ML20217G340

Insp Repts 50-254/98-04 & 50-265/98-04 on 980211-0331. Violations Noted.Major Areas Inspected:Operations, Engineering,Maint & Plant Support

ML20217G340
Person / Time
Site:	Quad Cities
Issue date:	04/23/1998
From:	NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20217G284	List: ML20217G280 ML20217G310 ML20217G340
References
50-254-98-04, 50-254-98-4, 50-265-98-04, 50-265-98-4, NUDOCS 9804290114
Download: ML20217G340 (29)

See also: IR 05000254/1998004

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U. S. NUCLEAR REGULATORY COMMISSION

REGION lli

Docket Nos:

50-254;50-265

License Nos:

DPR-29; DPR-30

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Report No:

50-254/98004(DRP); 50-265/98004(DRP)

Licensee:

Commonwealth Edison Company

Facility:

Quad Cities Nuclear Power Station, Units 1 and 2

Location:

22710 206th Avenue North

Cordova, IL 61242

Dates:

February 11 - March 31,1998

Inspectors:

C. Miller, Senior Resident inspector

K. Walton, Resident inspector

L. Collins, Resident inspector

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B. Pulsifer, Licensing Project Manager, NRR

R. Ganser, Illinois Department of Nuclear Safety

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Approved by:

Mark Ring, Chief

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Reactor P ojects Branch 1

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9804290114 980423

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PDR

ADOCK 05000254

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PDR

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EXECUTIVE SUMMARY

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Quad Cities Nuclear Power Station, Units 1 & 2

NRC Inspection Report No. 50-254/98004(DRP); 50-265/98004(DRP)

This resident inspection included aspects of licensee operations, engineering, maintenance, and

plant support.

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Operations

Non-licensed operators improperly retumed a safety-related breaker to service and

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logged the equipment as being available for five days before detecting the deficient

condition. The failure to properly retum the component to service was considered a

violation of procedures (Section 01.2).

Non-licensed operators injected incorrect grease into the station blackout diesel

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generator fuel oil transfer pump, which could have made the pump inoperable due to

grease incompatibility. Initial corrective actions did not address extended operation of the

pumps with incompatible grease and were considered weak (Section 01.2).

Maintenance

Reactor bottom head drain piping failed an in-service pressure test. The licensee

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conservatively used a reactor drain plug and a freeze seal to isolate the piping for repair

(Section M1.2).

An instrument technician found electronic controller modules which were improperly

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assembled by a contracted repair company. This condition was properly reported to alert

other facilities of a potential nonconforming condition (Section M1.2).

A maintenance contractor operated valves with out-of-service (danger) tags attached.

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This issue was considered a violation of the licensee's administrative procedures, and

demonstrated poor safety practices and ineffective control of contractor activities

(Section M1.2).

The licensee identified standby liquid control system temperature switches, used to

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satisfy a Technical Specification surveillance requirement, were set below the required

minimum temperature. There were prior opportunities to identify this missed surveillance

violation (Section M1.3).

All source range nuclear instruments on both units were rendered inoperable because of

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failure to perform Technical Specification required functional testing. Previous corrective

actions were not sufficient to ensure surveillances were performed in a timely manner.

This was considered a violation of surveillance testing (Section M1.4).

Quad Cities was overdue on completion of a number of surveillance and preventive

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maintenance items. The licensee was scheduling surveillances and preventive

maintenance items to be performed past the due date for the items. A violation was

issued for failure to perform snubber surveillances in the appropriate periodicity

(Section M1.5).

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The licensee's corrective actions for previously identified testing deficiencies with the

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' emergency diesel generator air start system were not technically adequate, and

procedure reviews failed to identify the problems (Section M3.1).

Enaineerino

The licensee was not successful in determining the root cause of the Unit 1 emergency

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diesel generator failure to start in January 1998. Nonetheless, operations declared the

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Unit 1 emergency diesel generator operable. No specific actions were recommended to

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improve airstart system performance which was a suspected contributor to the start

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failure. Similar failures had occurred in the past (Section E1.1).

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The prompt investigation team identified the cause of the Unit 1 emergency diesel

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generator failure to run on March 17,1998, to be a fuse block failure. The licensee took

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proper corrective actions to address the problem (Section E1.3).

There were inconsistencies between two 10 CFR 50.59 summary report summaries and

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the respective safety evaluations (Section E1 A).

Although licensee efforts to investigate emergency diesel generator time delay relay

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fa:iures were good, significant reliability problems still existed. Engineering justification

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for dedicating the relays as safety-related parts did not address vulnerabilities of the

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relays to vibration. Engineering justification for exceeding Updated Final Safety Analysis

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Report limits for the relay settings was not thorough (Section E3.1).

There were more preparations (meetings, drawing reviews and subsequent walkdowns)

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by the examiners for the Unit 1 pressure test than other similar pressure tests. The

examiners identified leakage which required repair prior to unit startup (Section E5.1).

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Plant Support

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Repair of the Unit i reactor water cleanup drain line and disassembly of the Unit 1 "A"

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residual heat removal pump were two maintenance activities performed in higher

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radiation areas. The use of as low as reasonably achievable initiatives were effective for

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the residual heat removal pump repairs (Section M1.2).

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The licensee was not aggressive in ensuring that radiation and contamination levels did

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not impact examiners and were kept as low as reasonably achievable in the Unit 1 drywell

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(Section R1.1).

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The Unit 1 scram discharge headers were recently hydrolased to reduce dose ratas for

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hydraulic control unit work and to reduce dose rates in the general area (Section R1.2).

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Report Details

Summary of Plant Stain

Operators maintained both Unit 1 and Unit 2 in cold shutdown during the inspection period due to

safe shutdown capability concems for both units and a planned surveillance outage for Unit 1.

The licensee performed both planned and emergent maintenance activities in parallel with

developing the safe shutdown analysis and implementing procedures for both units associated

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

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l. Operations

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Conduct of Operations

01.1 General Comments (71707)

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During the period, the licensee identified problems with non-licensed operators not

maintaining proper configuration control of equipment important to safety. This included

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the electrical output breaker for the Unit 2 station blackout diesel generator not being

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available for operation and log keeping errors.

01.2. Non-Licensed Operator Errors

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Inspection Scope (71707)

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Theinspectors reviewed problem identification forms, interviewed operators, attended

shift tumovers, observed work in the field, and interviewed operations managers.

b.

Observations and Findinas

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The inspectors noted several events attributed to non-licensed operator errors. Each

event was documented on problem identification forms and addressed by management.

b.1

Failure to Follow Procedures and Loa Takina Errors

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On March 14,1998, operators retumed the Unit 2 station blackout diesel generator to

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service. During the "retum to service," operators used a breaker installation checklist for

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the electrical output breaker. However, the operators failed to charge the output breaker

as required by the checklist. With the breaker not charged, the breaker could not be

closed remotely and the station blackout diesel generator would not be able to supply

power to the electrical bus. The error during the "retum to service" resulted in an

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equipment configuration error. After completing the "retum to service," and due to delays

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in testing, operations department considered the station blackout diesel generator

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available but not operable.

- Additionally, operators were required to ensure that the station blackout diesel generator

output breaker was charged and ready for operation on a daily basis. However, operator

logs indicated that this deficient condition was not detected for five days. The licensee

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documented this condition on Problem identification Form Q1998-01413 and commenced

an investigation into the event.

The inspectors considered this a Violation (50-265/98004-01) for failing to implement

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Quad Cities Operating Procedure 6500-07, " Racking in a 4160 Volt Horizontal Type AMH,

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AMHG or G26 Breaker," Attachment H. The individuals involved were disciplined and

operating crews were counseled about these events.

b.2

Wrona Grease Iniected into Station Blackout Diesel Generator Fuel Oil Transfer Pumo

Operating procedures required that the station blackout diesel generator fuel oil transfer

inboard and outboard pump bearings be injected with Chevron SRI-2 (green) grease.

