IR 05000298/1989032

Insp Rept 50-298/89-32 on 890901-30.Violation Noted Re Inadequate Procedure for HPCI Turbine Stop Valve.Major Areas Inspected:Monthly Surveillance & Maint Observations,Part 21 Repts,Ie Bulletin 88-007 & Info Notices

ML19327B367
Person / Time
Site:	Cooper
Issue date:	10/20/1989
From:	Bennett W, Constable G, Madsen G, Greg Pick NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML19327B365	List: IR 05000298/1989032 ML19327B364
References
50-298-89-32, IEB-88-007, IEB-88-7, IEIN-88-035, IEIN-88-35, NUDOCS 8910310030
Download: ML19327B367 (15)

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APPENDIX'

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U.S. NUCLEAR REGULATORY COMMISSION

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REGION IV

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NRC Inspection Report:

50-298/89-32 Operating License:

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Docket: 50-298 l

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Licensee: Nebraska Public Power District (NPPD)-

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P.O. Box 499

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Columbus, Nebraska 68602-0499

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Facility Name:

CooperNuclearStation(CNS)

Inspection At:

CNS, Nemaha' County,, Nebraska Inspection Conducted: September 1-30, 1989

' Inspectors:

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3. A. Pic Res ident Inspector, Project Section C, Date Division Rea : tor Projects

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W. R. Bennett, Senior Resident Inspector Project Date t

Section C, Division of Reactor Projet *.s

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' G. L. Madsen, Project Engineer, Project Section C, Date

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Division of Reactor Projects L

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Approved:

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G. WConstable. Chief, Project Section C, Division Date

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of Reactor Projects

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Inspection Sumary Inspection Conducted September 1-30, 1989 (peport 50-298/89-31)

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Artes Inspected: Routine, unannounced inspection of operational safety

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l vertrication, monthly surveillance and maintenance observations, engineered F

safety features walkdown, and followup of previously identified items,

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10 CFR Part 21 reports, IE Bulletin 88 07, and Information Notices, i

Results: Within the attas inspected, one noncited violation was identified in paragraph 4 for an inadequate procedure. The licensee responded promptly and adequately to the concerns of IE Bulletin 88-07. Control room response to an automatic scram was excellent. A walkdown of the instrument air system i

cenonstrated a satisfactory ongoing as-built program with some minor problems identified.

Engineering evaluations for the root cause of the scram and of the

' anomalies during the scram were conservative and thorough.

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DETAILS

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persons' Contacted f

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Principal Licensee Employees

• J. M. Meacham, Senior Manager of Operations-

• J. R. Ullmann. Supervisor Configuration Management

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• E. M. Mace, Engineering Manager

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• R. L. Bellke, Acting Radiological Manager

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• R. A. Jansky, Outage and Modifications Manager

• G. E. Smith, Quality Assurance Manager

• R. Brungardt, Operations Manager

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• H. T. Hitch, Plant Services Manager s

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• R. L. Gardnor, Maintenance Manager

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• H. A. Jantzen. Instrument and Control,(I&C) Supervisor l

• G. R. Smith, Licensing Supervisor

• L. E. Bray, Regulatory Compliance Specialist

• C, M. Estes, Management Trainee

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• Denotes those present during the exit interview conducted on i

October 4, 1989.

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The inspectors also interviewed other licensee employees and contractors

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during the inspection period.

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2.

Plant Status

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The plant operated at essentially 100 percent power until September 28, 1989.

On September 28 at'11:36 a.m., the reactor scrammed due to an

'N electrohydraulic (EH) system lockout.

The reactor was taken critical on.

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l September 30 at 7:56 a.m. and was synchronized to the grid at 7:14 p.m.,

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Operational Safety Verification (71707)

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The inspectors observed ope ational activities throughout the inspection v

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period.

Control room activities were observed to be well controlled.

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Proper control room staffing was maintained and professional conduct was

continuously observed.

