IR 05000461/1989038

Insp Rept 50-461/89-38 on 891219-900202.Violations Noted. Major Areas Inspected:Routine,Unannounced Safety Insp by Resident Inspectors of Licensee Action on Previous Insp Findings,Operational Safety & Followup

ML20006E961
Person / Time
Site:	Clinton
Issue date:	02/16/1990
From:	Ring M NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20006E959	List: IR 05000461/1989038 ML20006E958 ML20006E960
References
50-461-89-38, NUDOCS 9002270005
Download: ML20006E961 (14)

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U.S. NUCLEAR REGULATORY COMMISSION.

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REGION III

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' Report No. 50-461/89038(DRP)

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Docket No. 50-461.

License No. NPF-62 l

Licensee:

Illinois Power Company 500 South 27th Street

Decatur, IL 62525

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. Facility Name: Clinton Power Station

' Inspection At:.Clinton Site, Clinton, Illinois s

Inspection Conducted: December 19, 1989 through February 2, 1990 l

Inspectors:

P. G. Brochman S. P. Ray P. R..Pelke

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' Approved By:

M. A. Ring, Chie

/h[XV[

Ni M'To -

t Reactor Projects Section 3B O'

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. Inspection Summary

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Intpection from December 19, 1989 through' February 2, 1990 (Report =

.No. 50-461/89038(DRP))

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-Areas Inspected:

Routine, unannounced safety inspection by the resident

t inspectors of. licensee action on previous inspection findings; operational-safety; event. follow-up; maintenance / surveillance; licensee event reports;.

.-and meetings.

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Results: 'Of the five areas inspected, no violations or deviations were identified in four areas; one violation was identified in the remaining i

(failure to document the results of cleanliness inspections Paragraph 5).

area:

While this violation was of minimal safety. concern, it was indicative'of poor management responsiveness'to NRC concerns and inadequate understanding of the technical issues.

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9002270005 900216 PDR-ADOCK 05000461

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DETAILS

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Persons Contacted Illinois Power Company (IP)

1. W. Kelley, Chairman and CEO

1. L. Haab, President

• fJ. Perry, Vice President

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• fJ. Cook, Manager, Clinton Power Station

• fR. Campbell, Manager, Quality Assurance

• fR. Freeman, Manager, Nuclear Station Engineering

• fS.. Hall, Director, Nuclear Program Assessment

1. D. Holtzcher, Acting Manager, Licensing and Safety

• fJ. Miller, Manager, Scheouling and Outage Management

1. J. Palchak, Manager, Nuclear Planning and Support

• ff. Spangenberg, Manager, Licensing and Safety

'c fJ. Weaver, Director, Licensing

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• fR. Wyatt, Manager, Nuclear Training

• J. Pusauskas, Supervisor, Maintenance Planning

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• A. Haumann, Supervisor, Electrical Maintenance l

• C, Brown, Supervisor, Mechanical Maintenance

• W. Clark, Supervisor, C&I J

• G. Bell, Director, Stores i

• C, Elsassar, Director, Outage Management

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• J. Brownell, Project Specialist, Licensing and Safety

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Soyland

• fd. Greenwood, Manager, Power Supply Stone a' Webster

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- *D. Schlatka, Stone & Webster, Project Manager

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The inspector also contacted and interviewed other licensee and contractor personnel during the course of this inspection.

1. Denotes-those present during the management meeting on January 9,1990.

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• Denotes those present during the exit interview on February 2,1990.

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2.

Action on Previous Inspection Findings (92702)

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_(Closed) Violation (461/87036-02):

Entering Operational Condition 2.

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With Emergency Core Cooling System Inoperable Due to Isolated Reactor Pressure Instrument.

