak on Compensation Needle Valve Cover Plug Caused by Procedural Inadequacy 373/90003-00 Reactor. Core Isolation Cooling Isolation Signal During Warmup Due to Spurious High Steam Flow Signal Caused by Steam / Water Mixture Trapped Between Isolation Valves 373/90002-01 1A Diesel Generator Governor Low on Oil Due to 011 Leak on Compensation Needle Valve Cover Plug Caused by Procedural Inadequacy. Revised because of typographical error.
373/90003-01 Reactor Core Isolation Cooling Isolation Signal During Warmup Due to Spurious High Steam Flow Signal Caused by Steam / Water Mixture Trapped Between Isolation Valves.
Revised because of typographical error.
373/90004-00 Automatic Start of Control Room Energency Makeup Ventilation Train Due to Blown Buses on the Control Room Radiation Monitor 374/90001-00 Reactor Scram During Instrument Surveillance Testing Caused by Sputious Spike on Average Power Range Monitor b.
The following report of a nonroutine event involved a violation of regulatory requirements. Event closure is being tracked by the associated violation. Appropriate cross references are provided.
These reports are consideree closed.
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374/90002-00 Surveillance Not Performed Within Required Time Interval Due to Personnel Error and Procedural Inadequacies (Violation 374/90002-01).
No violations or deviations were identified in this area.
7.
ESF System Walkdown (71710)
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On April 2-4, 1990, the resident inspectors performed an Engineered Safety Feature (ESF) system walkdown of the Unit 2 Automatic Depressurization System (ADS) of the reactor.
The walkdown included areas within the euxiliary building, reactor building, the drywell and control room. At the time of the inspection, Unit 2 was in a 12 week refueling outage.
The objective of this inspection was to independently verify the status of an ESF system. Prior to performing the ESF system walkdown, the inspectors reviewed the applicable sections of the Updated Final Safety >
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AnalysisReport(UFSAR),theTechnicalSpecifications,theLicense Systems Lesson Plars, the Piping and Instrument Diagrams, and the licensee's system lineup procedures.
During the walkdown, items that were considered were:
Hangers and supports were made up properly, aligned correctly, and had sufficient hydraulic fluid levels.
Housekeeping was adequate and appropriate levels of cleanliness were being maintained.
Valves in the system were installed :.orrectly and did not exhibit gross packing leakage, bent stems, missing handwheels, or improper labeling.
No prohibited ignition sources or flammable materials were present in the vicinity of the system being inspected unless proper authorization had been granted.
Major system components were properly labeled, lubricated, cooled (cooling water / ventilation), and no leakage existed, i
Instrumentation was properly installed, functianing, and significant process parameter values were consistent with normal expected values.
Verification that instrument calibration dates were current.
Verification that valves in the flow path were in the correct positions as required by procedure by either visual observation or remote position i
indication; that power, if required, was available to the valve; that'
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valves were locked as appropriate; and that local and remote position j
indications were functional and indicated the same values.
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Verification that support systems essential to system actuation or performance (interlock, pump trip, cooling water,' ventilation, lubrication,compressedairorgas,etc.)wereoperational.
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Verification of proper breaker position at the local electrical boards and indications on control boards.
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Overall, the condition of the system appeared good. The areas inspected i
were clean, there were no noticeable leaks, and the hangers and supports
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appeared adequate'and in good shape.
Breakers and electrical
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j instrumentation did not exhibit any signs of degradation. The majority I
of the equipment was well labeled, but the inspectors did note that
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equipment for ADS located in the drywell was not well labeled. This
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also pertained to all of the equipment in the drywell.
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Upon conclusion of the inrpection, the inspector found no anomalies and
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has no concerns pertaining to the Aut0Ntic Depressurization System.
ha violations or deviations were identified in this area.
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8.
Training (71707)
The inspector, through discussions with personnel, evaluated the licensee's training program for operations and maintenance personnel to determine whether the general knowledge of the individuals was sufficient '
for their assigned tasks.
In the areas examined by the inspector, no items of concern were identified.
No violations or dt.viations were identified in this area.
9.
Security (71707]
The licensee's security activities were observed by the inspectors during routine facility tours and during the inspectors' site arrivals and departures. Observations included the security personnel's performance associated with access control, security checks, and surveillance activities, and focused on the adequacy of security staffing, the security response (compensatory measures), and the security staff's attentiveness and thoroughness. The security force's performance in these areas appeared satisfactory.
The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan except as noted below. This included verification that the appropriate number of security personnel were on site; access control barriers were operational; protected areas were well maintained;-
and vital area barriers "ere well maintained.
No violations or deviations were identified in this area.
10.
Radiological Protection (71707)
The inspectors verified the licensee's radiological protection prograra was implemented in accordance with the facility policies and programs and was in compliance with regulatory requirements.
No violations or deviations were identified in this area.
11.
ReportReview(90713)
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During the inspection period, the i...gectors reviewed the licensee's Monthly Operating Report for March.
