IR 05000373/1989017
| ML20245E891 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 08/03/1989 |
| From: | Harrison J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20245E873 | List: |
| References | |
| 50-373-89-17, 50-374-89-17, GL-84-15, NUDOCS 8908140037 | |
| Download: ML20245E891 (19) | |
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S. NUCLEAR REGULATORY COMMISSION-
REGION III
Report Nos. 50-373/89017(DRP); 50-374/89017(DRP)
Docket Nos. 50-373; 50-374 Licenses No. NPF-ll; NPF-18 Licensee: Commonwealth Edison Company Post Office Box 767 Chicago, IL 60690 Facility Name: LaSalle County Station, Units 1 and 2 Inspection At: LaSalle Site, Marseilles, IL Inspection Conducted: June 10 through July.24, 1989 Inspectors:
R. Lanksbury R. Kopriva D. Jones D. Miller R. Paul F. Maura hl)
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Approved By:
J. J. Harris n. Chief 7/V/ N/
Reactor Projects Section 1B
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Inspection Summary Inspection on June 10 through July 24, 1989 (Reports No. 50-373/89017(DRP);
50-374/89017(DRP))
-Areas lnspected: Routine, unannounced inspection conducted by resident and regional inspectors of operational safety; surveillance; maintenance; Licensee Event Reports; ESF system walkdowns; Quality Assuranct Program Implementation; onsite followup of events at operating power reactors; onsite followup of written reports of nonroutine events at operating pcwer reactors; radiation occurrence reports; ALARA; and licensee self assessment capability; and engineering evaluation of CILRT temperature sensor changes.
Results: Of the ten areas inspected, there was one violation identified.
During this inspection period, there were nine Emergency Notifica', ion System (ENS) notifications, two of which were courtesy calls for potential Quality Assurance (QA) deficiencies with Main Steam Isolation Valve (MSIV) actuators identified by the licensee's QA organization. Two ENS calls pertained to problems with the Unit 2, Division III battery charger, one ENS call pertained to the second occurrence of the loss of the Unit 2 System Auxiliary Transformer (SAT) and the associated system isolations and Engineered Safety Feature (ESF) actuation, one ENS call pertained to a partial ESF of the Unit i reactor water cleanup system that resulted from the Unit 2 SAT event, one ENS call pertained to the High Pressure Core Spray (HPCS) system being inoperable because of its Emergency Diesel Generator (EDG) being inoperable, one ENS call 8900140037 s90003 I
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pertained to a dropped new fuel bundle, and one ENS call pertained to'an inoperable Static-0-Ring (SOR) switch on the Reactor Core Isolation Cooling (RCIC) system.
In addition, the licensee made two Technical Specification (TS) non 10 CFR 50.72, reports to the NRC of dead fish in the cooling lake.
The one violation that was identified during this inspection period dealt with a shipment of byproduct material to a vendor not licensed to possess byproduct material. During this inspection period, the modifications to the spent fuel pool to incorporate the use of high density racks was essentially completed.
The licensee also commenced receipt and storage of new fuel in preparation for the upcoming Unit I refueling / maintenance outage in September of 1989. During this inspection period, the licensee requested and was granted a Temporary Waiver of Compliance (TWC) for testing the Unit 2 Division I and II EDGs due to the Division III EDG being inoperable.
Relief from these testing require-ments had been available since 1984 (reference Generic Letter 84-15) but the licensee had failed to aggressively pursue this option.
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DETAILS 1.
Persons Contacted
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+Gi J. Diederich, Manager,_ LaSalle Station
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- W._R. Huntington, Technical Superintendent
- J. C. Renwick, Production Superintendent D. S. Berkman, Assistant Superintendent, Work Planning J. V. Schmeltz, ~ Assistant Superintendent, Operations J. Walkington,. Services Director
- T. A. Hammerich,. Regulatory Assurance Supervisor W. E. Sheldon, Assistant Superintendent, Maintetiance J. H. Atchley, Operating Engineer i
W. Betourne, Quality Assurance Supervisor M. G. Santic, Master Instrument Mechanic.
W. J. Marcis, Site BWR Engineering Supervisor l
- J. Spieler Quality Assurance
+W. Luett, Operational Lead for Health Physics
-+M. Friedman, Health Physicist
+D. Hieggelke, Health Physics Services Supervisor
+F. Rescek, Corporate Radiation Protection Director
+G. Myrick, Corporate Radiation Protection Staff J. Roman,- Resident Engineer, Illinois Department of Nuclear Safety
+ Denotes personnel attending the interim exit interview on July 5,1989.
- Denotes personnel attending the exit interview on July 28, 1989.
Additional'11censee technical and administrative personnel were contacted by the_ inspectors during the course of the inspection.
2.
Operational Safety Verification (71707)
a.
.The inspectors observed control room operations, reviewed applicable
, 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 for potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenance. The inspectors, by observation
.and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan.