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This item was previously discussed in Inspection Report

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No. 461/87036, Paragraph 11.b.(8). LER 87-063 also reported the

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event. The inspectors verified that the long term corrective action l

of establishing the requirement to separately record and verify l

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instrument valve operations was completed. Maintenance Procedure l

CPS No. 8801.12, " Local Mounted Instrument Valve Operation," was i

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revised to require recording on checklist 8801.120001 the operation

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of all instrument valves and to require independent verification of valve restoration. Commitments regarding manipulations of root

. valves made in LER 87-063 were referenced in the procedure.

Problems similar to this violation have not recurred in the last two years. This_ item is considered closed.

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(Closed) Violation (461/88004-03): Material Staged Over the Suppression Pool During Plant Operations Without a Safety-

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Evaluation.

This item was previously discussed in Inspection Reports No. 461/88004, Paragraph 5.c. and No. 461/88021, Paragraph 4.b.

The inspectors have routinely observed material control procedures in the containment since the corrective actions for the violation were taken and have noted significant improvements in containment material control.

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However, some problems still existed with the control system.

Administrative Procedure CPS No. 1050.02, " Foreign Material Exclusion in the Containment and Drywell," listed the Technical Advisor -

Maintenance as responsible for reviewing-Inventory Control Forms and stated that he should notify the Assistant Manager - CPS of discrepancies. Neither of those two positions existed in the licensee's organization. When the Technical Advisor - Maintenance position was eliminated, responsibilities for containment material control were turned over to the Compliance Specialist. CPS-No. 1050.02 also made each individual responsible to ensure

that any-material he brought into containment would not exceed y

the limitations on maximum size of flexible material lin restricted i

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was virtually-impossible to achieve as noted by various QA audits and discussed in the licensee's Facility Review Group (FRG) Meeting 89-099.

Procedure revisions were underway and a better flexible material control program was being-tracked by FRG Action Item 89-099-01.

Based on improved performance in containment material control and

i the licensee's' interest in improving the program as demonstrated by-QA audits and FRG actions, this item is considered closed. The inspectors will follow the resolution of FRG Action Item 89-099-01 and the revision to Procedure 1050.02.

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(Closed) Open item (461/88004-05):. Failure of. Division III Diesel Generator Air Start Motors.

This item was p(9).reviously discussed in Inspection Report No. 461/88004,

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Paragraph 9.b.

The issue involved a failure of air start motors

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due to deterioration of the motor while in warehouse storage.

The deterioration was apparently due to mixing of lubricants when a j

modification was done on the motors when they were received.

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The1 inspectors reviewed the disposition of Conditiun Report No.-1-88-03-071 which documented the licensee's actions to correct-the problem.

The purchase requisition for new air start motors was l

revised to require that new motors be completely disassembled,

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lubricated, and reassembled in accordance with Maintenar.ce Procedure

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CPS.No. 8207.04, " Air Start Motor Maintenance," prior to being J

placed in storage.

Maintenance Procedure CPS-No. 8207.05, " Emergency Diesel Starter Motor Removal and Installation," was revised to include

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a prerequisite that all new air start motors be refurbished in accordance with CPS No. 8707.04 prior to initial use.

In addition, Preventative. Maintenance-Task PMMXDA141 was issued to require that stored air start motors be rebuilt such that the shelf life of their internal lubricant is not exceeded.

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Since the event discussed in the open item, there have been no

air start motor failures due to similar problems. During recent

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maintenance on the division II_ diesel generator, it became necessary to instell new air start motors that had not been refurbished

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because of a lack of rebuild kits, but that action was evaluated

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as acceptable since the new motors had been received quite recently.

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This item is considered closed.

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d.

(Closed) Violation (461/88016-01): Failure to Lock or Check Branch Line Isolation valves in the Standby Liquid Control (SLC) System.

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This item was previously discussed in Inspection Reports No. 461/87032, Paragraph 5 b. and No. 461/88016, Paragraph 2.a.

The inspector

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verified that Operating Procedure CPS No. 3314.01V001, " Standby

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Liquid Control Valve Lineup," had been revised to require Valves IC41-F314 A/B and IC41-F315A/B to be locked closed.

Field observations by the inspectors have confirmed that the valves were -

labeled as " locked valves" and were being maintained locked closed.