The inspectors confirmed that the information provided met the requirements of Technical Specification-6.6.A.5 and Regulatory Guide 1.16.
12.
UnitTrip(93702)
On March 28,1990, at 3:37 a.m. (CST), Unit I scranmed from 100% power.
At the time of the event Unit 2 was shutdown for a 12 week refueling /
modification outage and was nearing completion of being defueled.
Plant response to the scram was ncemal with the exception of the control room ventilation system switching to the emergency makeup mode. Three
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V under power operations will initiate a pump trip if they reach a position less than 90% of full open so as to prevent pump damage.
The original reactor recirculation pump discharge isolation valve design was a double disc configuration with two metallic disc inserts installed-between the two discs. This design had led to repeated maintenance problems due to the size of the bonnet, which was not large enough to allow the discs. to be completely extracted from the flow stream. This resulted in flow induced vibrations which have caused wear of the disc insert which then loosened and dislodged into the flow stream.
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September of 1987, Unit 1 jet pump no. 3 showed low flow indications
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with the reactor at 74f. power.
During the mid-cycle maintenance outage reactor recirculation pump discharge valve 1833-F067A failed to fully
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close. Upon inspection, it was discovered that one of the disc halves had separated from the valve stem. This allowed the disc inserts to separate from the disc ha;ves. Only one of the disc inserts was found in the valve. The missing disc insert was found lodged in the nozzle of jet pump no. 3.
In addition, problems have been' encountered with loose backseats which, during subsequent valve manipulations, have scored the valve stem. The modification replaced the existing double disc configuration with a solid one piece flexible wedge disc and a larger bonnet which allows the disc to be fully retracted into the bonnet and out of the flow stream. Other valve parts being replaced are the valve stem, stanchions, guides, and the packing assembly _ so as to be compatible with the new bonnet.
The modification to the recirculation discharge valves for Unit I was accomplished during the Unit 1 third refueling outage. The inspector i
reviewed the modification package prior to work commencing on the discharge valves and, during the outage, the inspector periodically j
i observed work being performed on the, discharge valve. Upon completion l
of the modification, the inspector reviewed the completed work request L
packages.
The following items were considered during the inspectim:
Verification that the modificatwns were reviewed and approved by onsite and offsite review organizations in accordance with Technical Specifications and established QA/QC program controls and did not invalidate modifications made previously to the same system / component.
Verification that modifications were controlled by approved procedures, i
Verification by review of completed test records that the licensee conducted a review and evaluation of test results prior to the modification being declared operable.
Verification that operating procedure and emergency operating procedure modifications were made and approved prior to the modification being declared operable in accordance with Technical Specifications.
Verification that operator training programs were revised and that necessary operator training was conducted prior to the modification being declared operable to reflect the modification that was implemented.
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Verification that prior to the modification being declared operable, the controlled copies of as-built documents used by the plant operators were either revised and distributed, or had been legibly marked-up on an
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interim basis to show all changes relating to the modification.
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Veritication that preventive maintenance and/or Inservice Inspection'
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(ISI) and Test (IST) requirements for newly installed equipment had been
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added or appropriately changed, prior to the modification'being declared
operable, to the respective programs maintained and implemented by the licensee.
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Verification that changes to the design as described in the Updated Final Safety Analysis Review (UFSAR) were properly controlled and documented in
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updates to the UFSAR.
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The inspector reviewed the applicable sections in the UFSAR, Technical Specifications, Safety Evaluation Review (SER), and station procedures pertaining to the modification.
The work performed by the licensee and its contractors was well planned and execution of the modificetion work went well.
Items.affected by the modification were minimal.
There are no affects on modes of operation of the reactor recirculation system.
The leak detection system lines associated with the valves will no longer be functional. As for radiological affects, the stem leak off of the discharge valves, IB33-F067 A & B, will now he part of the design leakage into the drywell floor drain sump. Operating procedures and alarm procednes have been revised. Training requirements for the lesson plan, and License System
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Description Chapter 73 for Leakage Detection are being revised to reflect
the removal of the stem leak off lines for valves 1833-F067 A & B.
Handswitches for the nonfunctional solenoid valves, and temperature element inputs to the multipoint recorders and alarms are annotated as being non-functional in the control room. Operator training was required on the affected procedures prior to startup after the refueling outage.
The UFSAR is being revised to reflect the removal of the stem leak off
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lines for valves 1833-F067 A & B and any leakage will now be part of the design leakage into the drywell door drain surcp.
There are no changes to any conditions and/or astunptions of any accident from the implementation of this modification.
Pertaining to affects of the Technical Specifications and/or operating license, there may be an
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insignificant increase in the amount of unidentifiable leakage, and subsequent decrease in the amount of identifiable drywell leakage as a result of this modification. Changes to-the Technical Specification-
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were not required.
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No violations or deviations were ide91fied in this area.
14.