However, operations personnel identified the pumps were injected with a Benton clay-

type (red) grease. The red and green greases were incompatible and could produce

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either a gummy-like orJelly-like material. This issue was documented on Problem

Identification Form Q1998-01184. The licensee reviewed this incident, and determined

that operators had likely injected the incorrect grease, either because of inattention to

detail or failure to follow procedures. The licensee's initial corrective action plan was to

replace both pumps in a future outage.

The inspectors determined that the licensee's root cause evaluation was weak in that it

did not address the failure of operations personnel to use the correct grease in equipment

important to safety. Additionally, the evaluation did not determine the ability of the pumps

to operate for an extended period of time with incompatible grease. Finally, the

inspectors noted that the proposed corrective actions were poor and did not specify

actions to prevent recurrence. After the inspectors presented these concems to senior

licensee management, the licensee decided to replace the pumps.

c.

Conclusions

Problems with operators maintaining equipment in required configurations continued.

Incidents involving poor non-licensed personnel performance included the failure to

properly retum a safety-related breaker to service, and the failure to detect this condition

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during five routine operator rounds. Additionally, a station blackout diesel fuel oil transfer

pump was injected with the incorrect grease. The inspectors noted the licensee's initial

evaluation and corrective actions did not adequately address the operability of the pumps

for an extended period of time. After the inspectors discussed these concems with senior

licensee management, the licensee replaced both fuel oil transfer pumps.

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Miscellaneous Operations issues (92700)

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(Closed) Licensee Event Report 50-265/96002-00: High Pressure Coolant injection

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Inoperable Due to inadequate Venting. During the quarterly vent verification, operators

were unable to verify that the Unit 2 high pressure coolant injection was properly filled. A

small amount of air had been introduced into the system several months ear 1ier during

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maintenance. Procedures were changed, and the system was filled and vented. A

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calculation was performed which concluded that the small amount of air would not have

prevented high pressure coolant injection from performing its safety function. The

inspectors verified the procedure changes were in place. This item is closed.

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11. Maintenance

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Conduct of Maintenance

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M1.1 . General Comments

The inspectors observed various ' maintenance activities and determined that for the most

part, maintenance was conducted safely and in accordance with regulations. However,

the inspectors noted an instance of the licensee not properly monitoring work performed

by a contract worker. This resulted in the contractor operating out-of-service equipment.

There were further instances of missed Technical Specification surveillances.

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M1.2 Work Reauest Observations

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Inspection Scope (61726. 62707)

The inspectors reviewed and/or observed the following maintenance activities and

assessed the workers' performance and compliance with plant requirements:

WR 950090066

Replace Unit 1 Emergency Diesel Generator Cooling Water Valves

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WR 980016772

Calibrate Unit % Emergency Diesel Generator Time Delay Relays

WR 980016774

Calibrate Unit 2 Emergency Diesel Generator Time Delay Relays

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WR 980018622 '

Inspect Unit 1 Feedwater Controllers for High and Low Current

Limits

WR 980021161

Perform 10-year inspection of Bus 31 Switchgear

WR 980021522

- Establish Freeze Seal for Reactor Water Cleanup System Pipe

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Repair

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WR 980024637

Inspect All Unit 1 Feedwater Modules for Correct Polarity

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WR 980024727

Inspect Unit 2 Jet Pump Modules for Correct Polarity'

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WR 980028384

Adjust Interlock Cam on Breaker 804, Bus 31

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b.

Observations and Findinas

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Deficiencies identified Durina Assembly of Controller Modules

An instrument maintenance technician completed a routine calibration of a controller

module removed from the feedwater system. The module tested satisfactorily, but during

module inspections, the instrument maintenance technician identified that a capacitor on

the module had failed. Further investigations by the technician determined that the

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capacitor was installed backwards. The technician identified a second failed feedwater

module with an incorrectly installed capacitor. The modules had previously been

refurbished by a contracted company, Integrated Resources, in March 1996. The

modules were calibrated by the licensee in the shop, then installed in the feedwater

system. The modules performed in service satisfactorily even with the fr.ud capacitors.

The licensee documented this cor,dition on Problem Identification Form 1998-01152.

Subsequently, the licensee identifiod approximately 180 modules in non-safety-related

applications which had been refurt>ished by Integrated Resources. By the end of the

inspection period, the licensee identified an additional five out of about 200 capacitors

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were installed backwards, and identified other workmanship deficiencies. The licensee

notified other facilities of the defects identified. The licensee planned to repair the

affected modules prior to installation.

b.2

Overhaul of Unit 1 "A" Residual Heat Removal Pump

During the disassembly of the Unit 1 "A" Residual Heat Removal pump, the inspectors

noted good teamwork by electrical and mechanical technicians. Work was conducted in

a time-efficient manner since the work area was in an elevated radiation dose rate field.

Radiation protection reduced area dose rates by flushing then filling system piping,

constructing a lead shield around the work area, minimizing personnel access and using

remote cameras. These efforts resulted in radiation exposures less than anticipated.

The foreman initially in charge of the job was sent to training and the substitute foreman

was unable to spend much time at the work site due to administrative burdens. Lack of

supervisory oversight has been a contributor to maintenance problems in the past. While

most replacement parts for the job were staged and available, some parts were not

available. While preparation and oversight of this activity was not comprehensive,

maintenance completed the rebuild of the pump on schedule.

b.3

Repair to Reactor Water Cleanuo Pipino

During a pressure test, the licensee identified a through-wall leak on an unisolable section

of reactor water cleanup piping under the Unit i reactor vessel. Seveial repair methods

were evaluated. The licensee initially considered a freeze seal alone to isolate the piping,

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but eventually decided to use the seal and install a plug from inside the reactor vessel.

This required removal of the reactor vessel head, removal of some fuel assemblies, and

removal of other interference items. The repairs were completed using a remote welding

machine to minimize worker exposure due to the high dose rates under the reactor

vessel. The contingencies made available in anticipation of a freeze seal failure and the

use of a redundant method to prevent draining the reactor vessel were conservative. The

decision to plug the line inside of the reactor was conservative from an inventory control

perspective.

b.4

Valves Out of Position Durina Work by Vendor

Operators completed an "out-of-service" on the Unit 2 instrument air compressor. Later

on March 26,1998, an operator identified two drain valves (2-4799-919 and 2-4799-920)

that were required to be open and were tagged as open, were in fact closed. The

licensee documented this condition on Problem Identification Form Q1998-01512, and

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subsequently determined that the valves had been improperly positioned in violation of

the attached out-of-service tags by a vendor who was working on the air compressor.

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The licensee used the out-of-service program to ensure personnel safety and system

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integrity. Operating tagged valves was indicative of knowledge and training weaknesses

and poor control of contractors.- Fortuitously, in this case, the operation of the tagged

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drain valves was of low safety significance. The inspectors considered this to be a

Violation (50-265/98004 42) of Quad Cities Administrative Procedure 230-04,

" Equipment Out-of-service," for operating equipment with out-of-service tags attached.

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Conclusions

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The inspectors concluded most maintenance activities were conducted in accordance

with regulatory requirements. However, poor contractor control and training resulted in

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an unauthorized manipulation of a tagged valve. The licensee addressed the reactor

water cleanup piping repair in a conservative manner. The use of as low as reasonably

achievable initiatives were evident for the work on the "A" residual heat removal pump.

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An instrument technician alertly identified a workmanship rieficiency on electronic

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controller modules which had been refurbished by a contracted company.

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M1.3 Missed Standbv Liould Control System Surveillance Due to inadeauate Procedure

a.

Inspection Scope

The inspectors reviewed the licensee's corrective actions in response to the discovery of

a missed surveillance on the standby liquid control system.

