ML20216C260

Insp Repts 50-254/97-28 & 50-265/97-28 on 971224-980210. Violations Noted.Major Areas Inspected:Operations,Maint & Engineering

ML20216C260
Person / Time
Site:	Quad Cities
Issue date:	03/06/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20216C246	List: ML20216C241 ML20216C253 ML20216C260
References
50-254-97-28, 50-265-97-28, NUDOCS 9803130354
Download: ML20216C260 (32)

See also: IR 05000254/1997028

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U. 8. NUCLEAR REGULATORY COMMISSION

REGION 111

Docket Nos: 50-254;50-265

License Nos: DPR-29; DPR-30

Report No: 50-254/97028(DRP); 50-265/97028(DRP)

Licensee: Corr,aonwealth Edison Company (Comed)

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

Location: 22710 206th Avenue North

Cordova, IL 61242

Dates: December 24,1997 - February 10,1998

Inspectors: C. Miller, Senior Resident inspector

C. Lipa, Senior Resident inspector (DAEC)

K. Walton, Resident inspector

L. Collins, Resident inspector

M. Holmberg, Reactor inspector

R. Ganser, Illinois Department of Nuclear Safety

Approved by: Mark Ring, Chief i

Reactor Projects Branch 1

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9803130354 980306

PDR ADOCK 050002t

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EXECUTIVE SUMMARY

Quad Cibes Nuclear Power Station, Units 1 & 2

NRC inspection Repost No. 50254/g7026(DRP); 50-265/g7028(DRP)

This inspection included aspects of licensee operations, engineering, maintenance, and a' ant

support. The report covers a six-week period of resident inspection.

Operations

. Technician error, inadequate communication and the misinterpretation of a procedure led

to the unexpected start of the Unit 1 emergency diesel generator (EDG). Licensee

investigation of operator performance during the event was insightful (Section 01.2).

. Two optors, using the licensee's independent verification methods, failed to establish

correct cooling watsr valve position for the Unit 2 EDG, renc'ering it inoperable during

some of the time that the Unit 1 EDG was also inoperable (Section 01.3). In addition, .

two individuals preparing a retum to service package caused a Unit 2 EDG air start valve

to be out of the reauired position. These events were indicative of a weakness in

independent verification (Section O2.1).

• The licensee did not proactively prepare for the effects of cold weather on equipment

deemed important to safety (Section 01.4).

. The licensee did not compiete a 10 CFR 50.5g evaluation for the change in the status of

the normal ventilation fan to the shared EDG room. This was considered a failure to

maintain the plant configuration in accordance with the Updated Final Safety Analysis

Report (UFSAR) (Section O2.1).

. The inspectors were concemed with the quality of system engineering walkdowns which

could result in conditions adverse to quality not being identified. (Section O2.1).

Maintenance

2 During a surveillance test, the inspectors noted the procedure adherence policy was not

followed. The inspectors also found problems with the use of independent vertfication

methods (Section M1.2).

. The licensee d!scovered that all three EDGs had out-of-tolerance time delay relay

settings. The maintenance work history showed that preventive maintenance to calibrate

the relays was not performed per the established schedule, and relays in the past had

exhibited a high failure rate (Section M1.3).

. Lack of control of foreign material (electrical tape) resulted in a condition which could

have adversely affected EDG performance and may have contributed to 'he failure of the

EDG to start. The licensee's investigation of this particular aspect of the event was

initially incondusive and did not include recommended corrective actions to prevent >

recurrence (Section M4.1).

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• 1he inspectors identified that weaknesses existed in documenting work history

informatum previously provided by a vendor. In addition, wiring errors resulted in a

safsty-is;eted system being inoperable longer than scheduled (Section M4.2).

• The quality control (QC) organization implemented overview inspections to replace non-

mandatory hold points in maintenance activities. The Quad Cities Maintenance staff did

not substitute the verificaten of hold point activities with maintenance supervisor

verifications as initially intended by management (Section M7.1).

Engineerina

• The lack of follow-through on long-term EDG improvement plans was a weakness made

more significant by recent EDG failures (Section E1.2).

• The inspectors concluded there were instances where engineering evaluations were not

completed or were not of sufficient quality in areas such as snubber requirements, EDG

ventilation, and electromatic relief valve vibration issues. However, the inspectors noted

instances where engineering support of maintenance activities for the radweste system

was good and some aspects of troubleshooting for an electromatic relief valve failure

were good (Section E2.1).

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Report Details

Summary of Plant Status

Both Unit 1 and Unit 2 were in cold shutdown during e.:!nspection period. The licensee

continued to develop the safe shutdown analysis and implementing procedures for both units

associated with 10 CFR Part 50, Appendix R " Fire Protection."

1. Operations

01 Conduct of Operations

01.1 General Comments (71707)

During the period, both the inspectors and the licensee identified configuration control

deficiencies, human performance issues, and continued problems with emergency diesel

generator (EDG) dependability and operability. All three EDGs experienced relay failures.

The Unit 1 EDG failed to start due to unkncwn causes.

Plant configuration was not maintained in accordance with operating valve lineups or in

accordance with the Updated Final Safety Analysis Report (UFSAR) in some cases. One

configuration error involved tagging the shared EDG ventilation room fan out of service

without evaluating the condition in accordance with 10 CFR 50.5g. Some of the

configuration problems were attributed to human errors; such as the Unit 2 EDG

becoming inoperabie due to a mispositioned cooling water valve. A second example '

involved a valve out of position in both the Unit 2 and shared EDGs, which did ed affect  !

system operability. Both the inspectors and the licensee identified weaknesses in 1

operators implementing independent verifications. Also, operator control of system lineup  !

configuration and use of system lineup procedures was weak in one instance.  !

01.2 C Jerator Performance Durina Unit 1 Ememency Diesel Generator Autostart

a. Inspection Scope fg2700)

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The inspectors reviewed the circumstances surrounding an unexpected start of the Unit 1

EDG. The initial investigation revealed that the EDG had initially failed to start after

receiving a start signal, but then unexpectedly started after operators cleared the alarms.

The inspectors reviewed the human performance aspects of this event. Other issues

regarding the EDG failure to start are covered under Sections M4.1 and E1.2.

b. Observations and Findanas

On January 5,1998, during the completion of logic testing involving the core spray

system, an electrician inae.ortently bumped the 1-1430127B relay which provided a start

signal to the Unit 1 EDG. Operators in the control room received two alarms immediately,

"DG [ diesel generator) 1 Trouble" and "DG 1 Autostart/Autostart Block," which were

indicative of an autostart demand. Sixteen seconds later operators received the alarm,

"DG 1 Fall to 8 tart," indicating that the EDG had failed to start.

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The coniiGI rut. operator directed an equipment operator (EO) to reset the EDG while

unaware that a start signal remained in the circuitry. The reset caused an unplanned

start of the EDG. Following initiation of the start signal, some operators were not aware

that the diesel had attempted to start, but failed to start. At this point, all actMties in the

control room were not stopped for a briefing as expected by operations departmord

management for abnormal events. Stopping and investigating the cause of the alarm I

condition, rather than resetting the EDG alarm, would have helped operators avoid an

inadvertent EDG start and might have helped to identify the cause of the EDG start

failure.

The licensee's root cause investigation into operator performance during this event waJ

thorough and the licensee determined that communications between the unit supervisor,

licensed operators, and electricians performing the core spray system logic testing was

inadequate. For example, control room operators were unaware that an electrician had '

bumped the relay causing the EDG start signal until approximately 15 minutes after the

alarms were received. Also, communications between the control room operator and the '

unit supervisor were not sufficiently clear to prevent the autostart of the EDG. The root

cause of the inadvertent start was determ8ned to be misinterpretation of a procedure by

the control room operator. The abnormal procedure for an EDG start failure used by the

operators covered " valid" start signals, whe eas the signal generated was " invalid." The ]

root cause team concluded that no procedure covered this situation, and the correct

response was to stop and initiate actions to investigate the source of the alarms.

Corrective actions included training, ccunseling, and procedure revisions.

Earty in the event, the unit supervisor indicated that alarms received at the onset of this

event were similar to an r.larm pattom operators had previously observed during auxiliary

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power transfers. This alarm pattom falsely indicated an EDG autostart and had been

observed oy operators bth in the plant and in the simulator. During the unit supervisor's

response to the similar alarm pattom observed in this event, he incorrectly believed that

the EDG should not have attempted to start. The inspectors questioned whether the

licensee had performed an assessment of the alarm circuitry to evaluate whether the

erroneous alarm pattem could be corrected. The licensee had rd done so, but rather

had accepted that this misleading alarm pattem had been adequately assessed in the

past. Subsequent to the inspectors' question, the licensee initiated an effort to determine

the validity of the existing circuit condition.

c. Conclusion

inadequate communications between the control room operators and test personnel and

the misinterpretation of a procedure step by a control room operator led to the

unexpected start of the Unit 1 EDG. The licensee's investigation of operator performance

during the event was good and revealed these problems. The root caue investination

team did not examine the erroneous alarm pattom normally associated with ine transfer

of auxiliary power which contributed to improper operator response in this event.

