ML20134M988

Insp Repts 50-254/85-17 & 50-265/85-19 on 850601-0731. Violation Noted:Inadequate Shift Turnover & Lack of Proper Protective Covers for safety-related Items in Storage

ML20134M988
Person / Time
Site:	Quad Cities
Issue date:	08/20/1985
From:	Wright G NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION III)
To:
Shared Package
ML20134M971	List: IR 05000254/1985017 IR 05000601/2007031 ML20134M968
References
TASK-2.B.3, TASK-2.F.2, TASK-TM 50-254-85-17, 50-265-85-19, NUDOCS 8509040367
Download: ML20134M988 (15)

See also: IR 05000601/2007031

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U. S. NUCLEAR REGULATORY COMMISSION

REGION III

Reports No. 50-254/85017(DRP);50-265/019(DRP)

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

Licensee: Comonwealth Edison Company

Post Office Box 767

Chicago, IL 60690

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

Inspection Conducted: June 1 through July 31, 1985

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Inspectors: A. L. Madison

A. D. Morrongfello

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Approved By:, . t h

Reactor Projects Section 2C

8//d[#3

Da'te '

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Inspection Summary:

Inspection on June 1 through July 31, 1985 (Reports No. 50-254/85017(DRP);

50-265/85019(DRP))

Areas Inspected: Routine, unannounced inspection by the resident inspectors

of actions on previous inspections findings; operations; radiological

controls; maintenance / modifications; surveillance; bousekeeping procedures;

fire protection; emergency preparedness; security; quality assurance; quality

control; administration; routine reports; LER review; TMI items; Review and

Audits including Site Review Committee; Receipt, storage and handling of

Equipment Program; Spent Fuel Pool Activities; and independent inspection.

The inspection involved a total of 391 inspector-hours onsite by two NRC

inspectors, including 80 inspector-hours onsite during off-shifts.

Results: Two violations were identified. The first involved inadequate

shift turnover and the second lack of proper protective covers for safety

related items in storage. Additionally, an item of concern relating to safety

system challenges was identified in the maintenance area. Overall, the

licensee's performance has remained steady.

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8509040367 85082124

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DETAILS

1. Persons Contacted

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• N. Kalivianakis, Superintendent

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• D. Bax, Assistant Superintendent for Maintenance

T. Lihou, Technical Staff Supervisor

R. Roby, Senior Operating Engineer

• N. Griser, Senior Quality- Assurance Specialist

The inspectors also interviewed several other licensee employees,

including shift engineers and foremen, reactor operators, technical

staff personnel, and quality control personnel.

• Denotes those present at the exit interview on July 31, 1985.

- 2. Routine Inspection

The resident inspectors, through direct observation, dis'cussions with

licensee personnel, and review of applicable records and logs, examined

the areas stated in the inspection summary and accomplished the following

inspection modules.

37700 Design Changes and Modifications

38702 Receipt, Storage and Handling of

Equipment Program

40700 Review and Audits, including State

Review Committee

42700 Plant Procedures

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61726 Monthly maintenance observations

62703 Monthly maintenance observations

71707 Operational safety verification

, 71710 ESF system walkdown

86700 Spent Fuel Pool Activities

90713 Review of periodic and special

reports

j 92700 Onsite review of LERs

92701 TMI Action Items

92706 Independent inspection

93702 Onsite followup of events

The inspectors verified that activities were accomplished in a timely

manner using approved procedures and drawings and were inspected / reviewed

as applicable; procedures, procedure revisions and routine reports were

in accordance with Technical Specifications, regulatory guides, and

industry codes or standards; approvals were obtained prior to initiating

any work; activities were accomplished by qualified. personnel; the

limiting conditions for operation were met during normal operation and

while components or systems were removed from service; functional testing

and/or. calibrations were performed prior to returning components or

systems to service; independent verification of equipment lineup and

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review of test results were accomplished; quality control records and

logs were properly maintained and reviewed; parts, materials, and

equipment were properly certified, calibrated, stored, and or maintained

as applicable; and adverse plant conditiens including equipment

malfunctions, potential fire hazards, radiological hazards, fluid leaks,

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excessive vibrations, and personnel errors were addressed in a timely

manner with sufficient and proper corrective actions and reviewed by

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appropriate management personnel.