This_ included verification that the appropriate number of security
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personnel were on site; access control barriers were operational; protected areas were well maintained; and vital area barriers were well maintained. The inspector verified the licensee's radiological.
protection program was implemented in accordance with the facility policies and prograr and was in compliance with regulatory require-ments.
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I b.
The inspectors performed routine inspections of the control room during off-shift and weekend periods; these included inspections between the hours cf 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 i
security personnel, shift supervisors and operators to determine if shift personnel were notified of the inspectors' arrivals onsite during off-shifts.
The inspectors determined that both licensed and non-licensed operators were attentive to their cuties, and that the inspectors'
arrivals on site appeared to have been unannounced. The licensee has implemented appropriate administrative controls related to the conduct of. operations. These include procedures which specify fitness for duty and operator attentiveness.
c.
On June 16, 1989, at approximately 5:28 p.m. (CDT), the licensee made a courtesy Emergency Notification System (ENS) phone call pertaining to the Unit 2 Main Steam Isolation Valve (MSIV) actuators on the 2A main steam line.
This concern involved both the inboard and outboard MSIV actuators. During a product Quality Assurance (QA) audit of the Ralph A. Hiller Company of Pittsburgh, Pennsylvania, the supplier of four (4) recently purchased MSIV actuators, QA program deficiencies were identified such that the quality of the product was questionable. Two (2) of the four actuators were installed on the A steamline and the other two were being held as spare parts. At 5:30 p.m., the licensee started to decrease power in preparation for isolating the affected steamline. At 9:05 p.m.
with Unit 2 at approximately 80% power, the operators closed the ZA outboard MSIV (2E21-F028A). This action was taken as a conservative administrative action pending further engineering evaluation.
On June 24, 1989, the licensee concluded the follow-up audit of the vendor and the analysis of the
. IV acteators that had been
installed on the A inboard and outboard MSIV's.
The licensee concluded that the vendor had some QA programmatic problems, but that the actuators were acceptable. On SundaJ morning, June 25,
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1989, at approximately 3:45 a.m., the licensee made a courtesy ENS phone tall informing the duty officer of the outcome of their investigation and that they were preparing to reopen the A outboard MSIV. At 4:00 a.m. the licensee reopened the 2A outboard MSIV.
I d.
On June 26, 1989, the licensee noticed approximately 20 dead fish in the cooling lake. On June 27, 1989, further inspection revealed a count of approximately 196 dead fish. The area had experiences a very warm weekend and both Units 1 and 2 had been operating at or near full power for over 100 days. Per Appendix 8 of the Technical Specifications for Unusual or Important Environmental Events, the licensee notified the NRC within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This notification will be followed up by a 30 day report.
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On June 28, 1989, during a routine inspection of the shad nets, another 90 to 100 dead fish were found. Again, the NRC was notified and the Department of Conservation was also notified. Subsequently, the temperature in the area decreased significantly and so did the cooling lake temperature.
e.
On July 15, 1989, at 9:19 p.m. (CDT), the licensee noted that the Unit 2 Division III (High Pressure Core Spray (HPCS)) battery chargers voltage and amperage were oscillating.
The licensee declared the Unit 2 HPCS system inoperable. At 10:05 p.m. the licensee cross-tied the Unit 1 and 2 Division III batteries and buses in order to supply Unit 2 loads, turned the Unit 2 battery charger off, and declared the Unit 1 HPCS system inoperable. At 10:50 p.m. the licensee made the required ENS notification.
The licensee investigated the cause of the fluctuations in voltage and amperage of the battery charger and determined that the cause was a bad phase A control board. The control board showed some signs cf overheated components. On July 16, 1989, at 12:10 p.m. the cross-tie between the Unit 1 and 2 Division III batteries and buses was removed and at 1:30 p.m. the Unit 1 HPCS system was declared operable. At E:35 p.m., after replacing the defective control board, the Unit 2 Division III battery charger and HPCS system were declared operable.
On July 17, 1989, at 5:45 p.m. (CDT), the licensee noted that the Unit 2 Division III HPCS battery chargers voltage and amperage were again oscillating. The licensee declared the Unit 2 HPCS system inoperable. At 6:30 p.m., the licensee cross-tied the Unit 1 and 2 Division III batteries and buses in order to supply Unit 2 loads, turned the Unit 2 battery charger off, and declared the Unit 1 HPCS system inoperable. At 7:35 p.m., the licensee made the required ENS notification.
Subsecuent to this event, the licensee replaced the B phase control board. After approximately 1/2 hour, the fluctuations returned. The licensee brought the vendor on site on the carning of July 18 to help with the investi-gation and repair. Over a period of several days, the licensee uncrosstied and recrosstied the Unit 1 and 2 Division III batteries and, in conjunction with the vendor, replaced various components and tried adjusting severai settings for the battery charger. On July 23, 1989, at 9:15 a.m., the licensee declared the Unit 2 Division III battery charger and HPCS system operable.
f.
On July 17, 1969, at 1:40 p.m. (CDT) while in the process of uncrating new fuel bundles for the upcoming Unit 1 refueling outage, one of the new fuel bundles fell out of its shipping container and landed on the refuel area floor.