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01.3 Emernancy Diesel Generator Coolina Water Valve Mispositionina

a. Inspection Soone

The inspectors reviewed the circumstances surrounding an EDG cooling water valve

found in an incorrect position.

b. Observations and Findinos

On December 10,1997, Unit 1 was operating at rated power and Unit 2 was in cold

shutdown when the Unit 2 EDG cooling water heat exchanger supply valve (2-3999-87)

was retumed to service (RTS). This valve controlled flow to the EDG heat exchanger and

was specified in the RTS checklist to be throttled 18.5 tums from the full open position.

Verification of the minimum cooling water flow of 900 gpm, as required by Quad Cities

Operating Surveillance (QCOS) Procedure 5750-09, " Room and DGCWP [ dies,el

generator cooling water pump) Cubicle Cooler Monthly Surveillance," was not directed in

the RTS. On December 23,1997, during performance of the monthly surveillance,

QCOS 5750-09, the cooling water flow was found to be about 600 gpm, or about

300 gpm less than the required 900 gpm. As a result, the Unit 2 EDG was declared

inoperable. The licensee issued Licensee Event Report (LER) 1-98-003 and Problem

Identification Form Q1997-04970 to report and address this issue.

The licensee's investigation found that the throttled Unit 2 heat exchanger supply valve

had been incorrectly positioned during performance of the RTS on Decerser 10,1997.

On December 16,1997, the Unit 1 EDG was made inoperable for routine maintenance.

On January 10,1998, the licensee discovered that neither the Unit i nor the Unit 2 EDGs

were operable from December 16,1997, through December 21,1997. The inoperability

of both unit EDGs rendered both standby c::s treatment (SBGT) subsystems inoperable

from December 16,1997. to December 21,1997. Unit 1 was placed in cold shutdown on

December 21 due to safe shutdown concems. Unit 2 remained in cold shutdown during

this period.

Technical Specification (TS) 3.7.P.2 stated that with both SBGT subsystems inoperable

in Operational Modes 1,2, or 3 restore at least one subsystem to operable status within

one hour, or be in at least hot shutdown within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and in cold shutdown

within the following 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Following the concurrent inoperability of the Unit 1 and

Unit 2 EDGs and consequently both SrGT subsystems on December 16, failure to place

Unit 1 in hot shutdown within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and in cold shutdown within the following

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> was a Violation (50-254/9702841) of TS 3.7.P.

The licensee identified the cause of this event as inadequate procedure development and

review in that a flow test was not performed to verify that the correct flow was established i

following repositioning of the throttled valve. Corrective actions included correctly

positioning the cooling water valve, revising the EDG operating procedure and the RTS >

procedures to require direct verification of correct flow in accordance with QCOS 5750-09 ,

following repositioning of the valve, conducting a search for similar positioning '

discrepancies, providing direction when conducting out-of-service and retum-to-service

activities to verify correct flow of throttle valves, and providir:g training to affected

personnel. The licensee found that the EDG cooling water throttia valves were the only

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throttled valves that were specified in the out of servios system as requidng repositioning 1

to a reco! red number of tums rather than to catisfy a particular parameter (firm, pressure !

etc.).

The inspectors identified that this problem could apply any time a throttled valve was

taken out of the normal position and may not be limited to the out of service systwn.

Therefore corrective actions aimed at the out of service system alone, did not appear

complete. At the end of the period, the licensee had not addressed the need to control

throttled valves which were not being taken out of service but were being repositioned. A

training session for operators was planned for May 1998, but that would not preclude

problems in the interim. This issue of controlling valve lineups for important systems

applied to other problems with controlling configuration of system parameters seen in this

period (Section 02.1.b.1).

The inspectors also found that improper positioning of the throttle valve by an initial

positioner and an independent vedfier also contributed to the event. Better attention to

detail by either of the two operators could possibly have prevented this condition. Other

problems with independent verification activities are identified in Sections 02.1 and M1.2.

c. ConclusiQD

Two oporators using the licensee's independent verification methods failed to establish

correct cooling water valve position for the Unit 2 EDG. The Unit 2 EDG and the

equipment supported by it were thus rendered inoperable during some of the time that the

Unit 1 EDG was also inoperable. In addition, operators declared the Unit 2 EDG operable

without verification that the required cooling flow to satisfy EDG operab"3 had been

established. Adctional problems with independent verification and syraem inneup control

are identified in other sections of this report.

01.4 Inadeouste Actions for Addressina Cold Weather Effects on Eauipment

a. Insoedion Scope (71707. 92700)

The inspectors reviewed the licensee's problem identification forms addressing cold

weather effects on equipment. The inspectors spoke to knowledgeable individuals,

toured the affected areas and reviewed the licensee's corrective actions.

b. Observations and Findinas

With both units shut down, discharged circulation water was not warm enough to ensure

the circulating water discharge canal remained ice-free. The altemate fire pumps took

suction from the circulating water discharge canal. The licensee identified the discharge

canal had iced over and could not positively ensure the availability of these pumps during

a postulated fire. On January 12, operators declared the suction to the attemate fire

pumps (also known as " Rainbow" pumps) inoperable.

As corrective actions, the licensee installed a portable air compressor on the rainbow

pump suction lines to ensure the suction lines remained free of ice. The licensee

changed the rainbow pumps operating procedures and winterization program to

incorporate the corrective actions.

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Operations supervisors required operators to record hourty the temperature in both units'

battery rooms to ensure the room temperature would not decrease below 65 degrees F.

Due to decreasing room temperatures, operators requested maintenance personnel to

repair room heaters and requested that engineering personnel develop a temporary

alteration to install portable heaters in the battery rooms. However, on January 14,

operators identified that the temperature in the Unit 2125 Vdc battery room had dropped

to below 65 degrees F. The licensee declared the Unit 2125 Vdc batteries inoperable

due to low battery electrolyte temperature. The licensee concluded that operations

supervisors failed to take ownership of the issues and failed to resolve the issues with

other organizations in a timely manner.

For corrective actions, the licensee installed room heaters for both units' safety-related

125 Vdc battery rooms. The celd weather checidist incorporated the use of this

temporary alteration for future cold weather operations.  ;

c. Concluuons

The inspectors concluded the licensee did not proactively prepare for the effects of cold

weather on equipment deemed important to safety in two cases. In a previous inspection

report (Inspection Report No. 50-254/97021; 50-265/97021) the inspectors concluded

station support for the cold weather program was lacking.

O2 Operational Status of Facilities and Equipment

O2.1 Enaineered Safety Feature System Walkdowns

a. lagooction Scope (71707)

The inspectors used inspection Procedure 71707 to walk down accessible portions of

EDG and supporting auxiliary systems; an engineered safety feature system. The

inspectors compared the as-found condition of the EDG and supporting auxiliary systems

and components with the system drawings and the UFSAR. Identified discrepancies

were reported to the responsible organizations for disposition. Potential conditions

adverse to quality were documented on problem identification forms (PlFs).

b. Observations and Findinas

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The inspectors identified various configuration-related discrepancies during the walkdown )

of the EDG and auxiliary systems. Some of these configuration discrepancies were

attributed to human performance problems, including improper independent verification.

The inspectors identified the following items during a walkdown of the EDG systems. i

b.1 Valves Found Out of Position in Ememency Diesel Generator Air Start System

The inspectors identified that two valves in EDG air start systems were out of position.

Both the Unit 2 and Unit % EDG air start system moisture separator drain valves (% and

2-4699-200) were ide.'4ified by the inspectors to be in the closed position. The Quad

Cities Operations M9anical (QOM) Procedure 6600-1 and mechanical drawings for the

system, required the valves to be open. Operators repositioned both Unit % and Unit 2

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4699-200 valves to the proper position and venfied EDG supporting system valve

positions. No other discrepancies were noted.

The licensee documented the condition on PlF Q1998-00506 and commenced an

investigation. The investigation revealed that on October 28,1997, two reactor

operator-qualified individuals independently verified a retum to service position for

Valve 2-4699-200 in the closed (incorrect) position. The error was not identified until a

walkdown of the system by the inspectors on January 29,1998. The investigation could

not determine the cause of the %-4699-200 valve being out of the required position.

Engineering personnel later determined the system was operable with the valves in the

closed position. The inspectors determined Valves %-4699-200 and 2-4699-200 being

out of position was a violation of minor significance and is being treated as a Non CNed

Violation (50-265/97028 02) consistent with Section IV of the NRC Enforcement Policy.

