IR 05000373/1990014

Insp Repts 50-373/90-14 & 50-374/90-15 on 900603-0717. Major Areas Inspected:Lers Followup,Operational Safety, ESF Sys,Maint,Surveillance,Training Effectiveness & Emergency Preparedness

ML20056A863
Person / Time
Site:	LaSalle
Issue date:	07/30/1990
From:	Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20056A862	List: IR 05000373/1990014 ML20056A861
References
50-373-90-14, 50-374-90-15, NUDOCS 9008090327
Download: ML20056A863 (15)

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S.. NUCLEAR REGULATORY ~ COMMISSION

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REGION III

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" Reports No.. 50-373/90014(DRP);-50-374/90015(DRP)..

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Docket Nos? 50.-373;'50-374

~ Licenses No.'NPF-11; NPF-18 i

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Licensee: Commonwealth Edison Company A

Post Office Box 1767

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' Chicago, IL 60690

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. Facility Name:- lLaSalle County Station, ' Units 1 and 2-j inspection At:

LaSalle Site, Marseilles, Illinois x

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Inspection! Conducted:': June 3 through July 17., 1990 yt

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-Inspectors:

T.; Tongue

R.-Kopriva

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Approved Bf G

.M. Hinds, f (

Asw14 Jry hief

. JUL 8 0 - 1990 Reactor Projects Section IA Date r

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Jnspection Sumary l

J Inspection from June 3 through July 17, 1990 (Reports No. 50-373/90014(DRP);

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-No. 50-374/90015(DRPJ)

Areas Inspected: -Routine, unannounced safety inspection by the resident

inspectors oF licensee event reports followup; operational safety;. engineered

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safety feature systems; maintenance; surveillance; ~ training. effectiveness;

report review; onsite followup of events at: operating power reactors; inspector a

inquiries followup; emergency ~ preparedness; plant startup: from refueling;. and

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meetings:and other activities.

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Results:= During the report period, Unit 1 operated at or near full power with ore unplanned reactor trip. The unit scrammed on June 26, 1990 during a main m

turbine stopLvalve surveillance (refer to Paragraph 9). The unit returned to service on July 1,1990.

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Unit 2 completed its. third refueling outage very close to original schedule.

The unit has experienced problems since returning to service-causing it to be

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derated or to be = taken out of service (i.e., recirculation flow control valve

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hydraulic leak, MSIV limit switches, and turbine driven feed pump vibration i

problem). The residents are following these items with emphasis on root Cduses, Corrective actions, and activities that took place on these systems i

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during the outage.

g 9008090327 900730

PDR ADOCK 05000373 Q

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The licenseeks; programs for site' operations have' continued to-improve.-

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Operations,; housekeeping rnaintenance -and emergency preparedness have remained-

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istrengths for the licensee. ' ALARA anditotaliman rem exposure are presently':

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exceeding ltheLsite estimate. There are=no more planned outages expected this

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year and the 1_icensee is. anticipating the man-rem exposure for the year -to;be:

. within:their targeted man-rem exposure.,There was;one occurrence pertaining--

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planned reactor shutdown on-Unit l2.

The-licensee thoroughly reviewed the ~

to-anLunanticipated reactor cool down which caused a power. increase during;a-a

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- event and: kepti the; resident; inspectors apprised of: their actions.

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0fithe twelve areas inspected,'noLviolations'or-deviations wereiidentified.

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0n' Jud 6,c1990 the licensee held theirjannual> Generating Station: Emergency l

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Plani (GSEP)j drill.zidentified as a weakness,. was the failure to promptly..'

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F iupgrade th~e dr' ll condition linL a timely manner..

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[Therewasone'unresolv'ditemidentifiedduringthisreportperiodpertaining i

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to:the ' unanticipated: reactor cooldown during the1 Unit:2 reactor shutdown.