The licensee had just completed inspecting the shipping container and verifying that the fuel bundle restraint was secured and had just uprighted i
l the container to a vertical position when the event occurred.
Shortly after uprighting the container the fuel bundle restraint was seen to fall from the container followed by the fuel bundle.
The bottom of the shipping container was approximately 4 to 5 inches off the floor when the bundle fell. The bundle was twisted
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out of shape but did not appear to have ruptured. The licensee took swipe surveys in the area of the bundle and could not find
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any evidence of contamination that would have come from the fuel
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bundle. At 2:35 p.m. the licensee made an ENS notification in accordance with 10 CFR 20.403.(a).(4).. This action was taken by the licensee because they believed the value of the fuel bundle to be in excess of $200,000 (the criteria for a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> report)
The licensee's investigation of the root cause of the event revealed that the shipping container had a cracked weld on a wall stiffener.
This allowed one side of the container to flex more than normal and veuld, when flexed, have allowed the fuel bundle restraint to come free. The licensee placed the damaged fuel bundle back in an undamaged shipping container and on July 24, 1989, shipped it and the damaged shipping container back to General Electric for inspection.
No violations or deviations were identified in this area.
3.
Monthly Surveillance Observation (61726)
The inspectors observed Technical Specification required surveillance testing and verified for actual activities observed that testing was performed in accordance with adequate procedures. The inspectors also verified that test instrumentation was calibrated, that Limiting Conditions for Operation were met, that removal and restoration of the affected components were accomplished and that test results conformed with Technical Specification and procedure requirements.
Additionally, the inspectors ensured that the test results were reviewed by personnel other than the individual directing the test, and that any deficiencies identified during the testing were properly reviewed and resolved by appropriate management personnel.
The inspectors witnessed portions of the following test activities:
LOS-RH-Q1 Unit 1 RHR (LPCI) and RHR Service Water Pump Inservice Test for Operational Conditions 1, 2, 3, 4 and 5 LIS-PC-403 Unit 2 High Drywell Pressure LPCS Initiation, RHR (LPCI Mode) Initiation, ADS Permissive, and RCIC Isolation Functional Test LIS-NB-102 Unit 1 Reactor Vessel Low Low Water Level (Level 2)
Primary and Secondary Containment Isolation Calibration
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LIS-NR-111 Unit 1 LPRM Flux Amplifier Gain Adjustment LOS-MS-MI Main Steam Isolation Valve-Leakage Control System Blower and Heater Operability Tests LOS-FP-W2 Diesel Fire Pump Weekly Operational Check LOS-DG-M3 IB(2B) Diesel Generator Operability Test
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On June 19, 1989, at approximately 9:05 a.m. (CDT), the licensee was performing special test surveillance LST-89-068, Unit 2 Reactor Core Isolation Cooling (RCIC) High Steam Flow Isolation Calibration, when L
Static-0-Ring (SOR) differential pressure switch 2E31-N013AA failed.
l Switch 2E31-N013AA controls the outboard containment isolation valve for the RCIC system and also the isolation of the steam supply for the RCIC turbine. This placed the unit in an eight (8) hour LCO time clock for one (1) containment isolation valve inoperable. The licensee made the ENS phone call at 10:30 a.m. (the licensee is required to report all SOR switch failures due to previous problems and history of SOR switches at La'Salle).
At the time of this event, the Unit 2 High Pressure Core Spray (HPCS)
system was out of service, on a fourteen (14) day time clock, for replacement of the Emergency Diesel Generator's (EDG) generator. The licensee anticipated potential problems with the testing of the RCIC SOR switches and because of HPCS being ino)erable had replacements ready to be installed in the event a switc1 failed. The licensee replaced the failed SOR switch, calibrated it, and placed it back into service at 1:15 p.m. on June 19, 1989.
No violations or deviations were identified in this area.
4.
Monthly Maintenance Observation (62703)
Station maintenance activities of scfety related systems and components listed below 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 Technical Specifications.
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; and activities were accomplished using approved procedures and were inspected as applicable. Other items considered also included verification that functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; and activities were accomplished by qualified personnel. Additionally, the inspectors verified that 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 outstanding jobs and to assure that priority is assigned to safety related equipment maintenance which may affect system performance.
On June 20, 1989, at approximately 12:30 p.m., the Unit 2 A Turbine Driven Reactor Feedpump (TDRFP) was shut down and taken off line in order to lubricate the turbine to feedpump coupling and the control linkages. Due to the failure of the trip solenoid (SV-12) to trip the Unit l's TDRFPs in early May 1989, the licensee elected to disassemble and inspect the SV-12 solenoid valve on the 2A TDRFP.
This was successfully accomplished on June 21, 1989, with both the solenoid and valve being cleaned and functionally tentec. The 2A TDRFP was then returned to service.
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l Early on June 23, 1989, the Unit 2 operators informed the technical staff that the 2A TDRFP emergency governor lock out normal light would.not iMuminate when the lock out switch was returned to the normal m ition. This indicated that the emergency governor and trip dump valve were still isolated and would not perform their intended functions. The instrument mechanics calibrated the pressure switches used to activate the indicating lights.