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The inspectors also reviewed drawings-and valve lineup procedures j

and conducted spot checks in the field to verify (ECCS)'were controlled that valves "in the flowpath" in emergency core cooling systems

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in accordance with Technical Specification surveillance requirements.

Numerous vent an:1 drain branch line isolation valves were not locked

closed. However, in the case of ECCS, improper positioning of those j

3/4 inch branch lines would not significantly affect the amount of -

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flow delivered to the reactor vessel so they did not have.to be considered "in the flowpath" in accordance with the staff's memorandum

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discussed in Inspection Report No. 461/88016, Paragraph 2.a.

This item is considered closed.

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Plant Operations The unit operated at power levels up to 100% for the entire report period.

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OperationalSafety(71707)

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The. inspectors observed control room operation, reviewed applicable logs and conducted discussions with control room operators during

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December 1989 and January 1990.- During these discucsions and

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observations, the inspectors ascertained that the-operators were

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alert, cognizant of-plant conditions, and attentive to changes in those conditions, and that they took prompt action when appropriate.

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The inspectors verified the-operability of selected emergency systems, reviewed tagout records, and verified the proper return to

-service of affected components.~ Tours of the plant were conducted

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to observe equipment conditions, including potential. fire hazards, s

fluid leaks. and excessive vibrations, and to verify that maintenance

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requests had been initiated for equipment in need of maintenance.

.The inspectors verified by observation and direct interviews that

the physical security plan is being implemented in'accordance with-

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the station security plan.

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The inspectors observed plant housekeeping / cleanliness conditiors and verified implementation of radiation protection controls. The

inspectors also witnessed portions of the radioactive waste system controls associated with.radwaste shipments and barreling.

The observed facility operations were verified to be in accordance with the requirements established under Technical Specifications,

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10 CFR, and administrative procedures.

(1). Leaks in Safety-Related Heat Exchangers On December 18, 1989, the licensee identified a lifting safety valve on the jacket water system for the Division II emergency diesel generator (DG),16 cylinder diesel. This was caused by-a leak in the diesel's jacket water heat exchanger (HX). The DG consisted of 2 diesel engines, a 12 cylinder.and a 16 cylinder, in. tandem with a generator. Each engine had its own HX, which cooled the jacket water and lubricating oil systems for the engine. Coolin service water (g water was supplied to the HX from the shutdown.

SX) system.

The HXs were safety-related, ASME Code Class 3 components. SX system pressure was higher than jacket water pressure; consequently, SX water filled up the

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jacket water surge tank and caused the jacket water safety valve to lift.

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The licensee plugged the leaking tubes and returned the DG to

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service. On December 21, 1989, the Division I DG,16 cylinder diesel's HX began to leak. The licensee performed eddy current testing on a sampling of the tubes to try to determine the extent of the problem. The licensee removed one of the leaking tubes and sent it,.several tubercles which were found growing inside the HX, and a sample of water, to an outside laboratory for analysis. The licensee plugged the tubes which were laaking

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and some of the other tubes which had indicated the deepest

~ itting in the eddy current examination..The DG HX tubes were-p of'a copper / nickel alloy..

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- On January 5,1990, the Division I DG,12 cylinder diesel's HX began to leak. The licensee plugged ~the leaking tubes but

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elected not to conduct eddy current examinations of the HX.-

On January 11, 1990, the same HX began to leak again. The

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licensee decided to perform a complete eddy current examination of all the remaining tubes in this HX and plugged all-tubes which indicated greater than 50% wall thinning.

The licensee initiated a program to perform 100% eddy current examinations on all of the DG HXs and a sampling eddy current examination of other HXs which are cooled by SX. There are-approximately 40 other safety related HXs at Clinton, primarily room coolers for engineered safety equipment.

Before completion of this examination, the Division I,16 cylinder diesel's HX-began to leak again. The licensee completed a 100% eddy

current examination of this-HX and plugged additional tubes (67 total).