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DETAILSi

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. Persons Contacted t

G. J. Disdefich,_ Manager, LaSalle Station '

1*W. ' R. _ Huntington, Technical: Superintendent

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J. C. Renwick,' Production Superintendent 4,

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4T 4s 1D; S. Berkman, Assistant Superintendent, Work: Planning

, J.-V. Schmeltz,' Assistant Superintendent,.0perations-

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a EJ.-Walkington, Services Director

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'T. A. Hammerich,ERegulatory Assurance Supervisor

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• W. E. Sheldon.-Assistant Superintandent, Maintenance.

'W.;Betourne, Quality; Assurance Supervisor-ye w

• J. Borm,' Quality Assurance ink

• P. Wisniewski,- Regulatory Assurance

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J. -Roman,. Resident Engineer, Illinois Department of Nuclear Safety

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• Denotes those attending' the exit interview conducted on July 17,1990, j

and at other times throughout the inspection period.

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The inspectors also talked with and interviewed several other licensee

W employees,iincluding members of the technical _ and engineering staffs,

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reactor and auxiliary operators,. shift engineers and foremen, and

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electrical,Lmechanical'and instrument maintenance personnel, and contract

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,.ic security? personnel.

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Licensee Event' Reports Followup (92700)

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-Through direct' observations, discussions with-licensee personnel, and-

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review of records, the:following event reports were reviewed to determine-i pi that reportability requirements were fulfilled,limmediate corrective

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A actionLwas accomplished, and corrective action to prevent recurrence a

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4.g had bem accomplished-in accordance'with Technica.1 Specifications.

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The following reports of nonroutine events were reviewed by the-

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inspectors.. Based on this. review it.was: determined that the events

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were of minor safety significance,'did not represent program

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- deficiencies, were properly reported,. and were propsrly_ compensated

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for. These reports are closed:

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o g' w 373/89027-01 - Primary Containment Isolation. During Surveillance

. Testing.Due to Burned Out' Annunciator Window Light-Bulbs i

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373/90006-00 - Reactor Scram Caused by Generator Trip Due to B' Phase

jig Insulator Failure and Subsequent Flashover to Ground i

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373/90009-00'- Fai?ed Differential Pressure Switch - RCIC Isolation

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Instrument i

37.4/90008-00 - Engineered Safety Feature Actuation of the Control

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Room B Emergency CTX Ventilation h keup Fan

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374/90009-00 - Reactor Water Cleanup Pump Tripped Due to a Procedural

' Deficiency During Surveillance Testing

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373/90008-00 - Missed Technical. Specification Hourly Fire Watch Due

'to Miscommunications-374/90005-00 - Inadvertent Division ! Isolation Due to Loss of DC Power to Isolation. Logic Due to Procedural Error 374/90006-00 - Inadvertent = Actuation.'of Group 2 Division I Isolation Logic Due to Procedural Deficiency and Inadequate Out of Service 374/90007-00 - Partial Group 11 Isolation During Reactor Protedtion System Bus Transfer Due to inadequate Procedure and Out of Service-In additicn to the foregoing, the. inspector reviewed the licensee's Deviation Repor ts (DVRs) generated during the inspection period.

This was done in an effort to monitor the conditions related to plant.or personnel performance, potential trends, etc. DVRs were also reviewed-to ensure that they were generated appropriately and dispositioned in-a manner Consistent with'the applicable procedures and the QA manual.

No violations or deviations were identified in this-area.

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Operational Safety Verification (71707)

During the inspection period, the inspectors verified daily,:and rendomly during back shif t-and on' weekends, that the facility was being operated in conformance with the licenses and regulatory requirements and that the. licensee's management control system was effectively carr,ing out its responsibilities for safe operation.

This was done on a sampling basis through routine direct observation of activities and equipment, tours of the facility, interviews and discussions with licensee personnel, independent verification of safety system status, limiting conditions for operation action requiren,ents (LCOs) and corrective actions, and reviews of facility records.

