ML20195H159

Insp Repts 50-254/88-11 & 50-265/88-12 on 880422-0601. Violations Noted.Major Areas Inspected:Maint Activities & Followup on Previous Identified Insp Items Using Selected Portions of Listed Insp Modules

ML20195H159
Person / Time
Site:	Quad Cities
Issue date:	06/21/1988
From:	Falevits Z, Jablonski F, Kropp W, Walker H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20195H140	List: ML20195H134 ML20195H159
References
50-254-88-11, 50-265-88-12, NUDOCS 8806280231
Download: ML20195H159 (21)

See also: IR 05000254/1988011

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U.S. NUCLEAR REGULATORY COMMISSION

REGION III

Reports No. 50-254/88011(DRS); 50-265/88012(0RS)

Docket Nos. 50-254; 50-265 Licenses No. DPR-29; DPR-30

Licensee: Commonwealth Edison Company

Post Office Box 767

Chicago, IL 60690

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Facility Name: Quad Cities Nuclear Power Station, Units 1 and 2

Inspection At: Cordova, Illinois

Inspection Conducted: April 22-26, May 2-6, 11, 31 and June 1, 1988

Inspectors:

. s .AtL

. A. Walker //Sf/98'

Date /

W Krop

Date

k. 't F~~

Z. Falevits 6!M/Sf(

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Approved By:

+).c W W

F. J. Jablonski, Chief [/d/ /['

Maintenance and Outages Section 06te

Inspection Summary

Inspection on April 22-26, May 2-6, 11, 31 and June 1, 1988 (Reports

No. 50-254/88011(DRS); No. 50-265/88012(DRS))

Areas Inspected: Special announced inspection of maintenance activities

and follow-up on previous identified inspection itemi using selected

portions of Inspection Modules 62700, 62702, 92701, 92702 and 92720.

Results: Control in some of the areas inspected appeared to be weak.

Based on the inspection, the inspectors reached the following conclusions:

• Maintenance craftsmen / technicians appeared to be knowledgeable and

conscientious in their work;

• Improvements made within the last two years were noted-in several

maintenance areas.

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• Management involvement in maintenance was noted; however, the failure

to recognize the significance of noted problems, determine problem causes

and to take prompt and effective corrective action was evident.' This

was'especially true of similar equipment in the same or adjacent unit.

An example was the failure to determine the proper cause and correct

the problem with Unit 2 steam jet air injector off gas butterfly isolation

valves.after problems were noted with Unit 1 valves. Two violations were

written in this area. One of these contained four examples and the other

resulted in the inoperability of critical equipment for a substantial

period of time.

• Plant management was deficient in allowing known problems to continue

without correction or proper . evaluations. This was reflected in the-

items on corrective action. An example involvad operating far significant

periods of time with known grounds in the 125 VCC system. '.his practice

makes detecting and locating grounds that can defeat functioning of

important equipment difficult. One additional violation was written

on failure to perform a 50.59 review for an unanalyzed plant condition

involving the DC grounds.

• The preventive maintenance program was incomplete and improperly

implemented. Failure to perform PM on electrical switchgear is an example

of improper implementation. Management controls for status, priocitizing,

and tracking were not in place. Management was aware of this problem and

had taken some action. One violation with two examples was written in

this area.

• Design weaknesses resulted in one violation. This consisted of several

examples of inaccurate drawings for electrical switchgear. The lack of

design to provide the reactor operators with the operability status of

an engineered safety feature was also a concern.

• Audits of mai...enance appeared to be narrow in scope and shallow in

depth. The failure to note pre'ientive maintenance problems in audits

of maintenance is an example. One violation was written in this area.

• Violations identified during this inspection are discussed in

Paragraphs 3.1.3.1, 3.1.3.2, 3.1.5, 3.3.1.1.2, 3.3.1.1.3, 3.3.1.3,

3.3.1.4, 3.3.1.5, 3.3.1.6, and 3.3.2.2.

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DETAILS

1. Persons Contacted

Commonwealth Edison Company

• • • R. Bax, Station Manager

• • • D. Craddick, Master Electrician

J. Fish, Master Mechanic

• • D. Gibson, Supervisor Regulatory Assurance

• • • L. Petrie, Assistant Superintendent Maintenance

D. Rajcevich, Master Instrument Mechanic

• N.-Smith, Nuclear Licensing Supervisor, BWRs

• G. Spedl, Assistant Superintendent Technical Services

• • H. Studman, Director of QA

• • J. Wethington, QA Supervisor

• Indicates those personnel who attended the exit meeting on May 11, 1988.

• • Indicates those personnel who attended the exit meeting on June 1,1988.

• • • Indicates those personnel who attended both the exit meetings.

Other personnel were contacted as a matter of routine during the

inspection.

2. Licensee Action on Previous Inspection Findings

2.1 (0 pen) Violation (254/87009-01; 265/87009-01): Failure to deter .ne the

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cause and take appropriate corrective action on several licensee event

reports (LERs). The inspectors reviewed action taken by the licensee in

this area. Procedures QAP 1200-3, Revision 2, "Licensee Event Report i

Investigation and Review Process" and QAP 1200-1, Revision 10. "Deviation '

Report Procedure" were reviewed. Both required an investigation for cause

and corrective action as appropriate. . In addition to this, a training

program entitled "Root Cause Analysis" had been developed and presented

to a large number of licensee personnel. The course appeared to be

adequate; however, during this inspection several incidents were noted )

(reference Sections 3.3.1.3 through 3.3.1.6 of this report) which

indicated lack of adequate or timely corrective action. This item

remains open.

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2.2 1_ Closed) Violation (254/87009-02;265/87009-02): No procedure for

documenting and controlling LERs. The inspector reviewed QAP 1200-3,

Revision 2, "Licensee Event Report Investigation and Review Process"

and found that it provides the necessary procedural control for LERs.

This item is closed.