The licensee performed a safety analysis on the Division I DG and determined that the HXs could perform their design function with up to 100 tubes plugged if lake water temperature. remained below 65 degrees F.

The licensee intended to retube the HXs in an outage scheduled to begin on February 25 and was monitoring lake water temperature to assure it remained below 65 F.

i The laboratory determined that the cause of-the leakage was microbiological 1y influenced _ corrosion (MIC) and that the aerobic bacteria involved were similar'to the. Arthrobacter encapsulatum bacteria implicated-with MIC of. copper-alloys.

The 5x system

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was being treated with liquid chlorine batch additions to control biofouling and the microbiological growths.

A. continuous sodium hypochlorite addition system had been installed but was not yet in operation. The licensee was developing a program to j

treat the SX system with additional chemicals such as sodium

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bromide; however, additional approvals must be obtained from; the Illinois Environmental Protection Agency.

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Additional' observations of the HX examinations are discussed-in the maintenance / surveillance area (Paragraph 5).

(2) Test Failures on Division I Diesel Generator On December 27, 1989, during the performance of Surveillance Procedure CPS No. 9080.01, " Diesel Generator'1A (18)

Operability Hanual," the Division I diesel generator failed to reach rated speed in less than or equal to 12.0 seconds as required by Technical Specification 4.8.1.1.2.a.4.

The diesel took 12.7 seconds to reach rated speed. Following the

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installation of additional recording instrumentation to aid

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in further troubleshooting, an attempt was'made to start the

l diesel which resulted in the diesel cranking but failing to i

start. This failure was determined to be caused by the

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placement of recording instrumentation leads which had been installed to monitor the response of the K19 starting relay.

j As reported by the licensee in Special Report U-601589 dated'

January 11, 1990, the root cause of the test failure was not positively determined but the' diesel was being thoroughly analyzedunderanactlonplantoimproveitsaerformance, The 12-cylinder governor was replaced after taese failures

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with one that exhibited better acceleration characteristics.

On December 30, 1989, during an attempt to return the diesel to operability following the December 27 failures, the diesel

again failed to start.

In this case the diesel: cranked, but failed to start. An investigation determined that the most l.

likely cause of-the failure was that'one of the contact pairs l

on the K19 starting relay were not contacting properly. The result of the malfunction of the relay contacts was.that the engine would crank but would not receive a signal to take the

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governor actuators out of the minimum fuel position.

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. licensee reported this failure in Special Report U-601599

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dated January 29, 1990.

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The December 30 failure represented the.fifth valid failure of the Division I diesel in the last 20 valid tests'and the eighth

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valid failure in the 68 valid' tests that had been performed on-the Division-I diesel since the plant received-its operating e

license. The failure also-constituted the seventh valid

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failure in the last 100 tests performed on a per nuclear unit basis. Therefore the Special Report contained the additional information on corrective measures to increaso reliability, j

assessment of existing reliability, and basis for continued operation required by Regulatory Guide 1.108, Position C.3.b..

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The report described the action plan which was. continuing in an

attempt to improve the diesel performance.

The high resistance

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on the K19 relay contacts was determined to be a possible contributor to three previous slow starts on the Division I

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diesel. Since the replacement of the 12-cylinder governor.

and the K19 relay there have been eight start attempts on the Division I diesel generator, all of which have resulted in successful starts with start times less than 10.5 seconds.

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Improvements to'the-air start piping, the fuel priming system, i

f and the fuel oil day tank level control system were planned,

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and other improvements were being investigated. The action plan was to be completed and a final report issued by March 30, 1990.

No violations or deviations were identified.

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OnsiteEventFollow-up(93702)

The inspectors performed onsite follow-up activities for events

which4 occurred during December 1989.and January 1990.