On.a sampling basis the inspectors daily verified proper control room staffing and access, operator behavior, and coordination of plant dClivities With ongoing control room operations; verified operator adherence with the latest revisions of procedures for ongoing activities; verified operation as: required by Technical' Specifications (TS); including compliance with LCOs, with emphasis on engineered safety features (ESF)

and ESF electrical alignment and valve positions; monitored instrumentation

. recorder traces and duplicate channels for abnormalities; verified status'

of various lit annunciators for operator understanding, off-normal condition,' and corrective actions being taken; examined nuclear instrumentation (NI) and other protection channels for proper operability; reviewed radiation monitors and stack monitors for abnormal conditions;

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Everified thd on' site and 'offsite power was available as required;;

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observed tne frequency of_ plant / control' room visits by the station -

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3-manager,: superintendents, assistant superintendents -and other managers;-

'dnd observed the Safety Parameter Display System (SPDS) for operability.

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During tours of accessible areas of the plant, the inspectors made note

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ofgeneralplant/equipmentconditions},includingcontrolofactivities-inprogress(maintenance / surveillance. observation of:-shift turnovers,,

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general safety items,. etc. -The specific areas observed were:

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. Engineered Safety Features (ESF) Systems Accessible portions of ESF systems and components were inspected toi verify: -valve position for proper flow path; proper alignment.

-_ofl power supply-breakers or fuses (if visible) for proper acttation;

on an initiating: signal; proper removal of power from components _if-required by_ TS or FSAR; and the operability of support systems

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. essential to< system actuation.or performance through observation of instrumentation and/or proper valve alignment. The inspectors also.

visually inspected components for leakage, proper lubrication, cooling water supply, etc.

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Radiation protection' Controls

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.The inspectors verified that workers'were following health physics proceduresL for dosimetry, protective clothing, frisking, posting, etc.,5 and randomly examined radiation protection instrumentation for.use, operability, and calibration.

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Security Each week during routine activities or tours, the inspector-monitored the licensee's security' program to ensure that observed actions were being implemented:according'to their approved security plan. The-inspector noted that persons within the protected area displayed proper photo-identification badges and those individuals requiring. escorts were properly escorted. The inspector also verified that checked -vital areas were locked and alarmed.

Additionally, the inspector. also verified that observed personnel and packages entering the protected area were searched by appropriate equipment or by hand.

Housekee2 ng_and Plant Cleanliness i

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The inspectors monitored the status of housekeeping and plant cleanliness for fire protection, protection of safety-related

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equipment from ir+rusion of foreign tatter and general protection of equipment. from hazards.

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LThe' inspectors also monitored various records, such as tagouts, jumpers,

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shiftlyz logs and surveillances, daily' orders, maintenan:e items, various chemistry'and radiological sampling:and analysis, third party review

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results,. overtime' records,.QA and/or QC; audit nsults and posti gs;

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irequired perJO CFR 19.11.

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No violations;or deviations were identified in this area. :

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Engineered Safety Feature (ESF) Systems (71710)-

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During the-in_spection, the inspectors selected accessible portions o.f p'

several ESF/ systems to verify their status.

Consideration was given to i

'the: plant mode, applicable Technical Specifications, Limiting Conditions

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' for Operation Action Requirements -(LC0ARs), and other applicable requirements.

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Eious observations' where applicable, were made of. hangers 'and supports;

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housekeeping; whether freeze protection was installed and operational;

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-valve positions-and= conditions; potential ignition sources; major.compone'nt-

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(labeling,1 lubrication, cooling,;etc.; interior conditions of electric:1

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breakers and Lcontrol panels; whether instrumentation was properly installej..

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and ft!nctionin~ ;Ewhether significant process parameter values were consistent

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' with expected values; whether instrumentation was calibrated; whether

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necessary support. systems were-operational; and whether locally and remotely

indicated breakerf and ' valve positions agreed..

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following ESF components were walked down:

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TUnit l~

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Standby Gas Treatment'

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Emergency Diesel Generator 2A, 28

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High Pressure Core Spray Batteries'

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No violations ~or deviations:were identified in this area.

15'.1 Monthly. Maintenance Observation '(62703)

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Station maintenance. activities affecting the safety-related systems'and-

.' components l listed below were observed / reviewed to ascertain that they j

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were ' conducted in accordance-with approved procedures, regulatory guides.