Both switches were determined to be operable, but it appeared that one of the pressure switches was just short of tripping,.thus preventing the normal light from illuminating. ' Pressure' gauges were installed in place of the pressure switches and the lock out test performed again. The pressure gauges revealed that the oil pressure did not-drop to its expected value when vented.
l The inspector observed portions of the removal of the cylinder block L-which contained the lock out piston. Mechanical Maintenance noted that the lock out piston was bent and dirty. After cleaning and-straightening the piston, the cylinder block was reassembled and tested. The normal light still would not illuminate. The cylinder block was.again disassembled, this tire the mechanics were extremely thorough in their cleaning of the cylinder block oil parts. A temporary supply:of oil was then introduced to the cylinder block to visually verify that the oil could pass through the openings.
The entire assembly was reassembled and retested.
This time the normal light indication was received in the control room.
The lock out test was performed again and revealed that the trip dump i
valve would not trip. The mechanics installed a temporary line from the discharge side.of the trip dump valve (SV-6) to the oil sump.
'When the solenoid was activated, no oil was discharged, indicating a problem with the solenoid. The SV-6 solenoid was removed and a manual gate valve was temporarily installed while the lock out test was
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performed again. The lock'out test was performed successfully. A new SV-6 solenoid valve was installed and satisfactorily tested prior to returning the 2A.TDRFP to service.
The inspector had observed several portions of this maintenance effort.
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Because of the problems the licensee has exhibited concerning the l
TDRFP trips, the resident inspectors will follow any upcoming TDRFP surveillance and/or problems pertaining to trip functions of the TDRFP.
No violations or deviations were identified in this area.
5.
Licensee Event Reports Followup (90712, 92700)
Through direct observations, discussions with licensee personnel, and. review of records, the following event reports were reviewed to determine that deportability requirements were fulfilled, immediate corrective 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 inspectors. Based on this review it was determined that the events were of minor safety significance, did not represent progran deficiencies, were properly reported, and were properly compensated for. These reports are closed:
374/89009-00 - Reactor core isolation cooling hi steam flow isolation switch failed diaphragm.
373/89015-00 - Missed fire protection valve position verifications due to procedural error.
373/89017-00 - Failure of 0 Diesel Generator cooling water pump breaker due to internal pitted contacts.
373/89018-00 - Reactor core isolation cooling isolation during warmup due to spurious high steam flow signal.
373/89020-00 - Failure of 250 VDC circuit breaker during ground isolation procedure rendering reactor core isolation cooling system inoperable.
373/89005-02 - Main steam high flow switch out-of-tolerance due to setpoint drift.
373/89009-01 - Reactor scram due to loss of main generator due to loss of Unit 2 system auxiliary transformer caused by inadvertent phase to ground fault during high wind conditions.
373/89019-00 - Charcoal laboratory sample results out of tolerance due to procedure deficiency.
373/89021-00 - Reactor core isolation cooling outboard isolation valve failure to open due to build-up of corrosion products on the stem nut.
b.
The following report of nonroutine events involved violations of regulatory requirements. These reports are considered closed.
Event closure is being tracked by the associated violation.
Appropriate cross references are provided.
373/89016-00 - Diesel Generator testing inadequacy and 2B Diesel Generator run solenoid failure (373/89010; 374/89010).
No violations or deviations were identified in this arec.
6.
ESF System Walkdown (71707)
The operability of selected engineered safety features was confirmed by the inspectors during walkdown of the accessible portions of the following systems. The following items were considered during the walkdowns:
verification that procedures match the plant drawings, equi? ment condi-tions, housekeeping, instrumentation, valve and electrical areaker lineup status (per procedure checklist), and verification that items including
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locks, tags, and jumpers were properly attached and identifiable.
The following systems were walked down this inspection period:
l Unit 2 High Pressure Core Spray Unit 1 Standby Liquid Control No violations or deviations were identified in this area.
7.
Quality Assurance (QA) Program Implementation (35502)
The inspector performed an evaluation of the effectiveness of the licensee's implementation of its Quality Assurance (QA) Program. The overall effectiveness of the licensee's QA program implementation is l
i directly related to the licensee's performance in specific functional disciplines, which is reflected in its operating history. Thcrefore, operating history is an indication of the effectiveness of the implementation of the QA program. The evaluation was conducted by review of the following:
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NRC inspection reports for the past 12 months b.
SALP reports for the past 2 years (SALP 6 and SALP 7)
c.
Outstanding regional Open Items List (OIL)
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Licensee corrective actions for NRC inspection findings e.
Licensee event reports for the past 12 months In' addition to the above review, the facility's recent operating history and the collective kncwledge of the resident and region based inspection staffs was also used in the evaluation process.