These-follow-ups. included reviews of op(where available), and interviews erating logs, procedures, Condition Reports, Licensee Event Reports

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with licensee personnel. For each event, the inspectors developed a chronology, reviewed the functioning of safety-systems required

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by plant conditions, and reviewed licensee actions to verify i

consistency with procedures, license conditions, and the nature i

of the event. Additionally, the inspectors verified that the licensee's investigation had identified the root causes of equipment malfunctions and/or personnel errors and that the licensee had taken appropriate corrective actions prior to restarting the unit. Details of the events and the licensee's corrective actions developed through inspector fol, low-up are provided in Paragraphs (1) and (2) below:

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(1) On December 19, 1989, the licensee informed the NRC via the ENS-

ofanEngineeredSafety) Feature (ESF) actuation (ReactorCore Isolation Cooling (RCIC isolation). The plant was operating at about 84% power at the time of the event and RCIC was in standby. No maintenance or operations _ activities were in progress at the time which would have been expected to cause the ESF actuation. About 20 minutes later, while operators

were restoring the RCIC system, they noted erratic readings -

on one of the RCIC steam line flow analog trip modules (ATMs)

in the leak detection system. At that point RCIC" isolated a second time.

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l An investigation determined that the steamline flow transmitter f

was overly sensitive to minor changes. in sensing line pressure.

l-It was believed that the periodic operation of a steam drain

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- trap in the RCIC system caused. small transients in steam pressure. Technicians replaced the transmitter's amplifier and calibration cards in accordance with Field Alteration C-F031.and Field-Engineering Change Notice 24557. -The new-

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cards had an adjustable inherent time delay which reduced the.

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sensitivity of the transmitter.

This solution had been used-

previously on other overly sensitive instruments. On-December 24, 1989, the changes were complete and the RCIC

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system de_clared operable.

The licensee followed up with.a written report (LER 89-042)

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The LER stated that Field Alteration C-F031 E

- would be installed on other sensitive transmitters when

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affected systems become available for work.

(2) On January 4,1990, while replacing optical isolator card

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E-85-A305 in Division I Nuclear System Protection System (NSPS)

panel H-13-P661 under Maintenance Work Request (MWR) C49510, the "A" reactor recirculation pump tripped off from fast speed.

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The reactor had been operating at full power prior to the event. The cause of tie event was determined to be an

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v-inadequate evaluation of the impact of performing the work

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j in the MWR, Because of the, circuit card arrangement, the MWR required

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that the edge connector. cable on the adjacent isolator card, E-85-A304, be removed. The MWR contained a system impact

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matrix which. identified that only certain-computer points

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'and annunciators would be affected by the removal of the edge connector. Actually, removal of the edge connector caused an r

incomplete sequence trip on one of the fast speed ~ breakers for-the recirculation pump.

A review of the E03 series electrical drawing for the isolator card did not show that the pump would

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trip but by following the signal path from the E03 drawing to a more detailed E02 series drawing, the trip could be predicted.

The tie from the E03 to the E02 drawing was very difficult to-make because there was no reference telling the planner which

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E02 drawing to go to.

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The system impact matrix had been prepared almost two years

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earlier. Since that time, the planners preparing matrixes had received additional training in reading and.using.E03 and E02

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drawings.

In addition, a Shift Supervisor had authorized the work to begin on the MWR almost one year-prior to the event.

At that time, recirculation pumps had not been. running.

The, inspectors observed the licensee's response to entering

R single loop operation and:the-recovery to normal two loop operation. All Technical Specification requirements were met and op_erators controlled the plant conservatively during the event.. The four hour action requirements of Technical

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Specification 3.4.1.1.a.1 were all completed within a short i

time of the pump trip except that not all of the average power range monitor scram and rod block trip setpoints were reduced

because.the pump was restarted before the four hour time limit expired.

Short term corrective action included requiring that any system impact matrix more than six months old be reevaluated before use and briefing all Control and Instrument planners on the event.

In addition, the Supervisor, Planning, was to ensure that planners were assigned to matrix development based on

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their experience and training on systems. Longer term corrective actions were to include providing system training-to appropriate planners and engineers and an engineering evaluation of the feasibility of improving E03 drawings.