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>and industry codes or standards and in conformance with Technical

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Specifications.

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The following items were considered during this review:

the Limiting

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Conditions for Operation were met while components or systems were j

removed from service; approvals wery obtained prior to initiating the

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work; activities were accomplished using approved procedb es and were

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inspected as-applicable;-functional testing and/or calibrations were

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performed prior to returning components or systems to service; quality

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control records'were maintained; activities were accomplished by i

qualified personnel; parts and materials used were properly certified;

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radiological _ controls were implemented; and, fire prevention controls

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M were implemented. Work requests were reviewed to determine status of

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p outstanding-jobs and to assure that priority is assigned to safety-related equipment mwintenance which ma.v affect system performance.

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The following maintenance activities were observed and reviewed:

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Control Rod 26-39 Drif t Response and Scram Discharge Valve Diaphragm Replacement

':eactor Feedwater 3 Element Control Repair

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9!!i.2 2A Motor Driven feed Pump Balancing and Coupling

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The inspectors monitored the licensee's work in progress and verified that it was being performed in accordance with proper procedures, and approved work acckages, that applicable drawing updates were made and/or planned, and tlat operator training was conducted in a reasonable period of time.

Nn violetions or deviations were identified in this area.

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Monthly Surveillance Observation- (61726)

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The inspectors observed surveillant.e testing required by Technical Spec 4 tcations during the inspection-period and verified that testing was performed in accordance with adequate procedures, that test i.7strumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the'affected components were accomplished, that results conformed with Technical Specifications and procedure requirements and were reviewed by personnel otSer than the individual directing the test, and that any deficiencies identified-Juring the testing were properly reviewed and resolved by appropriate management personnel.

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The inspectors witnessed portions of the following test activities:

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Unit-1 l

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LOS-DG-M1 0 Diesel Generator Operability Test

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LOS-RI-Q3 Reactor Core Isolation Cooling (RCIC) System Pump

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Operability and Valve Inservice Tests in Conditions 1

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2, and'3 i

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.LOS-DG-M2-Unit 1 Diesel Generator Operability Test

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' Unit 2

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LOS-MS-R2 Main Steam Safety Relief Valve Manual Cycling Test i

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LTS-1100-4 Control Rod Scram Insertion Times

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LIS-NR-211 LpRM Flux' Gain Amplifier Adjustment

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LOS-RI-R1 Reactor, Core Isolation Cooling Turbine Overspeed Test

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'LIS-NB-409 Unit 2 High Reactor Pressure Recirculation Pump Trip

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functional Test

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LOSvRX-M1 Remote Shutdown Monitoring Instrument Channel Check l

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On July 15,1990 at 12:10 p'.m. :DT, the licensee was performing monthly

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= surveillance LOS-ZZ-M2, Unit 2 Monthly. 0il Semples, on the reactor core

' isolation cooling (RCIC) turbine when water was discovered in the oil

sample that-had been taken., At 2:30 p.m. - the licensee declared the Unit i

2 RCIC system inoperable and made the Emerger cy Notification System (ENS)

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call at 2:45 p.m.

Using the bleed and feed inethod, oil / water was drained

from the RCIC turbine as new oil was added, five one half liter containers'of oil / water were removed from the oystem.

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-The water found in the turbine oil was the accumulation of condensation

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from the RCIC cvstem.

The RCIC turbine is steam driven and *- -"nerally

.in a standby n. ode of operation. During the unit startup,

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had'been tested several times resulting in a heating and cooling of'the

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, system componen 6s.

The RCIC system was declared operable at 5:55 p.m.

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Unit 2 was ope'tting at.25% power during the event. A followup oil

'l sample was drawn on July'16,1990 and no water was found in the sample.

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'No violations or deviations were identified..

