ML16342D162

Insp Repts 50-275/95-17 & 50-323/95-17 on 951021-1208.No Violations Noted.Major Areas Inspected:Causes,Immediate Response & Corrective Actions for Failure of Unit Auxiliary Transformer 1-1 on 951021

ML16342D162
Person / Time
Site:	Diablo Canyon
Issue date:	12/29/1995
From:	Wong H NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML16342D161	List: ML16342D160 ML16342D162
References
50-275-95-17, 50-323-95-17, NUDOCS 9601040219
Download: ML16342D162 (54)

See also: IR 05000275/1995017

Text

ENCLOSURE

U.S.

NUCLEAR REGULATORY COMMISSION

REGION I V

Inspection

Report:

50-275/95-17

50-323/95-17

Licenses:

DPR-80

DPR-82

Licensee:

Pacific

Gas

and Electric Company

77 Beale Street,

Room

1451

P.O.

Box 770000

San Francisco,

California

Facility Name:

Diablo Canyon Nuclear

Power Plant,

Units I and

2

Inspection At:

Diablo Canyon Site,

San Luis Obispo County, California

Inspection

Conducted:

October

21 through

December

8,

1995

Inspectors:

D. Acker, Project Inspector

J. Russell,

Acting Senior Resident

Inspector

L. Smith,

Reactor

Inspector

A. Singh, Fire Protection Specialist,

NRR

Approved:

ong,

C ie

,

eactor

Prospects

rane

IZZe fh

a e

Ins ection

Summar

Areas

Ins ected

Units

1

and

2

Special,

announced

inspection of the causes,

immediate respc"se,

and corrective actions for the failure of Unit Auxiliary

Transformer

1-1

on October 21,

1995.

Operators

attempted

to energize

a

12 kilovolt (kV) bus with a ground

buggy installed, resulting in

a transformer

failure, loss of offsite power,

momentary loss of shutdown cooling, loss of

spent fuel pool cooling,

and

damage

to offsite power supply components.

Results

Units

1

and

2

0 erations

and Maintenance

Event

Operator

and site

management

response

to the loss of offsite power and

transformer failure was generally

good (Section 3.1).

Operations

and maintenance

personnel

failed to properly plan

and

implement procedures

for the installation

and removal of a ground

buggy

9bOi0402iq 95i22'P

PDR

ADOCK 05000275

8

PDR

in the

12

kV cubicle location of Circuit Breaker 52-V"-4.

This was

an

apparent violation of Technical Specification 6.8.1

ainu applicable site

procedures

(Section 6.2).

~

Licensee

management

had not been enforcing compliance with established

procedures

for ground

buggy installation.

The licensee

had established

several

procedures

and mechanisms

in an attempt to control the

installation

and removal of ground buggies,

but the controls were not

being followed (Section 6.3).

The licensee

determined that neither the operations

nor maintenance

departments felt responsible

for ground

buggy control.

The licensee

considered

that this lack of ownership

was the major cause of the event

(Section 6.3).

~

Licensee

management

had

an opportunity to correct grounding device

control

problems after

an occurrence

in October

1994,

but interface

problems

between

the operations

and maintenance

departments

prevented

either from effectively resolving the matter.

Instead,

the licensee

added

another

procedure

requirement

onto those already

in existence

that

did not address

the root cause of the problem (Section 6.4).

~

Licensee

personnel

determined that fatigue contributed to the

maintenance

foreman's error.

He performed

a walkdown of the

12

kV

switchgear prior to reporting off the clearance

and did not identify

that the ground

buggy was still installed

(Section 6.6).

~

After offsite power was lost, operations

personnel

did not restart

spent

fuel pool cooling for 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />, resulting in

a 20'F rise in pool

temperature.

Cooling was restarted

during operator

rounds well before

any temperature limits were approached

(Section 3.3).

~

Licensee

management

routinely authorized

Technical

Maintenance

Section

personnel

to work more than

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in

a 7-day period.

In many cases,

full crews repeatedly

received

approval

to exceed

the guidelines.

This

is

an apparent violation of Technical Specification 6.2.2.f

(Section 6.6).

~

A licensee

procedure

designated

numerous

managers

to sign plant manager

approval of overtime extensions,

which may have contributed to routine

use of extended

overtime (Section 6.6).