Discussions with operators catermined that they i

<;were cognizant of plant status and understood the importance of, and l

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reason for, each lit annunciator.

The inspectors observed selected shift

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' turnover meetings and noted that information concerning plant status and

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planned evolutions was communicated to the oncoming operators.

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On September 28, 1989, at 11:36 a.m. (CDT), the reactor scrammed from'

i 100 percent power on low level EH fluid lockout.

The EH fluid lockout

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generated a turbine control valve fast closure and sub;equent reactor

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trip.

All safety systems responded as expected with the exception of four

anomalies described later in this report.

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The licensee initially developed a list of all credible causes of the reactor scram. The engineering staff did a thorough job of evaluating i

each susp>cted cause and eliminating each cause except for spurious low EH

fluid level switc5 operation. 3he most probable causes of the spurious

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low level switch operation were :ietemined to be vibration due to

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Sperating equipment and inadvertent mechanical agitation.

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wo to three minutes prior to the reactor scram, the licensee had shifted

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from operating EH pump A to standby EH pump B, which may have caused the

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unloader valve to o rate abnormally, setting up vibrations in the low level switch. 'The teensee commenceo a search of the Nuclear Plant

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Reliability Data System (NPRDS) to detemine if similar problems had

'i previously been identified on Westinghouse turbines.

The NPRDS search

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identified a similar event which had occurred at North Anna Unit 1 in

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1984 The North Anna vibration problem was attributed to unloader

malfunctions caused by particulates in the EH fluid.

After review of the

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infomation related to North Anna Unit 1. the licensee contacted the

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Westinghouse digital electrohydraulic (DEH) control system expert. The

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DEH control system expert stated that only an actual low level or

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mechanical actuation of the low level switch, due to vibration or bumping,

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could have caused a low level lockout. The licensee conducted testing of

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t the EH system including repeated EH pump swapping in an attempt to repeat l

the problem. Similar vibrations and subsequent lockout signals could not

be achieved.

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Since no definite cause of the scram was detemined, the licensee

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1mplemented the following corrective actions to prevent a similar

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occurrence in the future. A vibration recorder was mounted to the DEH i

skid to monitor and trend vibrations and Special Order (50) 89-05 was l

1ssued stating that the DEH pumps are not to be shifted except for j

scheduled surveillances or emergency operations. Additionally, i

engineering was assigned longer-term corrective actions which consisted of

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evaluating preventive maintenance (PM) requirements for the DEH unloaders, evaluating the DEH reservoir level switches to a vibration resistant

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model, and evaluating the low level DEH fluid trip logic.

The four anomalies identified subsequent to the scram were:

The feedwater (FM) startup flow control valves did not automatically

open;

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l The low pressure (LP) steam supply valve to the reactor feed pump

l turbines did not automatically close; The reactor recirculation pump trip (RPT) occurred which was

initially unexpected; i

and the reactor equipment cooling (REC) Pumps C and D tripped during

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the fast bus transfer which accompanied the scram.

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.s The first two anomalies were caured by the failure of a common control a

r relay to actuate.

The licensee discovered a wire trapped between the control relay contacts while attempting to determine the physical condition of the relay.

The licensee suspects that the wire was routed in this fashion during the Control Panel B upgrade implemented during the 1989 refueling outage.

All other relays in the back of Control Panels A and B were vi:ually inspected with no other problems identified.

The licensee is investigating the problem and has committed to complete the root cause analysis and identify required corrective actions by October 31, 1989.

The RPT was caused by the anticipated transient without scram (ATWS) high

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pressure circuitry which also caused an alternate rod insertion (ARI)

scram.

The trip setpoint of 1060 113 psig was installed during the 1988 refueling outage.

The ARI/RPT was initially considered an anomaly, since its actuation during a scram from 100 percent power had not been previously experienced; however, since peak pressure reached 1084 psig, the licensee determined that the ARI/RPT was a normal occurrence.

