IR 05000461/1989027

Safety Insp Rept 50-461/89-27 on 890818-1006.Violation Noted.Major Areas Inspected:Util Action on Previous Insp Findings,Onsite Followup of Written Repts,Nrc Compliance Bulletin Followup & Operational Safety Verification

ML19325E213
Person / Time
Site:	Clinton
Issue date:	10/23/1989
From:	Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML19325E211	List: IR 05000461/1989027 ML19325E210 ML19325E212
References
50-461-89-27, IEB-87-002, IEB-87-2, NUDOCS 8911020236
Download: ML19325E213 (16)

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U.S. NUCLEAR REGULATORY COMMIS$10N l

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REGION !!!

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Report No. 50-461/89027(DRP.)

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Docket No. 50-461 License No. NPF-62

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Licensee:

Illinois Power Company

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500 South 27th Street Decatur, IL 62525

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Facility Name: Clinton Power Station

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Inspection At: Clinton Site, Clinton, Illinois Inspection Conducted: August 18 through October 6,1989 l

l Inspectors:

P. Brochman

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i S. Ray B. Drouin I

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Approved By:

M. A. Rin Chief

/8 Reactor P ojects Sec ton 3B Date

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Inspection Sumya inspection on August 18 through October 6.1989 (Report No. 50-461/89027(DRP))

Areas Inspectec:

(1) Routine, unannounced safety inspection by the resident Inspectors of licensee action on previous inspection findings; onsite followup

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verification;monthlymaintenanceobservation;montdy(per6 of written reports; NRC Compliance Bulletin followu r o

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surveillance observation;

and onsite followup of events at operating reacto;5.

2)SIMSItemStatus:

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Closed BL-87-02.

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Results: Of the seven areas inspected, one violation was identified

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In the area of onsite followup of written reports concerning the feedwater

heating system not meeting its design basis.

In addition two Unresolved Items

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l were identified in the areas of operational safety verification and monthly

surveillance observation. Both items concerned inadequate procedures.

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DETAILS

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Personnel Contacted i

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Illinois Power Company (IP)

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1. W. Kelley, Chairman and CEO i

1. L. Haab, President i

@#D. Hall, Senior Vice President l

• @#J. Perry, Assistant Vice President

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• #K. Baker, Supervisor, I&E Interface

• #R. Campbell, Manager, Quality Assurance

1. J. Cook, Manager, Clinton Power Station

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• #R. Freeman, Manager, Nuclear Station Engineering Department

• #S. Hall, Director, Nuclear Program Assessment

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• #D. Holtzcher, Acting Manager, Licensing & Safety

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• #G. Miller, Manager, Scheduling & Outage Management

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J. Palchak, Manager, Nuclear Planning & Support

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• #J. Weaver, Director, Licensing

1. J. Wilson, Manager, Clinton Power Station

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• #R. Wyatt, Manager, Nuclear Training

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Soyland l

• #J. Greenwood, Manager, Power Supply

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Nuclear Regulatory Commission

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@ B. Davis, Regional Administrator, Region III

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1. C. Paperiello, Deputy Administrator, Region III t

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• @ P. Brochman, Senior Resident Inspector, Clinton i

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1. J. Clifford, Regional Coordinator, EDO l

1. B. Drouin, Project Inspector, Division of Reactor Projects, I

Region III

1. B. Forney, Deputy Director, Division of Reactor Projects, Region III

@ E. Greenman, Director, Division of Reactor Projects, Region III

@#J. Hickman, NRC Licensing Project Manag6t, NRR

@ C. Norelius, Director, Division of Radiation Safety and Safeguards, Region III

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@ T. Martin, Deputy Director, Division of Reactor Safety, Region III

@ H. Miller, Director, Division of Reactor Safety, Region III

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S. Ray, Resident Inspector, Clinton

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@#M. Ring, Chief, Reactor Projects Section 3B I

@ J. Zwolinski, Deputy Director, Division of Licensee Performance and Quality Evaluation, NRR

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• Denotes those atteading the monthly exit meeting on October 6,1989.

1. Denotes those attending the Management Meeting on August 23, 1989.

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@ Denotes those attending the Management Meeting on Septemb(t 13, 1989.

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The inspectors also contacted and interviewed other licensee and l

contractor personnel.

2.

Followup of Previously Identified Items (92701 & 92702)

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a.

(Closed) Open Item (No. 461/87031-01)-

Seismic Monitoring Instrumentation Reliability.