Further, additional observations were made in the following areas:

' Action on Previous Inspection Findings

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a.

] (Closed) Open Item 254/85007-01 and 265/85007-02: Install 48V

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Battery Seismic - side Spacing. Problems. This item was used to

track completion of modifications to the station 48V batteries to

, correct side spacing problems. It was determined by the licensee

I that adjustments could be made to the existing battery supports and,

therefore, no modifications were required. Proper adjustments were

i made. No further actions are required.

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(Closed) Open Item 265/85004-01: No Procedures For Dropped or

Otherwise Damaged Fuel Bundle. This item addressed concerns with

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the adequacy of the licensee's refueling procedures and identified

the following weaknesses:

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(1) No procedures for the refueling crew in the event of a dropped

or otherwise damaged fuel bundle.

(2) No requirements to ensure adequate radiation monitoring during

fuel movement.

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(3) No guidance given in the event of a loss of water level during

refueling operations.

! The licensee initiated changes to appropriate procedures to address

l these weaknesses prior to refueling operations on Unit 2. The

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inspectors reviewed these changes and found them adequate. No

further actions are required.

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(Closed) Open Item 254/85012-02 and 265/85013-02: Station Battery

Surveillance and Maintenance Procedure Changes. This item was used

to track procedure changes to address the following two concerns:

(1) No post-maintenance testing following cell jumpering or

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replacement.

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(2) No requirement for float charge as part of initial conditions

'for weekly and quarterly surveillances.

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Changes to appropriate procedures have been accomplished and

reviewed by the inspectors. No further actions are required.

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No violations or deviations were identified.

b. Operations

Unit I was in operation at the beginning of the report period. On

June 8, 1985, a Residual Heat Removal Services Water (RHRSW) pump

was found to have a broken seal cooling water line. This placed the

Unit in a 30 day Limiting Condition for Operation (LCO). During

testing of equipment required by the LCO, it was discovered that the

Torus Spray Valve would not open. Since the requirements of the LCO

could not be met, an Unusual Event was declared and a shutdown was

initiated. Subsequently, the RHRSW pump and valve were repaired and

returned to service and the Unusual Event and the shutdown were

terminated.

On June 17, 1985, a vent line on 1 C RHRSW pump ruptured, spraying

water on 1 B RHRSW pump and the 1/2 Diesel Generator service water

(DGSW) pump. This placed Unit 1 in an Unusual Event and an orderly

shutdown was initiated. Several hours later the leak was stopped

and the 1 B RHRSW pump and 1/2 DGSW pump were returned to service.

The Unusual Event and the shutdown were then terminated.

On July 11, during panel checks for shift turnover on Unit 1, it

was found that the High Pressure Coolant Injection (HPCI) controller

had been left in the manual position instead of automatic following

testing. This was the second shift change to occur following

completion of testing. The controller was set to 100% so HPCI would

have injected adequate cooling water upon an initiation signal.

However, QAP 300-7: " Shift Change Nuclear Station Operators",

requires that both the offgoing and oncoming operators check the

control room panels pursuant to QOS 005-2: " Normal Control Room

Inspection and Shift Turnover Panel Check". QGS 005-2 requires the

HPCI flow controller to be in automatic.

The initiating cause was an inadequate test procedure which did not

require the controller to be returned to automatic. Personnel error

on the part of the offgoing and oncoming operators in not performing -

an adequate shift turnover allowed the controller to remain in that

condition. This is a violation (254/85019-01(DRP)).

On July 25, 1985, the licensee declared an Unusual Event when it was

determined that the room cooler for one RHR corner room uas inoperable.