The inspectors also noted there were no requirements to periodically perform valve line

ups for all system valves. Typically before startups from refuel outages, operations I

supervisors would authorize valve lineups to be performed in accordance with system l

operating procedures. However, these procedures did not include all system valves such

as the two 4699-200 valves. Other problems with control of system lineups were

identified in Section 01.3. As a result of this and other events in operations,

management discussed recent operator errors with all operations personnel.

b.2 Chance to the Plant Without a Completed Safety Evaluation

The inspectors identified an out-of-service (OOS 15580), initiated on August 30,1994,

removed the normal ventilation fan to the % EDG room from service. However, the 4

UFSAR, Section 9.4.5.B stated the fan supplied air to the room at 1200 ft'/ minute. The l

package associated with OOS 15580 had a 10 CFR 50.59 safety evaluation screening

initiated, but not completed, with a note stating that a full 10 CFR 50.59 safety evaluation

needed to be completed. A nuclear tracking system (NTS) number was initiated to

ensure the engineering commitment was completed. However, the NTS item was closed

out without completing the 10 CFR 50.59 safety evaluation. As a result, the licensee

changed the plant from what was described in the UFSAR for over three years without a j

complete safety evaluation.

The inspectors considered the closure of the NTS item without the actions being

completed to be an example of poor corrective action follow-up by both the

engineering and operations organizations. The licensee documented the concem on

PlF Q1998-00531. The inspectors considered this to be a Violation (50-265/97028-03)

of 10 CFR 50.59.

b.3 Inadeounte Documentation of Emeraericy Diesel Generator Fuel Oil Pipina Support  !

The inspectors identified the fuel oil retum line to the day tank from the % EDG did not

appear to be adequately supported. A subsequent review of all EDG fuel oil retum lines

by a structural engineer revealed that there were no supporting calculations to ensure the

safety-related piping could remain intact after a seismic event (PlF Q1998-00559). The

inspectors consider this an Unresolved item (50-254/97028 04; 50-265/97028-04)

pending review of the licensee's operability evaluation of this condition.

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b.4 Tamper Seals Missino From Relief Valves

The inspectors identified a relief valve on an EDG sir receiver without a tamper seal. The

licensee similarly identified various other relief valves that also were missing tamper seals

(PIF Q1998-00527). The licensee was addressing this potential programmatic problem at

the close of the inspection period.

b.5 System Engineering Walkdowns

The licensee administratively required periodic walkdowns of systems by system

engineers in an attempt to detect potential conditions adverse to quality. The issues in

b.1 - b.4 were identified by the inspectors and had not previously been identified by

system engineering walkdowns. As a result, the inspectors questioned the effectiveness

of system engineering walkdowns.

c. Conclusions

The inspectors concluded errors by two individuals conducting a retum to service resulted

in Valve 2-4699-200 being out of the required position. The cause of Valve %-4699-200

being out of position was unknown, but the inspectors found that a lack of system line-up

procedure requirements may have contributed to both valve lineup problems. The EDG

and the associated air start system were dctermined to be operable with this condition.

This event was indicative of a weakness in independent verification of required valve

positions. Other examples of weak independent verification are discussed in

Sections M1.2 and O1.3.

The inspectors concluded the licensee did not complete a 10 CFR 50.59 evaluation for

the change in the status of the shared EDG room ventiistion fan. This failure to maintain

the plant configuration also revealed poor follow-up by operations and engineering staff

on design related questions.

The inspectors were c ancemed with the effectiveness of system engineering walkdowns

in identifying conditions adverse to quality.

.08 Miscellaneous Operations issues (92700)

08.1 (Closed) Inspection Follow-up item (50-254/94004-57: 50-265/940QtJ_7J; integrated

Reporting Program. This program was well established, generating several thousand

problem identification forms per year. Poor rat cause identification and poor trending of

issues had been identified in several 1997 NRC inspections such as the maintenance rule

team inspection (Inspection Report No. 50-254/97017; 50-265/97017). These issues will  :

be reviewed generically in following up on the items generated by those inspections and

as part of the core resident inspection program. This item is closed.

08.2 (Closed) InsMion Follow-up item (50-2-6 Site Quality

Verificat on Organization and Effectiveness. The licensee made a number of changes to

the organization in attempting to improve effectiveness, including a recent change to the

reporting structure. This was approved by the NRC as Revision 65 H to the quality ,

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assurance topical report. Some problems still exist with effectiveness of the organization

in identifying and forcing corrective actions. Rose issues are better tracked by the NRC

using inspection Procedure 40500 and other core inspections. His item is closed.

08.3 (Closed) Violation (50-254/94029-01a and 01b: 50-265/94029-01a and 01b): Inadvertent

Reactor Vessel Draining. An out of service error caused inadvertent draining of the

reactor vessel when a scram was inserted with the unit shutdown. Out of servios errors

have decreased at the station since this event occurred and a revised out of service

program provided better controls to prevent such an occurrence. The inspectore

continued to monitor 008 errors at the station (see Section O2.1.b.1). This violation is

closed.

08.4 (Closed) Inspection Follow-yo item (50-254/96002-04: 50-265/96002-04): Weak Log

Reviews. Weak log reviews resulted in decreased safety system availability. The control

room emergency ventilation system (CREV) was unavailable due to Freon leaks. The

operator log reviews did not detect the problem in a timely manner. Since this ,

occurrence, the licensee completed maintenance achvities and modifications to improve j

system performance. The CREV system performance was the subject of enforce.,wnt in

inspection Report No. 50-254/96017; 50-265/96017. No similar failures have occurred

since that time. This item is closed.

08.5 (Closed) LER 50-254/96005-00: The CREV System inoperable Due to Low Outside Air

Temperature. The outside air temperature at -29 degrees Fahrenheit was found to be

below the TS limit of -28.1 degrees Fahrenheit for the CREV filtration heater operabikty.

Outside air temperature increased above this record low temperature and the system was

declared operable. The licensee also changed th: TS method for determining heater

operability (measure heater power versus an absolute low temperature limit when the

upgraded TS was implemented). This item is closed.

08.6 (Closed) LER 50-254/96017-00: Manual Scram During Reactor Startup. The scram was

followed by an unplanned opening of all main turbine bypass valves. The bypass valves

opened when the condenser backpressure permissive was met and the Electrohydraulic

Control (EHC) system pressure setpoint was effectively above reactor pressure.

Operators did not fully understand the inherent inaccuracies in the calibration of the EHC i

system pressure transducers at low pressures and the procedure was inadequate. The  !

inspectors previously reviewed this event in inspection Report No. 50254/96012; I

50-265/96012 and concluded that no v'alations had occurred. Since the event, the I

startup procedure was revised to direct operators to establish condenser vacuum prior to  ;

decreasing the EHC pressure setpoint. This would allow for the controlled opening of l

bypass valves at low pressures. Operators and engineers were also trained on the event

and the details of the EHC system operation at low pressures. No other similar events

have occurred during subsequent reactor startups. This item is closed.

08.7 (Closed) LER 50-254/97022-00. The Control Room Emergency Ventilation System

(CREVS) Inoperable. The CREVS was declared inoperable due to inadequate cooling "

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water flow which was caused by a system perturbation. Cooling water flow rate through

the refrigeration condensing unit was recorded as 115 gpm and the performance

acceptance criterion was 120 gpm. The licensee established the probable cause as

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lifting of a relief valve during the test. The procedure was changed to check the status of

the relief valve dudng the test. The surveillance was satisfactorily performed and the

problem has not recurred. This item is closed.

ILKalntenance

M1 Conduct of Maintenance

M1.1 Oganfal Comments

During the inspection period, the inspectors noted problems associated with maintaining

the EDGs. Time delay relay problems contributed to inoperability of all three EDGs. The

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Unit 1 EDG was inoperable for longer than expected due to problems with planned

maintenance. The Unit 2 EDG was also inoperable at the same time due to a cooling

water flow control valve being out of position.

Additionally, maintenance workers failed to verify removal of foreign material exclusion

barriers on an EDG component which could have affected operability. At the same time,

1,1e inspectors found that responsibility for verifying such maintenance hold points as

cleanliness was being transferred from Quality Control inspectors to the maintenance i

staff, without the maintenance staff taking over the function in some cases.

M1.2 Surveillance Observations

a. inspection Scope (61726)

The inspectors observed or reviewed portions of the following surveillance tests:

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• Standby Liquid Control (SBLC) Check Valve Operability Test at Cold Shutdown,

QCOS 1100-03 (Unit 1)

. Main Steam Line Radiation Monitor Functional Test, QCIS 1700-01 (Unit 1)

b. Qhservations and Findinos

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The inspectors noted two concems during the SBLC check valve testing for Unit 1 on ,

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January 6,1998. During restoration of the system per QCOS 1100-03, the inspectors

questioned why operators performed Step I.3.h before Steps 1.3.e, f, and g were

completed. The licensed operator and unit supervisor explained that system restoration

(Steps 1.3.b, c, and d) and independent verification of valve lineup (Step I.3.h) were done

at the same time. Therefore, Step I.3.e, f, and g were done after Step 1.3.h was

completed.