L This item was previously discussed in Inspection Reports l

No. 461/87031, Paragraph 3, No. 461/87039, Paragraph 2.d, No. 461/88009, Paragraph 2.a. and No. 461/88023, Paragraph 11.b.(1).

The inspectors reviewed the licensee's response, dated July 10, 1988, to an NRR stcff letter of April 5,1988.

The response contained information regarding actions taken or planned to be taken to improve the reliability of the seismic monitoring system and i

procedures.

The inspectors also reviewed changes to the seismic

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monitoring procedures and reviewed the operating history of the

system for the last year.

The inspectors noted that the system reliability had improved.

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Operators and technicians were observed to be more adept at operating and maintaining the system.

Housekeeping in the area of the detectors had improved.

During the last year the system has actuated a few

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times due to lightning.

In those cases the operators took the

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proper actions to verify that the actuation was not due to a seismic i

event.

They also properly declared the system " inoperable" until tapes and scratch plates were read, if applicable, and the instruments

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were recalibrated.

During the time the instruments were technically

" inoperable", before calibration, the operators kept the system energized se that data would not be lost in the case of an actual seismic event.

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Overall, the inspectors noted general improvements in the seismic instrumentation, procedures, and personnel awareness since the

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seismic event of June 10, 1987.

The system should be able to provide reliable information in the case of a future actual seismic event.

This item is considered closed.

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(0 pen) Violation (No. 461/88004-01):

Failure to Promptly Investigate Degraded Reactor Core Isolation Cooling System Steam Line Flow Instrument.

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This item was previously discussed in Inspection Report No. 461/08004, Paragraph 5.a.

It dealt with the failure of operators to recognize i

a degraded flow instrument during daily channel check procedures.

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One of the contributing factors to the problem was that there was no i

guidance for the operators on acceptance criteria for channel checks.

As part of the corrective actions, Plant Manager's Standing Order (PMS0)-50 was issued.

PMS0-50 contained, among other things, guidance

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to the cperators and shift supervisors on actions to be taken upon discovering questionable indications during channel checks.

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On June 19, 1989, another finding involving failure of operators to identify miscalibrated instruments during channel checks was

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identified.

Titis event was discussed in Inspection Report i

No. 461/89018, Paragraph S.c.

The licensee reported the event as LER 89-024.

As a result of both events, the licensee attempted to establish quantitative criteria for instrument channel checks, i

After a significant amount of engineering effort and discussions with other utilities, the licensee decided that establishing rigid

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criteria for all channels was not feasible.

Technical Specifications required that a channel check be a qualitative comparison of data and

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did not require specific qualitative criteria.

On August 18, 1989,

,l the Facility Review Group agreed to close their action item on the

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issue.

Recommended acceptance criteria was established for the Riley l

temperature instruments used in the Leak Detection System and was

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promulgated by a memo from the Director, System Engineering to the

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Director, Plant Operations on June 19, 1989.

That memo was provided

to shift operators and, with some later revisions based on operating

experience, was used successfully by them.

The inspectors noted that the men.orandum was not a controlled document and recommended

that it be officially issued as a revision to PMS0-50, an Operator Aid,

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or b revision to the daily channel check surveillance procedure.

The

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Director, Plant Operations agreed to take one of those actions.

t As a result of a concern expressed by the Operational Safety Team l

Inspection (Inspection Report No. 461/89030), the licensee agreed to

further investigate the possibility of establishing more definitive i

criteria for channel check surveillances.

The inspectors recognized l

that rigid criteria might not be possible for all instrument

channelt but recommended that criteria be established wherever

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practicable.

This item remains open pending completion of the licensee's investigation.

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(Closed) Violation (No. 461/88016-02):

High Pressure Core Spray l

System Inoperable due to Shutdown of Room Cooling Fan.

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This item was previously discussed in Inspection Reports No. 461/88016,_

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Paragraph 4.a. and No. 461/89026, Paragraph 2.e.

In.the latter

inspection the inspectors verified the completion of all corrective actions but noted that a change to Administrative Procedure. CPS

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No.1014.01, " Safety Tagging Procedure," requiring that yellow (caution) tags contain descriptive information stating the specific

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reason for the tag and any specific instructions,was generally not

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being followed in the case of the miniature adhesive tags used in the Main Control Room.

During this inspection the inspectors noted that

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all the tags had been corrected to include the required information.

This item is considered closed.

No violations or deviations were identified.

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l 3.