0 erations

and Maintenance

Corrective Actions

~

The licensee's

root cause

evaluation

was generally thorough

and complete

(Section 6.1).

",". an interim basi ., licensee

personnel

revised t"e administrative

cvlllrols for the installation

and removal o;

g ound buggies

(Section 6.2.8).

Licensee

personnel

planned

to improve the tags,

labels,

and terminology

used for the control of ground buggies

(Section 6.5).

En ineerin

Corrective actions,

analyses,

and tests

to verify equipment operability

after the event were comprehensive

and conservative

(Section 4.1).

~

The transformer yard arrangement

and the fire protection features for

the transformers,

yard area,

and turbine building walls were in

accordance

with the Updated

Final Safety Analysis Report.

~

Fire brigade training, procedures,

and response

to the fire were

good

(Section 5.4).

~

While the fire was still burning in Unit Auxiliary Transformer

1-1, site

personnel

improperly blocked

a drain resulting in an oil/water pool in

part of the transformer

area

which included stored

compressed

oxygen

bottles

(Section 5.3).

~

Transformer fire protection

equipment

was installed in accordance

with

design

requirements

(Section 5.2).

Summar

of Ins ection Findin s:

~

An apparent violation of Technical Specification 6.8.

1 (six examples),

related to failures to follow procedures,

is identified in

Sections

6.2.

~

An apparent violation of Technical Specification 6.2.2.f, related to

overtime requirements,

is identified in Section 6.6.

~

An Inspector

Followup Item, related

to further evaluation of transformer

capability to withstand electrical faults, is identified in Section 4.3.

Attachments:

~

Attachment

~

Attachment

~

Attachment

~

Attachment

1

Persons

Contacted

and Exit Meeting

2 - Acronyms

3 - Diablo Electrical Distribution Block Diagram

4 - Diablo Unit

1 Transformer

Area Arrangement

Diagram

DETAILS

1

BACKGROUND

1. 1

Overview of Failure of Unit Auxiliar

Transformer

1-1

On Saturday

October

21,

1995, at 9:38 a.m.

(PDT) Unit Auxiliary (UA)

Transformer

1-1 exploded

and caught

on fire, causing

the subsequent

loss of

all offsite power to Unit 1, which was

shutdown in Mode

6 for a refueling

outage.

At the time,

power was being provided via backfeed

through the main

transformers

and

UA transformers,

while maintenance

was being performed

on

standby startup

(SU) transformers.

Fuel

assemblies

had

been reinstalled

into

the reactor vessel

and the reactor vessel

head

was ins'tailed,

but not

tightened.

Nozzle

dams

were installed

and

steam generator

eddy current

inspections

were in progress.

Shutdown cooling was operating.

When offsite

power was lost, all three

emergency diesel

generators

(EDGs) started

and

loaded to their respective

busses.

Operators

reestablished

shutdown cooling

within 2 minutes of losing offsite power.

Spent fuel pool cooling was

restored

approximately

8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the event,

but before

any temperature

alarms

were reached.

The licensee

declared

an Unusual

Event at 9:51

a.m.

(PDT) due to loss of offsite power

and the fire, for which they requested

offsite fire fighting support.

The fire was extinguished

by 10: 10 a.m.

(PDT)

Offsite power was restored

approximately

16 hours1.851852e-4 days <br />0.00444 hours <br />2.645503e-5 weeks <br />6.088e-6 months <br /> later through the

SU

transformers.

Unit

2 continued to operate

at

100 percent

power

and plant

operation

was not affected

by the event.

1.2

Electrical

Desi

n

Diablo Canyon

has

two sources

of offsite electrical

power,

a 230

kV system

and

a 525

kV system,.

as

shown in Attachment 3.

The 230

kV system supplies Unit

1

230/12

kV SU Transfor'mer

1-1

and Unit 2 230/12

kV SU Transformer 2-1.

SU

Transformer

1-1 supplies Unit

1 startup

and emergency

power to nonsafety-

related

loads

such

as the reactor coolant

pumps

and circulating water

pumps

and to safety-related

loads via 12/4

kV SU Transformer

1-2.