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b.

Observations and Findinas

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Dunng a review of licensee corrective actions to previous missed Technical Specification

surveillances, a Quality and Safety Assessment auditor identified that the as-left setpoints

of standby liquid control pump suction temperature switches for both units were lower

than the minimum temperature required by Technical Specifications. Technical

Specification Surveillance Requirement 4.4.A.1.C required the standby liquid control

system be demonstrated operable at least once per 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> by determining the

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temperature of the pump suction piping to be greater ther) or equal to 83 degrees

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Fahrenheit. To satisfy this requirement, control room operators verified the alarm,

" Standby Liquid Control Temperature Hi/Lo," was not actuated once per day.

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A quality and safety assessment auditor determined the setpoints of the temperature

switches for the alarm for both units to be less than 83 degrees. The specified setting of

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the temperature switches was 83 plus or minus 5 degrees Fahrenheit which could have

routinely allowed temperatures below 83 degrees.

Although both reactors were in Mode 4, and the standby liquid control systems were not

required to be operable in Mode 4, the calibration had last been performed in May 1997

and both units operated in Mode 1 since that date. Therefore, the licensee concluded

that surveillance requirements had not been met for the standby liquid control system

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during periods when it was required to be operable. An emergency notification system

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phone call was made on February 10,1998, to report the inoperability of the standby

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liquid control system for both units. The failure to adequately perform the surveillance

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was a Violation (50-254/98004-03; 50-265/98004-03) of Technical

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Specification 4.4.A.1C. For corrective actions, engineers planned to add a thermocouple

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on the suction piping to the standby liquid control system pumps and initiated an

engineering request to increase the temperature setpoint of the Unit 2 heat trace

controller.

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Before the corrective actions could be implemented, licensee management changed the

method for satisfying the surveillance requirement. Instead of relying on the alarm,

operators locally measured the temperature of the suction piping once per day. The new

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acceptance criterion was greater than or equal to 85.6 degrees Fahrenheit and included

uncertainties of both the installed thermocouple and readout device. However, after the

new surveillance method was implemented, operators identified temperatures on 2A,1 A,

and 18 standby liquid control system suction piping were below the acceptance criterion.

Operations declared the associated pumps inoperable. Operations supervisors increased

the surveillance frequency to twice per shift.

This surveillance requirement was new as of the Technical Specification upgrade

implementation in September 1996. The inspectors concluded that the licensee did not

sufficiently research the setpoint requirements to ensure new Technical Specification

requirements could be met. In particular, the effect of the heat trace cycle on the

temperature measurement and the potential for operator error had not been fully

evaluated. Dresden Station identified this and other problems with standby liquid control

system heat tracing in October 1997 and notified Quad Cities. Quad Cities documented

this issue on Problem Identification Form Q1997-04267, but the investigation failed to

recognize that the setpoints of the alarm could be below Technical Specification

requirements.

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Conclusion

The licensee identified standby liquid control system temperature switches, used to

satisfy a Technical Specification surveillance requirement, were set below the required

minimum temperature. A prior opportunity to identify the issue existed.

M1.4 Missed Surveillance Tests for Source Ranae instruments

a.

Inspection Scope

The inspectors reviewed the circumstances surrounding the licensee discovery that all

source range nuclear instruments were inoperable because of exceeding technical

specification surveillance frequency requirements,

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Observations and Findinas

On February 20,1998, a shift manager identified that the source range nuclear

instrument functional tests, which were required by Technical Specification 4.2.G.3.b in

Modes 2 (with intermediate range nuclear instruments on Range 2 or below),3 and 4,

were not performed within the acceptable 31-day periodicity. At the time of discovery,

both units were in a cold shutdown condition. The source range nuclear instruments

were declared inoperable, tested satisfactorily on February 22,1998, then declared

operable. Licensee Event Report 2-98-01 was issued to detail the problem with missed

surveillances.

For Unit 2 the procedure which implemented the Technical Specifications requirement

(Quad Cities Instrument Surveillance 0700-10) was performed on October 15,1997, then

not again until February 22,1998. Unit 1 wa.s brought to Mode 3 on December 20,1997,

and the Technical Specifications 4.2.G.3.b surveillance was not performed until

February 22,1998. Failure to perform the surveillances rendered the source range

nuclear instruments inoperable. With one or more of the source range nuclear

instruments inoperable, all insertable control rods were required to be verified fully

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inserted in the core with the reactor mode switch locked in the shutdown position within

one hour. Failure to perform the surveillances is a Violation (50-254/98004-04;

50-265/98004-04) of Technical Specification 4.2.G.3.b.

The licensee determined that the surveillance requirements were missed because of poor

implementation of upgraded Technical Specifications in 1996. The fact that the

surveillance was required in Mode 4 was not recognized and not put into the controlling

surveillance procedure. In addition, the electronic work control system schedule for the

surveillances was changed without adequate review.

Because of the long history of surveillance problems at Quad Cities and failure of

previous corrective actions to eliminate the problem, the licensee reverted to a manual

scheduling system for Technical Specification surveillances using a line by line

verification of Technical Specifications requirements.

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Conclusion

All source range nuclear instruments on both units were rendered inoperable because of

failure to perform Technical Specifications-required functional testing. Previous

corrective actions were not sufficient to ensure surveillances were performed in a timely

manner.

M1.5 Missed Surveillance and Preventive Maintenance

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Missed Technical Specification Surveillance items

a.

Inspection Scope

The inspectors reviewed the licensee's performance of preventive maintenance items

and surveillances including a surveillance where many snubbers were not performed

within required frequency.

b.

Observations and Findinas

The inspectors spoke with licensee management about the failure to meet a Technical Specification 4.8.F-required snubber visual inspection surveillance. Management had

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indicated that a small number of snubbers were not completed in the required frequency,

and actually went past the critical date. The critical date of a surveillance was the date at

which the surveillance was beyond the normal due date by 25 percent of original

surveillance interval. In this case, the licensee indicated that the 18-month interval was

exceeded by more than 25 percent on February 13,1998. The stated reason was that

unforseen circumstances, including inspector qualification prob; ems and a personal

emergency of the only qualified inspector, prevented completion of the last few

inspections.

The inspectors reviewed this and other surveillances and identified that the licensee had

been scheduling surveillances for performance past the due date (but before the critical

date) on a frequent basis. The snubber surveillance had been scheduled to start in

January 1998 during a planned outage, even though the due date for the surveillance was

thought to be September 1997, which was outside the 18-month interval from the last

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refueling outage. A further review of other surveillances from October 1996 through

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February 1998 showed 425 surveillances went past the initial due date compared to 6304

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performed on time. Inquiries by the inspectors identified that operations, schedulers and

other planners often did not question the scheduling of a surveillance past its due date as

long as the plan was to be complete before the critical date. The problem was

exacerbated by use of the electronic work control system to extend the due date of

surveillances, without keeping track of the original due date. The inspectors noted that

according to the Technical Specifications Section 4.0.B basis, the 25 percent Technical

Specifications margin was not intended to "be used repeatedly as a convenience to

extend surveillance intervals beyond that specified for surveillances that are not

performed during refueling outages." The licensee issued Problem Identification

Form Q1998-01215 to document the problem.

Planning aspects also appeared poor because after shutting down Unit 1 in

December 1997, insufficient planning and management attention were applied to ensure

completion of the snubber inspections by the critical date. The licensee relied on one

qualified inspector on the last possible day to perform the remaining surveillance

requirements, and that plan led to failure to meet the requirements. Planning was also a

problem because the actual interval for inspection of the snubbers was identified to be

improper. The scheduled due date for the inspections after refueling outage Q1R14 was

set for September 1997, which was actually longer than 18 months past some of the

snubber inspections performed in eariy February 1996. Preventive maintenance item

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Number 104537 was intended to initiate the snubber surveillances within the 18-month

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period, but actually scheduled the surveillance at 18 months from the end of the Q1R14

snubber inspections rather than the beginning of those same inspections. This caused all

118 snubber inspections to be beyond the critical date.

