IR 05000373/1990002
| ML20012C053 | |
| Person / Time | |
|---|---|
| Site: | LaSalle  |
| Issue date: | 03/09/1990 |
| From: | Hinds J NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III) |
| To: | |
| Shared Package | |
| ML20012C050 | List: |
| References | |
| 50-373-90-02, 50-373-90-2, 50-374-90-02, 50-374-90-2, NUDOCS 9003200018 | |
| Download: ML20012C053 (14) | |
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U.S. NUCLEAR REGULATORY COMMISSION
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REGION III
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Report Nos. 50-373/90002(DRP);50-374/90002(DRP)
Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18 Licensee: Commonwealth Edison Company Post Office Box 767 m"
Chicago, IL 60690 Facility Name:- LaSalle County Station, Units 1 and 2 h
Inspection At: LaSalle Site, Marseilles, Illinois L
_ Inspection Conducted: January 17 through February 28, 1990
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i Inspectors:
R. ' Lanksbury R. Kopriva D. Jones a
J. Smith
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Approved
J. M. Hinds,
., C ief MAR 0 91MD eactor Projects ection IA Date
Inspection Summary
Inspection from January 17 through February 28, 1990 (Report Nos.
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- 50-373/90002(DRP);- 50_-374/90002(DRP)).
Areas Inspected: Routine, unannounced safety inspection by the resident L
inspectors of licensee action on previously' identified items; operational l
safety; surveillance; maintenance; licensee event-reports; ESF: system i
l walkdowns; training; security; onsite followup of events at operating power reactors; radiological protection; temporary instructions; allegation
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. followup; and report review.
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'Results: Of the thirteen areas inspected, no violations were identified in i
L twelve areas.
In the remaining area, one violation was identified (see
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paragraph 4.c) regarding adherence to Technical Specifications.
The licensee maintained their increased efforts on housekeeping, radiological controls,.
and engineering support, which has significantly helped them prepare for the
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u) coming Unit 2 outage. Concerns were encountered pertaining to operations as tle licensee was confronted with the situation of commencing a unit shutdown perTechnicalSpecification(TS)3.0.3. The licensee's interpretation of TS 3.0.3 was-found not to be consistent with Region III's interpretation. The l
l concern has now been resolved.
L An allegation was received (see paragraph 13) concerning the safety significance of the reuse of structural steel bolts in a strut.
Records were reviewed and the results indicated that the old bolts had not been reused.
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The violation issued in this report was for not adhering to Technical Specifications (TS). A turbine bypass valve surveillance was missed which caused the licensee to declare the hypass valves inoperable. The TS requires that if the reactor power is greater than 25% and there are less than 4 hypass valves operable that within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> the licensee must increase the minimum critical power ratio (MCPR) limit. The licensee had not raised the MCPR limit which violated the TS. Due to the fact that this violation was discovered by the licensee and appropriate corrective actions were taken, the violation will not require a response.
There is one unresolved item (see paragraph 9) pertaining to a security concern.- This item will be reviewed during the next safeguards inspection.
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DETAILS 1.
Persons Contacted
- G. J. Diederich, Manager, LaSalle Station
- W. R. Huntington, Technical Superintendent
- J. C. Renwick, Production Superintendent
J. V. Schmeltz, Assistant Superintendent, Operations
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- J.-Walkington, Services Director T. A. Hammerich, Regulatory Assurance Supervisor i
W. E. Sheldon, Assistant Superintendent, Maintenance
- W. Betourne, Quality Assurance Supervisor R. Morley, Security Administrator l
- P. Wisniewski, Regulatory Assurance
- J. Roman, Resident Engineer Illiaois Department of Nuclear Safety
- Denotes personnel attending the exit interview on February 28, 1990.
Additional licensee technical and administrative personnel were contacted by the inspectors during the course of the inspection.
2.
Licensee Action on Previously Identified Items (92701)
(Closed) Violation (373/88022-04;374/88021-07): Did not accomplish an activity affecting cuality in accordance with the approved procedure.