No violations or deviations were identified.

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5.

Maintenance / Surveillance (61726 and 62703)

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Station mainten'ance and surveillance ac'tivities of the safety-related systems and components listed below were observed or reviewed to ascertain that they were conducted in accordance with approved procedures,

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regulatory guides, and industry codes or standards, and in conformance f

with Technical Specifications.

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The following items were considered during this review: the limiting conditions.for operation-were met while affected components or systems

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were removed from and restored to service; approvals were obtained prior to initiating work or testing; quality-control records were maintained;

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parts and materials used were properly certified;. radiological and fire prevention controls were accomplished in accordance with approved procedures; maintenance and testing were accomplished by qualified

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personnel; test instrumentation was within its calibration interval; functional testing and/or-calibrations were performed prior to returning

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components or systems to service; test results conformed with Technical Specifications and piocedural requirements and were reviewed by personnel other than the individual directing the test; any deficiencies identified -

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during the testing were properly documented, reviewed, and resolved by appropriate management personnel; work requests were reviewed.to determine-the. status of outstanding jobs and to assure that priority was assigned to safety related equipment maintenance which may affect system performance.

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The following maintenance and surveillance activities were observed:

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Activity-Title NWR D14101 Division I DG Heat Exchanger. Repair MWR 007323 Division I-DG Heat Exchanger Repair MWR D14098 Division II DG Heat Exchanger Repair MWR D08882 Division II DG Heat Exchanger Repair

'4 MWR D08216 Division III DG Heat Exchanger Repair.

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MWR 008234

"A" SGTS Room Cooler Inspection MWR D08233

"A" Hydrogen Recombiner Room Cooler i

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MWR D18959 Replace pyrometer on DG13A

~ CPS 9052.01 LPCS Pump Operability-CPS 9052.02 LPCS Valve Operability Checks CPS 9080.01 Diesel Generator IA Operability a.

On January 18, 1990, during observations of the work associated with MWR 007323, the inspector identified three concerns.

First, the MWR exchanger (HX) que value of 100 ft-lbs for the studs on the heat-specified a tor end flanges. However, one of the drawings contained

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in the MWR work package, Stewart Stevenson Drawing 61383, Revision E, specified a torque value of only 65 ft-lbs for the studs.

The inspector questioned this discrepancy and was told that the Nuclear Station Engineering Department (NSED) had performed a calculation, No. 283, and specified a torque value of 100 ft-lbs.

The inspector contacted NSED to determine if an engineering evaluation had been performed on the deviation from a manufacture's

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recommendation. The NSED staff stated that they were unaware that this -drawing. specified torque values and that the calculation which specified the value of 100 ft-lbs was based on standard engineering practice.

Subsequent to this discussion the NSED staff initiated a Condition report and performed calculation 291 which determined that

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a value of 65 10% ft-lbs was appropriate and that the value_of 100-

.ft-lbs, which had been used with the previous HX repairs was within allowable stress limits. The inspector reviewed the calculation and did not identify any further concerns.

Second, the inspector observed that the mechanics were going to use gaseous nitrogen to pressurize the shell side of the HX, on top of a water blanket, to look for leaks. The maximum value that the.HX i

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shell side could be pressurized to was 150 psig.

This value was:

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consistent with the system design. and was stated in the MWR.

However, based on_ previous problems the licensee had implemented

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a policy:of _ requiring that the safety group approve all uses of.

gaseous nitrogen to pressurize a system above 25 psig. When pressurizing systems, such as this HX,11t is preferable to use only

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water and a hydro pump rather than a mixture of gas and water. This -

is to minimize the danger caused by the energy stored in the system when it is pressurized; and consequently,'would be released if a

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catastrophic failure were to occur. The inspector discussed-this matter with the safety group and maintenance personnel. The inspector observed poor communication within the safety group and. _

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between the safety group and maintenance group.. Subsequent to these

't meetings the safety group banned the use of gaseous nitrogen without-specific written approval of the safety group and provided clearer guidance as to what were appropriate circumstances to use high-

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pressure-gasses, t

Third, the inspector noted that there were no signoffs in the MWR.

with regard to performing _a cleanliness inspection upon opening the HX or closing the HX, which is a safety related system.