Safety Assessment and Quality Verification (40500)
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On March 8, 1990, and again on April 12, 1990, the inspectors I
attended the licensee's Unit I and Unit 2 Monthly Performance
Evaluation. The April 12 neeting did not cover Unit 2 since it was in a refueling outage at the time.
The meeting was designed to
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review the operating performance of the units during the previous the following parameters:
monthincluaing(ESF)actuations,degradtdequipment,alarmedunit.stitus, Engin Safety feature.
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ennunciators in the control room, control room vorn requests, and the monthly review committee commitments. The meeting was attended by station managecent, personnel from the different departments, and management personnel from Ceco's corporate office.
Discussions were held on security concerns, Quality Assurance and Nuclear Safety Department concerns and comments from the Station Ownersh%
Committee, b.
On April 4, 1990, the inscoctors attended the licensee's Event Frequency Reduction Committee meeting.
The purpose of this committee was to improve station performance through the comprehensive review and correction of conditions which could or
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have resulted in events. The inspectors observed that the meeting-was well managed and attended with representatives from different
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disciplines present.
Concerns and commitments were being. tracked with specific individuals assigned. responsibility and completion-dates assigned. The meeting appeared to be an effective management tool for evaluating areas of improvement that affected station performance.
No violatiors or deviations were identified in this area.
15. Outajes (71707)
On March 16, 1990, at approximately 8:05 a.m. (CST), Unit 2 commenced
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shutting down in preparation for a scheduled 12 week refueling /modifi-
-l cation outage. On March 17 at 12:28 a.m., the turbine was manually l
tripped as part of a turbine overspeed surveillance test. M li18 a.m.,
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the ret.ctor was man'Jally scrammed in order to perform a Technical Specification surveillance, LOS-RD-R2, Scram Discharge Volume Vent and
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Drain Valve Timing.
The plant responded as expected to the scram with
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the exception that one control rod drifted back to the 02 position afto fully inserting.
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Major activities scheduled to be accomplished during the outage included j
refueling the reactor, control rod overhaul and replacement, modifica-
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tions of the Reactor Recirculation (RR) system discharge valves, j
maintenance work on the RR pumps, Appendix R modifications including
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work on the Emergency Diesel Generators, and control roonahuman factors j
work including replacement of the Containment Leak Detection System panels. As of the end of this inspection period, the outage is on o
schedule and is approximately 30% complete.
j 16. Emergency Preparedness (82701)
a.
On March 22,1990, et 12:40 p.m. (CST), the licensee declared an f
Unusual Event when it was discovered that they had. lost all land
based communication systems. This included commercial lines, the
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Emergency Notification System (ENS), and the Health Physics Network.
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Communication capability with the licensee's Corporate. Commcod
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Center (CCC) thru a microwava link was maint'ained. At 1:15 p.m.,
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the licensea contacted-the CCC and requestea that.they contact the NRC Operations Center to report the Unusual Event. This was accomplished at 1:25 p.m..
Illinois Bell we.s centacted and i
responded by sending a repair crew to determine the cause of,
failure.
Illinois Bell also provide the site with a Cellular. Phone.
M The cause of the event was determined to be water leakage into a i
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phone junction box several miles from the site.
Illinois Bell dried g
out the box and _ returned the system to an operable status at 9:50 p.m..
The Unusual Event was terminated at that time. At 10:05 p.m.
r the licensee made an ENS not'lfication to this effect.
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b.
On April 6,1990, th'e iiispector toured the Emergency Offsite
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Fecility (EOF). The facility and attendant equipment appeared to be d
it, a sMte of readiness.
In October of 1988 during a tour of the s
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EOF, thu inspector noted that the space allocated to the NRC was not
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the most viable arrangement available in that the status boards.
A could not be directly viewed from that location-(a separate room).
Therefore, in order to provide updates to offsite personnel, it
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would be necessary to go out of tiie rco.n to view the status boards and then return to pass the information along. At that time the
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inspector talked with a site representative, who1 indicated that the
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arrangement was to be changed as the ' result of a recent visit by the Region to assess the EOF.
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The inspector noted during this* tour that the original arrangement was still in place. Discussion with a licensee representative indicated that a change to the physical layout and saating arrangements is pituned for this summer, j
No violations or deviations were identified in this area.
17. Unresobed Items i
An unresolved item is a matter about which more ilesrmation is required
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in order to ascertain whether it is an accepttble item, an open item, a
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a deviation, or a violation. Unresolved items disclosed during this inspection are discussed in Paregraph 3.
18.
Exit Interview (30703)
The inspectors met with licensee representatives (denoted in Pa agraph 1)
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throughout the month and at the conclusion of the inspection period and
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sumarized the scope and findirgs of the inspection activities.
The
licensee acknowledged these findings.
The inspectors also discussed the
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likely informational contents of the inspection report with regard to
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documents or processes reviewed by the inspector'during the inspectico..
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The licensee did not identify any such documents or processes as
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proprietary.
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