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2.3 (Closed) Open Item (254/87030-01; 265/87030-01): Discarding previous

usage cards of mechanical M&TE after receipt of a calibration report.  ;

The inspector reviewed current practices regarding usage records for i

mechanical M&TE and noted that records are discarded only when equipment i

is found to be within specified calibration tolerances. If the equipment

is found to be out of calibration, usage records are used to identify

components tested in order that an evaluation can be performed for l

acceptability or possible retesting. The inspector reviewed evaluations 1

of equipment for three pieces of M&TE found out of calibration tolerances.

No problems were identified with the methods and process. Calibration

data sheets are ietained as permanent .'ecords. The inspector has no

further concerns in this area. This item is closed.

2.4 (Closed) Open Item (254/87030-02; 265/87030-02): Possible inadequate

evaluation of usage of a torque wrench found to be out of calibration.

The inspector reviewed records for torque wrench QA No. 021159Q at the

electrical maintenance department. There was no objective.evidene in

the file that one of the two usages had been evaluated after the wrench .

was found to be out of calibration. Licensa personnel stated that some

notations on the records indicated this review had been performed; however,

it was not clear. This evaluation was per formed during the inspection and

the results provided to the inspector. No problems were indicated. Records

of action taken in five other instances where torque wrenches were found

to be out of calibration were reviewed and found to be acceptable. The

inspector has no further concerns in this area. This item is closed.

3.0 Evaluation and Assessment of Maintenance

The purpose of this inspection was to evaluate and assess the accomplishment

and effectiveness of maintenance activities at Quad Cities. The inspection

coincided with a planned outage of Unit 2. The evaluation and assessment

were accomplished by:

Evaluation of maintenance backlog.

Obsctvation of maintenance activities

Walkdown of Plant Systems

Review of completed work requests

Discussions with Licensee personnel

This inspection also assessed the quality verification processes

related to maintenance, which was accomplished by:

Review of audit reports

Review of corrective action documents

3.1 Accor.plishment of Maintenance

The inspectors verified that maintenance was accomplished by reviewing

maintenance backlogs, the methods used for controlling maintenance

activities (both correcCve and preventive) and by reviewing completed

work requests,

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In preparation for this inspection, the inspectors reviewed a number of l

1987 maintenance related Licensee Event Reports (LERs). No particular  ;

maintenance related weaknesses were noted with the technical assessment,

timeliness and effectiveness of corrective action, or root cause analysis

of the LERs.

Results of the inspection are documented in the following sections.

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3.1.1 Maintenance Backlog

The inspector noted that near the end of the inspection, there were

1604 open corrective nuclear work requests (NWRs). Of these 929

were non outage related with 675 outage related. In addition to

these, there were 680 open NWRs for PMs and there were 941 that

were for modifications. Unit 2 NWRs should continue to decrease

until the current Unit 2 outage.is over. The number of open NWRs

for corrective maintenance does not appear to be excessive; however,

the number of open PM related NWRs appears to b2 high.

3.1.2 Corrective Maintenance

Corrective maintenance was performed utilizing the NWR. Methods

for using the NWR and the control of corrective maintenance were

described in QAP 1500-2, Revision 29, "Work Request Procedure

for Station Maintenance." The procedure and implementation were

, reviewed and were noted to be acceptable. A number of problems

were noted in activities supporting this area which are noted in

other sections of this report. Methods for tracking and maintaining

the status and priorities of open NWRs should be improved to provide

more effective control,

t 3.1.3 Preventive Maintenance

Preventive Maintenance (PM) was described in QAP 500-9, Revision 2,

"Preventive Maintenance." This procedure described the overall

program which was divided in five basic areas; mechanical, electrical,

instrument and control, operations and chemistry. Each of these

areas had specific responsibilities which were described in individual

procedures. Quad Cities was in the process of converting from a

manual system of PM control to a computerized system. PM events

were included in the new system, but no historical information was

in the system at the time of the inspection. Presently, the system

cannot track past due PM events due to the lack of historical

information such as when the event was last performed. Detailed

information of this type was available for the manual system, but  ;

it was time consuming and difficult to retrieve. The inspectors '

were informed that as PMs are performed they would be entered in l

the computerized system, but there are no intentions to enter  !

historical data from past performances in the system. The PM l

program appeared to be difficult to track and control and was '

incomplete. Licensee personnel stated that a contractor had been

hired to review the program and make recomendations for improvements. ,

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This work was scheduled to be completed by December 31, 1988. There

did not appear to be a method in place to periodically identify the.

status of overdue PMs to management. The changes currently planned

should address this concern. This is an open' item to be reviewed

on a subsequent inspection (254/88011-01; 265/88012-01).

3.1.3.1 During the observation of maintenance repair activities, the inspector

noted that the thrust bearing was replaced on Limitorque actuator

for M0V 2-2301-9 (WR No. 65322). The inspector noted that little

of nc grease was on or in the bearings. A review of maintenance

history for the limitorque actuator did not indicate that greasing

of the bearing or other PMs had ever been performed. The Limitorque

vendor manual recommends that greasing of the bearing and other

PM tasks be perfomed every 18 months. Some PM tasD, for these

actuators were also recommended to be performed every 36 months.

The failure to )'rfom PMs on the limitorque operators is considered

to be an example of a violation of 10 CFR 50, Appendix B, Criterion V

(254/88011-02A; 265/88012-02A) in that, the procedures and instructions

for PMs on.the Limitorque actuators did not invoke the vendor

recommendations or provide a tecnnical justification for not

performing the vendor recommendations.

3.1.3.2- In reviewing a computer listing of past due electrical PMs, the

inspector noted that 47 of 93 horizontal 4KV breakers were overdue

for the PMs required by procedure QEPM 200-1, Revision 1, "Inspection

and Maintenance of 4KV Horizontal Circuit Breakers." Of these

required PMs, 32 had never been performed. One of the above

breakers was the Unit 2 EDG generator bus breaker which failed

to close on October 5, 1987, due to dirty and sticking trip latch

rollers. Cleaning and lubrication of these rollers were covered

in this PM. The failure to perform the circuit breaker PMs as

required is an example of a violation of 10 CFR 50, Appendix B,

Criterion V (254/88011-02F 265/88012-028).