Onsite Followup of Written Reports of Nonroutine Events at Power Reactor j

l Facilities (90712)

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l a.

For the LERs listed below, the NRC has issued Notices of Violation, as indicated, concerning the same events.

The LERs are closed and

remaining correctives actions will be tracked with the Violations to

reduce administrative duplication.

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Closed LER Open Violation

i 461/87032-LL 461/87031-07

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l 461/87039-LL 461/87031-07 461/87063-LL 461/87036-02

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461/88016-LL 461/88009-03 461/88024-LL 461/88027-01

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461/89008-LL-461/89008-09

461/89009-LL 461/89008-09 l

461/89010-LL 461/89008-09

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461/89014-LL 461/89008-07

461/89016-LL 461/89014-07

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4G1/89021-LL 461/89018-02

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461/89021-IL 461/89018-02

461/89025-LL 461/89018-02'

461/89026-LL 461/89018-02 i

461/89031-LL 461/89026-01

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For the LERs listed below, the inspectors performed an onsite i

l followup inspection to determine whether responses to the events

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were adequate and met regulatory requirements, license conditions

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and commitments, and to determine whether the licensee-had taken

corrective actions as stated in the LERs.

j (1) (Closed) LER (No. 461/88022-LL) and (0 pen) LER (No. 461/88022-1L):

l Hydraulic Surge During Reactor Pressure Vessel Water Level (

Transmitter Restoration Results in High Pressure Core Spray t

Injection Because of Sensor System Design.

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On November 30, 1988, the licensee issued Revision 1 to the LER

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to include the special reaort data required by Technical Specification 3.5.1.f.

T1e original LER is closed to reduce

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administrative duplication.

Remaining corrective actions will

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be tracked by the revised LER.

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(2) (Closed) LER (No. 461/88025-LL) and (0 pen) LER (No. 461/88025-1L):

i Loss of Feedwater Heating System Transient Outside Design Basis

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Oue to Inadequate Communication Between the Architect Engineer'

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and the Nuclear Steam Supply System Supplier.

This event was previously discussed it Inspection Report No. 461/88023, Paragraph 11.b.(4).

The LER concerned an event

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on July 28, 1988, in which a partial loss of feedwater heating i

caused a drop in feedwater temperature of greater than 100 degrees Fahrenheit.

The design basis of the plant for a Loss

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of Feedwater Heating event, as stated in Section 15.1.1 of the Clinton Updated Safety Analysis Report (USAR), assumed that the most severe transient, for analysis considerations, was

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estimated to incur a loss of up to 100 degrees Fahrenheit in feedwater temperature.

The USAR further stated that "this event is analyzed under worst case conditions of a 100 degrees Fahrenheit loss and full power even thcugh a reduction of

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I feedwater temperature of as much as 100 degrees Fahrenheit at high power has never been reported."

l On October 24, 1988, during a subsequent review of the July 28 l

event, the licensee recognized that it had exceeded the design l

basis assumptions of the USAR and reported this to the NRC via

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the ENS; and subsequently issued LER 461/88025 on November 23,

1988.

The LER stated that analyses were being performed by the

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architect engineer, Sargent and Lundy Engineers (S&L), and the

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Nuclear Steam Supply System (NSSS) designer, General Electric l

(GE), to determine if the design basis for the plant required

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revision.

The LER stated that the event was also being

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cvaluated for reportability under the provisions of 10 CFR 21.

In addition, the LER stated that a supplemental report was expected to be submitted by February 25, 1989, with the results of the design basis evaluation, j

On August 25, 1989, the licensee completed the evaluation and l

reported that they had determined that the event was reportable

in accordance with 10 CFR 21.

They informed the NRC Staff at i

the Region III Office of the determination the same day and subsequently issued Revision 1 of the LER on August 30, 1989.

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The revised LER contained the 10 CFR 21 written report.

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original LER is closed to reduce administrative duplication and i

remaining corrective actions will be tracked with the revised LER.

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In LER 88-025-01 the licensee reported that the partial loss of feedvater heating event of July 28, 1989, had caused a total i

drop in feedwater temperature, excluding th4 change caused by

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the reduction in power, of greater than 102 degrees F,' but less

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than 112 degrees F.

The revised LER also discussed an event on June 13, 1988, which involved a-total loss of feedwater heating caused by a single failure.

In that case prompt operator action

prevented a large drop in feedwater temperature, but the-

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potential for a drop well in excess of 100 degrees F design basis

existed.