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Training Effectiveness (41400and4170L{

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The effectiveness of training programs for licensed and non-licensed I

personnel wa.; reviewed by the inwectors during the witnessing of the'

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licensee's performance of routin surveillance-maintenance, and

.operationalactivitiesandduringthereviewofthelicensee'sresponse

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to. events which occurred during the inspection' period.

Personnel

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appeared to.be knowledgeable of the tasks being performed, and nothing m

was observed which indicated any ineffectiveness of training.

No violations or deviations were identified.

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' Report: Review: (90713and92701)

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During the inspection period, the inspector reviewed the licensee's I

Monthly, Performance Report for June 1990. The inspector confirmed i

that the information provided niet the requirements of Technical

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Specification 6.6. A.5 and Regulatory Guide 1.16.

g The: inspector also reviewed the following licensee's reports: '

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LaSalle County Station Monthly Plant Status Report for June 1990..

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No violations or~ deviations were identified, f

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Onsite Fol Mwup of' Events at Operating Power Reactors (93702)

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Unp_lanned Engineere Safety Feature Actuations-d E

roximately 8:30 u.m. (CDT), the Unit 1 Reactor a.-

On June-18, 1990,

' Core isolation Coolingat apfRCIC) system turbine tripped on mechanical i

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overspeed. The licensee was performing a routine operating

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surveillance LOS-RI-Q4, " Reactor Core Isolation Cooling (RCIC) System

' Cold Quick Start in Conditions 1, 2, and 3", when the licensed operator

-started the RCIC turbine / pump. The turbine continued increasing speed up to the mechanical overspeed trip setting at.which time the turbine i

tripped.-- A. chart recorder-indicated that the overspeed trip occurred

.at 5650 RPM which is within the required setting of the mechanical

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- overspeed trip.

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The licensee declared the RCIC system inoperable and the licensee l

had'14 days in which to return the RCIC system to operable status

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per Technical Specification 3.7.3.

At the time of the event, Unit I was.at 100% and the High pressure Core Spray (HPCS) system was -

operable,

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y The licensee made the Emergency Notification System (ENS) phone call Thelicensee'per_10CFR50.72(b)(2)(iii)(0).accidentmitigation.

at 9:50 a.m.

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s investigation into the cause of the RCIC turbine

overspeed revealed that it was not related to dirt and/or water in

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the governor control oil.

The limit switch setting on_the F045

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valve, which causes the governor valve to rtart ramping down, was found to be the prob bm.

The limit switch, which trips at less than or equal to 2% of the-F045 valve travel, wr.s out of tolerance.

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was initiating the downward speed rap at appro/imately 1.1 seconds

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after initiation.

It was adjusted down to 0.1P seconds and the peak

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speed of the turbine dropped to the proper value of approximately-4750 RP'i.

At 7:05 p.m. on June 20, 1990, the licensee successfully.

completed LOS-RI-Q4 and declared the Unit 1 RCIC system operable.

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On July ~; 1990, at' 9:52 a.m. CDT, Unit I was at approximately 60%

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power when control rod 26-39 unexpectedly drifted into its fully

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inserted position._ The control rod-scram light was also lit._ The

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g station nuclear: engineers were contacted and, after reviewing the h

control rod positions within.the reactor and reactor. power level, b,,

concluded that there was no immediate concern with control. rod 26-39

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. being fully inserted.

It was not' part.of a control cell.

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Upon inspection the licensee discovered' that:the diaphragm for

hA the scram inlet valve had ruptured, which caused the controi rod 6<

insertion..The licensee replawd the scram inlet valve diaphragm-for control rod 26-39 and at 2:30 a.m. on July 5, 1990, they i

oi i-successfully completed ~ surve111ance.LTS-1100-4., Single Control Rod

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Scram Time Testing.

The control rod was declared operable at

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2:55 a.in.

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s This is the secon/_ diaphragm failure for inlet scram valve 26-39.

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c The first.occurre, ice was a) proximately one year ago. Both-

k replacements hav s been wit 1 a newer type of diaphragm. The licensee F

is continuing tteir investigation inta the cause of the~ failure and L

any potential ainorma'. ties with scram inlet valve 26-39.