The inspectors were concemed that the procedure steps were performed out of

sequence. Quad Cities Administrative Procedure (QCAP) 1100-12, " Procedure Use and

Adherence," Revision 13, SeWion D.4.c(5) specified that procedural steps must be

followed in sequence unless deviations are allowed by the procedure. Also,

Section D.4.c(7) specified that procedural revisions be obtained when the existing

procedure was found to be incorrect. Althcugh there were no apparent adverse

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consequences associated with performing the steps out of sequence in this case, the

inspectors were concemed that the procedure adherence policy was not followed. After

further discussion with plant staff, the licensee reperformed Step 1.3.h and documented

the occurrence on PlF Q1997-00051. This minor violation is considered to be a Non-

Cited Violation (50-254/9702845) consistent with Section IV of the NRC Enforcement

Policy.

The inspectors were also conoemed that the opemtors worked together during the valve

lineup restoration and independent verification. Quad Cities Administrative

Procedure 0230-05, " Independent Verification," Revision 5, Section D.1.b specifies,

" Verifier independence must be maintained to ensure the integrity of the independent

verification. When possible, then actual separation of the individuals should be utilized."

Other sections of QCAP 0230-05 allow the use of either " Apart-in-Action" or

" Apart-in-Time" ve.tfication. The inspectors were concemed with the effectiveness of

independent verification since the procedure did not clearly state which type of verification

to use for which types of evolutions. Also there appeared to be some conflict within the

procedure regarding when separation of individuals should be utilized.

c. Conclusions

The inspectors noted two concoms during the SBLC check valve testing. The procedure

adherence policy was not followed, and the effectiveness of independent verification was

riuced when actions were performed and verified together. Other independent

verification problems this period are identified in Sections 01.3 and O2.1.b.1.

M1.3 Relav Failures Render Multiple Ememency Diesel Generators Inoperable

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a. Inspection Scope (62707)

The inspectors reviewed the circumstances surrounding a December 18,1997, ENS

report regarding the inoperability of EDGs due to out of tolerance as-found settings of

time delay relays,

b. Observations and Findinas i

During preventive maintenance on the Unit 1 EDG on December 18,1997, the TD-2 relay

was found to be out of tolerance. This relay was intended to limit the stait crank cycle of

the EDG to 15 seconds. The acceptance criterion was 15.0 - 16.5 seconds. The UFSAR

and TS required that the EDG start and accelerate to full speed within 10 seconds. The

UFSAR also stated that if the engine does not reach 200 rpm in 15 seconds that the EDG

start failure logic actuation will occur. The concem with an out of tolerance TD-2 relay  ;

was that premature actuation could trip the EDG when a successful start may have

occurred, and late actuation could allow starting air to deplete or damage to occur from

excessive cranking.

The initial test timed the relay at 6 seconds. A second and third test timed the relay at

12.61 seconds and greater than 50 seconds, respectively. A new relay was tested and

installed, and PlF Q1997-04891 was generated. Electricians then tested the same relay

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on the shared EDG. The shared EDG TD 2 relay timed at 11 seconds. The Unit 2 EDG

TD-2 relay had been previously tested on December 9,1997, and found to be out of

tolerance at 13.85 seconds.

An ENS call was required due to the simultaneous inoperability of the Unit 1 and the

shared EDGs. However, the inspectors noted the TD 2 relays for all three EDGs were

found outside the acceptance criterion. For some unknown period of time, until the relays

were replaced in December 1997, all three EDGs may not have been able to perform

their safety function due to a common failure mode of EDG relays.

Prior to 1995, the calibration check of the TD 2 relay was performed via a work request

during refueling outages. Since 1995, a procedure, Quad Cities Electrical Preventive

Maintenance (QCEPM) 0700-18, " Calibration of Diesel Generator Time Delay Relays,"

was used and the calibration check was scheduled to be performed once every 18

months. The work history indicated that since 1991, all but one of the checks were past

due when performed. The longest period between calibrations was 34 months. The

longest period before calibration since the recent failures, was 25 months. The relay

vendor manual referenced yeady checks of the relays. Of the 12 test results reviewed,

8 relays failed the test and required calibration, or in most cases, replacement. In one

recent case, the corrective action for a TD relay failure was to replace the relay and close

the PlF for trending; even though an adverse trend was already established. No other  ;

corrective action to address the root cause of the failure was specified until later failures

occurred.

The inspectors reviewed the LER (50-254/97027-00) for this event. The root cause was

determined to be relay drift due to lack of proper setup testing. Prior to December 1997,

the test was conducted as a bench calibration rather than under normal operating

conditions. Corrective actions included sending the relays offsite for further testing and

failure analysis, and testing the installed relays monthly to trend results and determine if

the frequency of the preventive maintenance (PM) needed to be changed. These

corrective actions appeared to be appropriate, but were not planned to be completed until

after the current inspection period.

c. Conclusion

The licensee discovered that all three EDGs had out of tolerance time delay relays. The

likely cause was an improper test setup. However, maintenance work history showed

that preventive maintenance to calibrate the relays was not performed per the established

schedule, and that the relays in the past had exhibited a high failure rate that was not

recognized by plant personnel. Later, corrective actions, including monthly testing to

trend performance and reestablish the PM frequency, appeared to be appropriate.

However, some eariier failures did not receive rigorous root cause reviews.

M1.4 Maintenance Observations

a. Inspection Scope (61726)

The inspectors observed mechanical maintenance department personnel during the

overhaul of the high pressure coolant injection system air operated Valve AO 1-2301-29

in accordance with Nuclear Work Request 970125804-01.

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b. Observations and Findinas

The work statNm Was orderty, and workers performed the valve overhaul activities in

accordance with a work procedure. The inspectors observed that a maintenance

foreman frequented the work site to coach personnel conducting the overhaul activities.

During review of the work package, the inspedors identified th:d an attachment to the

work package, called a " red sheet," was inadequately completed. The " red sheet" was an

administrative control, used in the maintenance work package, to assure an adequate

level of management review was done prior to work being performed on critical plant

systems and components. This was an administrative weakness previously observed by

the inspedors and documented in NRC Inspection Report No. 50-254/95006; .

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50-265/95006. This example indicated that the licensee had not achieved a high level of

attention to adminis'.rative detail. There were no adverse consequences resulting from

these infrequently observed omissions, and no impad to safety.

c. Conclusions

Supervisory oversight was good during the observed work. Some lack of attention to risk

reduction administrative detail was observed (inadequate completion of a " red sheet").

]

M4 Maintenance Staff Knowledge and Performance

M4.1 Electrical Taoe Found on Ememency Diesel Generator Air Start Solenoid

a. Inspection Scope (62707)

The inspectors reviewed the root cause evaluation (RCE) for the EDG start failure.

b. Observations and Findinas

During the RCE, the system engineer identified black eledncal tape protruding from the

air start solenoid. Upon disassembly, tape was found covering the air ports. The

solenoid had been replaced on December 16, igg 7. Subsequent to the solenoid

replacement, the EDG had been successfully run five times. The tape was found

punctured from the force of air during previous start attempts. Electricians performed

bench testing of a similar solenoid with tape covering the ports and found that the force of

the air punctured 'w tape during all attempts. The tape, while not ruled out as the cause

of the EDG failure, was not considered to be the likely cause. Further tests of the

solenoid were planned.

Although the presence of the tape was not determined to be the likely root cause of the

EDG failure, the potential safety effeds of the failure to property control foreign material

on this device were serious. Foreign material fully blocking the por#2 of the air start

solenoid, would result in an EDG failure to start on demand. Addit 3nally, the RCE was

initially inconclusive regarding how and when the tape was installed and did not address

foreign material exclusion (FME) requirements and possible FME weaknesses exhibited

during the work. Therefore, corrective actions to prevent recurrence were delayed.

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c. Conclusion

Lack of control of FME (electrical tape) resulted in a condition which could have adversely

affected EDG performance and may have contributed to the failure of the EDG to start.

The licensee's investigation of this particular aspect of the event was initially inconclusive

and did not include recommended corrective actions to prevent recurrence.

M4.2 Maintenance Problems with the Toxic Gas Analyzer

a. Insocction Scope (g2700)

The inspectors reviewed problem identification forms and spoke to various engineering

and rr.aintenance personnel associated with maintenance activities with the control room

emergency ventilation system (CREVS) toxic gas analyzer (TGA).

b. Observations and Findinos

The licensee identified problems with the TGA. Maintenance personnel identified the

TGA chopper motor needed to be replaced. The new chopper motor was installed but

wired incorrectly. Troubleshooting by maintenance personnel could not identify the

problem. A vendor was summoned to the site to assist in troubleshooting efforts.

Previously, vendors assisting maintenance personnel provided knowledge about TGA

system operation and preventive maintenance. A maintenance worker documented the

vendor findings in work history, but did not notify work analysts for inclusion into future

work packages. When the recent chopper motor failure occurred, the work analyst failed

to include the previous work history in the packags. The analyst indicated the reason

was because the package was destined for fix-it now (FIN) team work, and history was

noi usually included in those packages. The licansee counseled the individual to ensure

work history was included in FIN team work ps.* ages. This event resulted in the CREV

TGA being inoperable longer than anticipated.

c. Conclusions

The inspectors identified that weaknesses existed in documenting work history

information previously provided by a vendor. In addition, wiring errors resulted in a j

safety-related system being inoperable longer than scheduled. l

M7 Quality Assurance in Maintenance Activities

M7.1 Quality and Safety Assessment involvement in Maintenance Activities

a. Inspection Scope (62707)

The inspectors reviewed the involvement of the Quality and Safety Assessment (Q&SA) _

department in two maintenance activities.