Clinton Administrative Procedure CPS No'. 1019.02, " System Cleanliness,"-

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Paragraph 8.2.1 states,. in part, "... when a safety-related system -

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1s opened for maintenance, the "as found" condition shall be documented on or attached to the work documents." Paragraph-9.1.1 states, in part, "Before final closure of a system after opening for maintenance or an operational evaluation, a visual insp'For safety-related-ection shall be

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performed...." Paragraph 9.3 states,

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H components the results of the inspection performed in Section 9.1 and 9.2 shall be documented and attached as part of the work package."'

These statements are based upon commitments made by the licensee to ANSI Standard N18.7-1976, Paragraph 5.2.10. " Quality Assurance at-Nuclear Power Plants." The inspectors discussed this concern with plant management. The licensee initiated Condition Report No. 1-90-01-059 to document this problem and problems associated with

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L five other MWRs which had opened the HXs for the other DGs.

10 CFR j

Part 50, Appendix B, Criterion V, requires that activities affecting l

quality shall be prescribed by documented instructions... and shall be accomplished in accordance with these instructions....

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The failure to document the results of the cleanliness inspection in MWR package 007323 is an example of a violation of 10 CFR Part 50,

AppendixB, Criterion-Y(461/89038-01a(DRP)).

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On -January 31, 1990, during observation of MWR 008216 the' inspectors noted there was a documentation-for the opening of the HX 'and opening.

of the SX piping leading to the HX, to replace Valve ISX0050. However,

there was-no documentation of a closeout inspection when.the valve was

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installed and no signature blocks were specified in the MWR to alert the mechanics that they had to document the'results of a closecut inspection, when they reinstalled the end flanges on the HX. The

failure to document the results of the cleanliness-inspection before final closure in MWR Package D08216 is an example of a violation of 10CFRPart50,AppendixB,CriterionV(461/89038-01b(DRP)).

The' root cause for.both of these examples of violation appeared to the inspectors to involve the licensee's inadequate awareness of their own procedures and requirements. The inspectors reviewed Condition Report No. 1-90-01-059 and noted that it only addressed

_;

documenting inspections during the opening of systems but made no mention of closing inspection. The NRC is concerned with the poor performance of the maintenance department in responding to the previous NRC concerns an6 in evaluating and resolving technical

..

issues raised by _the inspectors.

During.the inspection, the inspectors also noted that Valve ISX005C, HX inlet isolation valve, was marked to indicate a preferred.

-l-orientation, with respect to system flow.

However, the installed configuration-was in the opposite direction to the system flow.

The inspectors reviewed the vendor manual for the valves, Posi-International Manual K2868-001.

Paragraph 2 of the installation instructions specifies that although the Posi-Seal valve is capable of bi-directional seating, a preferred flow / disk relationship is u

indicated. The inspectors also reviewed maintenance procedures CPS l

No. 8120.13 and 8120.31 and noted that no guidance was specified to the mechanics about orientation of valves; however, discussions with

!

maintenance personnel indicated that as part of the craft capability.

the mechanics noted the orientation of a valve before they remove it, so that they could reinstall it in the same orientation.. The inspectors noted that four new valves had been installed in parallel with the work on the-HXs and that two of them were installed backwards (flow arrow reversed). The inspectors also looked at other systems in the plant and noted similar problems with Posi-Seal valve orientation The licensee is conducting a review of this problem and the inspectors will track this review as an l

{

open item (461/89038-02(DRP)).

One violation was identified.

-6.

Safety Assessment / Quality Verification a.

Licensee Event Report (LER) Follow-up (90712 and 92700)

Through direct observation, discussions with licensee personnel, and review of records. the following LERs were reviewed to deter-mine

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_

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'

e

"x

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-l 14;

,

that the reportability requirements were fulfilled, immediate

corrective: action was accomplished, and corrective action to prevent recurrence had been accomplished in accordance with Technical Specifications. Based on the inspectors' review, the following LERs are closed:

,

LER No.