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The inspectors identified a similar scheduling problem for the snubber functional testing

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and service life monitoring surveillances. The licensee initially indicated that the

inspections were performed just prior to the critical date being exceeded. However,

following the inspectors' questions, engineers identified two snubbers which did not have

functional testing required by Technical Specifications Section 4.8.F.5 performed in the

18-month plus 25 percent period. Snubbers with in Service inspection numbers

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10128-W-102 and 0200-W-127 were tested on January 8, and January 7,1998,

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respectively. The critical date for these tests was January 6,1998. Failure to perform

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Technical Specification Surveillance Requirement 4.8.F in the appropriate interval was

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considered a Violation (50-254/98004-05).

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Missed Psuventive Maintenance items

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The inspectors reviewed other preventive maintenance items and identified that the

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licensee had not completed many of these items within the scheduled frequency of the

preventive maintenance work request. A licensee preventive maintenance report for

items required in shutdown modes identified that from October 1996 to February 1998,

157 preventive maintenance items were on time, and 1,278 were overdue. The

inspectors identified specific instances where safety equipment preventive maintenance

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tasks were overdue. For instance,9 Cutler Hammer 250 Volt direct current breaker

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cubicle inspections exceeded the prescribed 6-year frequency. Twenty-one 480 V

General Electric breakers had exceeded their 3-year preventive maintenance frequency.

Station blackout diesel generator preventive maintenance items missed required

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frequencies or had never been performed (Problem Identification Form

Numbers Q1998-00587 and 00590).

For some of the equipment (breakers), the inspectors identified that the vendor manual

recommended a yearly preventive maintenance whereas the Quad Cities preventive

maintenance item was scheduled for three years. The licensee had not ensured that the

preventive maintenance requirements met the vendor recommendations for inspection

types or frequency, and had not evaluated the effect of exceeding vendor

recommendations. In some cases the vendor had recommended yearly inspections,

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however, the licensee was recommending three-year inspections but allowed 25 percent

margin or four-year inspections. Even so, maintenance had fciled to complete

inspections within this four-year time frame. The licensee planned to evaluate the effects

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of not performing timely preventive maintenance on breakers and perform breaker

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inspections to ensure preventive maintenance items were current prior to startup.

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c.

Conclusion

The licensee was overdue on completion of a number of surveillance and preventive

maintenance items. The inspectors identified that the licensee was scheduling

surveillances and preventive maintenance items to be performed past the due date for

the items. A violation was issued for failure to perform snubber surveillances in the

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appropriate frequency. The licensee was conducting reviews conceming the effect on

equipment of not performing vendor recommended maintenance on time.

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M3

Maintenance Procedures and Documentation

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M3.1 Emeroency Diesel Generator Testina Procedure

a.

Inspection Scope

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The inspectors reviewed emergency diesei generator testing procedures and issues

relating to Unresolved item 50-254/9700843; 50-265/9700843 regarding the status of

the air start system during emergency diesel generator testing. The inspectors reviewed

licensee actions, test procedures, and the Updated Final Safety Analysis Report

(Section 9.5.6) and discussed the issue with the Office of Nuclear Reactor Regulation.

b.

Observations and Findinas

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Previously, the inspectors identified possible deficiencies with the emergency diesel

!

generator testing procedures. The Technical Specification bases stated that the periodic

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surveillance requirements verify that sufficient air start capacity for each emergency

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diesel generator is available without the aid of the refill compressors. The bases further

stated that with either pair of air receiver tanks at minimum specified pressure, there was

sufficient air in the tanks to start the emergency diesel generator. Revision 15 of

Quad Cities Operations Surveillance 6600-01, * Diesel Generator Monthly Load Test," did

not require the air compressors be off and the air tanks at minimum specified pressure.

Revision 18 of the procedure was intended to implement these actions, but the procedure

was incorrect and directed operators to bleed down pressure in the isolated air tanks.

The independent technical reviews and validation of the procedure change did not find

the error. Operators noticed the deficiency and uaed numerous field changes to correct

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the procedure on a temporary basis. A permanent change was in progress at the end of

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the period. The failure to test the emergency diesel generator in accordance with the

design basis was not considered to be a test control violation because previous testing

had proven that the emergency diesel generator could be started at lower than

230 pounds per square inch gauge air start pressure.

During the review of the revised procedure, the inspectors noted the " Limitations and

Actions" section su90ested to operators that a failed start of the emergency diesel

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generator with one set of air receivers isolated was considered a failure of the air receiver

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tank and not the emergency diesel generator and suggested that operators attempt a

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second start. These statements in the " Limitations and Actions" provided inappropriate

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and conflicting guidance to operators and were not supported in the body of the

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procedure. The guidance was directly opposite of recent guidance given to operators

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after the emergency diesel generator start failure event of January 5,1998, (documented

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in inspection Report 50-254/97028; 50-265/97028). After that event, operations

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management emphasized the need to stop and evaluate the situation when abnormal

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events such as an emergency diesel generator failure occur. The licensee planned to

remove these statements when the procedure was revised.

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c.

Conclusion

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The inspectors had previously identified testing deficiencies with the emergency diesel

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generator air start system. The licensee's initial corrective actions weru "ot technically

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adequate and multiple reviews failed to identify the problems.

M8

Miscellaneous Maintenance issues (92902)

M8.1 (Closed) Inspection Follow-up item (50-254/94005-04: 50-265/94005-04): Problems with

Computer Room Ventilation System. In the past the licensee had numerous problems

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with the reliability of computer room ventilation. For corrective actions, the licensee

completed extensive maintenance to this system including the addition of preventive

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maintenance items. The inspectors noted the reliability of the system had been

increased. This item is closed.

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M8.2 (Closed) Violation 50-254/95002-04: 50-265/95002-04: Torus Recoat Documentation

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Deficiencies. The NRC inspectors identified there was no documented review that the

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deficiencies identified during torus recoating were evaluated for acceptance, rejection or

rework. The NRC inspectors determined this violated requirements for maintaining

quality assurance records. The licensee changed the method of documenting and

reviewing these deficiencies. The inspectors reviewed the improved documentation.

This item is closed.

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M8.3 (Closed) Unresolved item (50-254/96008-16: 50-265/96008-16): Intermixing of

Compression Fittings. The inspectors identified the licensee had intermixed various

manufacturer's compression fittings in the construction of hydraulic control units. The

licensee evaluated this condition as being acceptable in a parts evaluation. All

maintenance personnel had since been trained and procedures modified to ensure

workers do not mix compression fittings in all future uses. The inspectors reviewed the

applicable maintenance procedures and parts evaluation. As part of the parts evaluation,

various mismatched fittings were assembled and tested. The licensee concluded the

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fittings were acceptable for use in fit, form and function._ The inspectors noted the

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information provided was reasonable assurance that the mixed fittings would perform

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their function. This item is closed.

M8.4 (Closed) Violation 50-265/97002-04: High Pressure Coolant injection During Power

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Operation. In 1993 an instrument maintenance procedure was rewritten which removed

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prerequisite steps requiring the procedure be performed in either shutdown or refueling

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modes. In addition, maintenance supervisors inadequately reviewed the procedure and

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schedulers inappropriately scheduled the procedure for power operations. For corrective

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actions, the licensee reviewed surveillances performed more frequently than quarterly to

ensure plant conditions were proper for testing. The licensee changed the maintenance

procedure to ensure the proper plant conditions were included. In addition, other

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administrative procedures were changed to ensure proper review of surveillances prior to

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performance. The inspectors reviewed the revised procedures. This item is closed.