LaSalle's operating history has shown significant iinprovements in the number of ESF actuations and LERs attributable to personnel error:
ESF Actuations Personnel Error LERS 1984 120
1985
46 1986
18 1987
12 1968
9 1989 (May) 8
The number of LERs has also shown a decline:
LERs 1986
1987
i 1988
i 1989 (May) 26
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No negative performance trends were noted and based upon the review the inspector has concluded that the QA program at LaSalle is effectively implemented.
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No deviations or violations were identified in this area.
8.
Onsite Followup Of Events At Operating Power Reactors (93702)
a.
On May 1,1989, a radioactive material shipment from Westinghouse Electric Company _in Pennsylvania containing only an empty internally contaminated sea van arrived at the station. The sea van was on a flat bed trailer, designated as Radioactive Materials Empty Package i
UN 2908 and was labelled with Radioactive Label " EMPTY."
An arrival survey of the trailo" and the sea van was performed and the results indicated no loose or fixed contamination on external surfaces. The sea van was then transferred to the i
Refuel Floor (843' RB). The bottom of the sea van was smeared
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and the results were less than IK d m/100 cm.
The area of the
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trailer bed on which the sea van hat esided was also surveyed and smearable contamination ranging up to 20,000 dpm/100 cm2 was identified; an isotopic analysis indicated the primary isotope was cesium-137. The licensee attempted to decontaminate the tractor bed, but, due to the porous nature of the wood, the decon efforts were only minimally effective. As a result, the contam-
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inated wood was removed from the trailer and disposed of as radioactive waste. The truck was tnen released.
The licensee discussed this matter with the inspector on May 2, 1989. The inspector reviewed the shipping papers and licensee survey and decontamination results, then forwarded this information, and his findings, to Region I on May 8, 1989.
b.
On June 9,1989, the licensee informed the NRC that, on the same day, a vendor located in California notified the licensee < hat two hydraulic actuators shipped to them by the licensee were contaminated. The vendor does not have a license to receive /
possess radioactive material. The licensee dispatched two health physicists (HPs) to the vendor site on June 10, 1989, to perform surveys and provide radiological protection assistance. The HPs identified three spots of fixed contamination on the two actuators ranging from 1000 dpm to 7000 dpm, and several spots of removable contamination ranging from 1500 dpm/100 cm2
to 2500 dpm/100 cm,
Surveys were also performed of benches, equipment, floors, general office areas and personnel; no contamination was found.
The HPs discussed with vendor personnel the survey results and radiological risks associated with the levels of contamination found. The components were returned to the licensee on June 12, 1989.
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During this inspection the matter was reviewed by the inspector.
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The licensee issued an ROR and performed an investigation of the circumstances which allowed the contaminated components to be transferred to an unlicensed facility.
The licensee found no radioactive material shipping papers accompanied these components nor were any unconditional release tags found with the packing material. Although the investigation revealed that the uncondi-tional release tags were probably on the components before they
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were shipped, the licensee could not be completely certain the surveys were performed because the survey results are reco"ded on:the unconditional release tags and the tags are not saved.
The transfer of radioactive material to persons unautN ized to possess-such material is a violation (373/88017-01; 374/38017-01)
of 10 CFR 30.41(a) requirements. This violation was the result of the licensee's fadlure to perform an adequate evaluation to determine that radioactive contamination was not present on the components.
On several occasions in 1988, the licensee identified numerous contaminated items outside the radiologically controlled area (RCA) but within their restricted area fence.
This matter was discussed in Inspection P.eport Nos. 373/88024 and 374/88023-03, and an unresolved item was opened concerning the licensee's resolution to prevent recurrence of this problem.
In that report the inspector indicated that attention should be given to ensuring that:
a better survey program for releasing material into uncontrolled areas be developed; the routine uncontrolled area survey program be strengthened; and that a review be made to ensure that material leaving the RCA is surveyed.
In response to these concerns the licensee took several corrective actions, which are documented in Inspection Report Pos. 373/88028 and 374/88028, and the unresolved item was closed. However, as a result of the incident concerning failure to perform an adequate survey of material sent to an unlicensed facility, it appears the corrective actions taken to ensure quality surveys for materials being unconditionally released were not totally effective. These matters were discussed at the exit interview and will be reviewed at a future inspection, c.
On June 12, 1989, at 8:54 a.m., the Unit 2 System Auxiliary Transformer (SAT) Fire Protection System initiated, resulting in the deluge of the Unit 2 SAT. Approximately 76 seconds later a fault occurred at the phase A bushing on the primary side of the SAT. The fault was detected by Trip System I as Phase A Differential Current High, and by Trip System II as Phase A to Ground. Oil Circuit Breaker > (OCB) 4-6 and 1-6 opened to isolate the SAT from the switchyard. The loss of power frcm the SAT resulted in the fast transfer of buses 252, 241Y, 242X, and 242Y, as designed, to the Unit Auxiliary Transformer (UAT).
Bus 243 was deenergized upon the loss of the SAT due to the 2B Diesel Generator (High Pressure Core Spray (HPCS)) being out of service for maintenance. The 2B Diesel Generator is the alternate power source for bus 243. The Division III battery was immediately open circuited, to prevent the batteries from discharging.