3.1.3.3 During the PM review, the inspectors noted that a number of PMs

had been perfomed when PMs on what appeared to be more important

components had never been performed. Discussions with licensee

personnel indicated that no system existed to prioritize PMs

considering the importance of the component involved. This is

an open item (254/88011-03; 265/88012-03).

3.1.4 Review of Completed Work Requests

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Nineteen completed work requests were selected and reviewed. Of the

nineteen reviewed, nine had been closed by cancellation without work

being performed. Seven of the nine were cancelled because the work

request had been duplicated. The other two were cancelled after it

was determined that the problem did not exist. In discussing this

matter with licensee personnel, the inspector was informed that there

was no method in place to prevent duplication of work requests. The

duplication is noted and corrected at the time the work requests are

reviewed for issue to the field for work. Although the duplication

of work requests does not appear to be a safety issue, the writing j

and processing of almost twice the required number of work requests  !

has an impact on manpower rcquirements for control and processing of  !

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maintenance work. In addition to this, the inspector noted that two

of the work requests, cancelled because they were duplicated, were

cancelled after several years. This matter was discussed with

licensee personnel for their information since no regulatory

issue was involved.

The inspector reviewed the ten work requests for which work was

completed for identification of equipment, description of problem,

adequacy of work instructions, description of work performed,

replacement parts used, calibrated equipment used (if applicable),

required approvals in required sequence, and required reviews and

sign-offs. No problems or concerns were noted.

3.1.5 Engineering Support of Maintenance

The inspectors conducted a limited design and document control

review of documents associated with maintenance and modification

activities. In addition, the review included'as built drawings

compared to the actual plant configuration.

3.1.5.1 During the review and visual field inspection, the inspectors

identified a number of drawing discrepancies. Control circuits

shown on numerous 4.16 KV safety-related schematic diagrams have

been duplicated on internal schematic and device location diagrams

creating a system in which the same schematic circuit appears on

two different drawings. The inspectors identified omission and

errors on the duplicated r:hematics such as missing test switches,

and the wrong 4.16 KV cubicle designations. For example, "Diesel

Emergency Auto Start Relay" circuit shown on drawing No. 4E-13508,

revision AC, was also depicted on drawing No. 4E-1656H, Revision J.

However, the test switch (TS) was omitted from the circuit on drawing

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No. 4E-1656H, wFile the relay designations for ASR-1 relay and the

switchgear cubicle numbers for 127B14-1X3 (3-4) relay contact were

not shown on drawing No. 4E-1350B. Identical errors were noted on

the duplicated drawings associated with the Units'I and 2 and 1/2

Diesel Generator Auto start circuits. The licensee was informed

of the specific cases noted.

3.1.5.2 Wiring diagrams associated with 4.16 KV switchgear installatim :

(i.e., W/D 4E1655A) depicted only a portion of the actual interic'

wiring. A small note on the drawing references other drawings for

internal connections. This type of drawing leads to confusion

whereby, one might assume from looking at the internal side of

the termination blocks that no additional internal wiring exists.

3.1.5.3 The inspectors conducted a visual field inspection using the

electrical design drawings associated with Units 1 and 2,125VDC

ground detection system. The following drawings contained

discrepancies and did not conform to the field installations:

1. Drawing No. 4E-126858, Revision Y and No. 4E-2685B,

Revision S - did not represent the ground detection

circuity as it was installed in the field.

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2. S/D 4E-25755, Revision E - Annunciator Window No. 54 "125V

battery ground" circuity did not depict the negative ground

contact (11-12) in the alarm circuit.

10 CFR 50, Appendix B, Criterion III requires that design control

measures verify the adequacy of design. The numerous design.

document errors described above are considered to be a violation

of this requirement (254/88011-04; 265/88012-04).

3.1.6 Summary of Maintenance Accomplishment

Licensee procedures described the overal.1 maintenance

process in sufficient detail; however, additional procedures

or instructions were needed in some specific areas in order

to provide adequate instructions for maintenance work.

Management's ability to control some maintenance. activities ,

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appeared to be limited because of the difficulty or inability

in obtaining information on the status of maintenance items.

Administration of maintenance work appeared to be inefficient

as was evidenced by the excessive duplication of work

requests.

Considerable management attention must be directed towards

expanding and improving the preventive maintenance area. More

attention should be given to vendor. recommendations for PMs as

well as verifying that all necessary equipment and components

are included in the program.

The backlog of PM related NWRs appeared to' be high indicating

a possible lack of management attention in this area.

Accuracy verification of design drawings appeared to be

inadequate.

Two violations and two open items were identified in this

area.

3.2 Effectiveness of Maintenance

3.2.1 Observation of Work Activities

The inspectors reviewed work in progress for six nuclear work

requests. Craf t personnel performing the work were knowledgeable

and skills exhibited appeared to be adequate. Calibrated tools,

gauges and test equipment were used when required. Replacement

parts appeared to be correct and the parts were adequately

controlled.

During observation of the assembly of a limitorque valve actuator

under work request Q62322, the inspector noted that a piece of pipe

(approximately three feet long) was used on the wrench to tighten

bolts during reassembly. The work request required that assembly

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be performed per the vendor manual. -Torquing or tightening of these

bol & ras not addressed in the vendor manual.and there were no.

addnional instructioro in the work request. Failure to provide-

torquing instructions, especially in those cases where tightening

'is required in excess of riormal hand use of a wrench, appeared to

be inadequate work instructions. The: inspector noted that in this;

case excessive force did not appear to be exerted on these bolts.

During discussions with licensee personnel on..this matter, the

inspector was informec that the licensee was aware of.the need

for a torquing procedure and one was being developed. A_ draft

copy of this procedure was provided to the inspector. In addition,

the need for better work instructior,s had been recognized and plans-

had been made to increase the number of work analysts to provide

improvement in the area. The possible inadequacy of maintenance :

work instructions, especially in the mechanical area, is an open

item and will be reviewed during. subsequent inspections (254/86011-05;

265/88012-05).