The licensee revisec procedure LAP-850-3, Service Information Letters (sit's), to change the time limits for SIL implementation and to incorporate the use of Action Item Records (AIR's) to track the review of SIL's. 'The current procedure simplifies and clarifies the instruc-tions for processing, filing, and responding to SIL's sent to the LaSalle Station. The licensee reviewed and updated the SIL notebook with a list of all applicable SIL's that had been sent to the station by the vendor.
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Personnel involved in the processing of SIL's were given training on the i
revised LAP-850-3.
In addition the personnel were counseled on the importance of adhering to procedures.
No violations or deviations were identified in this area.
3.
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
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for potential fire hazards, fluid leaks, and excessive vibrations, and to verify that maintenance requests had been initiated for equipment in need of maintenance.
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b.
The inspectors performed routine inspections of the control room l
during off-shift and weekend periods; these included inspections i
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between the hours of 10:00 p.m. and 5:00 a.m..
The inspections were conducted to assess overall crew performance and, specifically, control room operator attentiveness during night shifts.
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inspectors also reviewed the licensee's administrative controls regarding " Conduct of Operations" and interviewed the licensee's
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security personnel, shift supervisors and operators to determine if shift personnel were notified of the inspectors' arrivals onsite during off-shifts.
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The inspectors determined that both licensed and non-licensed operators were attentive to their duties, 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 January 29,1990, at 8:15 p.m. (CST), an operatio'i's person found the oil cap missing and no visible oil level in the sight glass of the Unit 1 A Emergency Diesel Generator (EDG) governor. When the
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shift engineer was notified that the governor oil level could not be determined, the Unit 1 A EDG was declared inoperable.
Per the Unit 1 Technical Specifications (TS), the licensee also declared the Unit I hydrogen recombiner inoperable due to the fact that the Unit 1 EDG is the emergency backup power source for the Unit 1 hydrogen recombiner. On January 29, at 3:25 a.m., the licensee had declared the Unit 2 hydrogen recombiner inoperable because the Unit 2 B Residual Heat Removal (RHR) system was out of service.for environ-mental qualification inspection, and the RHR system supplies cooling for the hydrogen recombiner.
Because both of the recombiners were declared inoperable, the licensee placed Unit 2 in TS 3.0.3 in which the licensee has I hour to correct the situation or commence a shutdown of the. unit. At 9:15 p.m., the licensee commenced preparations to shutdown Unit 2.
The shift engineer decided to pursue getting.the Unit 2 B RHR system back in service since they did not know at that time how long it would take to get the Unit 1 L
A EDG operable. The RHR system was run in full flow test per L
operating procedure LOP-RH-13, Suppression Pool Cooling Operation.
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At 9:40 p.m., the Unit 2 B RHR system was declared operable and TS 3.0.3 was exited.
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An Equipment Operator (EO) obtained the correct oil for the Unit 1 L
A EDG governor and added approximately 10 to 16 ounces of oil to the governor to bring the level to the top of the mark on the sight glass. The E0 noted that after having added 4 to 5 ounces of oil to the governor, he saw the oil level back within the level of the sight glass. The Electrical Mechanics (ems) installed a replacement sight glass cap.
The EDG was started at 10:30 p.m., and loaded at L
10:33 p.m. for a 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> operability run. At 11:00 p.m., the i
licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> Emergency Notification System l
(ENS) call pertaining to the inoperability of both hydrogen l
recombiners. After reviewing the paperwork and observing the oil i
level in the Unit 1 A EDG governor sight glass not decreasing, the l
licensee unloaded and shutdown the Unit 1 A EDG at 12:00 a.m. on January 30, 1990. The Unit 1 A EDG was declared operable at 1:00 l
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A special log was initiated to check the Unit 1 A EDG governor-
oil level once per shift until a procedure change to the E0 rounds-package could be made.
The technical staff system engineer, upon reviewing the event,
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determined that the Unit 1 A EDG was never inoperable based on the
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L amount of oil it took tu refill the governor, and the fact that the L
EDG did not oscillatr when the governor was tested.
If sufficient oil had leaked from t.he governor to make the EDG inoperable, air
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I would have been in tl3 governor, which would have caused the EDG
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speed to oscillate w!.en running.
The root cause of the event has been attributed to a slow oil leak on the EDG governor that leaked oil over a period of a month and a half in the amount of approximately 10 ounces (amount required to return the level to mid-sightglass).