This made two RHR pumps inoperable and a third was already out of

service for repair purposes. Therefore, with three out of four RHR

pumps inoperable, an orderly shutdown was commenced. Several hours

later the room cooler was repaired and the Unusual Event and Shutdown

were terminated. Unit I remained at full power at the close of the

report period.

Unit 2 was shut down for a maintenance and refueling outage at the

beginning of the report period. On June 5, 1985, the unit returned

to power and, except for minor reductions for testing and load

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dispatcher requirements, remained at power throughout the remainder

of the report period. The smooth startup and relatively trouble

free operation of Unit 2 are evidence of an effective maintenance

program.

-During plant tours of Units 1 and 2, the inspectors walked down the

accessible portions of the Standby Liquid Control Systems, the

Standby Gas Treatment Systems, and the Reactor Core Isolation

Cooling Systems and performed the applicable portions of Inspection

Procedure 71710 "ESF System Walkdovn".

No other violations or deviations were identified.

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c. Radiological Controls

On July 24, 1985, the licensee confirmed that a pipe used to transfer

processed water from the liquid radwaste treatment facility to the

Condensate Storage Tanks (CST) had developed a leak. The pipe is

five feet below ground and covered by the radwaste concrete floor.

Discovery was made due to water seepage through the floor. The

licensee has isolated the pipe and intends to replace it with above

ground piping.

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Initial on-site sampling and observations by the licensee indicate

that no off-site releases have occurred. The concentration of

activity in the CST based on a gamma isotoxic analysis is below the

maximum permissible concentration for unrestricted release. The

licensee and Region III are continuing to investigate this matter.

Final resolution will be tracked as an Open' Item (254/85017-02(DRP)

and 265/85019-01(DRP)).

No violations or deviations were identified.

d. Maintenance

The following activities were observed / reviewed:

(1) Observed repair work and installation of IB Turbine oil cooler.

(2) Observed mechanical repair work on 2A Recircult:fon Motor

Generator.

(3) Observed mechanical repair work on 1A Diesel fire pump.

(4) Observed electrical repair work on IB Service Water motor.

(5) . Reviewed replacement of IB Residual Heat Removal Pump.

(6) Reviewed repairs to Unit 2 Scram Discharge Volume

Instrumentation.

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On July 29, 1985, Unit 2A Fuel Pool monitor tripped spuriously

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causing an automatic initiation of Standby Gas Treatment. All

systems responded as required. This is not a significant safety

issue. However, a large number of spurious trips have occurred in

the recent past as documented in LER 85005, 85012, and 85014 for

Unit 1, and this has resulted in excessive challenges to plant

safety systems. Also normal corrective maintenance does not appear

effective in preventing these spurious actuations. This is an item

of concern and will be tracked as an Unresolved Item (254/85017-03

(DRP) and 265/85019-02(DRP)).

The licensee has been requested to respond in writing identifying

what actions are intended to eliminate any further spurious

actuations and the schedule for completion of these actions.

i No violations or deviations were identified.

e. Surveillance

The following activities were observed / reviewed:

, (1) Observed High Pressure Coolant Injection overspeed test for

Unit 2.

(2) Observed hot scram timing for Unit 2.

(3) Observed Unit 1 Power Operation Fcnctional Test (QIS - 60).

(4) Observed Unit 2 Reactor High Pressure Automatic Blowdown

l Calibration.

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(5) Observed Unit 2 Main Steam line Radiation Scram and Isolation

testing (QIS - 31).

(6) Observed magnetic particle testing of lift piers for turbine

strongback.

(7) Observed Unit 2 Vessel level instrument calibration checks.

(8) Observed Unit 1 Local Power Range Monitor calibration and

associated Transverse Incore Probe operations.

(9) Reviewed Operability testing of Unit 2 Reactor Core Isolation

Cooling system.