3.2.2 Systems Walkdowns

To assist in an evaluation of the material condition of'the plant,

the inspectors walked down selected portions of the emergency

electrical systems and the residual heat removal (RNR) system for

Unit 1. The Unit 1 emergency diesel generator; 250Y, 125V, and

24/48V batteries and battery chargers; and 480V and 4150V switchgear

and motor control centers were included in the walkdowns of the

emergency electrical systems. The condition of the. electrical ,;

systems appeared to be adequate, however, several' questions and '

concerns were noted. These were satisfactorily resolved by the

licensee.

During the walkdowns of the RHR system, the inspectors ncted that

the area in the vicinity of a Unit No.1 RHR psmp contained litter

and debris. Scaffolding was also installed adjacent.to some RHR

piping. During discussions with licensee personnel,.the inspectors

were informed that the asbestos insulation was being replaced on

the RHR piping and this was the reason for the poor housekeeping as

well as the scaffolding. The inspectors have no further concerns

in this area.

3.2.3 Sunmary of Maintenance Effectiveness

Maintenance personnel performing repair work observed by the

inspectors appeared to be knowledgeable and thorough in their

work.

The inspectors concluded that the housekeeping and m'aterial

condition of the plant was adequate; however, attention is

needed to clesn up areas such as RHR when the insulation

replacement is completed. There should Le active plant

managerr.ent involvement in routine plant walkdowns to ensure

that housekeeping and the material condition of the plant-

are acceptable.

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One open item was identified in these areas.

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l 3.3 Licensee's Assessment of Maintenance (Quality Verification)

The inspectors reviewed audit records and records of actions taken l

on selected Licensee Event Reports (LERs) and Deviation Reports (DVRs)

to evaluate licensee assessment of maintenance.

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'3.3.1 Event Analysis and Cause Correction _

Several operational events or equipment failures were reviewed

to determine if maintenance was a contributing factor to the event

and to verify that the cause was properly determined and corrected, l

An evaluation was aise made of the timeliness and effectiveness of

the corrective action. Events were selected for review because they

either appeared to be repetitive or the nature of the event indicated ,

a possible maintenance problem. In most cases, the events were

documented on LERs or DVRs. Observations in this area' follow.

3.3.1.1 LER 87-01

Revision 1 of LER 87-01 documented the failure of the 1/2 emergency .

diesel generator (EDG) to automatically start during a test l

conducted January 3,1987, while Unit 2 was in the refueling mode.

This failure was the result of a blown negative fuse in the 125 VDC

auto stap circuit. The licensee identified the root cause as a  !

ground at a tie point in 4 KV Switchgear, Bus 13-1, Cubicle 1.

During the installation of Modification M-4-1/2-84-12, on February 3, j

1986, wires were incorrectly landed on a terminal point that was also l

used in the ground circuit for a current transformer. The licensee l

stated in the LER, that the wires had been landed at that tenninal l

point due to a design error on the electrical print used for.the j

installation of the modifications. LER-87-01 also identified that {

the post modification test completed on Marcn 1,- 1986, was successful l

as the 1/2 DG auto started as exoected.

The inspectors performed a detail review of various_ aspects of

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the event described in LER 87-01. As a result of this review, l

the following chronology was developed.

May 1985 - Modification M-4-1/2-83-9 was made by the Quad Cities

electrical maintenance (EM) department. This modification added j

annunciator relay 74-7 electrically in parallel with Auto Start

Relay (ASR) 1/2-2. The 74-7 relay was meant to duplicate

operation of ASR 1/2-2 and signal the control operator when the

1/2 DG automatically started from a Unit 2 auto start signal.

During the installation, the EM staff noted a wiring tennination

point error on drawing No. 4E-1655A and initiated FCR 4-85-16 to

correct the error.

February 3, 1986 - Modification M-4-1/2-84-12 was made by

the Site Substation Construction department and included the

ASR 1/2-2 circuitry depicted on drawing No. 4E-1655A; however,

FCR 4-85-16 had not been incorporated. It appears that the

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Substation Construction work crew was not aware of FCR 4-85-16

and utilized the uncorrected version of drawing 4E-1655A to

incorporate the modification. Substation Construction received

drawings for modifications from S&L and was not required by l

procedures to verify with station's document control.-to I

determine if there were outstanding FCRs against the drawings.

As a result, the ASR 1/2-2 circuitry was inadvertently modified

-as follows:

1. The 74-7 relay was rem 0ved from the circuit;

2. A negative leg of the ESS Div 1 battery was connected .

to station ground through the control fuse that supplied

control power to the 1/2 DG ASR 1/2-2 relay coil.

February 13, 1986 - Sargent & Lundy, the architect-engineer,

fomarded by express mail a copy of Drawing No. 4E-1655A, which .

incorporated FCR 4-85-16 to the. Quad Cities site. The transmittal

letter noted the design error in the wiring termination points;

however, no apparent action was taken by Quad Cities Site. Substation

Construction personnel to correct the errors previously

made by the Substation Construction crew on February 3,

1986.

February 27, 1986 - The 1/2 DG was returned to service

(R/S) in preparation for the post modification testing

of Modification M-4-1/2-84-12. Prior to the R/S of the

1/2 DG there was a 120 VDC positive ground indicated on

the Unit 1 battery ground detector. Also, control room

annunciator (901-8, B-9), "125 Volt DC Ground," was in the

alarmed state. When the 1/2 DG was R/S the ESS Div 1 battery

ground detector imediately indicated a 120 VDC negative

ground because of the inadvertently installed ground on-the ,

ASR 1/2-2. However, since the 125 DC ground annunciator was  !

already activated due to the existence of various.other i

grounds, the operators were not made aware that a 120 VDC i

negative ground existed in the circuitry of the 1/2 DG

ASR 1/2 circuitry.