The trip of REC Pumps C and D during a fast bus transfer was determined to be a normal occurrence.

The on-shift operating crew had not previously observed the condition and initially considered it offnormal.

As designed, the REC pump start circuit has a " seal-in" feature which drops out efter 15 milliseconds. When the " seal-in" feature times out, the REC pump start circuit will not cause an REC pump start.

A fast bus transfer takes approximately 100 milliseconds.

Therefore, due to operating characteristics of the equipment involved, the pumps will sometimes trip.

The possibility of having the REC pumps trip in this manner is noted in System Operating Procedure (50P) 2.2.65, " Reactor Equipment Cooling Water System," Revision 26, dated February 8,1988.

Tripping of the REC pumps

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was not-a safety concern as discussed in the Updated Safety Analysis

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Reporte The licensee issued 50 89-04 to specifically communicate to all operators the possibility of REC pump trips during fast bus transfers.

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Additionally, the licensee committed to provide an implementation schedule t

to NRC by October'31, 1989, for altering of the REC circuit logic.to I.

prevent such trips.

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Throughout the shutdown, the plant was maintained in a stable, hot standby

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configuration.

Because of thermal stratification, the temperature

't difference between the reactor vessel dome and the reactor vessel drain

{e exceeded the 145'F temperature limit for start of a recirculation pump.

The operators lowered reactor pressure to get within the temperature limitations for start of the second recirculation pump.

All surveillances required during an unscheduled shutdown were completed.

Surveillance

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b procedures with a frequency of 6 months were completed so that, if a

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problem occurred with these tests, the facility would not be placed in a

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limiting condition for operation.

Ten unscheduled shutdown maintenance items were completed.

These items included replacing the drywell floor

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drain sump (F1) pump bearings and limit switch adjustment on the inboard reactor sample valve.

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The reactor startup commenced at 4:41 a.'m.

(i'DT) September. 30, 1989, and

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criticality was achieved at 7:56 e.m.

The heatup and pressurization was j

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controlled and the turbine was synchronized to the grid at.7:14 p.m.

The heatup and pressurization were slow and carefully controlled as requested j

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by station management and specified in the night order leg.

The control rod withdraw sequence was utilized.

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Tours of accessible areas at the facility were conducted to confirm

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operability of plant equipment, including the fire suppression systei..s and'

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l other emergency equipment.

Facility operations were performed in k

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accordance with the requirements established in the CNS Operating License

and TS.

r The inspectors verified that selected activities of the licensee's

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radiological protection program were implemented in conformance with facility policies, procedures, and regulatory requirements.

Radiation

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and/or contaminated areas were properly posted and controlled.

Radiation

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l work permits contained appropriate information to ensure that work could t

be performed in a safe and controlled manner.

Radiation monitors were

properly utilized to check for contamination. On September 27, 1988, the L

inspector observed a health physics technician determine the type and

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verify the location of contaminates on an individual's clothing.

Proper precautions were taken to control further spread of the contamination.

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The. inspectors observed security personnel perform their duties of

vehicle, personnel, and package search.

Vehicles were properly authori7ed

and escorted or controlled within the protected area (PA).

The PA barrier i

had adequate illumination and the isolation zones were free of transient material.

Site tours were conducted by the inspectors to ensure that

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compensatory measures were properly implemented as required.

The PA

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barrier had adequate illumination and the isolation zones were free of transient material.

On September 8, 1989, the inspector observed a vital y

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area door locking mechanism changeout in accordance with security plan L

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. requirements due to a security employee termination, e

No violations or deviations were identified in this area.

Control of

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plant operations during the shutdown and while starting up was conservative.

The root cause determination for the scram, elimination of

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other potential causes of the scram, and evaluation and correction of the'

anomalies were thorough and indicated good engineering judgement.

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4.