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b. Observations and Findinas

A Quality and Safety Assessment inspector generated a PlF documenting three concoms

during an overview of maintenance work on the shared EDG TD 2 relay (see

Sechon M1.3). The concems included the method used to change acceptance criteria in

the work package, lack of proper work package documentation, and differences among

procedures regarding the acceptance criteria. The licensee determined that the PlF

required an apparent cause evaluation (ACE). The inspectors reviewed the ACE and

noted that it was closed with corrective actions being subsumed by those described in the

LER that was required due to multiple EDGs affected by TD 2 relay problems. The LER

did not address any of the original concems documented by the Q&SA inspe clor. The

Q&SA organization ultimately wrote a second PlF to document the inadequa e ACE

closure following the inspector's discussion of the concem with licensee management.

While reviewing work packages on the EDG, the inspectors noted that the quality control

(QC) hold points had been deleted from the procedure via a procedure field change

(PFC) to Quad Cities Mechanical Maintenance Surveillance (QCMMS) 6600-03,

Revision 7, " Emergency Diesel Generator Periodic Pmventive Maintenance inspection."

The QC organization revised the QC inspection plan to delete all but mandatory hold

points required by various procedures, codes, or regulations. In lieu of hold points, the

QC organization planned to perform more overview inspections. Station management's

intention was to convert these QC hold points to maintenance verifications performed by

supervisors. However, procedures had been changed to allow QC hold point deletion,

but did iot add the maintenance supervisor verification. The work package associated

with the EDG had several examples where the verification was performed by the same

individual who performed the work, one example where the supervisor did the verification,

and one example where no verification was documented.

While in this case, no problems appeared to result from the removal of the QC hold

points, the inspectors noted that one function designed to prevent conditions adverse to

quality had been removed rather than transferred to a different organizabon. Events such

as the tape found on the air start solenoid (Section M4.1) indicated the continued need

for such checks of critical maintenance work.

c. Gnaglualgn

The QC organization implemented overview inspections to replace non-mandatory hold

points in maintenance activities. The hold points were intended to be replaced with  !

maintenance supervisor verifications, bet on one occasion, QC concems identified during

an overview were not addressed by the station. The inspectors also noted that former

QC hold points were not translated into maintenance supervisor verifcations during EDG ,

work.

M8 Miscellaneous Maintenance issues (g2g02) ,

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M8.1 (ClosedH.ER 50-254/93025-01: "A" Loop Main Steam isolation Valves (MSIVs)

Exceeded TS Leakage Limits. The cause of the excessive leakage was steam erosion

on the pilot and main disc. The fasteners which retain the main valve disc to the valve

stem were also found to be loose. The inspectors verified the licensee commitments to

develop a maintenance procedure for disassembly and reassembly of MSIVs, to review

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the existing prevenGwe maintenance program, and to ensure that all disassembled M81Vs

have new locidng devices installed, were complete. Recent local leak rate test results

were satisfactory. This item is closed.

M8.2' (Closed) Inspection Follow-up item 50-254/94004-05: 50 265/94004-05- Repetitive

Oxygen Analyzer Problems. The safety-related containment atmosphere monitor (CAM)

system was used for de-inerting the drywell because of repeated problems with the non-

safety related oxygen analyzers. The oxygen analyzer sample pumps were replaced.

Over the last two years oxygen analyzer reliability had improved. No outstanding work

requests existed for the system. This item is closed.

MS.3 (Closed) Inspection Follow-up Item 50-254/94004-06: 50 265/94004-06: Back Leakage

Through 1-RHR-7B Valve. The licensee replaced or repaired three of four of the RHR-7

[ residual heat removal] valves. In January 1998 control room logs indicated that a

leakage of about 1 to 2 gallons per minute into the Unit 1 torus through a RHR torus

cooling valve had been observed. This was being tracked in the licensee's corrective

action system. This item is closed.

M8.4 (Closed) Inspection Follow-uo item 50-254/94004-27: 50-265/94004-27: Core Spray

Pump Discrepancy. The licensee minimized leakage into the torus through repairs and

replacements cf the 1A Core Spray pump, and brought pump performance more in line

with the 1B Core Spray pump performance. High pressure coolant injechon pump

performance was also an issue, and was evaluated in the System Operational

Performance inspection 50-254/97022; 50-265/97022. This item is closed.

M8.5 (Closed) Inspection Follow-up item 50-254/94004-34: 50-265/94004-34: Work Package

Preparation, Utilization and Processing. The licensee implemented a number of

initiatives to improve maintenance work package quality, completion, and processing.

These initiatives included a Fix-It-Now team concept for minor maintenance which had j

been successful in minimizing the time to process minor maintenance items. A work

control center concept for centralizing work packages, out of services and problem

identification forms was also implemented. Quad Cities switched to an electronic work

control system in 1997 to provide better tracking of work items. This system was

implemented with some flaws which affected the completion of surveillances. In addition,

not all fields for equipment were complete when the system was tumed on. Work

package improvement efforts also took place in 1996 and 1997. In late 1997, some l

problems still existed in the amount of data being recorded by technicians during work,

and the amount of material history available for certain components (see Section M4.2). l

These issues were being reviewed as part of routine resident core inspections. This item i

is closed.

M8.6 (Closed) LER 50-254/95001-00: During Unit 1 Startup The Reactor Core Isolation

Cooling (RCIC) System Govemor Valve Did Not Respond Property Due to Valve Stem

Corrosion. Dusing testing, the RCIC govemor valve remained full open and would not

respond to flow controller signals. The RCIC system was declared inoperable and the

plant was shut down in accordance with TSs. The l6censee concluded that with the

govemor valve full open, the RCIC system could have performed its design basis

function; and therefore, submitted the LER on a voluntary basis. Corrective actions

included valve stem replacement and changes to operating procedures to reduce the

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exposure to moisture. The inspectors verified that these actions were completed. No

similar RCIC valve failures had occurred sinos this event. This item is closed.

M8.7 (Closed) LER 50-254/95005-00: Control Room Emergency Ventilation inoperable Due To

Refrigerant Leak. A damaged joint in the system was repaired and operator surveillance

procedures were changed to perform trending of compressor refrigerant pressure each

shitt. This item is closed.

M8.8 (Closed) LER 50-254/96004-00 Unit 1 High Pressure Coolant injection (HPCI) System

inoperable Due To Gland Exhauster Breaker Trip. The breaker was replaced and the

HPCI system tested satisfactorily. Other corrective actions included a procedure change

to include breaker trip checks in the preventive maintenance procedure and a

reevaluation of the replacement schedule for the 250 Vdc breakers. The inspectors

vertfied that QCEPM Procedure 400-2, Revision 10, had been revised to incorporate the

trip checks _ The licensee reevaluated the replacement schedule, but determined that

acceleration of the schedule was not necessary. As of January 1996, five Unit 1 breakers

for reactor core isolation cooling system components were scheduled for replacement

during Q1R15 (beginning September 1998). No additional failures of these breakers have

occurred since this event. This item is closed.

M8.9 (Closed) LER 50-254/96014-00 Electrical Distribution Surveillance Did Not Document

Voltages in Accordance With TS 4.9.E. Revised TSs were implemented on

September 23,1996, which required verification of the proper voltage on safety-related

busses. On October 2, a unit supervisor discovered that the surveillance was not

satisfactorily completed as required by TS 4.9.E since there was no documentation that

proper voltages had been verified. In accordance with TS 4.0.C, which allowed 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

to complete a missed surveillance before taking actions specified by the TS action

statement, operators revised the procedure and completed the surveillance on October 3.

The inspectors confirmed that the procedure had been revised and that operations

personnel were briefed on the event as committed to in the LER. The failure to perform

the required surveillance was a violation of TS 4.0.B. This non-repetitive, licensee-

identified and corrected violation is being treated as a Non-Cited Violation

(50-254/97028 06; 50-265/9702846) consistent with Section Vll.B.1 of the NRC

Enforcement Policy. This item is closed.

M8.10 (Closed) Unresolved item 50-254/97002-07: 50-265/97002-07: Unit 2 Containment

Atmosphere Monitoring (CAM) System Maintenance Rule implementation. During the

maintenance rule baseline inspection, the inspectors reviewed the maintenance rule

implementation for the CAM system and identified several examples of apparent j

violations. Refer to inspection Report No. 50-254/97017; 50-265/97017 for further

details. This item is closed. l

M8.11 (Closed) Unresolved item 50-265/97027-02(DRS). On November 7,1997, the inspectors

identified an unresolved item pertaining to the adequacy of the visual test (VT-2)

examination of the Class 1 system boundary based on the short time taken and methods

used during the June 22,1997, leakage test. The licensee subsequently concluded that

this VT-2 examination was inadequate with respect to Code requirements, based on an

examination re-enactment on January 3,1998. This re-enactment demonstrated that

leakage (if present) would not have been detected in several areas of the Class 1 system

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boundary. On January 6,1998, the licensee issued PlF Q1998-0052 to document this

issue.