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February 28, 1986 - A post modification test was performed  !

for Modification M-4-1/2-84-12. ' Step 17, in Part B, required )

verification that relays ASR 1/2-2 and 74-7 pickup (energize)  !

from a 1/2 DG auto-start signal. The test report indicated

that relay 74-7 did not pickup; however, the test results were

accepted by the reviewer because the ASR 1/2-2 did pickup and

the 1/2 DG auto started. A note on the test data sheet indicated

that the 74-7 relay was only to the annunciator for the 1/2 DG

auto start. There was no apparent investigation by the licensee

to determine why relay 74-7 did not pickup. It is surmised that

an investigation would have revealed the wiring errors, ircluding

the one which resulted in the inadvertent grounding of the

ASR 1/2-2 relay.

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June 26, 1986 - For approximately two hours the Unit 1 Ground

Detector indicated approximately 20 V. The inspector co;ld not

determine the reason why the 125 VDC negative ground was not

indicated for these two hours.

July 11,1986 - A review of the ESS DIV I 125 VDC Ground

Detector strip charts showed that except for the two hour

period on June 26, 1986, a 125 VDC ground existed on the

negative bus of ESS DIV I from February 27 to July 11, 1986,

when Ground Detector indication changed to approximately 20 VDC

ground. This change coincided with replacing an ATWS inverter

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that had been previously identified in October 1985 as the

cause of the 75 VDC negative ground in the inverter pre-filter

circuit. A review of the Ground Detector strip charts from

July 11-30, 1986, shewed that a 125 VDC negative ground did

not exist; therefore, it is concluded that the negative fuse

for the ASR 1/2-2 circuitry was blown prior to July 11, 1986.

The exact date the fuse blew could not be determined because

of poor operating methods that allowed a series of various

positive and negative grounds to exist, such as the ATWS

inverter which masked the 120 VDC ground in the ASR 1/2-2

circuit.

January 3,1987 - At 0830, the 1/2 DG failed to auto start while

performing Core Spray Logic testing. Cause of the failure was

a blown fuse in the negative leg of ASR 1/2-2 control

circuit 1/2-2.

Based on the facts in the chronology described above, the inspectors

determined:

3.3.1.1.1. Sometime prior to July 11, 1986, the negative fuse for

the ASR 1/2-2 control circuit blew. It is sunnised that a ,

momentary ground occurred in the positive leg of the 125 VDC l

battery. This momentary positive ground shorted the battery

through the 15 amp negative ASR 1/2-2 circuit control fuse and

caused that fuse to blow. This removed the ground and rendered I

the automatic start feature for the 1/2 DG Unit 2 inoperable.

The control room operator was not aware of this condition since

the design of the ASR 1/2-2 circuit did not identify a loss of ,

power to the operators.

]

IEEE Standard 279, draft 1968, describes criteria for l

protection systems of nuclear power plants including signals i

that actuate engineered safeguards systems and components.

Paragraph 4.20 of that standard requires that the design of

the protection system provide the operator with accurate,

complete, and timely information pertinent to the status

of the protective circuit. Due to the initial design error,

the loss of control power to the ASR was not made known to

the control room operator. Loss of the auto-start capability

would not have been detected under normal circumstances of

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demonstrating DG operability manually, because the manual and )

automatic circuits were electrically isolated from each other.

This is considered an open item pending further licensee and NRC

review. (254/88011-06;265/88012-06)

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3.3.1.1.2 The hard ground, inadvertently installed during

Modification 4-1/2-84-12, on February 3. 1986, was masked by

various other negative grounds. -From February 27 to July 11,

1986, the licensee did not periodically isolate these known

grounds to ascertain if other grour.ds had developed on the

125 VDC battery system.

In sunrnary, the 1/2 emergency diesel generator was incapable

of automatically performing its intended safety function for

greater than six months (July 11, 1986

due to an undetected failure (blown control power fusethroughJanuary)3 in the

circuitry of the automatic start relay (ASR). Technical

Specifications 3.9.E.1 action requirement specifies reactor

shutdown in 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> if OG operability cannot be restored in

seven days. Therefore, operating Unit 2 without the auto-start

feature of the 1/2 DG for greater than seven days is considered

a violation of Technical Specification 3.9.E.1 (254/88011-07;

265/88012-07).

3.3.1.1.3. In reviewing the various system grounding problems,.the inspectors

noted that FSAR Section 8.2.3.2.2 stated "The 125 volt battery

system operates ungrounded with a ground detector alarm set

to annunciate the first ground. In addition, the ground fault

resistance and the time at which a ground fault occurs is

recorded by a recording voltmeter. Thus, multiple grounds,

the only reasonable mode failure are extremely unlikely."

10 CFR 50.59(b)(1), requires that licensee records include

a written safety evaluation which provides bases for the

detennination that changes in the facility, as described

in the safety analysis report, do not involve an unreviewed

safety question.

Contrary to the above, the licensee did not have a written '

safety evaluation for various grounds which existed between

February 22 through July 11, 1986, in the ESS DIV 1 125 volt

battery system. These grounds masked the ASR 1/2-2 ground that

ultimately caused the failure of the automatic start feature of

the 1/2 Emergency Diesel / Generator and the inoperability of the l

Diesel / Generator for six months. This is a violation  :

(254/88011-08; 265/88012-08).

The grounding problem is considered significant for the l

following reasons:

Contingency actions were not performed to monitor

grounds on the 125 VDC battery on a periodic basis between

February 27, 1936 to July 11, 1986. Since various grounds l

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were known to exist, the licensee did not isolate these

grounds to ascertain if other grounds had developed on

the 125 VDC battery.

No action was taken by the Site Substation Construction

department in response to the S&L Express Mail transmittal

that depicted the changes needed to correct the field wiring

errors shown on Drawing No. 4E-1655A;

Results of post modification tests of the ASR circuit

indicated that something was wrong with the mooification

as made, but no investigation was made to determine the

cause of the failure and the 1/2 DG was declared operable.