No violations or deviations were identified.

f. Procedures Reviewed

The following procedures were reviewed:

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QIS 34-1 Rev. 7 Reactor Building Ventilation Monitoring

Calibration

QIS 34-2 Rev. 6 Reactor Building Ventilation Monitoring

Functional Test

QOA 4100-2 Rev. 2 Fire Protection System Failure

90A 1700-5 Rev. 3 Main Steam Line High Radiation

Q0A 5450-6 Rev. 6 Off-Gas Recombination at a Location Other Than

the Recombiner

QOP 020-1 Rev. 3 (1 9ning a Penetration in Secondary Containment

QMP 100-12 Rev. 5 Electrical Maintenance of Safety-Related and

Non-Safety-Related Motor Operated Valves

QMP 100-2 Rev. 4 Control and Handling of Welding Electrodes and

Bare Wire

QMP 300-5 Rev. 6 Steam Separator Removal

QRP 1210-2 Rev. 2 Film /TLD Badge Issuance and Completion of

Occupational External Radiation Exposure

History Form (NRC)

QIS 27-1 Rev. 6 HPCI Turbine Area High Temperature Isolation

Calibration

QIS 45-1 Rev. 2 Primary Containment CAM Radiation Monitor

Source Calibration Check

QMS 200-S3 Rev. 5 Diesel Inspection - Monthly

QMS 7500-1 Rev. 4 Standby Gas Treatment Automatic Start

QOS 005-2 Rev. 8 Normal Control Room Inspection and Shift

Turnover Panel Check

QOS 500-1 Rev. 6 Mode Switch in Shutdown; Scram Instrumentation

Functional Test

QRP 1170-1 Rev. 1 Administrative Controls for Health Physics

Instrumentation

QRP 1610-S4 Rev. 5 Access Control Point Checklist

QOP 1900-19 Rev. 1 Discharging Fuel Pool Cooling into the RHR

Injection Loop

QOP 201-4 Rev. 1 Draining Reactor Cavity to the Suppression

Chamber

QTP 500-6 Rev. 3 Guidelines for Development of Tests for

Modifications

QTP 500-11 Rev. 23 Safety-Related, Code-Related, and Engineering

Assisted Modifications

QTP 500-12 Rev. 19 Non Safety-Related, Non Code-Related Non

Engineering Assisted Modifications

QDM-11 Rev. 12 Drawing and VETI Control for Work Requests,

Procedures, and Plant Modifications

QDM-11-T1 Rev. 3 Central File Document Update Notice

QDM-14 Rev. 1 Processing of Controlled Vendor Equipment

Technical Information (VETI) Document

QOP 6900-1 Rev. 5 250 VDC Electrical System

QOP 6900-2 Rev. 5 125 VDC Electrical

QOP 6900-3 Rev. 6 48/24 VDC Electrical System

QOS 6900-1 Rev. 10 Station Battery Weekly Surveillance

QOS 6900-2 Rev. 8 Station Battery Quarterly Surveillance

QOS 6900-4 Rev. 2 Station Battery Monthly Surveillance

QOS 6900-S1 Rev. 11 Station Batteries (Weekly)

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QOS 6900-S2 Rev. 10 250 VDC Station and Computer UPS Batteries

(Quarterly)

QOS 6900-S3 Rev. 8 125 VDC Station Batteries (Quarterly)

QOS 6900-S4 Rev. 9 24/84 VEC Station Batteries (Quarterly)

QOS 6900-S6 Rev. 3 Station Batteries (Monthly)

g. Review of Routine and Special Reports

(1) The inspectors reviewed the monthly performance report for

Units 1 and 2 for the months of May and June, 1985.

(2) The inspectors reviewed a special report detailing the actions

connected with finding that the recombiner for Unit I was not

put on the line prior to reactor. pressure reaching 900 psig as

required by the Technical Specifications.