Technical Specification 4.0.E, required in part " inservice inspection of ASME [American

Society of Mechanical Engineers] Code Class 1,2, 3 components...shall be performed in

accordance with Section XI of the ASME Boiler and Pressure Vessel Code..." The 1989

Edition of the ASME Code Section XI, IWA-5242(a) " insulated Components" required that

"For other components, visual examination VT-2 may be conducted without the removal

of insulation by examaing the accessible and exposed surfaces and joints of the

insulation. Essentially vertical surfaces of insulation need only be examined at the lowest

elevation where leakage may be detectable." Section IWA-5242(b) " Insulated

Components" required that "When examining insulated components, the examination of

surrounding area (including floor areas or equipment surfaces located undemeath the

components) for evkience of leakage, or other areas to which such leakage may be

channeled, shall be required." Contrary to these requirements, during the June 22,1997,

Class 1 system leakage test, the licensee had not completed a complete examination of

accessible sudaces and joints of the insulated Class 1 system boundary. Failure to

meet Code (IWA-5242) requirements for the VT-2 examination of the Class 1 system

boundary performed on June 22,1997, is considered an apparent violation

(FEl 50-265/97028 47(DRS)) of TS 4.0.E. The licer'see root cause evaluation and

corrective actions for this issue were presented to the NRC at the January 9,1998,

predecisional enforcement conference. Licensee corrective actions for this issue were

under NRC review, and no additional response is required at this time. This unresolved

item is closed.

Ill. Enoineerina

E1 Conduct of Engineering

E1.1 General Comments

Problems with safety-related equipment continued, and engineering department plans to

resolve the issues were not completed as planned in some cases. The Unit 1 EDG fr Nd i

to start on demand, with a root v o pursued but not found by the licensee at the en 9f

the inspection period. Several oh, c EDG failures to start on demand have occurred

since 1993. The inspectors identified that previous corrective action plans were not fully

implemented. In addition, electromatic relief valve (ERV) vibration problems from 1993

have not been fully resolved, and the inspectors identified that action plans to replace the

valves were only partially completed. A recent failure of the 3E ERV was attributed to

vibration. Some problems with safety evaluations and operability evaluations were also

noted.

E1.2 Unit 1 Emeroency Diesel Generator Fr"ure to Start on Demand '

a. Inspection Scope

The inspectors reviewed the circumstances surrounding a January 5,1998, ENS call

reporting the unexpected start of the Unit 1 EDG. The initialinvestigation revealed that

the EDG had initially failed to start after receiving a start signal, but then unexpectedly

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started when operators cleared alarms. Section 01.2 describes the inadvertent start. In

order to evaluate the failed start, the inspectors attended root cause team meetings,

reviewed PlFs and root cause reports, evaluated previous corrective actions to EDG

failure events, and spoke with engineers and operators,

b. Observations and Findinas

An inadvertent EDG start signal was generated by an electrician intdvertently bumping a

core spray relay. The starting of the Unit 1 EDG would have been the proper system

response. The cause of the failure to start was not determined. However, the

investigation revealed several problems with the EDG that could have contributed to the

failure to start. Among the problems noted during the investigation were:

. Tape was found covering the air ports of the air start solenoid. The tapo had

probably been punctured by the force of the air during the five successful starts of

the EDG prior to this failure. This issue is discussed further in Section M4.1.

. The air start motor main check valve, Valve 1-4699-309, was found to be stuck

closed.

. The lower air start motor pinion gear was found to be intermittently binding when

rotated by hand.

. One of the upper air start motor mounting bolts was found to be loose.

Because the investigation did not reveal the root cause of the failure to start, the licensee

used an independent EDG expert to review the problem and the investigation to

determine if any possible causes were overlooked. This review did not indicate that any

major issues were missed, but provided some suggestions for further testing.

The inspectors concluded that this problem was a continuation of a high number of EDG

failures, for each of which the licensee had not determined a definitive root cause. As a

result of this concem, the inspectors reviewed the licensee's corrective actions for the

shared EDG failure on January 17,1997, and the Unit 2 EDG failures on May 8,1997,

September 26,1995, and October 24,1995.

The inspectors found that a number of longer term corrective actions established in

response to the failures and as a result of the EDGs becoming a Maintenance Rule (a)(1)

system were delayed or had not been initiated. In particular, a corrective action item after

the May 1997 failure was to evaluate the need for EDG modifications to tolerate air start ,

motor pinion gear abutment. The original due date of November 1997 was extended to l

June 1998. Little progress was made on the modification options until this most recent l

EDG failure event when the licensee decided to more aggressively pursue redundant air  !

start motors. (NOTE: Recommendations to enhance air start system performance were

included in a report to the licensee from Sargent and Lundy, and acknowledged in a i

September 22,1993, report by the licensee. See Inspection Reports No. 50-254/97022;

50-265/97022, Section E8.2). Corrective actions from the January 1997 failure event

involved obtaining additional maintenance and inspection guidance on the air start motors

from the vendor, co" sidering additional air start motor inspection requirements, and

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evaluating replacement frequency of the air start motors. These actions, originally due to

be completed in July 1997, were still open pending additional testing of the air start

motors by the vendor.

Also, the Maintenance Rule (a)(1) action plan first developed in April 1997 had many

action items which were overdue or had not been started, including such activities as

determining system performance improvement areas and developing action plans to

address those areas. Essentially none of the tasks of the action plan which may have led

to improved EDG performance were completed or even initiated.

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c. Conclusion

The EDGs had experienced a number of start failures over the past several years and

root cause evaluations did not always identify the root cause of failures. Notwithstanding

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the lack of definitive root causes, the licensee developed several long-term corrective

action plans designed to improve system performance. However, the plans were often

not completed, indicating a lack of follow-through on long-term EDG improvement plans.

E2 Engineering Support of Facilities and Equipment

E2.1 Enaineerina Support to Operations

a. Inspection Scoce (71707)

The inspectors reviewed PlFs, engineering evaluations, and troubleshooting plans. The

inspectors spoke to engineering and operations personnel and toured the facility.

b. Observations and Findinas

b.1 On December 30,1997, engineering personnel identified and replaced a damaged

snubber on the Unit i decay heat removal system piping. On January 10,1998, the

damaged snubber was tested and failed in the acceleration mode. To meet TS 3.8.F

requirements, operations personnel tasked the engineering staff with performing an

engineering evaluation to determine the cause for the failure within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Engineering personnel presented the evaluation to operations personnel on January 13,

but the operations personnel were not satisfied with the quality of the engineering

evaluation since it did not include a failure analysis of the snubber. The extra time taken

by engineering staff to include the failure analysis in the evaluation resulted in exceeding

the 72-hour TS criteria and required operations personnel to notify the NRC via the ENS.

b.2 On August 30,1994, operations personnel removed the normal ventilation fan to the

shared EDG room from service. Administrative procedures required completing a

10 CFR 50.59 evaluation for the condition since the out of service was to remain in effect

for greater than three months. However, engineering staff did not complete the

10 CFR 50.59 safety evaluation. An NTS item was initiated to ensure the engineering

commitment was completed. However, the NTS item was closed out without completing

the 10 CFR 50.59 safety evaluation (see Section O2.1b.2).

b.3 On December 20,1997, operators tested five automatic depressurization system (ADS)

relief valves by operating a test switch from the control room However, operators

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determined relief Valve 1-0203-3E failed to open (PlF Q1997-04938). The other ADS i

valves operated property. Engineering personnel developed an action plan to determine  !

the most likely cause of failure. Subsequent troubleshooting by engineering staff

determined the adjusting screw on the leverxrm on the pilot assembly had vibrated out of

position. Proposed corrective actions included locking the aquating screw and applying a .

stiffening agent to the threads to ensure the adjusting screw would not move after it had i

been set. Engineering personnel determined this was the first time vibrations from

the steam piping had resulted in a movement of the relief valve adjusting screw.

Section 6.3.3.1.4 of the UFSAR (emergency core cooling system (ECCS), Performance  !

evaluation of ADS) stated only four of the five ADS valves were required to be operable in

the loss of coolant analyses.

In the past, the licensee had detected other vibration-related failures of ADS valves. The l

licensee replaced the Unit 2 ADS valves during a previous refuel outage but had not

replaced the ADS valves in Unit 1. The inspectors were concemed that the root cause of

ADS valve failures had not been corrected since system vibrations continued to result in

degraded equipment.

b.4 Operators identified indications of a leak in the waste collector tank. A tour of the l

associated room indicated the tank developed an 18-inch crack at a weld joint towards

the bottom of the tank. Engineering personnel developed an action plan to drain and

repair the tank. Engineering personnel proactively addressed similar concems with the

floor drain collector tank, which was a twin to the waste collector tank.

c. Conclusions

The inspectors concluded there were instances where engineering evaluations were not

completed or were not of sufficient quality in areas such as snubber requirements, EDG

ventilation, and electromatic relief valve vibration issues. However, the inspectors noted

instances where engineering support of maintenance activities for the radweste system

was good and some aspects of troubleshooting for an electromatic relief valve failure

were good.