The manual start feature of the 1/2 DG is not reliable

since the starting of a RHR pump could trip the 1/2 DG

on underexcitation when the DG is not in parallel with

the grid (see Paragraph 3.3.1.3.).

Contrary to the FSAR conmitment (Section 8.2.3.2.2), the

licensee operated the 125 volt hat,tery between February 27

and July 11, 1986, with various grounds without taking

compensatory action.

3.3.1.2 DVR 1-87-039

On May 6, 1987, Units 1 and 2 were at 98 and 100 percent power,

respectively, when the "Diesel Generator (DG),1/2 Relay Trip" alarm

was received on the Unit 1 control room panel. It was determined

that the lockout. relay tripped and the "A" phase differential current

relay had activated. This event was documented on DVR 1-87-039.

The corrective action stated on this DVR referenced two

Modifications, M-4-1(2)-85-26 and M-4-1/2-85-7. These modifications

were initiated prior to this event to replace all the DG differential

relays with Westinghouse type SA-1 relays which were seismically

qualified and less susceptible to spurious trips due to vibration.

DVR 1-87-039 identified a similar event which was reported on

LER 86-007 on February 28, 1986. The inspector determined that the

differential relays installed were General Electric (GE) Model 12CFD.

These relays were addressed in NRC Information Notice (IN) 85-82

dated October 18, 1985. This notice stated that a GE test report

showed the 12CFD differential relay had only been successfully tested

for .759 in the de-energized mode. The inspector also determined

that the GE Model 12CFD relay was a subject of INP0 Significant Event

Report (SER) 18-84.

Modifications M-4-1(2)-85-26 and M-4-1/2-85-7 were initiated to i

resolve IN 85-82 and INPO SER 18-24. These modifications required

the GE 12CFD relays, to be replaced with Westinghouse tyoe SA relays,

lhe GE 12CFD differential relays were planned for replacement for

the Unit 2 and Unit 1/2 DGs during the Unit 2 outage that was underway

during this inspection. However, the licensee was planning to replace '

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the Unit 1 DG GE 12CFD differential relays during a June 1989, Unit 1

outage. The inspector was concerned that a potentially non-seismically

qualified differential relay would.be installed in the Unit 1 DG until

June 1989. During discussion between licensee, NRC Region III and

NRR personnel, the following was agreed upon:

A letter from the licensee's engineering organization will be

placed in Modification packages M-4-1(2)-85-26 and M-4-1/2-85-7

that states the installed GE 12CFD differential relays would

perform during a seismic event.

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The Unit 1 DG GE 12CFD differential relays would be replaced

with Westinghouse SA 1 relays at the first opportunity.instead

of during the Unit 1 June 1989 outage.

The replacement of the GE 12GFD differential relays in accordance

with Modifications M-4-1(2)-85-26 and M-4-1/2-85-7 is considered an

open item pending further NRC review. (254/88011-09;265/88012-09).

3.3.1.3 LER 86-032

LER 86-032 documents an event which occurred on November 8, 1986,

when the 1/2 DG was manually started and connected to Bus 13-1 to

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provide power to Unit 1 during modifications work in the electrical

switch yard. When the 1A RHR pump was started to provide shutdown

cooling flow, t6 1/2 DG feed breaker to bus 13-1_ tripped, due to

the arming of the underexcitation relay.

Due to a change in personnel in the licensee's Technical Staff,

the corrective action from the licensee's corporate engineering

staff was not received until March 21, 1988. At the time of this

inspection, the corrective actions had not been reviewed by the

plant's technical staff. The inspectors reviewed the proposed

corrective actions and determined that they were inadequate. The

March 1988 proposed corrective action for LER 86-032 referred to a

November 4, 1982 letter, that outlined the corrective actions for

LER 82-012. The event described in LER 82-012 pertained to tripping

of the 1/2 DG feed breaker to Bus 13-1 when the RHR Service Water Pump

was started. However, the precursors to the event described in

LER 82-12 were different than in LER 86-032. During the event

in 1982, the 1/2 DG had auto started due to' loss of offsite power

where as; the 1/2 DG was manually started during the event described

in LER 86-032. The corrective acticns to LER 82-012 consisted of  ;

the auto-start relay circuit being modified to "seal in," thus l

removing the protection feature of under excitation as required

by the FSAR even if the conditions that caused the auto-start were l

removed. Therefore, the modification to the auto-start circuit was '

not acceptable corrective action for the event described in

LER 86-032 since that event involved the manual starting of the

1/2 DG. The lack of having established corrective actions for

LER 86-032 (November 1986) is untimely and is considered a violation

of10CFR50,AppendixB,CriterionXVI(254/88011-10A;265/88012-10A).

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3.3.1.4 DVR 87-91

During a monthly surveillance test on October 5, 1987, 4 KV breaker

152-2329, which connects the 1/2 diesel with bus 23-1, failed to

close. The root cause was identified as dirty and sticking trip

latch rollers. The sticking trip latch in the breaker did not catch

and hold the breaker closed. The corrective action included cleaning

and lubricating the trip latch rollers of breaker 152-2329, per a '

electrical preventive maintenance (PM) procedure. The DVR stated

that this preventive maintenance program was started in 1985 and all

of the 4 KV breakers had not yet received their initial cleaning and

lubrication. During this inspection, the inspector reviewed the

status of the PM for 4 KV horizontal breakers as defined in

procedure QEPM 200-1, Revision 1, "Inspection and Maintenance of

4 KV Horizontal Circuit Breakers." This procedure addressed.the

cleaning and lubrication of the trip latch mechanism.

The inspections in QEPM 200-1 were required every 300 operations

or every three years, whichever occurs first. Based on information

from the licensee, approximately 47 4 KV horizontal breakers were

overdue. Of these 47, 32 had never been subjected to the

requirements of QEPM 200-1. One of the 32 4 KV breakers was for the

Unit 2 DG. Therefore, the corrective actions for DVR 87-91 was

untimely since the licensee had not inspected the Unit 2 DG 4 KV

breaker trip latch mechanism subsequent to October 1987 when the 1/2

DG breaker failed to close due to a dirty and sticking trip latch

mechanism. This failure to provide timely corrective action to

correct the latch mechanism problem is considered to be a violation

of 10 CFR 50, Appendix B, Criterion XVI (254/88011-10B; 265/88012-10B).