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The licensee reported that the cause of the plant being

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constructed such that it could exceed the design basis was the lack of adequate communication between the NSSS supplier, GE, and the architect engineer, S&L. regarding the NSSS design

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requirements for the feedwater heating system.

S&L designed the

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feedwater heating system in accordance with a GE design i

specification that stated that the maximum temperature decrease i

possible by bypassing the feedwater heaters by a single valve i

operation was 100 degrees F.

However, other GE design and j

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licensing documents required that the feedwater heating system be designed such that any single failure, operator error, or single event, would not cause a feedwater temperature drop of

greater than 100 degres F.

The licensee also reported that, although no safety limits were i

exceeded as a result of the events of June 13, and July 28,

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1988, the potential to exceed the Safety Limit for Minimum

Critical Power Ratio (MCPR) existed under certain conditions.

The Loss of Feedwater Heating accident was the limiting accident

for MCPR.

l 10 CFR 50, Appendix B, Criteria III, required, in part, that

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measures shall be established to assure that applicable design

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basis are correctly translated into specifications, drawings procedures, and instructions.

Criteria III further required, in part, that measures shall be established for coordination among. design organizations.

Failure of the licensee to ensure r

that tLe design basis was correctly translated into specifications and to ensure coordination between GE and S&L in regard to the design basis of the feedwater heating system is a an apparent

violation of 10 CFR 50. Appendix B, Criterion III.-

(No. 461/89027-01(DRP)).

f3) (Closed) LER (No. 461/88031-LL):

Licensed Operator Failure to Follow Procedures Results in Missed Surveillances of Rod

Pattern Control System High and Low Power Setpoints

This event was previously discussed in Inspection Reports l

No. 461/88030, Paragraph 5.b and No. 461/89018, Paragraph 5.d.

As discussed in the latter, corrective actions for LER 88031 were not adequate to prevent a similar event which was reported

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by LER 89025.

Violation No. 461/89018-02 was issued as a result of that event.

The inspectors reviewed the' corrective actions.

taken for LERs 88013, 89025 and the response to Violation

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No. 461/89018-02 anddetermInedthattheyweresufficientto close LER 88031.

Some corrective actions discussed'in the

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I violation remained uncompleted so it will remain open.

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(4) (Closed) LER (No. 461/89015-LL):

Failure of Assistant Shift Supervisor to Adequately Evaluate Technical Specification

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Requirements Results in Exceeding the Surveillance Interval for Average Power Range Monitors.

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This event was previously discussed in Inspection Report

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No. 461/89014, Paragraph 5.b.

The event was considered a-

" licensee-identified" violation for which a Notice of Violation

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I was not issued in accordance with 10 CFR 2, Appendix C,

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Section V.G.I.

Corrective action consisted of counseling for the

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Assistant Shift Supervisor involved and a briefing for all Shift

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Supervisors by way of a specific training brief and a night order.

I In addition, the inspectors verified that Surveillance Procedure

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CPS No. 9031.12, "APRM Channel Functional," was revised to

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include information on which steps were applicable to which'

OPERATIONAL CONDITIONS.

This item is considered closed.

l (5) (Closed) LER (No. 461/89020-LL):

Failure to Investigate the

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Consequences of Inadvertent Shorting of Terminations Prior to Performing a Temporary Connection Results in a Trip of the l

Reactor Protection System.

This event was previously discussed in Inspection Report-

No. 461/89014, Paragraph 8.b.(5).

Corrective actions consisted i

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of counselling of the Control and Instrumentation (C&I)

Supervisor involved in the event, briefing of all C&I Technicians

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and Supervisors, and a procedure change to Surveillance Procedure

CPS No. 9431.12. " Turbine Control and Stop Valves Scram i

Response Time Testing," to require the use of insulated sM p-on

connectors for connecting test equipment leads to the digital

signal conditioner (DSC) outputs and to require the installation

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of insulating sleeves on adjacent DSC pins to ensure that test i

equipment leads do not short adjacent pins.

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Shorting of pins during the instcllation of test equipment and jumpers during surveillance testing has been a continuing problem due to the tight quarters and lack of installed test jacks in the licensee s solid state protection system cabinets.

l In addition to the above corrective actions, the licensee

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issued Clinton Commitment Tracking No. 51019 to track the l

development of plans for the review of surveillances to be

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conducted in the next refueling outage.

The purpose of the i

review was to try to reduce the difficulties such as those that led to this event in performing the surveillances.

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inspectors will continue to monitor the' licensee's progress in

that plan.