E8 Miscellaneous Engineering issues (92902)

E8.1 (Closed) Inspection Fol19w-up item 50-254/92018: Control Room Emergency Ventilation

Train Surveillance Failure. This item documented inspector concems with CREV system

performance and the inspectors' intention to follow up on a CREV system modification

that was documented as a commitment in LER 50-254/94002-00, in inspection Report i

No. 50-254/97014; 50-265/97014 a deviation was issued for the licensee's failure to

install the modification. This item is closed, i

E8.2 (Closed) LER 50-254/93023-00- Engineered Safety Feature Actuation Caused by Main

Turbine Control L;g c Relay Failure. On December 16,1993, a relay failure in the main

turbine control logic resulted in a turbine trip, reactor trip and a main steam isolation valve

closure. Corrective actions were to replace the failed relay and to investigate options for

improving reliability and possibly adding redundancy to the turbine trip logic. The

inspectors verified that the engineers had proposed several modifications to the logic

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which were approved for installation during the Q1R16 and Q2R15 refueling outaces.

The inspectors also reviewed reactor trips since this occurred in 1993 and found that no

other trips were caused by failures in the turbine control system. This item is closed.

E8.3 (Closed) Inspector Follow-uo item 50-254/94004-43: 50-265/94004-43: System

Engineering Weaknesses. The licensee initiated several improvement efforts and

managemnt changes to address system engineering weaknesses, including those

incorporated into The three year Course Ot' Action. Improved qualification cards, some

improved trainleg initiatives, and hands on training on system walkdowns were

implemented in 1994 and 1995. Recent problems indicated continued deficiencies in

system engineer understanding of expectations and roles and system engineer support to

other parts of the station. System Engineering improvements were planned by Comed at

Quad Cities in order to bring the system engineers into a system manager role. These

efforts will be evaluated as part of the core program using inspection Procedure 37550.

This item is closed.

E8.4 (Closed) Insoefon Fobow-up Item 50-254/94004-45: 50-265/94004-45: Single Element

Feedwater Regulaung Valve Control. The licensee repaired and tuned the feedwater

regulating valve control system for both units and installed improved feedwater regulating

vanes. Both units are now capable of operation with three element feedwater control.

This item is closed.

E8.5 (Closed) Inspection Follow-uo item 50-254/94004-47: 50-265/94004-47: Potential Low

Pressure Coolant injection Swing Bus Deficiencies. This issue received Nuclear Reactor

Regulation (NRR) Electrical Engineering Branch rcview and was subsequently addressed

in the review of LER 50-254/93003-00. The LER was closed in Inspection Report

No. 50-254/96011; 50-265/96011. This item is closed.

E8.6 (Closed) Inspection Follow-up item 50-254/94004-51: 50-265/94004-51: Design Basis

Documentation (DBD). The licensee initially intended 22 system and/or topical reports to

be issued by December 1995. Many of these DBDs were issued for "information only" as

they had not been validated. The licensee was recently using outside resources to

perform a design basis initiative review and validation which was scheduled to extend into

1999. The licenses was also performing a line item validation of the UFSAR as part of a

10 CFR 50.54(f) request for information. This effort was scheduled to be completed in

October 1998. Design basis information availability was reviewed and discussed as part

of the System Operational Performance inspection 50 254/97022; 50-265/97022. Further

reviews will take place as part of routine enginesring inspections in accordance with

inspection Procedure 37550 and in conjunction with other regional and headquarters

inspection initiatives. This item is closed.

E8.7 (Closed) Violation 50-254/94004-54: 50-265/94004-54: Title 10 CFR 50.59 Evaluations.

The licensee evaluated the specific examples and either corrected the equipment

problem so that a safety evaluation was not needed (pumpback compressor), verified the

existing safety evaluation had addressed the concem noted (1 A RHR torus cooling and

test retum valves), or improved the safety evaluation (1 RHR 36 B valve.) Examples of

poor safety evaluations continue even thaugh the licensee took some corrective action to

trein engineers on better safety evaluation techniques in 1995. Ars enginecring

assessment group was formed in 1997 to address poor quality engineering work including

safety evaluations and screenings. Nevertheless, poor safety evaluations continued,

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iridis.;,,g the effectiveness of these actions had been limited. An apparent violation for

an ir+f+F safety evaluation was identified in inspection Reports No. 50-254/97027;

50-265/97027 as item 6. Corrective action for continued problems with safety evaluations

will be tracked along with licensee response to the 50065/97027-06 Item. This item is

closed.

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E8.8 (Closed) Unresolved item 50-254/95009-02: 50-265/95004 02: Failure of the EDG to

Operate. The root cause of the failure was determined to be swelling of the air start

motor vanes due to improper control of moisture levels during storage. The NRC issued

a violation regarding the improper storage in Inspection Report No. 50-254/9600P

50-265/96002. This URI was created to follow up on the management initiatives to

improve root cause evaluations and troubleshooting methodology. Since this event, the

station has conducted root cwse training and established various root cause evaluation

experts. Additionally, more rigor in the troubleshooting process had been displayed as

root cause evaluations were conducted in accordance with the Nucioar Station Work

Procedure (NSWP-A-13). Although improvements in the process had been made, the

inspectors remained cc acomed with the number of EDG failuras and the lack of a

definitive root cause (see Section E1.1) and will continue te evaluate root cause

investigations during the normalinspection process. Th!s item is closed.

E8.9 (Closed) Unresolved item 50-254/96006-08: Secondary Containment Deficiencies. This

issue was addressed in inspection Report No. 50-254/96019; 50-265/96019 and resulted

in three Severity Level ill violations. This item is closed.

E8.10 (Closed) Unresolved item 50-254/96008-08: Reactor Building Siding issue. This issue

was addressed in inspection Report No. 50-254/96019; 50-265/96010 and resulted in

three Severity Level ill violations. This item is closed.

E8.11 (Clanad)_LER_50-25Mifa10: Gallery Steel above Primary Containment Equipment

installed improperty. Engineers preparing a modification noted that the gallery steel cross

bracing identified in drawings was not installed in the plant. The cross bracing would

auctify the gallery steel for seismic loading. T;w deficiency had existed since original  ;

construction. The licensee concluded that during a postulated seismic event, the gallery

steel would fail. Some systems and components could be affected but, redundant

systems would be available for safe shutdown of the reactor. Corrective actions included

installing the cross bracing to achieve the seismic qualification. This item is closed.

E8.12 (Closed) Unresolved item 50-254/96012-07: Reactor Building Blowout Panel Bolts ,

Broken. This issue was addressed in IR 50-254/96019; 50-265/96019 and resulted in

three Severity Level lit violations. This item is closed.

E8.13 (Closed) LER 50-254/96012-00. Diesel Fuel Oil Transfer Piping Was in an Unenalyzed

Condition. The fuel oil transfer piping supplying the diesel fire pump day tank was not

safety-related. No isolation existed between this non-safety related piping and the safety-

l related piping to the EDG fuel oil system. Therefore, a failure in the non-safety portion of

the piping could have adversely affected the EDG safety function. This was discovered

during a station review of open items in the component classification program. Corrective

actions included isolating the two systems by closing two valves and reviewing other

open items within the component classification program to ensure that no similar issues

existed. This item is closed.

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E8.14 (Closed) Unresolved item 50-254/9601444: 50-265/96014-04: The CREV System

Refrigerant Crankcase Heater Was Fed from Non-Safety Related Power Supply. The

system engineer identified the deficiency and the licensee took corrective actions to

provide a safety-related power supply to the heater. This item is closed.

E8.15 (Closed) Violation 50-254/96017-06: 50-265/9601/-06: Failure to incorporate a TS

Requirement. Technical Specification 4.8.D.4 required a laboratory analysis of the control

room HVAC charcoal adsorber after 720 hours0.00833 days <br />0.2 hours <br />0.00119 weeks <br />2.7396e-4 months <br /> of operation. The test procedure did not

track the hours of operation. This was a new requirement to the TSs and an oversight

resulted in not tracking the hours of operation. Licensee estimates cosecluded that it was

unlikely the 720-hour limit was exceeded. Procedures were changed to have operators

track the run times. This violation is closed.

E8.16 (Closed) Inspection Follow-up items 50-254/96017-07. 08. 09. 50-265/96017-07. 06. 09:

Control Room Dose Calculation. The inspectors questioned the licensee's operability

assessment which used different assumptions and parameters than the calculation of

record in the UFSAR. The licensee subsequently revised the calculation and the entire

t abitability study. The CREV system operability was the subject of enforcement as

documented in inspection Report No. 50-254/96017; 50-265/96017. These items are

closed.