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On July'12,199P, at 2:26 a.m. CDT, Unit 2 experienced a single _

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ontrol rod sc'am.

The unit was at 98%

scransned from.its full out aosition (48) power when control rod 26-55

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tc its full.in position (00).. Per tW 11censee's a > normal operating procedure LOA-RD-06..

the licensed operator reduced power approximately 100,MWe and i

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contacted the. nuclear engineer.

Upon review of the reactor core configura+ son and power level, the nuclear engineer confirmed that r6d f6-% being in the 'ull in position dict not pose a concern.

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The cause of control, rod 26-55 scramming wss that the hydraulic control unit'(HCU) scram outlet valve (127 valve) had a blown

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.diophragm.

The.11censee'took HCU 26-55 out of service and replaced

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the 127 valve diaphragm. ' Repairs were completed by July 13, 1990.

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Due to the second r, cram valve diaphragm faflure in a week, the l

111censee has contacted the' reactor vendor,. General Electric, and

-is pursuing the problem with them.

Resolution of this issue is

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Open Item 373/90014-01(DRP)374/90015-01(DRP).

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On July 13, 1990, the licensee informed the resident inspector that during monthly operating surveillance LOP-RP.-M1, Main Steam-

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IsolationValve(MSIV)ScramFunctionalTest,theReactorProtection

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System (RPS) B1 scram limit switch on the A inboard MSIV failed to

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reset af ter it had been tripped. Also, on July 11, 1990, the RPS

Al scram limit switch on the B inboard MSIV hadl failed-to trip

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during the same surveillance.

At that time, the licensee had pulled

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the fust associated with the B inboard MSIV switch rendering it inoperab le.

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' At 5:30 a.m. on July 13, 1990, the RPS A2 acram. limit switch on i

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the D inyoard and outboard MSIVs failed to trip. At 9:00 p.m.,

the licensee commenced a load drop to approximately 15% reactor.

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power and deinerted the drywell. At 8:30 a.m., on July 14, 1990

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- work commenced on the MSIV scram limit switches within the drywell.

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At.12:15 p.m., all of the scram limit switches had been reset and-the MSIV's stroke tested per LOS-RP-MI. ' At 6:40 p.m., LOS-RP-M1

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Wds Completed satisfactorily, the drywell inerting commenced, and i

power was increased.

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l Reactor Trip q

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On June 26,1990 at 4:53 a.m Unit I experienced a reactor scram from

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near full power while conducting surveillance testing of the main turbine

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stopvalves(MTSVs).

Initial indications we r that when the number 2

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MTSV was coming open, the number 1, 3, and 4 MTSVs went shut resulting

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in the _ turbine trip and reactor trip. -There is a protective electrical

circuit associated with the electric hydraulic control (EHC) system t

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built into the system to prevent this type of occurrence during testing.

MTSV's 1, 3, and 4 are slaved to respond to MTSV number 2.

Investigation

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revealed that an associated limit switch on the nu'nber 2 MTSV was loose F

and resulted in an interruption of the test circuitry during testing

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i creating a'non test condition.

This resulted in the 1, 3, and 4 MTSVs going shut. The licensee has called in General Electric for concurrence with their evaluation. The switch was tightened and the system tested

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satisfactorily.

In addition, following the reactor tri), the IB turbine driven reactor feed pump (TDRFP) did not trip using tie manual push button and had to be b

done by an alternate method.

Manually tripping the TDRFP upon a scram is

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a protective stcp'to prevent an autos.atic trip on reactor vessel high water level for turbine protection from moisture carry over.

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The licensee reported the event per 10 CFR 50.72 and to the SRI who

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responded to the site for followup.

The. licensee used the forced outage

- to conduct several days of maintenance work such as repair of main condenser tube leaks and work in the drywell of replacing the reactor

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recirculation flow control valve linear variable differential

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transmitters (LVDTs).

'During the forced outage., the licensee pursued the root cause of the IB_TORFP not tripping upon initiation of the manual trip signal.