SU

Transformers

2-1

and 2-2 supply similar loads in Unit 2.

The output of SU

Transformers

1-1

and 2-1 can

be provided to the opposite unit during

an

emergency situation via

a cross-tie circuit breaker.

During power operation

the

230

kV system is normally unloaded.

The second

source of emergency

power,

the

525

kV system,

is backfed

from the

525/25

kV main transformers after the main generator

is separated

from the

system.

The

525

kV supply is

a delayed

source,

since operator action is

required to restore this power following loss of the main generator.

All

Unit

1 loads

are normally supplied

by the main generator

during power

operations

through

25/12

kV UA Transformer

1-1, which supplies

nonsafety-

related

loads,

and 25/4

kV UA Transformer

1-2, which supplies safety-related

loads.

Unit

2 operation is the

same

through

UA Transformers

2-1

and 2-2.

After a reactor trip, power is automatically fast transferred

to the

230

kV SU

system.

0

. 11 the Unit

1 transfo> vers, Unit 2

SU Transformer

.". 1,

and

two spare

transformers

are located north

and northeast

of the turbine building,

as

shown

in Attachment

4.

The transformer

area,

or yard, contained

no missile shields,

and

no individual oil pits.

The yard design for a'oss

of transformer oil

event

was for the oil to flow away from the transformers

by gravity

approximately

100 feet north where it would drain to

an underground

separator,

designed

to retain the oil from an oil/water mixture.

2

SEQUENCE

OF

EVENTS

The 525

kV system

was supplying power to Unit

1 loads, while the

SU system

was

deenergized

for maintenance.

Operations

personnel

were preparing for filling

the reactor coolant

system

in anticipation of completion of steam generator

eddy ce rent inspections.

One of the next steps

was to restore

power to the

12

kV Susses

so that uncoupled reactor coolant

pump motor runs could

be

completed.

After completing the

12

kV bus work, maintenance

personnel

turned

the busses

over to operations;

however,

due to

a number of errors discussed

in

detail

in Section

6 of this report,

licensee

personnel left a grounding device

installed

on

12

kV Bus

D.

The grounding device

was

a "ground buggy," which

consisted of an empty breaker

frame with stabs

connected

to the ground

by 4/0

size cables.

The licensee

installed ground buggies

in the cubicle locations

of removed circuit breakers

to facilitate maintenance,

testing,

and personnel

safety during electrical

system

outage periods.

At 9:38 a.m.

(PDT), operators

attempted

to energize

12

kV Bus

D from UA

Transformer

1-1 by closing the input Circuit Breaker

52-VD-8 with the ground

buggy still installed

on

Bus

D.

Circuit Breaker

52-VD-8 closed

and tripped,

UA Transformer

1-1 exploded

and caught fire, and the Unit

1 525

kV supply

breakers

in the switchyard tripped,

causing

loss of all offsite power to

Unit 1.

All three

EDGs started

and loaded.

Operators

restored

shutdown

cooling within 2 minutes.

Fire alarms indicated

a fire in the Unit

1

switchyard.

At approximately 9:51

a.m.

(PDT), the licensee

declared

an

Unusual

Event due to loss of offsite power

and the transformer fire.

The fire

brigade

responded

to the fire and offsite fire fighting support

was requested.

The

UA Transformer

1-1 explosion released

approximately

3400 gallons of oil on

to the ground

and

on adjacent

transformers.

The transformer yard water deluge

system

remained sufficiently intact to extinguish the fire external

to

UA

Transformer

1-1; however,

the oil and combustible material within the

transformer

continued to burn.

The oil/water mixture flowed north to the

drain;

however,

licensee

personnel

not familiar with the drain design,

thought

the oil was flowing directly into

a creek.

These

personnel

blocked the drain,

and the oil/water mixture backed

up in the transformer yard.

The mixture did

not reach

the

SU transformers

which were

on slightly higher ground.

The fire

continued to burn within UA Transformer

1-1 until approximately

10: 10 a.m.

(PDT), when the fire brigade completely extinguished

the fire using

foam.

The licensee

discontinued

work on the Unit

1

SU system

and

began restoration

of this source of offsite power.

Offsite power began to be restored

to Unit

1

via the

SU system

on October

22,

1995, at approximately

12:22 a.m.