This item is considered closed.

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One apparent violation was identified.

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NRC Compliance Bulletin Followup (2500/027)

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(Closed) Temporary Instruction 2500/27 - Inspection Requirements for NRC

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Compliance Bulletin 87-02, " Fastener Testing to Determine Conformance with Applicable Material Specifications."

(SIMS Issue No. BL-87-02)

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For this licensee, the Temporary Instruction required that the inspectors assure that adequate root cause analysis and corrective action has been

taken for sample number CPS-18A, an ASME SA320 GRL7 3/4-10 X 3 Capscrew.

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In addition the Temporary Instruction required that the inspectors assess

the adequacy of the licensee's effort to identify all possible locations l

where the fasteners may have been used and show that all applications are

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acceptable and appropriate disposition has been implemented where needed

to either "use-as-is," or replace.

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The licensee's Nuclear Station Engineering Department (NSED) did not

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perform an engineering evaluation for impact because no end use for the i

capscrews in question could be identified.

Based on a physical count of

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the capscrews in the warehouse compared to the number of items received, NSED determined that none of the capscrews had been issued for use.

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addition, due to the large variance in yield strength, two additional

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samples of the capscrew were tested by St. Louis Testing Laboratories on s

January 22, 1988.

Both samples met all material requirements.

Based on (

the above, the inspectors have determined that the licensee's response to Bulletin 87-02 was adequate and this Bulletin and SIMS Item are

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considered closed.

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5.

Operational Safety Verification (71707)

l The inspectors observed control room operations, attended selected pre-shift briefings, reviewed applicable logs, and conducted discussions

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with control room operators during the inspection period.

The inspectors

verified the operability of selected emergency systems and verified tracking of LCOs.

Routine tours of the auxiliary, fuel, containment,

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control, diesel generator, turbine buildings and the screenhouse were i

conducted to observe plant equipment conditions including the potential

for fire hazards, fluid leaks, and operating conditions (i.e., vibration,

process parameters, operating temperatures, etc).

The inspectors verified i

that maintenance requests had been initiated for discrepant conditions

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observed.

The inspectors verified by direct observation and discussion

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with plant personnel that security procedures and radiation protection (RP) controls were being properly implemented.

Inspections were routinely performed to ensure that the licensee conducted

activities at the facility safely and in conformance with regulatory

I requirements. The inspections focused on the implecentation and overall

effectiveness of the licensee's control of operating activities, and the performance of licensed and nonlicensed operators and shift technical

advisors.

The following items were considered during these inspections:

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• Adequacy of plant staffing and supervision.

i Control room professionalism, including procedure adherence, operator

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attentiveness and response to alarms, events, and off-normal

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conditions.

L Operability of selected safety-related systems, including attendant

alarms, instrumentation, and controls.

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i Maintenance of quality records and reports.

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On August 29, 1989, the inspectors observed that licensee employees t

I were demonstrating poor radiological work practices in processing

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through the Personnel Contamination Monitors (PCMs) leading to the i

Main Control Room and Chemistry Laboratories.

Because of recent

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heavy rains, the incidence of natural radon contamination on shoes l

was higher than normal.

Personnel were seen attempting to process through the PCMs numerous times without informing Radiological

Protection (RP) personnel after alarming the PCMs twice as required by RP procedures.

The inspectors informed the Director, Plant Radiological Protection of the observations and he took immediate corrective actions.

The inspectors noted that all employees were t

reminded of the correct procedure for use of the PCMs.

l This reminder was especially timely and necessary considering that, on the same day, a RP technician discovered that he had a " hot i

particle" on his arm.

He had been working in the plant and, upon

exiting the Radiological Controlled Area, alarmed the PCM.

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passed through the PCM without alarming it on his second attempt.

Approximately one half hour later he alarmed the portal monitor on l

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his way home and subsequently discovered a particle with 900,000 i

disintegration per minute activity on his arm.

Preliminary analysis

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indicated the individual received an extremity dose of about 5 REM.

The extremity dose limit in 10 CFR 20 was 18.75 REM per quarter.

l The inspectors attended a critique of the incident on August 31,

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1989.

The licensee was investigating the source of the partic.le,

refining the dose estimate, and trying to determine why the PCM

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didn't alarm on the individual's second attempt.

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b.

On September 1,1989, the inspectors were informed by a licensee employee of an industrial safety concern regarding employees working in the plant without shoes.