The oil was leaking out the compensation. needle valve cover plug, which failed to seat following the last governor
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oil flush performed in December of 1989. The cause of the seating failure appeared to be the copper washer at the seating surface of the cover plug failing-to seal when the plug was replaced. The EM foreman stated that the old washer was reused after the governor flush, which could have caused it to leak.
Upon review of the event, the licensee concluded that they should havebeeninTechnicalSpecification(TS)3.0.5versusTS3.0.3.
TS 3.0.5 is similar in its requirements of a unit shutdown, but it allows 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> prior to commencing the shutdown.
d.
On February 2,1990, at 8:45 p.m., a Security Guard reported that
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y there was a warm area in the Unit 1 Auxiliary Building and an odd
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l smell. The licensee investigated this and found a haze in the Unit 1 B Turbine Driven Reactor feedwater Pump (TDRFP) room.
Unit I was
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at 100% power at this time. The haze appeared to be caused by oil getting under-oil soak pads on the suction side of the pump casing and onto the hot pipe. The licensee decided to reduce power and i
place the_ Unit I Motor Driven Reactor Feedwater Pump (MDRFP) on line.
and take the IB TDRFP off line to allow the pipe insulation to be-
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removed and the oil cleaned up. The source of the oil was a leak at
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the inboard bearing of the TDRFP that had started approximately I week previously.
The licensee had been waiting until the weekend to reduce power to attend to repairs in the heater bay.and to make the -
l repair to the TDRFP. At 9:45 p.m., the MDRFP was started. As the-L insulation was removed from the IB TDRFP suction piping, small fires flared up as the oil soaked insulation was exposed to air. These
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were quickly extinguished using hand held dry chemical extinguishers.
The fire brigade was not dispatched and no off site assistance was required.
l On February 5,1990, the repairs to the IB TDRFP were completed and L
the MDRFP taken off line and the IB TDRFP placed back on line. No damage to the pump or piping was noted as a result of the fires.
e.
On February 13, 1990, at 4:45 p.m. (CST), the licensee experienced an Engineered Safety Feature (ESF) actuation when the B Control Room
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Ventilation (VC) B radiation detector fuses failed. The failure of
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the fuses automatically started the B Emergency Make Up (EMU)
control room ventilation train. Due to the fact that the A VC system was already in normal operation, the licensee placed the B
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emergency make up train fan in pull-to-lock (PTL). At 5:30 p.m.,
the instrument mechanics replaced the blown fuses on the B VC B radiation detector and restored the EMU fan to standby status.
l-The instrument mechanics performed a calibration on the B VC B radiation detector and no anomalies were noted. The B VC B i*
radiation detector was then declared operable, and the licensee has not noted any problems with the system since that time.
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At 5:55 p.m., the licensee made the required 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> ENS phone call pertaining to the failed fuses and automatic starting of the c
B EMU control room vent: 1etion system.
No violations or deviations were identified in this arca, i
4.
MonthlySurveillanceObservation(61726)
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The inspectors observed surveillance testing, including required Technical Specifications surveillance. testing, and verified for actual activities observed that testing was performed in accordance with adequate procedures. The inspectors also verified that test instru-mentation 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 Tecinical 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 activity:
LIS-NR-403 Unit 2 Average Power Range Monitor (APRM) Rod Block and Scram functional Test i
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On January 22, 1990, at 8:58 p.m. (CST), the licensee was performing instrument surveillance LIS-MS-305, Unit 1 Main Steam Tunnel High Area Vent Differential Temperature Main Steam Isolation Valve (MSIV)
Isolation Functional Test. TheInstrumentMechanic(IM)hadtagged r
the appropriate wires to be lifted during the surveillance and began to lift the lead from temperature differential switch TDS-1E31-N615A,
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Prior to lifting this lead, the IM had to move the wires from switch IE31-N601G out of the way.
In the process of moving the wires, one-of them (F2) came off and the IM immediately heard relays actuate.