E8.17 (Closed) Violations 50-254/96017-10.11: 50-265/96017-10,11: The CREV System

Could Not Maintain Required Positive Pressure. The CREV test program failed to verify

the system could maintain greater than or equal to 1/8 inch water gauge positive pressure

as specified in the UFSAR and per TS 3.8.D. The licensee repaired the system and

successfully completed testing that verified the control room would be maintained at the

required positive pressure. These violations are closed.

E8.18 G2339 Violation 50-254/96020-03: 50-265/96020-03- ImproperTesting of CREVs. The

inspectors identified that the CREV system was not adequately tested per TS 4.8.D.5.b.2.

Subsequent testing was performed to verify system operability. The test procedure was

changed. This violation is close,d.

E8.19 (Closed) LER 50-254/96024-00 The CREV System inadequately Tested. This issue

was identified by the NRC inspectors and documented as a violation in inspechon Faport

No. 50-254/96020; 50-265/96020. The inspectors confirmed that the proper test was

ultimately performed. As part of the corrective actions, the licensee performed a review

of new surveillances required as a result of the technical specification upgrade program. l

Although this review was completed in earty 1997, the inspectors noted that the review

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did not identify a number of deficiencies and missed surveillances that were found in

late-1997. This item is closed.

E8.20 (Closed) LER 50-254/97020-00 The B Train CREVs Air Handling Unit Breaker Cycled

and Tripped. The licensee conducted testing to identify the cause but could not

reproduce the event. The monthly surveillance was performed successfully. No similar

failures have occurred since this event. This item is closed.

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IV. Plant Succod

R1 Radiologios! Protection and Chemistry Controfs

R1.1 Uconsee's Actions to Address Past Hiah Radwiion Area Violations

The inspectors observed that the licensee had implemented new measures to assure

adequate attention was given to control access to high radiation areas. This was

accomplished through the use of high radiation area entry slips and a special computer

sign-in process to remind all personnel entering high radiation areas of their

responsibilities in maintaining proper cantrol of access to these areas. The results

observed thus far have been positive and no high radiation area access problems have

been observed since the implementation of these measures.

V. Manaaement Mootinas

X1 Exit Meeting Summary

The inspectors presented the inspection results to members of licensee management at the

conclusion of the inspection on February 10,1998. The licensee acknowledged the findings

presented.

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PARTIAL LIST OF PERSONS CONTACTED

Licensee

E. Kraft Site Vice President

L Pearce Station General Manager

C. Holbrook Engineering Manager

M. Wayland Maintenance Manger

B. Svaleson Operations Manager

G. Powell Acting Radiation Protection / Chemistry Manager

F. Famulari Quality and Safety Assessment Manager

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INSPECTION PROCEDURES USED

IP 61726: Surveillance Observations

IP 62707: Maintenance Observations

IP 71707: Plant Operations

IP 92700: Onsite Follow-up of Written Reports of Nonroutine Events at Power Reactor

Facilities

IP 92902: Follow-up - Engineering

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

50-254/97028-01 VIO EDG cooling water valve mispositioning

50-265/97028-02 NCV valves found out of position in EDG air start system

50-265/97028-03 VIO out of service existing greater than three months

without completed safety evaluation

50-254/97028-04; 50-265/97028-04 URI inadequate documentation of EDG fuel oil piping

support

50-254/97028-05 NCV steps performed out of sequence during SBLC )

check valve test 8ng 1

50-254/97028-06; 50-265/97028-06 NCV failure to perform required surveillance )

50-265/97028-07(DRS) eel failure to meet Code requirsments for the VT-2

examination of the Class 1 system boundary

Closed 1

50-254/94004-57; 50-265/94004-57 IFl integrated reporting program

50-254/94004-58; 50-265/94004-58 IFl site quality verification organization and

effectiveness

50-254/94029-01a, 01b VIO inadvertent reactor vessel draining

50-265/94029-01a, 01b

50-254/96002-04; 50-265/96002-04 IFl weak log reviews

50-254/96005-00 LER the CREV system inoperable due to low outside air

temperature

50 254/96017-00 LER manual scram during reactor startup

50-254/97022-00 LER t% CREVS inoperable

50-254/93025-01 LER "A" loop MSIVs exceeded TS leakage limits

50-254/94004-05; 50-265/94004-05 IFl repetitive oxygen analyzer problems

50-254/94004-06; 50-265/94004-06 IFl back leakage through 1-RHR-78 valve

50-254/94004-27; 50-265/94004-27 IFl core spray pump discrepancy

50-254/94004-34; 50-265/94004-34 IFl work package preparation, utilization, and

processing

50-254/95001-00 LER during Unit 1 startup the RCIC system govemor j

valve did not respond property due to valve steam

corrosion

50-254/95005-00 LER CREV inoperable due to refrigerant leak

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50 254/96004-00 LER Unit i HPCI system inoperable due to gland

exhauster breaker trip

50-254/96014-00 LER electrical distribution surveillanos did not document

voltages in accordance with TS 4.9.E

50-254/97002-07; 50-265/97002-07 URI - Unit 2 CAM system maintenance rule

implementation

Go doiw/027-02(DRS) URI URI portaining to the adequacy of the VT-2 exam of

Class 1 system boundary

6y 42016-01 IFl CREV Train surveillance failure

56 64/93023-00 LER engineered safety feature actuation caused by main

turbine controllogic relay failure

50-254/94004-43; 50-265/94004-43 IFl system engineering weaknesses

50-254/94004-45; 50-265/94004-45 IFl single element feedwater regulating valve control

50-254/94004-47; 50-265/94004-47 IFl . potential LPCI swing bus deficiencies

50-254/94004-51; 50-265/94004-51 IFl design basis documentation

50-254/94004-54; 50-265/94004-54 VIO Title 10 CFR 50.59 evaluations

50-254/95009-02; 50-265/95009-02 URI failure of the EDG to operate

50-254/96006-08 URI secondary containment deficiencies

50-254/96008-08 URI reactor building siding issue

50-254/96010 LER gallery steel above primary containment equipment

installed improperty

50-254/96012-07 URI reactor building blowout panel bolts broken

50-254/96012-00 LER diesel fuel oil transfer piping was in an unanalyzed

condition

50-254/96014-04; 50-265/96014-04 URI the CREV system refrigerant crankcase heater was

fed from non-safety-related power supply

50-254/96017-06; 50-265/96017-06 VIO failure to incorporate a TS requirement

50 254/96017-07; 50 265/96017-07 IFl control room dose calculation

50-254/96017-06; 50 265/96017-08 IFl control room dose calculation

50 254/96017-09; 50-265/96017-09 lFl control room dose calculation

50-254/96017-10; 50 265/96017-10 VIO the CREV system could not maintain required

positive pressure

50-254/96017-11; 50-265/96017-11 VIO the CREV system could not maintain required

positive pressure

50 254/96020-03; 50-265/96020-03 VIO improper testing of CREVs l

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50-254/96024-00 LER the CREV system inadequately tested

50-254/97020-00 LER the B Train CREVs air handling unit breaker cycled

and tripped

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LIST OF ACRONYMS AND INITIALISMS USED

ACE Apparent Cause Evaluation

ADS Automatic Depressurization System

ASME American Society of Mechanical Engineers

CAM Containment Atmosphere Monitor

CFR Code of Federal Regulations

Comed Commonwealth Edison Company

CREVS Control Room Emergency Ventilatum System

DBD Design Basis Docuraentation

DG Diesel Generator

) DGCWP Diesel Generator Cooling Water Pump 1

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CCCS Emergency Core Cooling System

EDG Emergency Diesel Generator

EHC Electrohydraulic Control

ENS Emergency Notification System

EO Equipment Operator 1

ESF Engineered Safety Feature

FME Foreign Material Exclusion

GL Generic Letter j

HPCI High Pressure Coolant injection System )

HVAC Heating, Ventilation, and Air Conditioning

IDNS lilinois Department of Nuclear Safety

IFl Inspection Follow-up item

LER Licensw Event Raport

LPCI Low Pressure Coolant injection

MSIV - Main Steam Isolation Valves

NTS Nuclear Tracking System  !

OOS Out of Service

PDR Public Document Room

PFC Procedure Field Change

PlF Problem identification Form

PM Preventive Maintenance

QAP Quad Cities Administrative Procedure

QC Quality Control

QCAP Quad Cities Administrative Procedure

QCEPM Quad Cities Electrical Preventive Maintenance

QCMMS Quad Cities Mechanical Maintenance Surveillance

QCOP Quad Cities Operating Procedure

QCOS Quad Cities Operating Surveillance Procedure l

QOM Quad Cities Operating Mechanical Procedure  !

RCE Root Cause Evaluation

RCIC Reactor Core isolation Cooling System

RG Regulatory Guide

RHR Residual Heat Removal

RTS Retum to service

SAR Safety Analysis Report l

SBLC Standby Liquid Control j

TD Time Delay  ;

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TGA Toxic Gas Analyzer

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TS Technical Specification l

UFSAR Updated Final Safety Analysis Report i

URI Unresolved item

Vdc Volt direct current '

VT Visual Test -

VIO Violation

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