On May 17, 1985, Unit I was in the STARTUP mode at less than 1 percent

thermal power. Control rods were being pulled and Reactor pressure

was increasing. During this time, difficulty was experienced with

condenser vacuum. This difficulty led to the belief that a possible

vacuum leak had developed, and therefore, efforts were concentrated

on locating the leak. Because of this preoccupancy with the potential

vacuum leak, a Recombiner was not put on-line when Reactor pressure

reached 700 psig as required by the Normal Startup Procedure. A

Recombiner is required to be in ope. ration whenever Reactor pressure is

above 900 psig in accordance with Technical Specification 3.8.A.5.a.

Hofever, Technical Specification 3.8.A.S.b allows the Recombiner to

be made inoperable for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />. In this case, Reactor pressure

reached 900 psig at approximately 3 a.m. on May 17, but the 1A

Recombiner was not put on-line until approximately 8 a.m. on May 17

when Unit I was operating at 458 MWt. No equipment failures were

involved, therefore, no action was required to prevent a recurrence

of equipment failures, and the 1A Recombiner was put on-line using

normal procedure.

The immediate corrective action upon discovery was to put the 1A

Recombiner on-line. Because the Shift Engineer has the ultimate

responsibility of seeing that plant operation is in compliance with

the plant's operating license and operating procedures, a discussion

with all Shift Engineers regarding this deviation was conducted by

Station management. This was the first time that Recombiner

operation was inadvertently overlooked since the new Technical

Specification requirement to have a Recombiner in operation when

Reactor pressure exceeds 900 psig took effect in December 1984.

Also, the Deviation Report was included in the Required Reading book

for all NS0's and SCRE's.

Because this error was identified by the licensee and prompt,

effective corrective actions were taken and because of the relative

safety significance of this event, no violation was issued.

No violations or deviations were identified.

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-h. LER Review

(1) (Closed) LER 85002, Revision 0: Unit 1 #4 Tip Ball Valve

On May 9,1985, while performing TIP system power operated

Valve Stroke Testing, #3 TIP Ball Valve failed to close

following testing. The unit was shut down and did not require

Secondary Containment at the time. The cause of the stuck ball

valve was a loss of lubrication. The valve was cleaned and

lubricated and returned to service on May 11, 1985. No further

actions are required.

(2) (Closed) LER 85003, Revision 0: Unit 1 Group II Isolation and

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'A' Standby Gas Treatment Failure To Start On May 17, 1985,

while Unit 1 was in the RUN mode and Unit 2 was in COLD SHUTDOWN,

Unit 2 received an unexpected Group II isolation signal. This

signal occurred when the test for a modification tripped Group

II Channel B. Group II Channel A was previously tripped due to

the removal of the 2A Drywell radiation monitor for maintenance.

Upon receipt of the Group II isolation signal, the 'B' Standby

Gas Treatment System (SBGTS) (BH) auto-started. The 'A' SBGTS,

which was selected as primary, failed to start. When the 'B'

SBGTS started it was immediately noticed that the heater did

not energize. An Operator was sent to investigate and he

discovered that the breaker for the heater was tripped.

The breaker was reset and the normal differential temperature

across the heater was established. Repeated attempts were

performed to duplicate the 'A' SBGTS failure to start, but in

every case the 'A' SBGTS properly served its function. After

further investigation, it was postulated that the cause of the

'A' SBGTS failure to start was a degradation of the auto-start

relay 595-133. The similar relay on 'B' SBGTS caused an

identical failure of 'B' to start on June 5,1985. The relay

failure was intermittent in nature, causing a failure to start

in 1 out of 3 cases.

The breaker trip appears to have been caused by a faulty breaker

which was replaced after it totally failed on June 12,.1985.

.The personnel error and communication problem involved in testing

Channel B while a Trip signal was present on Channel A was

discussed with the licensee (See Report 254/85012 and 265/85013)

and adequate corrective actions were taken. As such, no further

actions are required.

(3) (Closed) LER 85004, Revision 0: Unit 1 Loss of Essential

Service System Bus.