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The IM proceeded to reland lead F2. The relay that actuated was for the Division 1 ambient temperature high isolation signal for the Reactor Water Cleanup (RWCU) system. The RWCU outboard isolation valve 1G33-F004 automatically closed, isolating the RWCU system which was followed by an automatic trip of the A & C RWCU pumps due to low system flow. The isolation signal was reset, and after confirming that lead F2 had been securely relanded and that no other causes were discovered for the isolation, the RWCU system was returned to service. The ENS call was made at 10:35 p.m.
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On February 1.1990 at approximately 6:22 p.m. (CST), the Unit 1 Reactor Core Isolation Cooling (RCIC) System received a high steam flow isolation signal. At the time of this event, Unit I was operating at 99% power. The licensee was in the process of returning the RCIC system to standby after completion of surveillance testing when the isolation occurred. The licensee reset the isolation signal.and continued to return the RCIC system to operability. At 8:58 p.m. the licensee made the required four hour ENS notification and at 10:30 p.m. the Unit 2 RCIC system was declared operable.
The licensee has theorized the cause of the isolation signal to be condensed steam trapped between the inboard and outboard steamline isolation valves running down the steamline when the outboard isolation valve is cracked open and running over one of the elbow taps for the high flow isolation signal causing that instrument to actuate. During the last refueling outage the licensee made a modification to the RCIC system.to valve out the reverse piped instrument line break detection sensors. Based on testing, it was believed that the sensors were causing the isolations to occur.
This was supplemented with a change to the operations procedures for shutting the system down and was expected to resolve the problem. The licensee has indicated that they have contacted General Electric (GE) for assistance in resolving this problem (the RCIC system is GE supplied) but that GE has not been of assistance.
The inspectors have noted that the RCIC system high steam flow isolations seem to be occurring only on Unit 1.
The licensee has not been able to explain this to date. The licensee is continuing to investigate this problem in an attempt to
. determine the root cause of the isolations and to develop an effective resolution.
ectors that the licensee notified the insp(TS) surveillance c.
On February 16, 1990, they had missed a required Technical Specification of the Unit 2 main turbine bypass valves on February 9.
TS 4.7.10.a requires that each bypass valve be cycled through at least one complete cycle of full travel every seven days. The licensee implemented this requirement with surveillance procedure LOS-TG-W1, Turbine Weekly Surveillance.
LOS-TG-W1 had last been done on January 31, 1990, at 2:45 a.m.
It was due again, in accordance with the licensee's surveillance schedule, on February 7 and would be considered critical (i.e. past the nominal TS time but within the TS 25% allowance) on February 8.
On February 6 Unit 2 scrammed.
Since the TS's only require the bypass valves to be operable when thermal power is greater than 25% the time clock for performing the surveillance ended. On February 8, Unit 2 was started up and at 9:00 p.m. on February 8 reached 25% power. At this time, the previous LOS-TG-W1 had exceeded the seven day plus 25% allowance and was no longer valid. Based on this, the turbine bypass valves were technically inoperable. TS Limiting Condition for Operation (LCO) 3.7.10.a.2 requires that with less than four operable bypass valves that within 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> the Minimum Critical Power Ratio (MCPR)
value is to be increased and, within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, the system is to be restored to operable status.
If this can not be
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I accomplished, reactor power must be reduced to less than 25% of rated within the following four hours. On February 9, at 4:15 a.m.
(CST), surveillance LOS-TG-W1 was completed and the bypass valves-were operable. However, in the interim the required LC0 action to increase the MCPR limit was not accomplished. The failure to comply withTS3.7.10.a.2isaviolation(374/90002-01)DRP)).
The missed surveillance was found by the licensee on February 15 when the surveillance coordinator, during a routine review of completed surveillances, noted it had not been done within the required time frame. The licensee's investigation found that the Unit 2 Shif t Foreman (SF) on the second shift on February 8 knew that the surveillance was due and critical per the surveillance schedule, which was not updated after the scram. At this time the licensee was in the process of performing the Unit 2 reactor startup in accordance with LGP-1-1, Normal Unit Startup. LGP-1-1, step F.12, states, " Increasing load after generator synchronization....
h. verify that LOS-TG-W1 has been performed....." The operators were aware that the surveillance needed to be performed but since LGP-1-1 does not specify when it has to be done, they were unaware that it needed to be completed prior to exceeding 25% power. The Unit 2 SF had gotten the LOS-TG-W1 procedure out to have it done but was waiting for an opportune time.. He stayed over a second shift with the. intentions of completing the surveillance, however, when the second shift ended the surveillance had still not been completed.