The investigation revealed that the manual trip solenoid had a small amount

of an oily residue on the solenoid prohibiting its actuation.

The solenoid is located-in a less than desirable environment being subjected

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to heat and dust. The solenoid was cleaned, tested, and returned to service.

The solenoid is on a six month schedule for preventive

maintenance (PM) and was scheduled for cleaning at the time of-the reactor trip, but the cleaning had not been performed because of other activities taking place on> the units.

The licensee is reviewing their PM frequency for. the TDRFP trip solenoids.

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The licensee completed their forced outage work and on June 30, 1990 l

initiated a unit startup. At 10:42 p.m. the reatter was critical with

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a 104 second period and the generator was synchronized to the grid on

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July 1,1990 at 4:48 p.m.

Unanticipated Cooldown Rate Ouring Planned Reactor Shutdown On June 23, 1990, Unit 2 was being taken from about 24% power to hot

b standby'for repair of a hydraulic oil leak in the drywell on the-20

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reactor recirculation flow control valve hydreulic power unit (HPV).

The shutdown.was being accomplished by the normal procedure through

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control rod insertions.

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il n During the shutdown, the Unit experienced a cooldown rate higher than L

expected., This resulted from the operation of the Reactor Core Isolation k

Cooling (RCIC) for reactor pressure control and the absence of normal

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decay heat due to its relatively new reactor core. Reactor power had

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been reduced to 0.04% on range 4 of the intermediate range monitors i

a (1RM's) in order to shut the Main Steam Isolation Valves (MSIV's) and two l

MSIVs had been shut. The Nuclear station operator (NS0) observed power

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The shif t engineer (SE) and shif t control: room

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engineer (SCRE) immediately reviewed reactor temperature and determined i

that the increase in power was due to the cooldown from the RCIC

operation and low core decay heat.

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The SE directed the NSO to stop shutting the MSIVs and stop inserting

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control rods unt,'1 the reactor temperature and pressure stabilized which-took about 2 to 3 ainutes with a period of about 100 seconds wP.h is t

normal for a startup. The SC also directed-the NSO to manually scram the

reactor if power had ontinued to increase.. Reactor power stabilized at

about 1% on range 7 or 3 on the IRMs.

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Following the stabilization and consultation with a qualified nuclear-

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engineer, the NSO was directed to continue inserting control rods and shutting the MSIVs.

The licensee completed the shutdown at about 9:00 p.m.

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on June 23. 1990.

The licensee informed appropriate corporate personnel, the senior resident inspector (SRI), and made a courtesy ENS notification i

to-the NRC.

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The SRI responded to the site and verified the information provided through interviews with personnel involved, review of logs, and process computer output.

It was confirmed that the reactor had not'been subcritical during the occurrence.

On June 24, 1990, the licensee convened a potentially significant event (PSE) report review panel to evaluate the occurrence.

The reactivity

increase was found to be caused by the core being relatively new with low decay heat which resulted in a greater cool down rate than normal.

This and a lack of procedural guidance for such a condition, i.e., shutting l

MSIVs during a shut down, also contributed to the occurrence.

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After review of the licensee's conclusions, the following questions remained-

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What procedules were being used at the time of this event and were they adequate?

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Why did the operator upscale the IRMs instead of iriserting a manual

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scram or driving rods in when he saw the positive reactivity additir.n?

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What information was provided to the crew regarding the uniqueness j

of this evolution (e.g. lack'of decay heat) and was the information:

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What is your basis for not reporting this event within one hour as

required by 10 CFR.50.727

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What were the root causes identified and the corrective actions

taken with regards to this event (e.g. was a nuclear engineer sufficiently involved; is operator training adequate)?

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These questions were discussed by telephone with the licensee on July 27, 1990. This event is i.onsidered an Unresolved Item (373/90014-0 $ Rp)*

374/90015-02(DRp)).

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By June 25, 1990, the licensee had completed the.necessary repairs:to the

recirculation flow control valve hydraulic system and commenced a reactor

'startup. At 7:55 p.m. the reactor was critical with a 165 second period.