Monthly Surveillance Observations (61726)

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The inspectors observed performance of and/or reviewed the following

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surveillance procedures (SP):

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SP 6.2.2.3.12

"HPCI Turbine Stop Valve Monitor Oil Pressure, and 1.

Supervisory Alarm Timer Calibration and Functional / Functional Test,"

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Revision 16, dated August 10, 1989.

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.On September 1, 1989, the inspector observed the performance of this

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i functional test of the high pressure coolant injection (HPCI) auxiliary

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oil pump low oil pressure sensor (HPCI-PS-2787).

The auxiliary oil pump e

',provides lubricating oil to the HPCI pump turbine when the main oil pump is not operating.

The pressure sensor stops the auxiliary oil pump when

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the lube oil header pressure reaches 85 psig and starts the pump at i

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30 psig.

A qualified I&C technician conducted the test in accordance with

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the procedure.

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Initially, the technician connected the volt-ohm-milliamp (V0M) meter f

across the wrong terminals.

The mistake was discovered when no movement t

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of-the V0M needle occurred as the test pressure was increased. After L

connecting the VOM to the correct terminals, the test was satisfactorily

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The procedure failed to provide sufficient guidance to the I&C technician for proper connection of test equipment.

This procedure j

inadequacy is an apparent violation of the requirements of 10 CFR 50,

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Appendix B, Criterion V.

This apparent violation was discovered by the j

inspector, but was corrected by the licensee prior to the end of the r

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i inspection period.. The. licensee added a step to clarify where the VOM was

to be connected prior to the end of the inspection period.

The licensee

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committed to review the other I&C procedures by October 31,'1989, to

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determine if similar situations exist.

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A Notice of Violation for this violation is not being issued because tho l

criteria of.Section V. A. of the NRC Enf orcement Policy were niet, t

.SP b.2.2.'3.11. "HPCI Gland Seal Condenser Hotwell level Calibration and i

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Functional / Functional Test," Revision 13, dated September 9, 1988.

On September 1, 1989, the inspector observed the performance of this

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functional test of the HPCI gland seal condenser hotwell level switches initiation logic.

Proper communications were established with the control

room and good radiological practices were observed.

The level switches

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actuated as specified in the procedure, j

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SP 6.2.2.1.10, "4160 V Buses IF and 1G Under-Voltage relays and Relay Timers Functional Test," Revision 14, dated August 31, 1989.

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-This surveillance functionally tests both the first and second levels of undervoltage (UV) relay' and relay timer actuations for 4160 Vac critical.

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switchgear Buses IF and IG.

The inspector observed the test conducted on

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September 8, 1989.

The undervoltage protection for Buses IF and IG was

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altered during the 1989 refueling outage to allow each bus to shed loads

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for equipment protection while being powered by the EDGs.

The setpoint i

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for Time Delay Relay 27X16/1G was 2511.5 seconds which allowed sufficient

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time for all safety-related loads to sequence onto the bus.

After Relay

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27X16/1G times out, the load shed circuitry is reenabled.

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During the performance of this surveillance, the Time Delay Relay 27X16/10

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actuation exceeded the 26.5 second maximum time specified in the

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procedure.

This was in the conservative direction because more time was

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allowed for the bus voltage to stabilize..,from discussions with the licensee, the inspector determined that the time delay was chosen to allow

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sufficient time for bus voltage to stabilize without being exceedingly

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long.

The test was conducted three separate times to verify that the maximum time was,actually exceeded and.not a recording error,

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i4 Investigation by the licensee determined the time delay relay setpoitit b

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tolerance should.be 12.5 seconds.

This reflects the manufacturer s L

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tolerance for'the relay with a 25-second setpoint.

The licensee committed

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to approve a permanent procedure change incorporating the increased

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setpoint tolerance prior to the scheduled October 1989 surveillance test.

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The licensed operators conducting the test were knowledgeable about the-i.

purpose and scope of the test.

Excellent communications were established f

among the operators.

One noncited violation was identified for an inadequate procedure.