On May 23, 1985, the Essential Service System (ESS) Uninter-

ruptible Power Supply (UPS) failed causing a half scram and an

auto-start of the 'B' Standby Gas Treatment System. The ESS

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Bus transferred to its AC backup. This event occurred again at

10:08 a.m. on June 12, 1985, when the UPS was repaired and the

feed was transferred from its reserve feed to the normal feed.

The UPS failed due to the failure of two transistors in the

Inverter Logic Power Supply. All circuitry was repaired and

the UPS was successfully returned to service at 10:08 a.m. on

June 12, 1985. No further actions are required.

(4) (Closed) LER 85005, Revision 0 and Revision 1: Unit 1A Fuel

Pool Monitor - Various Trips.

As noted in Section d. of this report, concerns related to this

LER and others have been addressed as an Unresolved Item and

the Licensee has been requested to respond in writing.

Therefore, tracking of this issue will be handled in that

manner.

(5) (Closed) LER 85006, Revision 0: Unit 1 Reactor Scram From

Group I Isolation.

On May 30, 1985, while valving in Pressure Transmitter PT

1-5641-2, Instrument Rack 2251-1 began to vibrate. This rack

contains pressure switches which actuate a Group I isolation en

Main Steam Line low pressure. The vibration on Instrument Rack

2251-1 caused these pressure switches to trip initiating a

Group I isolation. The reactor then scrammed from Main Steam

Isolation Valve (MSIV) closure. The MSIVs were reopened and

the Bypass Valves opened to lower Reactor pressure. Reactor

water level decreased rapidly. A Reactor feed pump was started

to replace the lost inventory. A second Reactor scram occurred

at 6:07 p.m. due to low Reactor water level. A minute later,

Reactor water level was restored to normal.

The licensee is investigating possible engineering solutions

to reduce the potential for this event. Also, in the future,

when valving in on this rack, Instrument Maintenance will

pre pressurize the sensing line to prevent vibration. No

further actions are required.

(6) (Closed) LER 85007, Revision 0: Unit 1A Fuel Pool Monitor Trip.

See Item 4.

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(7) (Closed) LER 85008, Revision Oi 1/2 Diesel Generator Cooling

Water Pump and 1B Residual Heat Removal Service Water Pump Out

of Service.

On June 17, 1985, a high level alarm was received from the

IB/1C Residual Heat Removal Service Water (RHR) vault sump.

The IC RHR Service Water Pump was immediately tripped and an

Equipment Attendant was dispatched to investigate. It was

discovered that a broken vent line on the 1C RHR Service Water

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Pump existed and that the vault was partially filled with

water. As a precautionary measure, the 1B RHR Service Water

Pump and the 1/2 Diesel Generator Cooling Water Pump were

declared inoperable because they are locted in the same room.

This action rendered the 1/2 Emergency Diesel Generator

inoperable. Electrical integrity tests were performed on all

the motors and showed all parameters to be normal. The'1C RHR

Service Water Pump was repaired on June 18, 1985. The 1/2

Diesel Generator Cooling Water Pump and the IB RHR Service

Water Pump were also returned to service on June 18, 1985. No

further actions are required.

(8) (Open) LER 85011, Revision 0: Unit 1 Scram and Loss of Unit 2

Auxiliary Power.

On May 7,.1985, Unit l'was in the RUN mode and Unit 2 was in

COLD SHUTDOWN. Contractor personnel working on roof repairs

were attempting to connect a power cord for a drill to an AC

outlet located near the ground below. While lowering the cord

from the roof, a sudden 'A' phase to ground fault occurred.

This fault opened oil circuit breakers, which caused a loss of

normal auxiliary power to Unit 2. Diesel Generator 1/2 auto-

started and closed-in to Bus 23-1 on a Bus 23-1 undervoltage

signal. Unit 2 remained stable.

The electrical transient in the 345 KV switchyard caused a

transient on the Unit l' electrical system. The transient

caused a loss of 'A' Reactor Protection System Bus and a

lock-up of a Feedwater Regulating Valve. The locked-up

Feedwater Regulating Valve resulted in a high Reactor water

level condition which resulted in a Turbine trip, and Reactor

scram. Subsequently, a normal scram recovery was performed and

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all_ electrical systems were returned to normal. All systems

and equipment functioned-as designed.