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M8.5 (Closed) Inspection Follow-up Item 50-265/97002-05: High Pressure Coolant injection

During Power Operation. The inspectors were concemed with the scheduling process

which allowed an instrument surveillance procedure be performed for the wrong plant

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conditions (see above item). The licensee changed an administrative procedure to

require use of a daily work addition sheet and subsequent reviews to ensure proper plant

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conditions were in place for testing. This item is closed.

M8.6 (Closed) Unresolved item (50-254/97008-03: 50-265/97008-03): Emergency Diesel

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Generator Testing. This item is addressed in Section M3.1 of this report and is closed.

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Ill. Enoineerina

E1

Conduct of Engineering

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E1.1

General Comments (71707)

The licensee continued to experience problems with emergency diesel generator

performance. A prompt investigation team could not positively identify the root cause for

problems associated with the Unit 1 emergency diesel generator failure to start in

January 1998. However, the prompt investigation team did identify the cause for a

second failure of the Unit i emergency diesel generator to run. The inspectors noted

improvements in the licensee's preparation and execution of visual test examinations of

the reactor vessel during pressure testing on Unit 1.

E1.2

Root Cause of Unit 1 Emeroency Diesel Generator Failure Not Identified

a.

Inspection Scope

The inspectors reviewed the continuing root cause investigation for the Unit 1 emergency

diesel generator failure on January 5,1998.

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b.

Observations and Findinas

This failure was similar in several respects to emergency diesel generator failures that

occurred in August and October 1995, January and May 1997. In each of these cases

the emergency diesel generator failed to start but successfully started on a second

attempt some time later. Root causes were not always identified but the air start system

was the focus of the investigations. Binding of air start motors was identified in this most

recent event in addition to two of the previous failure events.

A previous corrective action was to inspect the air start motors for binding upon

installation. Since the air start motors were installed in December 1997 and one was

identified to be binding in January 1998, the inspectors noted that to inspect for binding

may not be effective. The licensee sent the air start motor offsite for further failure

analysis, and no binding mechanism or problem with the air start motor was identified.

Although the air start motor was replaced, no other corrective actions to address air start

system problems were taken prior to declaring the emergency diesel generator operable.

An action item to investigate air start motor binding was given a September 30,1998, due

date. A trend investigation team issued a report detailing a number of corrective actions

for improving reliability. The report, titled, " TREND INVESTIGATION OF EMERGENCY

DIESEL GENERATOR START FAILURES AND RECOMMENDATION TO INCREASE

RELIABILITY (Nuclear Tracking System number NTS 254-230-98-SCAQ00003)," was

issued March 2,1998. Recommendations in the report to add air start motor redundancy

(Nuclear Tracking System item 007-200-97-QRCR01-01) were not implemented.

The licensee had speculated that the air start motor problems were due to abutment of

the pinion gear to the emergency diesel generator ring gear which prevented the pinion

from turr,ing the ring gear. Engineers designed and performed a test on a similar model

diesel generator which indicated that abutment would not prevent a diesel start. No

further short term analyses of the air start motor problems were pursued. The inspectors

discussed with Com8:d management that the design of the Quad Cities emergency diesel

generators was susceptible to air start motor failures because only two air start motors

were available to crank the diesel, vice four motors available on many other similar

engines at nuclear plants. The system engineer indicated that the manufacturer

representative explained that one air start motor was not sufficient to start the emergency

diesel generator. Thus with the failure or reduced torque capacity on only one air start

motor, a Quad Cities emergency diesel generator may not start. Susceptibility of air start

systems on Quad Cities emergency diesel generators was identified to Quad Cities in a

June 2,1992, architect engineer report which compared the Quad Cities design to

10 CFR 50, Appendix A requirements and to the Dresden Station design. Modifications

to improve reliability were recommended at that time, but were not implemented by

Quad Cities because it was believed that the method the Dresden Station used to

improve reliability (multiple start attempts) may introduce circuit problems. Other

methods to improve reliability were not addressed.

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On March 2,1998, the plant operations review committee reviewed a trend investigation

of emergency diesel generator failures and recommended that the Unit i emergency

diesel generator be declared operable based on troubleshooting and testing performed,

thirteen successful starts, and the replacement of the questionable air start motor. The

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operability recommendation was made even though no root cause was identified, a past

history of similar failures existed, and no short term actions to address air start motor

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vulnerabilities were implemented. Subsequent to the plant onsite review committee

recommendation, operators declared the Unit 1 emergency diesel generator operable on

March 3.

c.

Conclusion

The licensee was not successful in determining the root cause of the Unit 1 emergency

diesel generator failure to start in January 1998. Nonetheless, operations declared the

Unit 1 emergency diesel generator operable based on a history of successful starts. No

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specific actions were recommended to address air start motor problems and design

vulnerabilities, although several root cause investigations and failure determinations had

pointed to air start motor failures in the past. The inspectors recognized substantial effort

was expended by the licensee to evaluate this emergency diesel generator failure.

However, the licensee's inability to determine a root cause and the lack of recommended

actions for airstart system problems caused the inspectors to be concemed with the

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effectiveness of licensee corrective actions for diesel generator failures.

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E1.3

Unit 1 Emeroency Diesel Generator Tripped Durina Testina

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a.

Inspection Scope (71707)

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The inspectors reviewed problem information forms and the prompt investigation team

report associated with the Unit 1 emergency diesel generator electrically tripping during a

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surveillance test. The inspectors also observed licensee walkdowns of the emergency

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diesel generator and observed some maintenance activities.

b.

Observations and Findinas

On March 17,1998, operators started the Unit 1 emergency diesel generator for testing

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and electrically loaded the generator to the bus. After about 30 minutes, the emergency

diesel generator electrical output breaker unexpectedly opened. Operators previously

identified unusual light flickering during the test. After depressing the stop switch in the

control room, the operators detected further indications of unusual light flickering from the

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"run" and "stop" indicating lights.

Operators quarantined the faulty equipment and initiated a prompt investigation team.

The team gathered data from the event, visually inspected the equipment, and reviewed

electrical drawings in an attempt to determine the cause of the electrical fault. The team

concluded that a loose connection in a fuse assembly associated with the power supply

to the emergency dieael generator circuitry was the cause of the fault. The team also had

the same item checked on the other emergency diesel generators to ensure there was no

common mode failure, No discrepancies were identified. The licensee removed and

planned to autopsy the faulty fuse assembly. A new fuse assembly was installed, and the

diesel was later tested satisfactorily.

c.

Conclusions

The licensee continued to have problems associated with the reliability of the emergency

diesel generators (see Section O2.2 in this report and inspection Report 50-254/97028;

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50-265/97028). The prompt investigation team identified the cause of the event and took

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proper corrective actions to address the problem.

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E2

Engineering Support of Facilities and Equipment

E2.1

Problems with Time Delav Relavs on Emeroency Diesel Generators

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a.

Inspection Scope

The inspectors reviewed the licensee's troubleshooting and maintenance process for

failures of time delay relays similar to failures noted in December 1997 and documented

in Inspection Reports 50-254/97028 and 50-265/97028.

b.

Observations and Findinas

On March 22,1998, the licensee identified problems with the timing setpoints of the

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Unit i emergency diesel generator time delay relays 1 and 2. Time delay relay 2 limited

the amount of time the emergency diesel generator cranked during start attempts to

preserve starting air for another attempt. Timing out too early on time delay relay 2 could

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prevent an emergency diesel generator start and possibly damage the emergency diesel

generator due to high temperature problems. Time delay relay 1 ensured that the

emergency diesel generator would stop (unless an auto-start signal was present) after

90 seconds if sufficient oil pressure was not achieved in the emergency diesel generator.

Timing out too early on time delay relay 1 could cause the emergency diesel generator to

shut down in all but auto start situations. Both relays were Square D Type EQ1933G2

with a range of zero to three minutes.