Title

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461/87004-LL Automatic Actuation of Division I-

>

Emergency Core Cooling Systems (ECCS)

'

Oue to Hydraulic Surge Coupled with Air in Pressure Transmitter.

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461/88012-LL~

Failure to Adequately Control the Equipment l

Qualification Program Results in Inoperable i

Standby Gas Treatment System and Plant l

Shutdown-461/880I3-LL Faulty Card Select Decoder Causes Spurious Low Reactor Water Level Trip of Instrument

.

Air Isolation Valves During Drywell Pressure Channel Calibration.

l 461/88015-LL Incorrect Command During Channel Functional'

Test Leaves Flush Valve Partially Open and Results in Inoperable Off Gas Pretreatment

';

Radioactivity Monitor and Invalid Hydrogen Samples.

461/88023-LL Flush Valve Mispositioned by an'

Indeterminable Person Results in Inoperable Accident Range Gaseous Effluent Monitor.-

l 461/89002-LL Inability to-Meet Surveillance Requirements Due to Editorial Error Results in Initiation.

of a Technical Specification Required Shutdown.

461/89022-LL Failure of the Motor Driven Reactor Feedwater

_"

Pump Regulating Valve Results in a Level Transient and the Insertion of a Manual Scram Signal.

r 461/89028-LL Water Intrusion Into Main Power Transformer Sudden Pressure Sensor Relay Causes Corrosion

.

and Results in Relay Failure, Turbine-Generator Trip and a Reactor Scram.

c1 461/89042-LL Sensor System Design Causes False Reactor Core Isolation Cooling (RCIC) Steam Line Differential Pressure High Signal and RCIC Isolation.

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.

.,

,

7.

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'o No violations or deviations were identified, l

>

b.

Followup of Regional Requests (71707)

In a memorandum dated December 28, 1989, regional _ management described a number of problems which have occurred with safety relief valves

.

G RVs) including inadvertent blowdowns of reactor. pressure, valves (

failing to open at set pressures, and partial drywell flooding when SRVs had been removed, One potential cause of.SRV malfunction is

.

,

the introduction of contaminants into the SRV when the reactor vessel

,

level is raised above the main steam line. nozzles when there are no plugs installed or the plugs leak.

In the memorandum, the region

"

requested additional information regarding the Clinton SRVs. The ins >ectors provided the requested information following interviews t

wit 1 licensee personnel and document reviews.

"

No violations or deviations were identified.

.

9.

Meetings a.

ManagementMeetings(30702)

.

~ On January 9,1990, Mr. A. B. Davis, Regional Administrator, and members of his staff met at the site with Mr. W. Kelley, Chairman and CEO,' Illinois Power, and menters of his staff denoted in Paragraph 1 of this report.

This meeting was held to discuss j

current items of concern including failures of the Division I

'

diesel generator, service water heat exchanger corrosion, problems with the reactor water cleanup system, and an. increasing backlog of unresolved condition reports. Mr. S. Perry, Vice President, discussed

,

the-company's accomplishnents since the last meeting and led = an

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extensive discussion on-initiatives for 1990.

Initiatives discussed

^

included new programs for improving corrective actions, reducing the corrective' maintenance backlog, improving procedural compliance, y

instilling responsibility and a sense of; accomplishment, and

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assessing the licensee's progress in those improvements.-

=i

'b.

Exit Interview (30703)

~

The inspectors met with the licensee representatives denoted in Paragraph I at the, conclusion of the inspection on February 2,1990.

The inspectors summarized the purpose and scope of the inspection

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and the findings. The inspectors also discussed the likely

. informational content of the inspection report, with regard

.

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to documents or processes reviewed by the inspectors during the inspection.

The licensee did not identify any such documents

<

or processes as proprietary.

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