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The auxiliary transformer was examined and damaged insulators

were found on the 'A' phase lines feeding the transformer. The

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i insulators were replaced and the transformer was returned to

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service on May 8, 1985. All systems and equipment functioned

L as designed and no changes were necessary. However, the

Station is considering a modification which may prevent losing

the feed to the RPS MG Set drive motor for similar faults on

the 345 KV system. The' modification involves a time delay

relay which allows the flywheel to.be more effective in

performing its intended function.

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This LER will remain open pending resolution of this modification.

(9)- '(Closed) LER 85014, Revision 0 and Revision 1: Unit 1A Fuel

Monitor Trip.

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(10) (Closed) LER 85006, Revision 0 and Revision 1: Unit 2 Main

Steam Isolation Valves Failed Local Leak Rate Testing.

The licensee has submitted a supplemental report detailing the

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amount of leakage and the repairs performed to correct the

sealing surface wear. No further actions are required.

(11) (Closed) LER 85007, Revision 0 and Revision 1: Unit 2 Local

i Leak Rate Tests Exceeded Limits.

The licensee has submitted a supplemental report detailing the

amount of leakage and the repairs performed to correct problems

found. No further actions are required.

(12) (Closed) LER 85008, Revision 0 and Revision 1: Unit 2

Recirculation Pipe Riser Crack.

The licensee has submitted a supplemental report delineating

crack indications found and corrective actions taken. No

further actions are required.

(13) (Closed) LER 85012, Revision 0: Unit 2 Group II Isolation.

On May 20, 1985, the main feed breaker to Bus 24-1 tripped

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during testing by the Operational Analysis Department (OAD).

The Unit 2 Diesel Generator was already running for testing and

it was feeding Bus 24-1. Because the Diesel Generator was then

carrying the full load of Bus 24-1, Diesel Generator load went

y from 700 KW to 2500 KW. Since the unit operator was not aware

3' of the cause of the breaker trip, the Diesel Generator was

tripped. This caused a one/ half Group II isolation. The other

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half of the Group II isolation logic was already satisfied

because the 2A High Drywell Radiation Monitor was removed for

maintenance. This started the Standby Gas Treatment System

(SBGTS).

After it was determined that OAD personnel had tripped the main

feed breaker to Bus 24-1, normal power was restored to the Bus.

The Group II isolation was reset and the SBGTS was secured.

Station Management immediately stopped all OAD work. The

following day it was emphasized to 0AD that all work performed

at the Station must be done under the control of a Work Request.

The Work Request that controlled the wiring verification did

not allow the movement of any relays. The personnel involved

with this incident were cautioned to not operate outside of a

Work Request. This prompt action by Station Management should

prevent future recurrence. Because of this prompt corrective

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action and the relative safety significance of the event, no

violation will be issued.

(14) (Closed) LER 85013, Revision 0: Unit 2 loss of Emergency

Diesel Generators.

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On May 22, 1985, Unit 2 was in the REFUEL mode. The 1/2 Diesel

Generator was out of service while the Electrical Maintenance

Department was performing QMS 700-5, " Core Spray Logic Functional

Test". In accordance with the test,.the Unit 2 Diesel Generator

started. The Diesel Generator only ran 30 seconds when it

tripped out mechanically on overspeed. A Generating Station

Emergency Plan (GSEP) Unusual Event was declared since Unit 2

had no operable Diesel Generator. The 1/2 Diesel Generator was

immediately returned to service. The Unit 2 Diesel Generator

trip was caused by the governor compensating mechanism being

out of adjustment. It was readjusted and the Diesel Generator

was returned to service on May 24, 1985.

No further actions are required. ,

(15) (Closed) LER 85014, Revision 0: Unit 2 Scram From Surveillance

Procedure.