In his turnover to the oncoming SF, he indicated that the surveillance had not been done yet and needed to be completed.
He did not mention that the surveillance was critical. At this
)oint-the surveillance should have been completed since 25% power lad been achieved approximately 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> earlier. The offgoing SF did not recognize at the time that the TS for the bypass valves required this test prior to exceeding 25% power. During subsequent discussions with the individual, he did indicate that he was aware of-the requirement but that with all the work going on in starting the unit up it slipped his mind. A review of LGP-1-1 reveals that the requirement to perform LOS-TG-W1 does not specify that it must be complete prior to exceeding 25% power nor does it reference the TS.
In addition to the above, it was also noted in the licensee's investigation that the oncoming SF, after completing the surveillance on February 9, signed off its completion on the surveillance schedule and apparently did not note that the schedule indicated that the surveillance had been critical, and should have been completed on February 8.
In response to this event, the licensee has taken the following actions to prevent recurrence:
A change to LGP-1-1 is in progress to specify that LOS-TG-W1
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must be performed prior to exceeding 25% power if the surveillance is not current. This change will be issued prior to the next use of LGP-1-1.
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The SFs are required to identify on their turnover sheet all
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operating critical surveillances.
The SFs must discuss all operating critical surveillances at
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the shift briefing.
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The Shift Control Room Engineers (SCRE) will also review the
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operating surveillance schedule. The shift is to identify any operating critical surveillance.
Training on the operating surveillance schedule has been added
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to the on-the-job training for new SF.
This specific event is being discussed with all the operating
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crews as they come on shif t.
This action will be completed by April 13, 1990.
The inspectors have evaluated the actions taken by the licensee to date as well as the actions that are planned but not complete at this time and the proposed schedule for completion.
Based upon these actions, the inspectors have no further concerns and this violation (374/90002-01) is considered closed.
No deviations were identified in this area, however, one violation was identified.
5.
MonthlyMaintenanceObservation(62703)
Station maintenance activities of systems and components listed below,
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including safety-related systems, were. observed / reviewed to ascertain
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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
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removed from service; approvals were obtained prior to initiating the
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work; activities were accomplished using-approved procedures and were inspected as applicable; functional testing and/or calibrations were performed prior to returning components or systems to service; quality control records were maintained; activities were accomplished by qualified personnel; parts and materials used were properly certified; radiological controls were implemented; and, fire prevention controls were implemented. Work requests were reviewed to determine status of outstanding jobs and to assure that priority is assigned to safety-related equipment maintenance which may affect system performance.
portions of the following maintenance item were observed during the inspection period:
2A Reactor Building Closed Cooling Water (RBCCU) Pump Motor Replacement No violations or deviations were identified in this area.
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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 reportability requirements were fulfilled, immediate corrective
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action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specifications, a.
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 program deficiencies, were properly reportea, and were properly compensated for. These reports are closed:
373/89008-01 Setpoint Drift of Reactor Yessel Low Water Level (Level 2) Switch 373/89010-01 Setpoint Drift of Low Level Confirmed Automatic Depressurization System Permissive Switch 373/90001-00 Reactor Water Cleanup Isolation Due to Broken Thermocouple Lead During Surveillance Testing 374/89009-01 Reactor Core Isolation Cooling Hi Steam Flow Isolation i.
Switch Failed Diaphragm b.
The following report of non-routine events involved violations of regulatory requirements. Event closure is being tracked by the L
associated violation. These reports are considered closed.
L 374/89014-00 Primary Containment Isolation System Group 4 Isolation l
During Ground Isolation (Violation #373/2301-A, 374/2201-A)
374/89010-01 High Pressure Core Spray Inoperable Due to Division
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III Battery Charger Oscillations l
374/89011-01 Spurious Reactor Protection System Actuation Due to Unknown Cause l.
No violations or deviations were identified in this area.
7.