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5.

Monthly Maintenance Observation (62703)

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On September 25, l9'89, the inspector observed maintenance activities related to work item (W1) 89-3906.

This WI required the locating and correcting of an intermediate ground fault indication on the ground fault relay for the EDG No. I generator field.

The electrician checked the mechanical linkages for. binding and cleaned and burnished the contacts, s

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Additionally,-the contacts were adjusted to increase the tension to assure proper wipe.

Documentation of the work activities conducted accurately

. reflected all tasks performed.

All reviews and approvals were obtained, Postmaintenance testing assured proper operation'of.the ground fault s

relay,

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On September 20, 1989, the inspector observed troubleshooting activities

conducted by an I&C technician for WI 89-3867.

The purpose of this WI was

to' determine the cause of a spurious alarm received in the control room related tt a standby gas treatment system high efficiency particulate air (HEPA) filter.

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Troubleshooting revealed an intermittent light in the photohelic wh'ich

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generated the alarm for a high differential pressure across the HEPA

filter.

A photohelic utilizes a light source and a photocell to generate a continuous electrical signal.

Dimming of the light source broke the

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circuit ~ causing the alarm. -After replacing the light, the technician U

performed a calibration check ano determined that the photohelic had

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failed.

Using a calibration data sheet obtained from the instrument folder, the technician checked-the instrument's calibration.

The alarm actuated at 6 inches water vacuum instead of the required 2 inches water

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vacuum.

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Since the same model number single element photohelic was not available, plant temporary modification (PTM)89-042 was generated to replace the single element photohelic with a dual element photohelic.

PTH 89-042 expires in 60 days, when a single element photohelic should be available

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for installation.

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After determining tnat all plant instrumentation did not have a calibration procedure, the inspectors reviewed the instructions available

f to I&C technicians for conduct of surveillances, PM activities, and

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P calibrations.

Three different categories of instructions are available.to I&C technicians:

TS required surveillance, surveillances for instruments

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important to the operation of the facility but not required by TS, and

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noncritical instrumentation.

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TS required surveillances are controlled by Volume 6 of the CNS Operations

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.7 Manual.

These procedures require 50RC approval for any change in the j

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procedure body or the attached data sheets.

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Procedures for instrumentation important to the operation of the facility I

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are located in Volume 14 of the CNS Operations Manual.

Volume 14

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procedures require SORC approval before they may be altered.

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Additionally, some Volume 14 procedures authorize the I&C Supervisor to

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approve changes to calibration data sheets for any of the instruments

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listed on an attachment to the procedures.

For each listed instrument on-i

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the attachment there exists, in the I&C shop personal computer, a

preprinted calibration data sheet witn setpoints and tolerances.

These

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sheets are revised as necessary and are used for calibrations when

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implementing PMs or corrective maintenance WIs.

After the work'is

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-complete, the I&C foreman must sign the bottom of each calibration data

sheet to indicate review and acceptance of the data..

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,There are six Volume 14 procedures that list approximately 369< instrument or instrument loop calibrations.

Included in the list are those instruments located in:

residual heat removal, HPCI, reactor core t

isolation cooling, instrument air (IA), service air (SA), and reactor

feedwater control.

The instruments provide system performance information

and have no TS requirements.

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The final category and type > of control for conducting I&C work activities

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are noncritical instrument data sheets which are contained in instrument folders.

This instrument performance information was obtained during i

original plant startup and is transferred from data sheet to data sheet

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each time a calibration.is performed.

50RC has no formal control of these

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setpoints and the calibrations are conducted to implement WIs.

The I&C

foreman reviews the completed data sheet prior to filing in the instrument

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folder.

No violations or deviations were identUied in this area.

The different categories used to provide guidance to the technicians for conduct of

'I surveillances, PMs, and calibrations meet or exceed regulatory

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requirements and appear to be satisfactory.

Documentation on completed

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W!s accurately reflected the work conducted.