On May 31, 1985, the surveillance Q0S 1600-11, " Primary

Containment Isolation (PCI) Simulated Automatic Close

Initiation Test" was performed. In the course of adhering to

the procedure, a full scram was initiated. The cause of the

scram was an inadequacy of the procedure. The procedure called

for resetting the alarms, but did not require the resetting of

a 1/2 scram signal initiated on a previous step. A full scram

was, therefore, initiated. The procedure was modified to

require resetting of the 1/2 scram signal before tripping the

other channel.

No further actions are required.

No violations or deviations were identified.

i. TMI Action Items

(1) (Closed) Item II.B.3 Post-Accident Sampling

NRR has issued a Safety Evaluation Report (SER) dated

July 23, 1985 accepting the licensee's Post-Accident sampling

system. The resident inspectors have verified that the

licensee's program does correspond to their submittal.

No further actions are required.

(2) (0 pen) Item II.F.2 Inadequate Core Cooling Instrumentation.

NRR has issued a SER dated June 5, 1985 accepting the licensee's

submittal to comply with this requirement. Actions associated

with replacement of mechanical level indication equipment has

been accomplished and reviewed by the resident inspectors.

Actions to address reference leg overheating are scheduled to

be completed sometime in 1988 and will be reviewed at that time.

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j. Receipt, Storage and Handling of Equipment Program

The inspectors reviewed the licensee's program for receipt, storage

and handling of equipment in accordance with Inspection Procedure

38702 and found it to be acceptable. However, during a tour of the

station warehouse two safety related check valves were found to be

without protective covers as required by QAP 300-13 (1976): Levels

of Storage and Inspection Criteria and ANSI N45.2.13(1976) Quality

Assurance Requirements for Control of Procurement of Items and

Services for Nuclear Power Plants which refers to ANSI 45.2.2 (1972)

Packaging, Shipping, Receiving, Storage and Handling of Items for

Nuclear Power Plants for additional requirements. This is a

violation (254/85017-04(DRP) and 265/85019-03(DRP)).

When notified, the licensee placed protective covers on the valves.

No other violations or deviations were identified.

k. Design Changes and Modifications (40% complete)

The following modifications were reviewed and found to be in

conformance with the requirements of Technical Specifications and

10 CFR 50.59:

M-4-2-84-20 Indicating-lights for Control Valve Test Switches

M-4-2-84-30 Outer Bellows on Core Spray Penetration X-16B

M-4-2-85-20 Feedwater check valve pivot pin modification

M-4-1-85-1 SBLC swing pump - (This modification is still in

progress)

M-4-2-85-23 Fabricate sleeve for 2ARHR Pump Motor

M-4-2-85-13 Limitorgue Motor Operator - EQ Modifications

No violations or deviations were identified.

4. Regulatory Improvement Program Meeting

On July 16, 1985, a meeting was conducted between Ceco and Region III

management. The purpose of the meeting was to discuss additional aspects

of the licensee's Regulatory Improvement Program (RIP) which were

identified during the June 24, 1985 RIP meeting. This meeting was part

of the continuing series of management meetings aimed at improving

licensee regulatory performance and enhancing communications between the

NRC and Ceco.

5. Open-Items l

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

will be reviewed further by the inspectors, and which involve some action

on the part of the NRC or licensee or both. The open item disclosed

during the inspection is discussed in Paragraph 2c.

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6. Unresolved Items

Unresolved items are matters about which more information is required in

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order to ascertain whether they are acceptable items, items of

j noncompliance, or deviations. The unresolved item disclosed during the

! inspection is discussed in Paragraph 2d.

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1 7. Exit Interview

4

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

- throughout the month and at -the conclusion of the inspection on

July 31, 1985, and summarized the scope and findings of the inspection

activities.

4

The inspectors also discussed the likely informational content of the

inspection report with regard to documents or processes reviewed by the

i inspectors during the inspection. The licensee did not identify any such

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documents / processes as proprietary.

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