(PDT).

The

EDGs were secured

and the Notice of Unusual

Event

was terminated

at

approximately

1:29 a.m.

3

OPERATIONS

RESPONSE

3. 1

Overview

Based

on observations

in the control

room and other plant locations

immediately after the event,

the inspectors

concluded that overall licensee

response

to the event,

both by operators

and support organizations,

was

appropriate.

Licensee

management,

including the Operations

Manager

and Plant

Manager,

responded

to the site

and actively participated

in assessing

and

planning plant recovery activities.

However,

the inspectors

identified

several

associated

weaknesses

which are discussed

in the following

sections'.2

Initial Res

onse

The Resident

Inspectors

were notified of the declaration of an Unusual

Event

and the transformer fire, by the Shift Superintendent,

and arrived at the site

at approximately

10:30 a.m.

(PDT), October 21,

1995.

The inspectors

observed

licensee

actions

in the control

room, walked

down the transformer

area shortly

after the fire had

been extinguished,

attended

licensee

engineering

assessment

team meetings

as the licensee

developed

plans for plant recovery,

and

periodically walked

down the operating

EDGs.

The Acting Senior Resident

Inspector

remained

on s-.

until the Shift Supervisor terminated

the Notice of

Unusual

Event at 1:29 a.m.

(PDT), October

22,

1995,

when offsite power was

restored

and the

EDGs were placed

in standby.

3.3

0 erator Actions

Overall, the inspectors

'concluded that operators

properly responded

to the

event with restoration of shutdown cooling performed promptly and

a deliberate

approach

taken for restoration of offsite power.

The inspectors

noted that the operating residual

heat

removal

pump

and the

operating

spent fuel pool

(SFP) cooling

pump both stopped

when offsite power

to the 4160

V Class

1E buses

was lost.

These

pumps

are not automatically

powered

from the

EDG buses

since there

was

no engineered

safety feature

signal

present.

The status of the resident

heat

removal

pump was indicated in the

control

room; however,

there

was

no indication for the

SFP cooling pump.

When

power was restored

via the

EDGs, the operators

restarted

the residual

heat

removal

pump within 2 minutes to reestablish

shutdown cooling.

However,

the

operators

did not restart

the

SFP cooling

pump until 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> after the initial

loss of power during operator

rounds.

The inspectors

noted that the only

indication of SFP cooling in the main control

room was

one annunciator,

which

alarms

on high

SFP temperature

or low level.

These conditions were not

reached

during this event.

-7-

Th

licensee's

review of the event noted the failure tv promptly restart

the

SFP cooling

pump

and the licensee initiated action to train personnel

on the

need to restart this

pump when

power

was lost.

The inspectors

reviewed the

associated

procedures

and noted that the procedure initially entered

by the

operators

for a loss of shutdown coo1ing,

Procedure

OP-SD-O,

"Loss of, or

Inadequate

Decay Heat Removal," Revision

5, did contain procedural

guidance to

restart

SFP cooling.

In fact, the operators

had followed the procedure,

but

exited the procedure prior to encountering

the step

(Step 6) that would have

directed

them to restart

the

SFP cooling pump.

This was

because

Step

5

directed

the operators

to transition to

a loss of .residual

heat

removal

recovery procedure

and,

once residual

heat

removal

was restored,

to exit the

shutdown

emergency

operating

procedures,

of which Procedure

OP-SD-0

was

a

part.

Licensee

personnel

indicated that operators

had

remembered

to restart

the

SFP cooling pump,

but personnel

were responding

to the transformer fire

and could not respond

to restart

the

pump.

During operator

rounds later in

the event,

an operator restarted

the

SFP cooling pump.

The inspectors

discussed

the issue with the licensee

and noted that the

licensee

had not determined that

a procedural

flow problem had caused

operators

not to start the

SFP cooling

pump in

a timely manner,

The licensee

indicated that they would revise

Procedure

OP-SD-0 to incorporate

the

SFP

cooling restart prior to the transition out of Procedure

OP-SD-0.

The

inspectors

considered

that the licensee's

review of the failure to immediately

restart

SFP cooling was incomplete,

in that it did not identify the procedure

problem noted

by the inspectors.