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 l-walkdowns:
verification that procedures match the plant drawings, equipment conditions, housekeeping, instrumentation, valve and electrical breaker lineup str.tus (per procedure checklist), and verification that items including locks, tags, and jumpers were properly attached and L
identifiable. The following systems were walked down this inspection period:
Unit 1A Emergency Diesel Generator Unit 2B Emergency Diesel Generator
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No violations or deviations were identified in this area.
8.
Training (71707)
The inspector, through discussions with personnel, evaluated the licensee's training program for operations and maintenance personnel to determine whether the general knowledge of the individuals was sufficient for their assigned tasks.
In the areas examined by the inspector, no items of concern were identified.
No violations or deviations were identified in this area.
9.
Security (71707)
The licensee's security activities were observed by the inspectors during routine facility tours and during the inspectors' site arrivals and departures. Observations included the security personnel's performance associated with access control, security checks, and surveillance activities, and focused on the adequacy of security staffing, the security response (compensatory measures), and the security staff's attentiveness and thoroughness. The security force's performance in these areas appeared satisfactory.
The inspectors, by observation and direct interview, verified that the physical security plan was being implemented in accordance with the station security plan except as noted below. This included. verification that the appropriate number of security personnel were on site; access control barriers were operational; protected areas were well maintained; and vital area barriers were well maintained.
The inspector identified a security concern pertaining to access control-and accountability of personnel. The inspector notified the licensee and the Region III safeguard's inspectors. This concern and the licensee's actions will be reviewed during the next safeguards inspection and will be tracked as an unresolved item (373/90002-01;374/90002-02).
No violations or deviations were identified in this area, however, one unresolved item was identified.
10. Onsite Followup of Events at Operating Power Reactors (93702)
On February 6,1990, at approximately 9:26 a.m. (CST), the Unit 2 reactor scrammed from approximately 100% power. The licensee was performing instrument surveillance LIS-NR-403, Unit 2 Average Power Range Monitor (APRM) Rod Block and Scram Functional Test, on the F APRM.
The instrument mechanic had tripped the F APRM, which provided a half-scram signal to the Reactor Protection System (RPS), when a spurious half-scram signal was received on the E APRM approximately 1.5 seconds later. This completed the RPS signals neeced to provide a reactor scram. The scram and scram recovery were routine. However, one control rod stopped at the 02 position.
Subsequent to the scram, water level dropped to a low of
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approximately -20" and then recovered to a normal ran The licensee made the required Emergency Notification System (ENS)ge.
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notification at 12:10 p.m.
- During the event there were several pieces of equipment that did not
. operate properly. During the initial manual start of the motor driven feed pump )it tripped on neutral over current (the second attempt was successful, the 2A circulating water pump tripped on C phase over current, dual position indication on the scram vent and drain valves was received when the valves were closed, the il bypass valve showed mid-position indication when it was full closed, and when the main generator field breaker opened the voltage regulator cycled between manual and auto instead of staying in manual.
The licensee completed their investigation into the scram. As part of this investigation, several tests on the APRM instruments were performed to duplicate the event and to detect any spurious signals. This attempt to duplicate the event was unsuccessful.
High speed recording equipment designed to actuate on a reactor scram indicates that the spurious high neutron flux signal lasted approximately 15 milli-seconds. The licensee repaired the equipment that malfunctioned and reviewed their forced outage work list for equipment that needed to be be repaired / replaced prior to restarting the unit and performed work as time allowed. The l
J licensee completed their onsite review and all equipment repairs by l
February 7 and commenced withdrawing control rods at 7:22 p.m. on February 7.
The main generator was placed on line at 1:25 p.m. on February 8.
The resident inspectors were on site during the event and arrived in the control room shortly after the scram. They also attended the licensee's l
review meetings of both the reactor scram and for the forced. outage work l
and followed the licensee's testing and investigation for the initiating cause of the event. During the scram recovery, the inspectors observed
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that the o)erators communication was good, procedures were being used, and that t1e control room was not congested with unnecessary personnel.
No violations or deviations were identified in this area.
i 11. Radiological Protection (71707)
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The inspectors verified the licensee's radiological protection program was implemented in accordance with the facility policies and programs and was in compliance with regulatory requirements.