The troubleshooting

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activities conducted were thorough.

Although no procedure was available,

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the I&C technician did a professional job of checking the instrument's j

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. calibration.

All reviews and approvals associated with the work item and i

the PTM were performed.-

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,Egneered Safet.y Features (ESF) Walkdown (71710)

The inspector conducted a field walkdown of the IA and SA systems. The l

field configuration was verified in accordance with 50P 2.2.59A, " Plant o

Air System Yalve Checklist," Revision 2. dated August 31, 1989.

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Approximately 1800 valves out of an estimated 2150 were verified by the

inspector. Thirty-two discrepancies were identified and are categorized i

as follows:

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Number T1tle

Missing tags which were previously in place j

Problems previously identified and in process of i

being solved

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Valves not positioned as stated in the valve l

checklist nor as represented on drawings

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Minor description discrepancies l

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Valve inproperly tagged and not identified by the contractor 3Z Total These discrepancies were presented to the licensee with a concern f

expressed about the acequacy of the drawing verification project. The

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categorization of the above discrepancies was done by the licensee while

resolving the inspector's concerns. The discrepancies identified were of

minor safety significance.

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Discussions between the inspector and the General Office Configuration l

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Managecent Supervisor detennined that the contractor's original scope

consisted of verifying the plant configuration utilizing IA piping and l

instrunent diagrams (PalD). The contractor was required to stop at the

root valves represented on the 1A P&lDs and not walkdown the related l

instrunent rack diagrams.

The inspector determined that nunerous IA system valves are located on

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other safety-related P&lDs or on instrunent rack drawings. The 1A valves

on the other P&lDs are to be walked down as part of those system walkdowns

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and not during the 1A walkdown.

Presently, the IA instrument rack l

drawings are not required to be walked down.

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From discussions with the licensee. the inspector detennined that licensee managenent did not understard all aspects of the contractor's job scope and was unclear about the amount of work actually completed by the

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contractor. Licensee management stated that they would have become aware of any discrepancy in scope durmg their final review of the project,

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-11-A walkdown of the instrument air systoni demonstrated a satisfactory on90ing ar-built program with sone minor problems identified.

No violations or deviations were identified in this program area.

7.

Followup on Previously Identified Findings (92701)

(Closed)OpenItem(298/8412-03) This item involved the failure to have established a fomal written training program for the offsite technical support staff.

Training Program Description (TPD) 0507, " Corporate Support Training,"

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' Revision 0 dated February 23, 1989, provides " position required" and

" task required" training requirements for the general office engineering staff.

" Position required" courses included:

general employee training (GET), ALARA,10 CFR 50.59, and industry eventt. The only " task required" course is respiratory training.

Each of the abcVe courses had a requalification frequency specified.

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The inspect 1r detemined from discussions with training departnent personnel taat GET is taken as required and that 10 CFR 50.59 initial training /requalification training will be presented in September 1989 and October 1989 to assure that all engineers have received the training.

ALARA training for the technical staff is being developed by General Physics.

Industry events were presented to the engineering staff and will be scheduled periodically in the future. This item is considered closed.

(Closed)OpenItem(298/8636-04) Deficient As-Built Instrument Drawings:

The licensee walked down the systems associated with the as-built drawings included in the open item. Design Change Notices (DCNs) were issued for updating the as-t uilt drawings. The inspector verified that the DCNs were incorporated into the as-built drawings. This item is considered closed.

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(Closed)OpenItem(298/8706-05) Mislabeled or Misnunbered Equipment in As-Built Records: The licensee walked down the systems included in the l

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open item. DCNs were issued and the associated as-built drawings were updated. The inspector verified that the DCNs were incorporated into the

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as-built drawings. Additionally. Procedure 2.2.20, " Standby AC Power i

System (Diesel Generator)," was revised to incorporate the updating of the

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as-built drawings. This item is considered closed.