At 9:50 a.m., the licensee made the Emergency Notification System (ENS) notificat on on the loss J
d of the Unit 2 SAT, the reactor building ventilation isolation, and i
rhe automatic starting of the control room ventilation emergency j
make-up train. The 2B Diesel Generator was returned to service
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at approximately 10:00 a.m. and power to bus 243 was restored.
I With the 2B DG supplying power to bus 243, it was necessary to l
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arc damage _at the top and bottom of the bushing. The actuation i
of.the_ deluge system has been attributed to a spurious electrical signal,'possibly an electrical ground, which initiated the ystem.
f Maintenance personnel replaced the electrical parts, checked the system out and_ returned it to service. -The-licensee has reviewed the event and has not been able to detcrmine a definite cause for-the actuation. There have been no other occurrences of this kind at the site. The licensee does not plant on pursuing this event any further..
d.
On Jur.e 14, 1989, at approximately 12:00 p.m., the Unit 2 System Auxiliary Transformer (SAT) had just been returned to service following the replacement of the primary A phase bushing. At this time the 2B Diesel Generator (DG) was supplying ESF bus 243, since its normal source of power (SAT) had been out-of-service.
With the return of the SAT, preparations were underway to parallel the SAT-(grid) to bus 243 and the 2B DG, The synchronoscope between the grid and bus 243 was enabled, and the Nuclear Station Operator (NS0)' adjusted bus 243 voltage and frequency (via the 2B DG) until the grid and bus voltage were synchronized. The NSO then attempted to close the SAT feedbreaker (ACB 2432) to bus 243. The breaker failed to close. The NSO then placed the breaker control switch to the NORMAL-AFTER TRIP position and turned the synchronoscope off.
This action would normally remove the breaker closure permissive.
There are no automatic auto-close signals to this breaker.
At this point, Technical Staff assistance was requested. Breaker 2432 closing circuit voltages taken acrog the closing permissives (synchronoscope on, and 2432 handswitch in cbse) indicated no continuity between the handswitch contacts and the closing coil.
Technical Staff and Operating personnel then proceeded to the 2432 breaker cubicle to investigate further.
Physical inspection of the breaker revealed that it did not seem to be fully in the raised position. The breaker must be fully raised (racked in) in order for the breaker limit switches to operate properly. One of these breaker raised limit switchis, operates in the closure permissive circuit..This limit switch prevents breaker closure attempts with the breaker not racked in (raised).
It was determined by Technical Staff personnel that the breaker was not fully raised, hence the breaker raised limit switch was not physically closed preventing breaker closure. The closing and tripping fuses were removed, the breaker racked out (lowered), and racked back in, and the fuses re-installed. Closure circuit status was checked again, indicating the problem still existed. This breaker lower and raise procedure was repeated two additional times.
On the third attempt, the breaker seemed to fully raise to the racked in position. When the closing fuses were replaced, the SAT feecureaker to bus 243 unexpectedly closed.
ACB 2432 closure onto bus 243 immediately connected two separate sources of power (the grid and 2B DG) in an uncontrolled manner.
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Personnel in the control room did not observe any significant DG deviations from normal operation. The 2B DG did not trip, nor did its output breaker ACB 2433. The 2B DG continued to operate,
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loaded to 2200KW, for approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> following this event, The 28 DG was, subsequently shutdown due to a fuel oil leak.
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was.then suggested by the off-site Operational Analysis Department T
N (OAD) that an inspection of the ZB generator stator windings-before returning.the DG to service should be made. This inspection revealed that some stator windings had-shifted position'by approximately 1/4" to'3/8"'(maximum). Resistance checks.taken
were. satisfactory. At 6:15 a.m., on June 15, the HPCS EDG had not been returned to operable status so the licensee in accordance with the~ Technical Specifications declared the HPCS system inoperable and entered:the Technical Specification action statement which requires.that the~HPCS system be returned to operable status within 14 days'or commence shutdown of Unit 2.
The licensee made the-required ENS notification at 6:50 p.m. on June 15, 1989.
LaSalle Special Test LST-89-066, Unit 2 Division III SAT Feedbreaker ACB'2432 Troubleshooting, was performed to determine i
the cause of the breaker auto-closing. A bent stab was found
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during the' performance of.this test. The breaker with the bent stab was-then removed from the SAT feed breaker cubicle. The breaker from the'2B DG output breaker /CB 2433 cubicle was'tnen racked into the SAT feed breaker cubicle. Prior to raising the.
breaker, the secondary stabs were inspected for damage. Once the breaker _was raised, continuity checks with the control circuit fuses removed were performed to verify that no:short circuit paths to the closing coil existed. The SAT feed breaker was then closed to re-eriergize bus 243.with no abnormalities.