The inspectors informed the acting

plant manager and site safety personnel of the concern and submitted i

an OSHA Non-Radiological Hazards Data Sheet in accordance with NRC l

Regional Procedures.

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c.

During the first part of the inspection period, the inspectors noted I

a deterioration in the area of Main Control Room instrumentation.

i On September 6,1989, with the plant at 100% power, the inspectors noted that a total of 34 annunciators were lit in the " horseshoe"

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and back panel area.

In addition, there were 48 caution tags and 49 l

deficiency tags on the panels.

Fifteen of the caution and deficiency l

tags were on a single system (Leak Detection).

The inspectors

discussed the plans for correcting material deficiencies in the

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control room with the Manager - Clinton Power Station and noted some

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l improvements near the end of the inspection period.

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d.

On September 14, 1989, the inspectors toured the Division III Diesel

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Generator room and noted several deficiencies in the Air Start

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l System.

The system consisted of two 100% capacity air compressors l

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redundant air receivers, along with associated air drying towers i

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The inspectors noted that the motor-driven compressor was running

continuously but not increasing receiver, pressure due to a leak in

the compressor head gasket.

The diesel-driven compressor was turned i

off due to a leak in the exhaust line.

In addition, there were two

other deficiencies in the air drying towers.

The inspectors noted

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that the air receiver pressure met the Technical Specification t

limits but the system may not have been able to recharge the t

accumulators if pressure had been lost for some reason.

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inspectors noted that the licensee had also taken the Reactor Core Isolation Cooling (RCIC) System out of service for routine

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maintenance.

The inspectors informed the Line Assistant Shift Supervisor of their i

concerns and the licensee decided to place the RCIC System back in

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service until the deficien.ies on the Division III Diesel Generator

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Air Start System could be corrected.

The inspectors acknowledge i

that the licensee made a conservative decision when informed of the

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situation but were concerned that operating shift supervisory

personnel had not been aware of the degraded conditions in the Air Start System.

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e.

On October 4, 1989, the licensee identified that'they had apparently t

failed to perform a daily channel check surveillance on the stack effluent radiation monitor, OPR001, when it was placed in service.

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The monitor had been taken out of standby and placed in service at 8:26 a.m. on October 4, and the daily channel check was not recorded until 8:00 p.m. on the same day.

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The inspectors attended a critique of the event in which it was

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determined that the technician had apparently performed checks which

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met the requirements of a channel check surveillance when he placed i

the monitor in service but had not logged that the checks had been performed.

However, during the critique, several other problems with placing radiat1on monitors in service were identified.

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The technician who placed the detector in service stated that he had l

never performed the task before and was not aware that a written

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procedure existed for the evolution.. He asked another technician

for help and was instructed how to perform the evolution but was not

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informed that there was a procedure nor that a surveillance check was required.

The technician had not received formal trainin the operation of the Area Radiation / Process Radiation (AR/PR)g onSystem i

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l but was signed off as being qualified based on " experience." The Radiation Protection Shift Supervisor (RPSS) discussed some of the administrative actions that the technician had to accomplish as a result of placing the monitor in service but did not discuss with

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the technician the use of the procedure or the surveillance

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requirements.

In addition, the critique identified a lack of

understanding on the part of several licensee personnel about the l

surveillance time requirements when placing nonitors in service.

j The RPSS stated that he believed that eight hours were available to i

complete the surveillance.

This was apparently based on the LCO ACTION requirement to complete a grab sample once every eight hours i

if the monitor is inoperable.

Other attendees believed that only I

one hour was available based on a note in the Technical i

Specification that allowed the monitor to be taken out of service I

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CPS No. 7410.75 had contained a Procedure Deviation for Revision (PDR) that stated that i

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the channel check surveillance could not be done for ten hours after the monitor was energized to ensure enough data history was

available for a performance check.

The inspectors believed that l

when a monitor was placed in a service, for which any surveillance

interval had elapsed, the monitor must be considered inoperable until all surveillances were current.

l The inspectors also noted several problems with the procedures for I

operating the AR/PR System.

CPS No. 7410.75, " Operation of Digital AR/PR Monitors " contained a prerequisite step which required that

" Prior to placing the monitor in service, verify the detector calibration is current and the operability checks have been performed

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in accordance with the applicable procedure." However, Step 8.5 of the procedure, which contained the actual steps to place a monitor from standby to operation, did not reference the surveillance requirements. Also, the procedure required that the Shift Supervisor

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be informed when starting or stopping a Technical Specification

monitor but not when switching monitors in or out of standby.