During this inspection, the inspectors inspected the trip latch

mechanism for the Unit 2 DG 4 KV breaker. The mechanism was clean

and not sticky. The inspectors also inspected four other 4KV breakers. l

Three of these breakers had recently been cleaned and lubricated per

QEPM 200-1. No problems were noted. However, the breaker for the

2B Core Spray Pump, which had not yet been subjected to the cleaning

and lubrication requirements of QEPM 200-1, was inspected. Two

of the three trip rollers that were accessible would not rotate

due to hardened grease. These two rollers were not critical to

the operations of the breaker per the vender representative. However,

the reliability of the trip latch mechanism was questionable. This  ;

breaker was scheduled for QEPM 200-1 during the Unit 2 outage. This i

failure to perform required preventive maintenance as defined in '

licensee's procedure QEPM 200-1 and the vendor's manual (VETI-C029)

has been previously discussed in Section 3.1.3.2 of this report.

3.3.1.5 During a review of deviation reports, the inspector noted that

several DVRs issued in 1987 pertained to auxiliary contacts in

480 volt motor control centers (MCC). In all cases, the cause was

determined to be binding of the auxiliary contacts. The corrective

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action further stated that Quad cities had experienced binding of

auxiliary contacts in the past. LER 87-016 identified the previous

events that were caused by binding of auxiliary contacts.

On July 30, 1987, the station electrical maintenance department

received two General Electric (GE) Instructions for auxiliary

contacts from the licensee's Dresden plant. GE instruction,

GEJ-5277A, delineates steps for the changeout of the auxiliary

contact plunger arm and insulation. This instruction was dated May

1984, and identified that the plunger guides should have a thin coat

of Aero Shell No. 7 grease. The licensee stated that the previous

lubrication used by GE had left a white film on the plunger guides

that could cause binding of the auxiliary contacts. The other GE

instruction, GEJ-2877D, pertained to the installation of Auxiliary

Contact Kits. These instructions also stated that a fiber washer I

should be installed between the auxiliary contacts. Absence of  !

this washer could also cause bonding of the auxiliary contacts.

The licensee concluded that the binding of auxiliary contacts would

be prevented if the plunger guides were lubricated with Aero Shell

No. 7 and the fiber washers were installed between the auxiliary i

contacts. The inspector requested that the licensee submit a '

revision to LER 87-016 describing this corrective action to resolve l

the bindini of the auxiliary contacts. Since the problem with the

binding of the auxiliary contacts had been occurring for several i

years, the failure to identify the corrective action until July l

1987 was untimely and is an example of a violation of 10 CFR 50, 1

Appendix B, Criterion XVI (254/88011-10C; 365/88012-100). j

The licensee had initiated Nuclear Work Requests (NWR) in September

1987 for Unit 1 and January 1988 for Unit 2 for lubricat"an of the i

auxiliary contact plunger and the installation of the film washer. l

The inspector reviewed three NWRs and determined that proper

instructions and post maintenance tests were included. The

licensee's plan for implementing these NWRs was based on l

the EQ surveillance schedule for each of the MCCs.

3.3.1.6 Improper Assembly of Butterfly Isolation Valves

On May 26, 1988, the licensee raported to the NRC that a Unit 2

butterfly isolation valve (No. 4501-8) for the steam jet air injector

off-gas system had been improperly assembled and would have opened

on an isolation signal rather than closed. Two of these valves were

installed in parallel in the condermte system of each unit to

isolate the condenser vacuum pump and prevent off-gas radiation

release in case of a main steam line hig,' radiation condition during

startup. Due to operating difficulties, to originally installed

gate valves were replaced with the existing Outterfly valves by

modification in 1984. Unit i valves were replaced in July and Unit 2

valves were replaced in February. No problems were noted with the

Unit 2 valves after replacement; however, an inability to obtain

condenser vacuum indicated a problem with Unit I valves. The

Unit i valves were found to be improperly assembled. Valve position

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-indicators were located 90 degrees from the proper position. When

the valves _were indicating open, they were actually closed and when

they-indicated closed, they were open. The problem was corrected

for the Unit i valves. Unit 2 was not considered a problem since

no problems with condenser vacuum had been noted.

'During discussions with licensee personnel, the inspectcr was

told that a subsequent failure of the radiation sensor for Unit 2

resulted in actuation of these valves without a loss of condenser

vacuum. This was at+.ributed to leakage by the valve' seat which.

initiated the valve cisassembly and resulted in the discovery of

the improperly assembled valve. The inspector was also told

that there had been no maintenance performed on the four valves

since the installation in 1984.

Because of this problem, Unit 2 operated from February 1984 until

the present outage with an inability to isolate the condenser vacuum

pump to prevent off gas radiation releases during reactor startup.

The safety impact of the condition appeared to be minimal since the

valves only provide isolation during startup when danger of fuel

cladding damage is low. Also high radiation levels in the steam

lines would close the main steam isolation valves providing

isolation in this manner.

This problem appears to have been caused by several contributing

factors. These are as follows:

Inadequate work instructions which failed to require verification

of valve position prior to installing position indicators. This

has now been addressed for butterfly valves. This is another

example of inadequate work instructions which is addressed as

an open item (254/88011-05; 265/88012-05) in Section 3.2.1 of

this report.

Failure to properly verify operability of a component after

installation. This is another example of a condition noted

in Section 3.3.1.1 of this report.

Failure to determine root cause and correct a significant

condition adverse to quality. The lack of proper action

occurred at the time the same type problem was noted on Unit 1

and also at the time of the failure of the radiation sensor

sometime later. This is another example of a violation of

10 CFR 50, Appendix B, Criterion XVI (254/88011-10D;

265/88012-10D).