Although the damage.to the generator appeared'to be minor, the licensee decided to replace the generator._ Because.the generator replacement made the-HPCS~ system inoperable, on June 16, 1989, the licensee requested a. Temporary Waiver'of Compliance from the LaSalle Unit 2 Technical Specification to test the remaining DGs every 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> if the Unit 2 8 DG is inoperable. The NRC staff agreed to grant a Temporary Waiver of Compliance. This waiver was effective beginning June 16, 1989, and would remain effective unti1' issuance of the Technical' Specification amendment took place. The waiver was
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consistent with the NRC' position contained in Generic Letter 84-15 which states that fast start. testing of DGs should be reduced so that mechanical stress and wear in DG engines is minimized and reliability is not diminished. The licensee further agreed that they would submit a supplement to the existing Technical Specification amendment submittal dated March 16, 1989, in response to GL 84-15 by June 23, 1989, that would eliminate these unnecessary testing requirements and that would also address the testing requirements for all five diesel generators for both units. The NRC staff informed the licensee's management that its submittal in response to GL 84-15 for a Technical Specification change was deficient in that it failed to provide the changes that were required by this waiver. Had the appropriate changes been' identified in their submittal, this Waiver could have been avoided.
The replacement generator used was the old 2A DG generator that i
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had been rebuilt in 1984.
Preventative maintenance under the supervision of the generator vendor (Ideal Electric) was performed on the rebuilt generator prior to installing it on the 2B DG.
All of the work and testing performed on the 2B DG was documented in LST-89-074, 2B DG Return to Service Following Generator Replacement. The post replacement testing lasted approximately 6d hours. LST-69-074 also documented all of the Tecnnical Specification surveillance requirements that were performed and which surveillance and/or special tests covered them.
General Electric (G.E.), the breaker vendor, was contacted by the licensee on the subject of the bent secondary stab.
G.E.
stated that these stabs should be inspected prior to raising the
breaker, and that a protective cover should be placed on the
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stabs rhen the breaker is lowered and removed from the cubicle for extended periNs of time, or when maintenance is being performed on these breakers.
G.E. performed a site inspection of the SAT feed breaker and concurred that the cause of the auto-closure was the bent stab. The licensee's procedures for the feed breaker currently do not have steps to inspect for bent stabs or for installing a protective cover. Action Item Records (AIRS) have been written to revise and track the revisions to the licensee's procedures to include the steps necessary to perform the stab inspection and to install the protective cover.
The consequences of the event were minimal with respect to plant
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safety. This event, however, damaged a major piece of plant equipment. The HPCS system was declared inoperable as a result of this event. This placed Unit 2 in a 14 day timeclock, which would have expired on June 28, 1989. The licensee changed the status of the HPCS system from inoperable to degraded on June 27, 1989, at 5:30 a.m. and subsequently declared it fully operable. The Reactor Core Isolation Cooling System (RCIC) was fully operable as an alternate high pressure injection system.
Division I and II Emergency Core Cooling Systems (ECCS) were also fully operable.
One violation was identified and no deviations were identified in this area.
9.
Onsite Followup Of Written Reports Of Nonroutine Events At Power Reactor Facilities (92700)
Pursuant to a memorandum from the Region III Director, Division of Reactor Projects, dated May 1, 1989, and titled, Recent Operational Events, the resident inspectors have, during their routine walkthroughs of the facility, been observant to the licensee's administrative and physical controls of explosive materials. These materials include items such as pressurized hydrogen and oxygen cylinders. The inspections not only included storage and handling, but also were reviewed to ensure that these external hazards would not affect safety related components, equipment or facilities.
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Since the issuance of the memorandum only two occurrences have been I'
noted at the site. The first one was an oxygen bottle being temporarily stored in a " Nitrogen Only" storage area in the reactor building. The second occurrence was considered to be more serious, a hydrogen bottle was temporarily stored with two oxygen bottles. These gas bottles had been brought into the Unit 2 reactor building and were to be used as replacements in the post LOCA (loss of coolant accident)
Containment Monitoring System.
One item of concern was that these bottles had been temporarily stored in the rack for a longer duration than expected. A second concern was that hydrogen was stored with oxygen. The resident inspectors brought these observations to the attention of the site fire marshall and to plant management. The storage problem was immediately addressed and corrected. The licensee also investigated this concern and re-emphasized the sites'
procedures and policies, pertaining to pressurized gas bottles to the licensee's staff.
The residents, during their inspections, will continue to monitor the licensee's use, handling, and storage of compressed gases and explosive materials on sits.
N deviations or violations were identified in this area.
10. Radiation Occurrence Reports (RORs) (83750)
The licensee trends and categorizes RORs by work group and type of occurrence under the major classifications of external dose control, internal dose ind surface contamination, administrative controls, and others. RORs are generally written for violations of station radiation control standards and procedures and any significant action cr situation inconsistent with the ALARA philosophy.
The inspector reviewed RORs generated pursuant to station procedure LRP-ll50-1 for 1988 through the first quarter 1989.