(Closed)OpenItem(298 Implementation of Station Operations Review Consnittee (SORC)/8824-01)

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Training:

This open item was established to track the implenentation of a formal SORC trafning program and attendance by

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cot.unittee nenbers.

The inspector reviewed the training requirements contained in TPD 0508,

"50RC." Revision 1, dated April 26, 1989. The training included two

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" position required" lesson plans,10 CFR 50.59 and Technical Specifications (TS), and one " task required" lesson plan, Industry Events.

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Each of the above lesson plans had specified a requalification cycle.

Memorandum CNS$895696 from G. R. Horn, Division Manager Nuclear Operations, to P. R..Windham, Technical Training Supervisor, dated April 28, 1989, documented that the SORC menbers listed on the TPD were certified to the TPD training requirements and that SORC was in a requalification status. The nemorandum requested that the TS lesson plan be presented in'the fall of 1989. The inspector detemined that this training is scheduled to be presented in Decenber 1989.

Industry Events training will be presented to 50RC in October 1989. This item is

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considered closed.

No violations or deviations were identified in this area, r-I 8.

Followup on 10 CFR Part 21 Reports (92701)

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'The following 10 CFR Part 21 rtports were closed on the basis of the

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inspector's review of licensee documentation and discussions with personnel:

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a.

87-074:

Limitorque Supplied SMB-00 DC Motor Operators With lead

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Wire Defects - The 11censee's Inspection of L.1m1 torque drm-UU motor operations in stock revealed no defective wires. The CNS approved suppliers list was changed to require that all limitorque operators received be' inspected for wire damage. Limitorque has committed to inspect for lead wire damage prior to future shipments, b.

87-084: Nuclear Valve Division of Borg-Warner Corporation Fasteners Installed In motor operator Valves - The 11censee's search of

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purchase orders and equipment data files indicated that NPPD had

. purchased equipment from Borg-Warner; however, none of the valves

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were installed at CNS.

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88-004:

General Electric Conpany Hydraulic Control Unit (HCU)

Scram Solenoid Valve Hebuild K1ts - LNd had previously received a

Rap 1d Information Consnun1 cations Services Information letter dated July 2,1986, regarding~ HCU scram valve rebuild kits and the subject concerns were addressed prior to the 1986 outage. The following I

actions were taken at CNS:

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Strip chart recordings of' scram timing data for all rods was reviewed and no discrepancies were found.

L 69 rebuild kits in inventory were returned to General Electric

tor reinspection.

Maintenance Procedure 7.2.49.5, " Scram Pilot Solenoid Valve

Maintenance " was revised to include a final inspection of the core assembly, f

Af ter refurbishment of a scram solenoid pilot valyc, valve

operation is demonstrated prior to returning the HCU to service.

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Single rod scram time testing is then performed to verify control rod drive HCU operability.

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88-005:

Kaman Instrument Corporation Defect in Particulate and l

Iodine Monitors - The gaseous effluent monitors. manufactured by Kaman, identified in the CNS TS, do not require monitored particulate

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i or iodine monitors. One of the CNS Kaman monitors is a model KMPG

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D which is included in the Part 21 report.- In order to avoid a

potential future problem arising from chemistry procedure changes,

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L the Kaman monitor was updated with the current recommended software,

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88-019:

Limitorque Corporation Melamine Torque Switch Failures in i

L-SMB-000 and SMB-00 Valve Actuators - The initial review of records by i

the licensee revealed that 25 Limitorque SMB-000 valve actuators were

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suspect.

A maintenance work request (MWR) was issued for the

inspection and needed replacement of torque switches.

As a result, 23 SMB-000 valve actuator torque switches were replaced.

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89-001:

Cooper Bessemer Standby Diesel Generator Rocker Arm Failure -

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An MWR was issued for a visual inspection to look for cracks in the

' bosses on rocker arms in both emergency diesel generator (EDG) units, i

fio cracks were identified.