The Unit 2 generator was synchronized to the grid on June 26, 1990 at 4':51 L,

p.m.

No violations or deviations were identified.

10.

Inspector Inquiries Followt.p (92701)

i During the inspection period, the inspectors raised a number of issues of

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concern. The following is a summary of those responses, j

During a plant tour on June 4 and 5, 1990, a-fire seal was-found damaged in-a wire passage way.

A review verified the damage by unknown persons,-

l however, the damage was not sufficient to degrade the seal, i.e.,

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sufficient fire resistant material remained to sustain the rated fire.

On June 4, 1990, an electrical junction box was found opened in the

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overhead of the-Unit 2 cable spreading room and no apparent work in the araa. This was found to be a communications system junction box and the cover was replaced.

No violation or deviations were identified in this area.

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' 11. Emergency Preparedness (82301)

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. An inspection of emergency preparedness activities was performed to assess the. Ifcensee's implementation of the emergency plan and

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implementing procedures. The inspection included monthly observatior

'J of emergency facilities and equipment, interviews with licensee stafs,

L and a review of selected emergency. implementing procedures, j

On June.6, 1990 the licensee held their 1990 Generatinq Station

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Emergency Plan [GSEP) exercise. The exercise was a._ daytime event to p

is test the integrated capability and a major portion of the basic elements

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existing'within the licensee's emergency preparedness plan.

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verify their capability to respond to an emergency.

The resident inspectors attended meetings on June 5, 1990.on site in--

preparation for.the exercise.

The exercise commenced at approximately

.1 7:30 a.m. on June 6,1990, and was terminated at approximately 3:00 p.m. -

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The exercise went well and the licensee's response to the scenario in

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the exercise was well executed.

L On June 7,1990, the NRC held their exit meeting on.the drill at the-site.

The results of the exercise are reported in Inspection Reports

No. 373/90005 and No. 374/90006.

• No, violations or deviations were identified in this area.

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Plant Startup From Refueling (71711)

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L On June 10, 1990, the' licensee commenced a reactor startup on Unit 2.

~At 2:40 p.m..CDT, the reactor was critical with a 57 second period.

.The unit was synchronized to the grid at 2:42 p.m. CDT on June 12 -

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1990. The outage had been scheduled for 12 weeks in duration and

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actually took 121/2 weeks.

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Major activities accomplished during the outage included control rod

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overhaul and replacement, modifications of the reactor recirculation

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'(RR) system discharge valves, maintenance work on the RR pumps, Appendix-R modifications including work on the emergency diesel generators,

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control room human factors work including replacement of the containment leak detection system panels, manufacturing and installation'of a jet a

pump instrumentation line-clamp and expanded inservice inspection on the

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reactor steam dryer. A total of 36 modifications were completed.

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No' violations or deviations were identified in this area.

13.- Meetings and Other Activities (30702)

-Commissioner Visit

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i On July 10,1990, Commissioner Kenneth Rogers and the Region III Regional

, Administrator, Mr. A. B. Davis, visited the LaSalle County Nuclear Station. The station manager and select staff personnel provided a tour of the site for the commissioner and Regional Administrator. During a working. lunch, the plant manager end his staff, along with corporate

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staff members provided a brief historical synopsis of the LaSalle plant.

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. The-Commissioner then held-.one-on-one. discussions with select plant'

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.Open Items are matters Which have been discussed with' the licensee which a

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, will be' reviewed further by the inspector and which. involve some actionL

on the partLof:the NRC or': licensee or both M 0ne Open Item disclosed-j m

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'during this:inspectionJis discussed in paragraph 9.:

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. Exit Interview (30703);

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during-the1 inspection period and at the conclusion of the inspection.

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period on July 17,'1990.'The inspectors summarized the scope'and results ti

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of,the; inspection andLdiscussed the likely content of this inspection

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J report.; The. licensee acknowledged the information and did not indicate -

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that 3any of theyinformation; disclosed during the

inspection: could be4 ("

considered: proprietary in nature;

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