Possible inadequate QC coverage of the installation. QC hold

and witness points were primarily.in the welding and fit-up

area and did not seem to address the valve instal _lation and

connection. This matter is unresolved and will be reviewed

during a subsequent inspection (254/88011-11; 265/88012-11).

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As the result of this problem, the licensee took the following

actions:

Verified or established methods and short term schedules to

verify proper operation of all safety-related butterfly

valves for both units.

Issued instructions for the installation and maintenance of

butterfly valves fo verification to ensure proper orientation

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of the valve position and the position indicator.

3.3.2 QA Audits of Maintenance

The inspectors reviewed records of_nine QA audits conducted on

maintenance or supporting activities during the past year. One

of these audits (QAA-87-55) was an audit developed to cover overall

maintenance activities; four of the audits were product audits which

covered specific activities involving some maintenance related

activities, the other two were surveillances which were upgraded

to audits because of problems noted. During the review of the

audit records the following observations were made.

3.3.2.1 Audit QAA 04-88-43

Audit QAA 04-88-43 was conducted on March 3, 1988, and was originally

a surveillance. The surveillance was upgraded to an audit because of

the significance of the finding. Discussions with licensee personnel

indicate that it is normal practice to upgrade surveillances to

audits if significant findings are noted in order to provide higher

management visibility of the problem. The inspector was assured

that these audits are not substituted for normal scheduled audits.

During this audit, the auditor identified a problem with the failure

to perform lubrication of electrical equipment. The finding states,

"Review of the Electrical Maintenance Lubrication Program noted that

approximately ten percent -(10%) of the 1987 annual lubrication

schedule and three percent (3%) of the biennial lubrication schedule

had been performed." This means more than 90 percent of the

electrical lubrications scheduled in 1987 were not performed. This

item will be followed as an open item to be reviewed on a subsequent

inspection (254/88011-12; 265/88012-12).

3.3.2.2 Audit QAA 04-87-55

Audit QAA 04-87-55 was an audit of the maintenance program conducted

November 30 to December 4, 1987. The scope of the audit, as

described in the audit plan, included preventive maintenance (PM).

There were no findings on PM and a statement in the report indicated

that PMs were completed on time. This statement did not appear to be

consistent with the inspectors findings on this inspection and -the

licensee finding described in Paragraph 3.3.2.1. A review of the

checklists and other documents in the audit records did not indicate

that implementation or performance of the PM program was reviewed.

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During discussions with the lead auditor, the inspector was informed

, that possibly as many as four or five items in the PM program

! (primarily EQ items) were reviewed to verify implementation. There

was no record of this. Criterion XVIII of 10 CFR 50, Appendix B

requires that audits be perTormed to "verify compliance with all

aspects of the quality assurance program and to determine the

effectiveness of the program." Contrary to this requirement,

audits were not performed to verify compliance with and determine

the effectiveness of the documented PM requirements. This is a

violation (254/88011-13; 265/88012-13).

3.3.3 Summary of Maintenance Assessment

Maintenance assessment appearrd to be ineffective in the areas

reviewed. Lack of proper investigation for problem cause was

evident.

In some cases, investigations were not conducted and in others

they were not thorough. A training program has been developed

in this area and should provide improvement if management *

emphasis in the area is evident. A sense of urgency.to correct

significant problems on similar equipment or the adjacent unit

was lacking.

QA audits of maintenance seem to be narrow in scope and shallow

in depth. The extent of the audits with the five day time

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limitations presently imposed for audit completion seemed to

ensure inadequate coverage. Audits, as presently conducted,

do not provide a useful management tool for maintenance

assessment.

Three violations, one unresolved item and three open items were

identified in this area.

3.4 Conclusions

Based on the activities described in this report, the inspectors

concluded that:

Maintenance craftsmen / technicians appeared to be knowledgei .e and

conscientious in their work;

Improvements made within the last two years were noted in several

maintenance areas.

Management involvement in maintenance was noted; however, the

failure to recognize the significance of noted problems, determine

problem causes and to take prompt and effective corrective action ,

was evident. This was especially true of similar equipment in the.

same or adjacent unit. Two violations were identified in this area.

One of these contained four examples and the other resulted in the

inoperability of critical equipment for a substantial period of

time.

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Plant management was deficient in allowing known problems to

continue without correction or proper evaluations. This is

reflected in the item on corrective action. One additional

violation was identified on the failure to perform a 50.59

review for an unanalyzed plant condition.

The preventive maintenance program was incomplete and improperly

implemented. Management controls for status, prioritizing, and

tracking were not in place. Management was aware of this problem

and had taken some action. One violation with two examples was

identified in this area.

Design weaknesses resulted in one violation. This violation

documented several examples of inaccurate drawings. An inadequate

design was also noted in the lack of the design to provide the

reactor operators with the operability status of an engineered

safety feature.

Audits of maintenance appeared to be narrow in scope and shallow

in depth. One violation was written in this area.

Apparent inadequate staffing was noted in some areas such as job

analysis.

In some cases work insttuctions were lacking or needed improvement.

4.0 Open Items

Open items are matters that have been discussed with the licensee, which j

will be reviewed, further, and involve some action on the part of the NRC j

or licensee or both. Open items identified during the inspection are 1

discussed in Paragraphs 3.1.3, 3.1.3.3, 3.2.1, 3.3.1.1.1, 3.3.1.2, and 1

3.3.2.1.

5.0 Unresolved Items j

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Unresolved items are matters about which more information is required

in order to ascertain whether they are acceptable items, violations,

or deviations. An unresolved item disclosed during this inspection

is included in Paragraph 3.3.1.6.

6.0 Exit Meeting

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

on May 11, 1988, at the Quad Cities Plent and summarized the purpose,

scope, and findings of the inspection. After some additional inspection,

a second meeting was held on June 1, 1988. The inspectors discussed the

likely informational content of the inspection report with regard to

document or processes reviewed by the inspectors during the inspection.

The lic<:nsee did not identify any such documents or processes as

proprietary.

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