The

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procedure referred the op'erator to CPS No. 7410.71, " Operation of the AR/PR Control Terminals, for the steps to be performed when placing monitors in or out of standby.

That procedure contained no instructions concerning surveillance requirements or Shift Supervisor I

notification.

In addition, although Step 8.8 of 7410.71 contained a

warning to place the standby unit in service before placing the l

operating unit in standby, the actual steps of the procedure were

written such that, if they were performed in the order written, the

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operatorwoulddojusttheopposite.

The weaknesses noted above in procedures and training concerning the

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operation of Technical Specification radiation monitors were considered en Un esolved Item (No. 461/89027-02)' pending the licensee's

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investigation and correction of the problems.

One Unresolved Item was identified in review of this area.

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6.

Montbly Maintenance Observation (62703)

Selected portions of the plant maintenance activities on safety-related I

systems and other components were observed or reviewed to ascertain that

the activities were performed in accordance with approved procedures,

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re0ulatory guides, industry codes and standards, and that the performance

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of the activities conformed to the Technical Specifications.

The

inspection included activities associated with preventive or corrective

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maintenance of electrical, instrumentation and control, mechanical j

equipment, and systems.

The following items were considered during these j

inspections:

the limiting conditions for operation were met while

components or systems were removed from service; approvals were obtained

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prior to initiating the work; activities were accomplished using approved i

procedures and were inspected as applicable; functional testing and/or j

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calibration was performed prior to returning the components or systems to

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service; parts and materials that were used were properly certified; and

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appropriate fire prevention, radiological, and housekeeping conditions

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were maintained.

l The inspectors observed / reviewed the following work activities:

Maintenance Work Procedure No.

Activity (

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CPS No. 2604.01 VX Chiller Performance MWR No. D13864 Seismic Monitor Troubleshooting l

In addition, several maintenance activities were observed by the

Operational Safety Team Inspection during the inspection period.

l No violations or deviations were identified.

f 7.

Monthly Surveillance Observation (61726)

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I An inspection of inservice and testing activities was performed to

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ascertain that the activities were accomplished in accordance with i

applicable regulatory guides, industry codes and standards, and in conformance with regulatory requirements.

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Items which were considered during the inspection included whether adequate procedures weie used to perform the testing, test instrumentation was calibrated, test results conformed with Technical Specifications and i

procedural requirements, and tests were performed within the required time

limits.

The inspectors determined that the test resulte, were reviewed by

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someone other than the personnel involved with the performance of the test,

and that any deficiencies identified during the testing were reviewed and resolved by appropriate management personnel.

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The inspectors observed / reviewed the following activities:

Surveillance / Test I

Procedure No.

Activity CPS No. 3322.01 Traversing In-Core Probe (TIP) Operation CPS No. 9031.12 APRM Channel Functional Test

CPS No. 9038.68 MSIV-LC Outboard Main Steamline Pressure l

056/057 Channel Functional Test

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CPS No. 9861.02 Containment Hatch LLRT In addition, several surveillance activities were observed by the Operational Safety Team Inspection during the inspection period..

For Surveillance Procedure CPS No. 9038.68 the inspectors noted some weaknesses in the procedure that the technicians were able to overcome by i

referring to other documents and the use of toolbox skills.

Step 8.2.16.3

of the procedure required that the technicians reland a lead on an Agastat

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time delay relay.

The procedure did not inform the technicians that

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Agastat relay leads must be torqued to 8 inch pounds.

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That information was found in Maintenance Procedure CPS No. 8801.16,

" Wire or Component Removal / Jumper Installation," although CPS No. 9038.6G did not reference 8801.16.

Step 2.1.5.d of 8801.16 states that the procedure does not cover " wires / jumpers / components specifically contained within approved written Plant Staff procedures in which appropriate d

notifications, verifications and torquing requirements are met implying that Procedure 9038.68 shouldeithercontainthetorquingrequIrementsor refer to Procedure 8801.16.

CPS No. 9038.68 also contained several steps which required that technicians verify various relay contacts were open or closed by measuring voltage and resistance across various points.

The procedure did not provide the technicians information concerning what voltage or resistance to expect if the relays were operating properly.

The technicians used craft capabilities to comp 1ste the steps but stated that the procedure would be easier to perform if it indicated whether high or low voltage or resistance was expected in each step.

Discussions with licensee personnel indicated

that Maintenance Department Channel Calibration procedures had acceptance i

criteria for voltage and resistance measurement steps, but Operating Department Channel Functional Test procedures did not.