The licensee assembled a prompt investigation team to review the operability of the

emergency diesel generator, and to identify what actions needed to be taken if it was

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found necessary to modify the time delay circuitry. The team identified a number of

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problems with the relays and their application.

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The relays were not designed for a vibration environment according to system

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engineer discussions with the vendor (Engine Systems Incorporated). However,

the relays were installed on the emergency diesel generator skid which was

subjected to vibration during diesel operation.

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The relays had a plus or minus ten percent stated repeat accuracy according to

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the manufacturer, but were being set in an acceptable band of only half that

amount for time delay relay 2.

The relays were very sensitive, and difficult to set property.

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The relays exhibited varying amounts of drift outside of the stated accuracy.

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Some of the drift was associated with the difference between static and engine

running conditions.

The team concluded that the relays would likely hold to an acceptable calibration if the

setpoint band was changed to be within the stated accuracy of the relays. The time

delay relay 2 band was expanded from 15 to 16.5 seconds to 13.5 to 16.5 seconds. The

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time delay relay 1 setpoint band of 81 to 99 seconds was deemed acceptable. The team

also established by field testing that the relays would drift to actuate more quickly in a

vibration environment (by about two to four seconds). Based on six starts of the Unit 1

emergency diesel generator with only one failure of time delay relay 1 to maintain the

acceptable band and no time delay relay 2 failures, the station concluded that the Unit 1

emergency diesel generator was operable. Relays in the Unit 2 and Unit % emergency

diesel generators were tested, and reset or replaced. The team concluded that all

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emergency diesel generators were operable, and continued to pursue a long term

solution to time delay relay reliability, including potential replacement with relays not

affected by vibration, and movement of the relay onto a non-vibrating environment.

Engineers also planned weekly tests of the emergency diesel generators for at least three

weeks to establish a reliability trend.

Although the licensee's evaluation efforts were substantial, the inspectors were

concemed with the licensee's approach to determining operability.

The inspectors identified that even though testing methodology was improved, a

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number of time delay relay failures occurred outside the expected 10 percent

accuracy range. One time delay relay 2 failure occurred only three months after

relay replacement, and exhibited a six-second setpoint drift. Other time delay

relay failures were also documented because of repeatability problems. Although

several tests had been performed, sufficient data to establish an adequate

calibration frequency and methodology had not been developed by the close of

the inspection period. The licensee had planned at least three weekly tests during

running conditions for each emergency diesel generator, but had not started these

tests due to plant conditions.

The inspectors observed the field setpoint for time delay relay 2 on the Unit 1

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emergency diesel generator, it was set at 16.4 seconds which was in the

acceptable band provided by the procedure. However, the inspector identified

that the basis for allowing a setpoint greater than 15 seconds was not well

established. With a stated manufacturer accuracy of plus or minus 10 percent,

cranking time for the emergency diesel generator could be as long as 18 seconds.

Updated Final Safety Analysis Report Section 9.5.6 indicated the starting air

system for the engine would crank the engine for 15 seconds or until the engine

started, that there was sufficient air for two 15-second starts, and if the engine did

not reach 200 rpm within 15 seconds, a diesel generator " fail to start" alarm would

annunciate in the main control room. Quad Cities design basis document

DBD-QC-009, Revision A, Section 4.1.7.2 indicated the 15-second cranking cycle

was determined to allow the maximum cranking time and still prevent the

equipment from overheating. Although the licensee documented this information

in a screening for Problem identification Form Q1998-00251, the justification for

not damaging components or for challenging the 15-second Updated Final Safety

Analysis Report criteria was not well established. This is considered an

Unresolved item (50-254/98004-06; 50-265/98004-06) pending review of

licensee justification for changing Updated Final Safety Analysis Report

requirements.

The inspectors ieviewed the qualification paperwork which upgraded the

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commercial grade time delay relays to a safety related status. Parts Evaluation

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CE-89-1540 dedicated both time delay relays 1 and 2 for 10 CFR 21 safety-related

status. The evaluation clearly justified the need for the parts to be classified as

safety related. However, the authorizing evaluation (M-95-0697-00) provided by

the licensee as the document used to qualify the commercial grade part, did not

provide a discussion of critical characteristics for the relays. The inspectors

identified no discussion of any sort as to the qualification for vibration or seismic

conditions, high temperatures or other adverse conditions in the emergency diesel

generator rooms during operation. This is considered an Unresolved item

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(50-254/98004 07; 50-265/98004-07) pending further review of licensee

qualification information.

c.

Conclusions

Although licensee efforts to investigate emergency diesel generator time delay relay

failures were good, significant reliability problems still existed. Engineering justification

for dedicating the relays as safety-related parts did not address vulnerabilities of the

relays to the vibration environments in which they operated. Engineering justification for

exceeding Updated Final Safety Analysis Report limits for the relay settings was not

thorough.

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E5

Engineering Staff Training and Qualification

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E5.1

Unit 1 Class 1 Leak Test

a.

Inspection Scope (37551)

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With the system pressurized to normal operating pressure, the inspectors accompanied

Level ll Visual Test-2 examiners during the operational pressure test of the Unit i reactor

vessel and attached piping both inside and outside the drywell.

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b.

Observations and Findinos

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Licensee personnelinspected the Unit 1 pressure vessel, including head flange and all

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piping up to low pressure interfaces, with reactor pressure at 1000 pounds per square

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inch gauge. Personnel training and numerous briefs were conducted prior to the

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pressure test to ensure examiners were properly informed of management expectations

and familiar with the newly approved procedures. Each examiner conducted walkdowns

of inspection points using marked up maps with specific inspection points prior to the

pressure test.

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During the pressure test, the examiners used inspection mirrors and spotlights to assist in

examinations. The examiners were familiar with the piping and carried piping diagrams

and sign off sheets, which were marked while conducting examinations. The inspections

took several hours, as opposed to the twenty minute versions performed last summer on

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Unit 2. The examiners in the drywell were subjected to elevated ambient temperatures

and higher radiation dose rates. The inspectors observed the examinations and

determined that even under these difficult conditions, the examinations were thorough.

A portion of the visual test examination was located undemeath the reactor vessel. The

areas of leakage were not readily accessible and considerable effort was needed for the

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examiner to identify the locations of leakage. However, from this examination, a leak in

the Unit 1 reactor bottom head drain line was identified and repairs were subsequently

initiated. The examiners determined a 2 inch reactor water cleanup pipe beneath the

reactor vessel had a through-weld leak. Similarly, the reactor vessel head flange leak

detection system alarmed indicating possible reactor vessel head flange leakage.

Licensee management was informed of the results of the test. The licensee planned to

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address the leaks prior to unit staeo.

c.

Conclusions

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The inspectors noted there were more preparations (meetings, drawing reviews and

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subsequent walkdowns) by the examiners for this pressure test than other similar

pressure tests. Piping inspections observed were thorough. The examiners identified

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leakage which required repair prior to unit startup.

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E7

Quality Assurance in Engineering Activities

E7.1

Review of 10 CFR 50.59 Summary Report and Updated Final Safety Analysis Report

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Update

a.

Inspection Scope (71707)

The inspectors reviewed the licensee's " Summary Report of Changes, Tests and

Experiments Completed," dated October 31,1997, and " Updated Final Safety Analysis

Report (UFSAR) Update," dated October 22,1997. The inspection included a review of

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selected changes to the Updated Final Safety Analysis Report and 50.59 summary

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reports, and discussions with regulatory assurance personnel.

b.