During this period the licensee identified about ten incidents involving liquid spills which caused floor and area contamination. Several of the spills caused significant contamination control problems inside and outside the radwaste building. Most of the spills occurred in the radwaste building; four were caused by tank overflow. The inspector informed the licensee that this number of contaminated spills resulting in contamination control problems and causing unnecessary personal exposure ap, neared excessive. As a result, the licensee performed a review of the problem and found that most of the spills occurred during outages when water is transferred to support outage activity and that the major causes were poor planning, poor communication, personnel error (iack of training), mechanical failures, and system design problems.
This matter was discussed at the exit meeting and will be further reviewed at a future inspection (0 pen Item 373/89017-02; 374/89017-02).
During this period the licensee also identified several incidents concerning 'mproper High Radiation Area (HRA) controls. The events involved HRAs found unsecured / unattended, lost HRA keys, and ladders /
scaffolding used in areas which could allow easy access to a HRA.
- lone of the events involved HRAs in excess of 1000 mrem / hour. Although
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corrective actions were taken for each individual event, the licensee determined that an underlying cause for most of the events was poor worker understanding of HRA controls. As a result, increased training on HRA controls will be included in Nuclear General Employee Training (NGET) and yearly retraining. The inspector informed the licensee that continuation of HRA control problems is unacceptable and that stronger actions by the licensee may be required. This matter was discussed at the exit interview and will be further reviewea during a future inspection (0 pen Item 373/89017-03; 374/89017-03).
The inspector also reviewed other RORs (thought to be significant)
concerning failure to follow radiation protection procedures and good health physics practices.
On each occurrence it appeared the licensee took adequate corrective actions and strong disciplinary measures.
No violations or deviations were identified in this area, however, two open items were identified.
11. ALARA (83728)
During a meeting between the licensee and NRC Region III personnel to discuss ALARA activities, the licensee stated that the 1989 projected person-ram goal was about 1000 person-rem. This goal was documented in Inspection Report Nos. 3/3/88028 and 374/88026 along with the results of the meeting.
In a letter from the Nuclear Licensing Administrator to Region III, dated May 23, 1989, the licensee indicated that the projected dose for 1989 would be approximately 1650 person-rem based on historical data for planned work, and the established goal was about 1400 person-rem. During this inspection it was noted that to date, the station dose is running slightly below the projected dose and that significant licensee attention / effort has been given to exposure control for routine and future outage activities. This matter will be reviewed further during future inspections (0 pen Item 373/89017-04;374/89017-04).
No violations or deviations were identified in this area, however, one open item was identified.
12. Licensee Self Assessment Capability (40500)
During the SALP 8 period (March 16, 1988 - June 30, 1989), the inspectors attended several of the various meetings that the licensee holds as part of their self assessment function. These included the Event Frequency Reduction meetings, Error Free meetings, and Onsite Review meetings.
As part of the review of this area, the inrg etors, on a sample basis, verified that the applicable requirements of the Technical Specifications were met with respect to the composition
.ies, and meeting frequency of the committee. Plant management involwraenc was evident during those meetings and in some instances the meetings included attendance by senior corporate management.
The inspectors also noted that during the SALP 8 period that the offsite and onsite nuclear safety organization met with licensee management every quarter and reviewed the effectiveness of corrective actions associated with nonroutine events.
The inspectors noted that identified issues were tracked and assigned to responsible
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individuals for action and that dates for corrective action response j
were assigned. However, it was also noted that individual accountability
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for meeting assigned completion dates was lacking and that extensions appeared to be routinely granted.
No violations or deviations were identified in this area.
13.
Engineering Evaluation of CILRT Temperature Sensor Change _s (70307)
Commonwealth Edison Company plans to replace the RTD senors used to
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r:easure containment temperature during containment integrated leak rate tests (CILRT) with ceramic thermistors.
Because of the few disadvantages that thermistors have when compared to platinum RTDs, such as nonlinearity, CECO purchased a limited number of the new detectors for trail tests which were conducted at the LaSalle Station.
On July 13, 1989, the ir.spector res.cwed the test instrumentation setup, instrument calibrations, and some of the data obtained. Based on observations and discussions with the licensee the inspector has no concerns regarding the licensee's plans to replace the RTDs with thermistors for future CILRTs. The licensee plans to document the results of their study justifying the change from RTDs to thermistors.
The inspector will review the documentation as part of the CILRT review for Quad Cities or LaSalle whichever takes place first.
No violations or deviations were identified in this area.
14. Open Items Open items are matters which have been discussed with the licensee, which will be reviewed further by the inspector, and which involve some action on the part of the NRC or licensee or both.
Three open items disclosed during the inspection are discussed in Paragraphs 10 and 11.
15. Exit Interview (00703)
On July 5, 1989, an interim exit interview was held to cover the scope and findings of the inspection of radiological controls and events. The inspectors also met with licensee representatives f
(denoted in Paragraph 1) throughout the month and at the conclusion of the inspection period and summarized the scope and findings of the inspection activities. The licensee acknowledged these findings.
The inspectors also discussed the likely informational contents of the inspection report with regard to documents or processes reviewed d
by the inspector during the inspection. The licensee did not identify any such documents or processes as proprietary.
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