Additionally, two spare rocker arms in e

the warehouse were inspected and no cracks were identified.

NPPD added a requirement to procurement receipt inspections to look for (

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cracks in rocker arms.

I The following Part 21 report remains open pending further licensee evaluations:

88-018:

Limitorque Corporation - Reduced Starting Torque at Elevated Temperatures in SMB Valve Actuatars with RH Insulated DC Motors - NPPD Engineering evaluated the SMB Valves actuators with the RH insulated DC (

motors 'and determined that Valves RR-MO-S3A and RR-MO-53B would be required to. operate at temperatures greater than specified in Limitorque's Part 21

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report.

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CNS'provided Limitorque, by letter dated December 7, 1988, with the

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information specified in the Part 21 report:

Motor Starting Torque - 100 ft. Ibs.

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Voltage Rating

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Maximum specified temperature at which motor will develop rated

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O starting torque - 150 degrees Fahrenheit ( F)

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Accident temperature conditions

.296'F peak in 10 seconds and 175'F for 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />

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By letter, dated August 24, 1989, Limitorque responded to the CNS evaluati'on request.

Limitorque concluded that the two subject valves

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would provide the 100 f t-lb starting torque and the motors are suitable for operation at 175'F.

Limitorque specified that their experience indicated that a transient condition of 296'F for 10 seconds will not

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substantially change standard torque conditions.

However, equipment qualification data curves indicate that the drywell temperature during a

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loss of coolant accident would exceed 175'F for about 15 minutes.

The inspector was informed that NPPD engineering has not completed their evaluation of the limitorque response.

This item will remain open pending completion of tte NPPD engineering evaluation and designated corrective actions.

No violations or deviations were identified.

9.

Licensee Action in Response to NRC Bulletin 88-07 (TI 2515/99)

The purpose of this portion of the inspection was to verify that the licensee has successfully completed the actions requested in NRC Bulletin 88-07, " Power Oscillations in Boiling Water Reactors."

The inspector reviewed NPPD Letters NLS 8800450 dated September 15, 1988,

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and NLS 8900096 dated February 28, 1989, which responded to the bulletin.

The inspector determined that the responses were adequate and satisfactorily addressed all requirements of the bulletin.

j The licensee generated Abnormal Procedure (AP) 2.4.1.6, " Abnormal Neutron

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Flux Oscillations or Operation in the Instability Region," Revision 0,

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dated January 27, 1989, to address responses to abnormal neutron flux

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oscillations.

The inspector reviewed the procedure and determined that

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the procedure adequately addressed all concerns of the bulletin, The inspector interviewed two senior reactor operators (SRO). two reactor

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operators (RO), and one shift technical assistant.

The inspector

determined that all personnel interviewed had received training on the event at LaSalle Unit 2, described in the bulletin, and had a full i

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understanding of the significance of operation in the instability region.

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The. inspector walked through an oscillation event with one R0 and one SRO.

Both operators were aware of the symptoms of the event and of immediate

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actions required.

Both operators knew which procedure directed'

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appropriate actions and were able to describe and simulate appropriatu

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actions in accordance with AP 2.4.1.6.

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No violations or deviations were identified in this area. 'The licensee

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responded promptly and adequately to the concerns of the bulletin.

The

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operators demonstrated a thorough understanding of operations in the

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.;f instability regions.

NRC Bulletin 88-07 and Temporary Instruction 2515/99

are considered closed.

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Followup on NRC Information Notices (IN) (9?701)

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The inspector reviewed CNS followup actions relating to NRC IN 88-035.

The IN was processed in accordance with procedures and routed properly.

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Based on this' review, j

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S11.', Exit Interview.(30703)

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An exit interview was conducted on October 4,1989, with licensee.

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representatives. identified in paragraph 1.

During this interview, the

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inspectors reviewed the scope and findings of the inspection. ' Other

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The licensee did not identify as proprietary any information provided to,

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