During this inspection period, the licensee took additional positive steps to control the spread of contamination and to decrease the possibilit area (RCA)y of contaminated material exiting the radiation controlled The licensee has reduced the number of exit points from the
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RCA from six to three in order to increase control and mor tw ing of l
individuals and material coming out of the plant. During ounge periods this number may increase based upon need.
The licensee's efforts in reducing the number of personnel contaminations (PCs) and exposure also appear to have been very effective.
The j
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-licensee's 1989 goal for PCs was less than 350 with an actual total for the year of 193. This was a significant improvement over 1988 when the
. licensee had 529 PC events.
For 1990 the goal has been reduced to less than 190. The licensee appears to be on track to obtain their goal with the number of PCs standing at 10 as of February 28, 1990.
In the area of personnel radiation exposure, the licensee's 1989 goal was less than 1400
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man-rem with an actual total for the year of 1386 man-rem.
This was a significant improvement over 1988 when the year end total was 2462 man-rem.
For 1990 the goal has been reduced to less than 875 man-rem.
The licensee also appears to be on track to better this goal with a total exposure of 83.8 as of February 27, 1990.
No violations or deviations were identified in this area.
12.
Temporary Instructions (255104)
(Closed) TI 2515/104 - Fitness For Duty: Inspection of Initial Training Programs
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l The purpose of this instruction was to provide guidance for determining whether required training was being conducted to implement Fitness-For-Duty (FFD) program required by 10 CFR 26. This temporary instruction included three checklists that were to be completed after attending the licensee's FFD training for general employees, supervisors,
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and for escorts, respectively.
On December 5, 1989, the inspector attended one session of the licensee's onsite FFD training.
However, at that time the inspector did not have
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l this TI so that session was not inspected against.
On February 21, 1990, L
the inspector viewed video tapes made at one of the earlier training
sessions and used that as the basis for completirg the checklists. The completed checklists were provided to the-NRR Reactor Safeguards 8 ranch as requested in the TI. The deficiencies / weaknesses identified by the inspector in the licensee's FFD training were noted on thc checklists.
This TI is closed.
No violations or deviations were identified in this area.
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13. Allegation Followup (99014)
Allegation AMS No. RIII-89-A-0151 (Closed)
Allegation: An anonymous allegation was received by the NRC resident inspector on November 29, 1989. The alleger indicated that structural bolts used on Work Package No. 93011 had been reused. He indicated that he would call back during the week of December 4,1989, but did not.
Discussion: A review of the records for Work Package No. 93011 disclosed that the job included the removal and replacement of a structural steel strut which was held in place by eight bolts conforming to American Society for Testing Materials (ASTM) A-325. The strut is located in the drywell beneath the floor grating. Although American Institute of Steel Construction (AISC) does not permit the reuse of galvanized A-325 bolts, it makes such reuse optional at the discretion of the responsible
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engineer. The Laselle bolting specification (Tightening Mechanical and Structural Jointt, LMP-GM-7, Revision 3, dated October 7,1989) does not allow the reusr, of either galvanized or nongalvanized A-325 bolts.
The work package clearly identified the fact that the A-325 bolts were
not to be reused.
In addition, the operation was signed off by the foreman of the job as being satisfactorily completed.
Documentation confirms that eight new A-325 bolts were issued for use on this job at a time when they would have been necessary. All of the available evidence points to the replacement of the A-325 bolts with new bolts.
Inspection of the installation would be unlikely to disclose any evidence to the contrary, even if the bolts were reused.
Finding: This allegation was not substantiated. There are no tangible e
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indications that the bolts were reused and no means by which the alleger can be contacted.
-No violations or deviations were identified in this area.
14. Report Review (90713)
During the inspection period, the inspectors reviewed the licensee's
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Monthly Operating Report for January.
The inspectors confirmed that the information provided met the requirements of Technical Specification 6.6. A.5 and Regulatory Guide 1.16.
No violations or deviations were identified in this area.
15. Unresolved Items An unresolved item is a matter about which more information is required in order to ascertain whether it is an acceptable item, an open item, a
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deviation, or a violation. An unresolved item disclosed during this inspection is discussed in Paragraph 9.
16. Exit Interview (30703)
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The inspectors met with licensee representatives (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 by the inspector during the inspection.
The licensee did not identify any such documents or processes as proprietary.
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