The procedural i

problems identified in this section are considered an Unresolved Item (No. 461/89027-03) pending completion of the licensee's investigation of the deficiencies.

j One Unresolved Item was identified in review of this area.

8.

Onsite Followup of Events at Operatino Reactors (93702)

a.

General l

The inspectors performed onsite followup activities for events which i

occurred during the inspection period.

Followup inspection included r

one or more of the following:

reviews of operating logs, procedures, l

condition reports; direct observation of licensee actions; and i

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interviews of licensee personnel.

For each event, the inspectors

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l reviewed one or more of the following:

the sequence of actions; the

functioning of safety systems required by plant conditions; licensee

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actions to verify consistency with plant procedures and license

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conditions; and verification of the nature of the event,

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Additionally, in some cases, the inspectors verified that

licensee investigation had identified root causes of l

l equipment malfunctions and/or personnel errors and were

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l taking or had taken appropriate corrective 1ctions.

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l of the events and licensee corrective actions noted during

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I the inspectors' followup are provided in Paragraph b below.

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Details

i Reactor Recirculation Pump Trip l

On August 26, 1989, while operating at 100% power, the plant experienced a trip of the

"A" Reactor Recirculation (RR) Pump from i

fast speed. Control and Instrumentation technicians had been

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conducting maintenance on Scram Discharge Volume Analog Trip Module

IC11-N601A in the Reactor Protection System when the event uccurred, t

The trip was apparently caused by the technicians accidentally

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l shorting out contacts while removing the trip module panel cover.

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The control room received division 1 and 4 scram, manual scram,

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level 3, and recire pump auto shift to slow speed annunciators.

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inspectors verified that the RR pump would have been expected to trip off rather than only shift to slow speed for the event. All

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required surveillances for single loop operation were completed

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within the required time limits.

The pump was restarted in fast speed approximately six and one half hours later. The licensee

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verified that the reactor did not operate in the restricted zone of i

the power-to-flow map during the event.

No violations or deviations were identified.

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9.

Management Changes l

On September 5, 1989, the licensee announced that James W. Wilson,

Manager, Clinton Power Station, had been named technical advisor to the Senior Vice President. John G. Cook, previously Manager, Nuclear l

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Planning and Support, and formerly Assistant Manager, Clinton Power

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Station, was named as the new Manager, Clinton Power Station.

• 10. Management _ Meeting (30702)

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a.

On August 23, 1989, Illinois Power (IP) Company Chairman W. Kelley i

l and members of his staff met with Region III Deputy Administrator

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C. J. Paperiello and members of his staff at the Clinton Power Station.

Those in attendanco are denoted in Paragraph 1.

Among the topics discussed in the meeting were the current plant status, management

initiatives to improve operator performance during off normal i

operations, refueling outage planning, environmental qualification l

(EQ) program upgrades and increased vigilance in satisfying IP

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commitments to the NRC.

l The Deputy Regional Administrator discussed the potential negative

impact of Limiting Conditions for Operations (LCO) and significant

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l maintenance work order (MWO) backlogs on operator performance.

The licensee indicated their awareness of the potential negative impact l

i and stated that management initiatives were in the process of being I

implemented which would eventually reduce the MWO backlog.

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b.

On September 13, 1989, Illinois Power Company Vice President, D. P. Hall and members of his staff met with Region III Administrator A. B. Davis and members of his staff and NRR Deputy Division Director J. A. Zwolinski and members of his staff at the

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Region III offices.

Those in attendance are denoted in Paragraph 1.

The purpose of the meeting was to discuss the recent Institute of Nuclear Power Operations evaluation of tne Clinton Plant and the licensee's response to the evaluation, j

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Unresolved Items Unresolved Items are matters about which more information is required in

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order to ascertain whether they are acceptable items, violations, or deviations.

Unresolved Items disclosed during this inspection were i

discussed in Paragraphs 5.e and 7.

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12.

Exit Meetings (30703)

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The inspectors met with licensee representatives (denoted in Paragraph 1)

throughout the inspection and at the conclusion of the inspection on October 6, 1989.

The inspectors summarized the scoae and findings of the i

inspection activities.

The. licensee acknowledged tie inspection findings.

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The inspectors also discussed the likely informational content of the

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inspection report with regard to documents or processes reviewed by the inspectors during the inspection.

The licensee did not identify any documents / processes as proprietary, t

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