Observations and Findinas

The inspectors reviewed " Summary Report of Changes, Tests and Experiments

Completed," dated October 31,1997. One summary in the report stated there was a

reduction in the margin of safety. Upon further review of the actual safety evaluation, it

was determined that the summary report was in error. A licensee letter dated March 20,

,

1998, corrected this error. This was the second safety evaluation summary in this report

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which incorrectly indicated there was a reduction in margin of safety. The other safety

evaluation,96-043, was discussed in Inspection Report 50-254/97022; 50-265/97022.

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On two occasions, information removed from Technical Specifications was either

changed without an evaluation or not placed into the Updated Final Safety Analysis

Report in its entirety. The items were removed from Technical Specifications with the

intention of being placed in the Updated Final Safety Analysis Report. In Technical

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Specification Amendment 177 for Unit 1 and 175 for Unit 2, dated May 23,1997, previous

Technical Specification Section 5.4, " Reactor Coolant System," was removed from

Technical Specifications and was to be placed into the Updated Final Safety Analysis

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Report. The licensee was not able to provide documentation showing that all of the

information in Technical Specification 5.4 had been placed into the Updated Final Safety

Analysis Report.

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The second example involved the removal of Table 4.6-2, * Revised Withdrawal Schedule

For Quad Cities Unit 2" from the previous Technical Specification and placing the

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information into the Updated Final Safety Analysis Report in accordance with

Amendment 158. This table was the schedule for removal of the reactor vessel material

samples based on a surveillance program as defined in Section Ill.C of 10 CFR Part 50,

Appendix H. The azimuth location for one of the sample holders in the Updated Final

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Safety Analysis Report did not reflect the position shown in Table 4.6-2.

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The licensee stated the Updated Final Safety Analysis Report would be corrected and the

information in previous Technical Specification Section 5.4 and Table 4.6-2 would be

included into the Updated Final Safety Analysis Report. On January 6,1998, the

Quad Cities Station Manager stated he would ensure that all the items removed from

Technical Specifications that were to be placed into controlled documents in accordance

with the Technical Specification Upgrade Program (Amendment 171 for Unit 1 and

A.mendment 167 for Unit 2) had been accomplished.

c.

Conclusions

There were inconsistencies between two 10 CFR 50.59 summary report summaries and

the respective safety evaluations. Also, the Updated Final Safety Analysis Report update

identified two former Technical Specification items that were not placed into the Updated

Final Safety Analysis Report as intended. These inconsistencies pointed to a need for

more attention to this area to assure the licensing basis was properly maintained.

E8

Miscellaneous Engineering issues

E8.1

(Closed) Unresolved Item 50-254/94028-01: 50-265/94028-01: Incorrect Rod Withdrawal

Sequence Error. The licensee identified that the sequence for control rod withdrawal was

not in accordance with fuel vendor requirements. This condition existed when an

engineer developing the rod program did not encounter any waming messages of the

deviation from the software. The sequence was copied for rod withdrawals since

October 1991. The licensee analyzed this condition and determined the Technical

Specification requirements for energy deposition in the fuel during a rod drop accident

were not exceeded. The licensee corrected the rod withdrawal sequence error and

retrained nuclear engineering personnel. The software used in building the control rod

withdrawal sequence was reviewed for technical accuracy and validated. The inspectors

reviewed the licensee's investigation and corrective actions for this event. This item is

closed.

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E8.2

(Closed) Inspection Follow-up item 50-254/95005-05: 50-265/95005-05: Incomplete

Disposition of Information Notice 91-78. The information notice documented instances

where safety-related breakers had failed due to existing blown fuses in the control circuit

that were not indicated. The issue was applicable to breakers at Quad Cities; however,

no changes to the control circuit were planned and operators were not aware that a

failure in the control circuit could prevent a breaker from closing but would not always be

indicated by the loss of indicating lights. The station chose to train operators and

presented this topic in a training session (95-6). The inspectors reviewed the training

module. This item is closed.

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E8.3 (Closed) Unresolved item 50-254/96012-03: 50-265/96012-03: Altemate Battery

Replacement. Operators removed the Unit 2 altemate 125 Volt direct current battery

from service for a four month period. During an extended maintenance activity, the

attemate battery lost the ability to maintain a charge. The licensee removed the Unit 2

attemate battery and replaced it with the attemate battery from Unit 1. Both the normal

and attemate batteries from Unit 2 were tested satisfactorily. This item is closed.

E8.4

(Closed) Deviation 50-254/96015-01: 50-265/96015-01: Residual Heat Removal Service

Water Cooler Fouling. The inspectors identified that residual heat removal service water

cooling to the safety-related components was not trended as the licensee had committed

to in a licensee event report. The reason for the deviation was an inadequate tumover in

system engineering and no procedural requirement to trend and analyze system

performance. The licensee implemented a procedure to trend and analyze residual heat

removal service water system performance and electronically tied this procedure to the

surveillance test to ensure the system engirteer was notified of the test performance. The

inspectors reviewed the licensee's corrective actions. This item is closed.

E8.5 (Closed) Licensee Event Report (LER 50-254/96016) and (Closed) Violation

(50-254/96019-02al: Reactor Building Siding Damaged by High Wind. On May 10,1996,

high wind damaged the reactor building siding. The licensee identified reactor panel blow

out bolts, which fastened the siding to the structural steel, had been damaged prior to the

event. The licensee also identified that the bolts and structure had never been subjected

to inspection as required by a design drawing. This, and other issues, were discussed in

Inspection Report 50-254/96019; 50-265/96019 and were subject to enforcement action

(Enforcement Action 96-531). The licensee completed the corrective actions stated in

the licensee event report. The inspectors reviewed the corrective actions and verified the

reactor building structure was included in an inspection program. These items are

closed.

E8.6

(Closed) Violation 50-254/96019-01: 50-265/96019-01: 50-254/96019-02b:

50-265/96019-02b: Design Control and Modification Violations Associated with

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Secondary Siding. These violations were associated with Enforcement Action 96-531.

The inspectors identified piping fastened to the reactor building blow out panels that was

not properly analyzed and a 10 CFR 50.59 evaluation which improperly concluded that a

change to the facility did not involve an unreviewed safety question. The licensee

completed the corrective actions documented in the response to the violation. The

inspectors verified the piping fastened to the reactor building blow out panels was

removed. These items are closed.

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E8.7

(Closed) Unresolved Item 50-254/97006-06: 50-265/97006-06: Inservice Test

instrumentation Requirements. The inservice test alert and required action range limits

were calculated down to tenths of gallons per minute as noted during the standby liquid

control system surveillance. The installed gauge was in increments of two gallons per

minute. The inspectors reviewed the inservice test program requirements and concluded

that these limits were acceptable. This item is closed.

E8.8

(Closed) Unresolved item 50-254/97028-04: 50-265/97028-04): Emergency Diesel

Generator Fuel Oil Retum Piping Inadequately Supported. The inspectors identified that

the fuel oil retum pipe from the shared emergency diesel generator to the day tank was in

contact with an adjacent electrical conduit and questioned the distance between

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supports. Engineering analyzed both conditions. Engineering determined the fuel oil

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retum piping was adequately supported and determined the interaction between the two

pipes, even during a seismic event, was within the design margins. The inspectors

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reviewed the supporting calculations. This item is closed.

IV. Plant Support

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R1

Radiological Protection and Chemistry Controls

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R1.1

Unit 1 Drywell Radioloaical Conditions

a.

Inspection Scope

The inspectors reviewed drywell conditions during and following a reactor pressure

boundary leak (Mt.

b.

Observations and Findinas

During preparations for a Unit 1 drywell tour, inspectors and senior NRC management

were briefed by radiation protection technicians as to the contamination and radiation

levels in the basement and first two levels of the drywell. Contamination levels in the

Unit 1 drywell basement reached as high as 1 million disintegrations per minute per

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100 square centimeters. General area dose rates averaged about 80 millirem per hour.