The inspectors

concluded,

based

on interviews

and procedural

review, that the

operators

did not restart

the

SFP cooling

pump for an extended

period due to

the procedural

flow problem discussed

above,

lack of specific control

room

indication,

and failure of personnel

to remain cognizant of the need to

restart

the

pump.

The inspectors

noted that the

SFP temperature

increased

from 92

F to

112

F, with the annunciator setpoint at 130'F.

Based

on these

temperatures

and annunciator availability, the inspectors

concluded there

was

not impact

on plant safety.

The licensee

was also'va'luating

adding

annunciation of low SFP cooling

pump discharge

pressure

to the main control

boards.

The inspectors

concluded that the licensee's

response

was adequate.

3.4

Emer enc

0 eratin

Procedures

The inspectors

noted that

Emergency

Operating

Procedure

ECA 0.3,

"Restore

4

kV

Buses,"

Revision 6, for restoration of offsite power while operating

on the

EDGs, stipulated starting transformer cooling prior to energizing

a

transformer.

With the nonvital

buses

deenergized,

transformer cooling was not

available until after the transformer

and appropriate

load center

were

energized.

The licensee

determined that it was acceptable

to run the

transformer for a short period without cooling until transformer cooling was

made available.

The licensee

made

approved

pen

and ink changes

to the

procedures,

which were

implemented to restore offsite power.

The licensee

is

in the process

of revising both units'mergency

operating

procedures

to

incorporate

a

new abnormal

procedure,

developed

as

a result of the event, that

would provide specific guidance.

The inspectors

concluded that the licensee's

independent

assessment

and corrective actions to restore offsite power

were

excellent.

The inspectors

also noted that Procedure

OP

AP SD-1,

"Loss of AC Power,"

Revision

6A,

(one of the shutdown

emergency

operating

procedures)

directed

implementation of Procedure

OP J6 A:1,

"4160 Volt System

Make Available,"

Revision 6, which would also not work as written unless

power was already

available for various loads including transformer cooling.

However,

Procedure

OP AP SD-1

was written for a station blackout in Modes

5 or 6, during which no

AC power would be available other than that provided

by the station batteries.

In response

to this concern,

the licensee

agreed

to change this procedure

to

ensure that appropriate initial conditions

were considered.

The inspectors

concluded that the licensee's

actions

were

adequate'he

inspectors

noted that the

pen

and ink changes

were minor

and the 'licensee

was acting conservatively.

Consequently,

the weaknesses

of existing

procedures

were considered

to be procedure

enhancement

issues.

3.5

Control

Board Breaker Position

The inspectors

noted that

some control

room red breaker

closed light bulbs did

not illuminate subsequent

to the event

as the operator closed

breakers

while

restoring

power to Unit 1.

Over half of the light bulbs

had burned out,

apparently during the event,

and the operator

had to replace

bulbs

as

he

restored

power.

The inspectors

considered

that inconsistent

breaker position

indication was not conducive to ensuring

proper operator actions

and correct

switch manipulation.

The number of burned out light bulbs indicated

a

potential

common

cause

problem with the indication system design

on

a loss or

restoration of power.

Based

on the inspectors'oncern,

the licensee

was

evaluating this problem at the end of the inspection period.

4

ELECTRICAL SYSTEM REVIEW AND EVALUATION

4.1

Overview

The licensee

concluded that:

(1)

UA Transformer

1-1 was not designed

to

withstand

a bolted secondary fault; (2) all damaged

equipment

was associated

with the transformer

explosion

and fire; and

(3) protective relays operated

as

designed.

The inspectors

reviewed the licensee's

evaluations

and concluded

that the licensee's

analyses

were appropriate

and technically sound.

The inspectors

independently

observed

damaged

equipment

and witnessed

licensee

repairs

and tests.

The inspectors

concluded that the licensee

had performed

8

thorough

and conservative

review of equipment potentially affected

by the

event.

4.2

Licensee

En ineerin

Anal sis

and Corrective Act'ons

The licensee

performed

a review of electrical

data

from the event.

The

initial fault was

seen

on the

525

kV system

as

a current of approximately

570

amps,

which was approximately

24,000

amps at

12 kV.