On the first and second levels of Unit 1 drywell, contaminations levels averaged about

25,000 disintegrations per minute per 100 square centimeters. General area dose rates

on the first and second levels averaged about 60 millirem and 300 millirem respectively.

During the tour, inspectors identified some of the areas reading in excess of 500 millirem

per hour.

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Although the licensee indicated that the normal refueling outage process of chemical

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decontamination had not taken place tweduce dose rates, and the drywell had not been

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cleaned as it would for an outage, the inspectors considered the dose rates and

contamination levels abnormally high. Cursory reviews of several other boiling water

reactor drywells indicated general area dose rates in the range of 10 to 20 percent of the

Quad Cities Unit 1 levels, and contamination levels of 1 to 20 percent of the Quad Cities

Unit i levels. The high contamination levels had affected workers performing leak test

inspections in that they were required to wear face shields and full rubber gear during

drywell basement inspections. The high radiation levels affected all drywell workers,

especially leak test inspectors who needed to perform detailed piping inspections, and

may have been limited by dose concems. The inspectors identified that while the

radiation protection planning had incorporated as low as reasonably achievable

considerations, the management attention to high dose rates and contamination levels

did not lead overall to as low as reasonably achievable work practices.

Previous practices of cycling hydrogen addition (used to protect reactor recirculation

piping from cracking) was believed to be the reason for increased reactor system dose

rates. The licensee indicated that chemical decontamination was not possible for the

expected duration of the safe shutdown outage, and hanging lead shielding would not

yield as low as reasonably achievable radiation doses because of the excessive dose

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accumulated in hanging the shielding compared to the amount of work remaining in the

drywell. The licensee agreed that contamination levels could be reduced to levels which

would not require face shields or as extensive rubber gear protection and formulated a

plan to spot clean Unit 2 prior to the leak test. Spot cleaning in the Unit 2 drywell reduced

contamination levels from over 2 million disintegrations per minute per 100 square

centimeters to about 75,000 disintegrations per minute per 100 square centimeters and

allowed inspectors and workers to be free from face shields. Dose rates for the shut

down Unit 2 reactor at Quad Cities were about 20 percent of the Unit 1 rates due in part

to a recent chemical decontamination and in part to installation of depleted zinc injection.

Zinc injection was also instalfed in Unit 1 during the present outage.

The inspectors reviewed the licensee's plans to use zine injection for Unit 1. Chemical

decontamination prior to using zinc injection had been observed to reduce the high

radiation depositions prior to adding the zinc coating, and yield an overall lower dose rate

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for reactor systems. The licensee had not yet determined if a chemical decontamination

should be completed.

c.

Conclusion

The licensee was not aggressive in ensuring that radiation and contamination levels did

not affect worker performance and were kept as low as reasonably achievable in the

Unit 1 drywell. Plans to use zine injection for Unit 1 were aimed at future radiation dose

reduction.

R1.2

Hydrolasina Effectively Reduced Dose Rates

The Unit i scrarc discharge headers were recently hydrolased to reduce dose rates for

hydraulic control unit work and to reduce dose rates in the general area. Station workers

had written a new procedure which allowed workers to perform the hydrolasing operation

faster than previously. The licensee found that personnel dose for this job was

significantly reduced. Over the last two hydrolasing efforts, the dose was reduced by

three to six times over previous performances. This was a significant contribution in

keeping exposure to workers as low as reasonably achievable.

R8

Miscellaneous Radiological Protection and Chemistry issues

R8.1

(Closed) Unresolved item 50-254/96020-08: 50-265/96020-08: Weaknesses in

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Calibration Program. The inspectors identified a low flow condition in a radiological

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effluent monitoring system. The licensee determined the cause of the radiological

effluent monitor low flow was due to weak change management by the design engineer

and poor deficiency resolution by the instrument maintenance department. For corrective

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actions, the licensee calibrated the appropriate flow switch and pressure indicators, and

included the pressure indicators in a calibration program. The licensee also developed a

calibration procedure for the flow switch on an 18-month frequency. The inspectors

consider this unresolved item closed.

The inspectors further questioned the licensee's calibration program used in support of

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safety-related systems. The inspectors opened Inspection Follow-up

Item 50-254/97002-06; 50-265/97002-06 to evaluate other safety-related instrument

calibration issues.

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V. Manaaement Meetinos

X1

Exit Meeting Summary

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

conclusion of the inspection on March 31,1998. The licensee acknowledged the findings

presented.

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PARTIAL LIST OF PERSONS CONTACTED

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Licensee

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D. Sager

Site Vice President

L. Pearce

Station Manager

J. Walker

Quality Safety & Assessment Manager

R. Holbrook

Engineering Manager

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R. Svaleson

Operations Manager

G. Powell

Radiation Protection / Chemistry Manager (Acting)

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A. Chernick

Regulatory Affairs Superintendent

J. Kudalis

Business Manager

R. Cook

Electrical Maintenance Team Coordinator

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J. Weaver

Training Supervisor

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INSPECTION PROCEDURES USED

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IP 37551:

Offsite Engineering

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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

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lP 92902:

Followup - Maintenance

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

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50-265/98004-01

VIO

failure to follow procedures and log tracking

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errors

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50-265/98004-02

NCV valves out of position during work by vendor

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'50-254/98004-03; 50-265/98004-03

VIO

missed standby liquid control system

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surveillance due to inadequate procedure

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50-254/98004-04; 50-265/98004-04

VIO

missed surveillance tests for source range

instruments

50-254/98004-05

VIO

missed surveillance on piping snubbers

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50-254/98004-06; 50-265/98004-06

URI

EDG Updated Final Safety Analysis Report

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discrepancies

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50-254/98004-07; 50-265/98004-07

URI

time delay relay qualification for part 21

Closed

50-265/96002-00

LER

high pressure coolant injection inoperable

due to inadequate venting

50-254/94005-04; 50-265/94005-04

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problems with computer room ventilation

system

50-254/95002-04; 50-265/95002-04

VIO

torus recoat documentation deficiencies

50-254/96008-16; 50-265/ % 008-16

URI

intermixing of compression fittings

50-265/97002-04

VIO

high pressure coolant injection during power

operation

50-265/97002-05

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high pressure coolant injection during power

operation

50-254/97008-03; 50-265/97008-03

URI

Technical Specification bases not in

agreement with procedures

50-254/94028-01; 50-265/94028-01

URI

incorrect rod withdrawal sequence error

'50-254/95005-05; 50-265/95005-05

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incomplete disposition of Information Notice 91-78

50-254/96012-03;50-265/96012-03

URI

attemate battery replacement

50-254/96015-01; 50-265/96015-01

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residual heat removal service water cooler

fouling

50-254/96016-00

LER

reactor building siding damaged by high

wind

50-254/96019-02a

VIO

reactor building siding damaged by high

wind

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50-254/96019-01; 50-265/96019-01

VIO

design control and modifications violations

associated with secondary siding

50-254/96019-02b; 50-265/96019-02b

VIO

design control and modifications violations

associated with secondary siding

50-254/97006-06; 50-265/97006-06

URI

inservice test instrumentation requirements

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50-254/97028-04; 50-265/97028-04

URI

emergency diesel generator fuel oil retum

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piping inadequately supported

50-254/98004-02

NCV valves out of position during work by vendor

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50-254/96020-08; 50-265/96020-08

UNR Weaknesses in Calibration Program

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LIST OF ACRONYMS AND INITIALISMS USED

CFR

Code of Federal Regulations

Comed

Commonwealth Edison Company

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DEV

Deviation

IDNS

lilinois Department of Nuclear Safety

IFl

Inspection Follow-up item

IR

inspection Report

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LER

Licensee Event Report

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PDR

Public Document Room

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RG

Regulatory Guide

UFSAR

Updated Final Safety Analysis Report

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URI

Unresolved item

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VIO

Violation

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WR

Work Request

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