This current attained

a value of approximately

6000

amps

on the

525

kV system at approximately

1.7

cycles into the event.

Switchyard breakers

on the

525

kV side of the main

transformers

cleared

the fault in less

than five cycles.

Initial licensee

inspections of 12

kV Bus

D, ground buggy,

and associated

electrical

equipment

indicated

no damage.

The licensee

stated that the

momentary withstand current of 12

kV Bus

D was 60,000

amps.

The licensee

stated that the recordings

indicated that

UA Transformer

1-1 sustained

primary-to-ground faults at 1.7 cycles,

which essentially

interrupted

the

fault current to the

12

kV system.

The licensee

stated

that the

12

kV system

fault was within the design capability of 12

kV Bus

D.

In the transformer yard,

UA Transformer

1-1

had sustained

total casing failure

with the corner

between

the south

and east

sides

separated

by more than

6 feet.

All four sides

showed

some separation.

Large bulges

in the

approximately I/4 inch sheet

metal

casing

indicated that the welding on the

seams

had failed under

a very large pressure

surge.

The licensee

stated that

the internal

damage

from .the explosion

and fire was too extensive

to

specifically determine

where the transformer

had first failed, although coil

movement

and resultant

phase-to-ground

faulting was apparent

from burn marks

on the sides of the transformer.

There

was external fire and heat

damage

to

nearby

UA Transformer

1-2,

Main Transformers

Phases

B and

C,

and

some of the

isophase

bussing.

The licensee

took numerous

actions to determine

the extent of the damage

and

correct

any damage

found.

The licensee

found that all the

damage

was from the

explosion of UA Transformer

1-1

and resultant fire.

The licensee

did

extensive

checks

on the

12

kV busses

inside the turbine building and

associated

corr", onents

and found no damage.

The licensee

found the

12

kV

bussing

between

UA Transformer

1-1

and the turbine building was

damaged

due to

excessive

movement

caused

by the transformer failure.

The licensee

determined

that damage

to Hain Transformers

Phases

B and

C and

UA Transformer

1-2 was

limited to external

devices

damaged

by the fire.

The licensee

drained the oil

from a main transformer

and visually inspected

the internals.

No damage

was

found.

Electrical

and oil tests

on Main Transformers

Phases

8 and

C and

UA

Transformer

1-2 did not identify any damage.

The licensee

analyzed

the event

and concluded that there

was

no potential

damage to safety-related

4

kV busses

and equipment.

The licensee

conducted

two independent

evaluations of the failure of UA

Transformer

1-1.

Both of these

evaluations

concluded that the original

bracing of the transformer

was insufficient to withstand

a

100 percent bolted

secondary fault.

The evaluations

noted that transformers built in the 1960's

were not usually designed

to withstand

100 percent

bolted secondary faults.

0

-10-

The licensee

was attempting to determine

the withstand cap"vility of the other

site transformers.

The licensee

noted that the maiiufacturers for all their

transformers,

except

the

new main transformers just installed in Unit

1 this

outage,

were

no longer in business.

Preliminarily, it appears

that Unit

1

SU

Transformer

1-2 and Unit 2

UA Transformer

2-1

have designs

similar to

UA

Transformer

1-1

and would fail if subjected

to

a secondary

side bolted fault.

The remaining

UA and

SU transformers

appeared

to be adequately

braced

to

withstand

a secondary

bolted fault long enough for protective devices to clear

the fault.

In addition,

the newly installed Unit

1 main transformers

have the

capability to withstand

a fault.

The Unit 2 main transformers

were still

being reviewed during this inspection.

The licensee

stated that potential

failure of transformers

under bolted fault conditions did not affect their

operability.

However,

the licensee

had initiated

a long term review of the

need to replace

any transformers

with insufficient bracing to withstand large

secondary faults.

4.3

Ins ectors

Review of Desi

n and Evaluation of Electr'ical

E ui ment

The inspectors

reviewed the licensee's

records

and assessments

associated

with

the event

and concluded that the licensee's

evaluation that

UA Transformer

1-1

had failed prior to the capability of any circuit breaker to clear the fault

was supported

by the data

and the lack of damage

to

12

kV Bus

D.

The

inspectors

noted that 1.7 cycles

was faster than protective devices

could

clear the fault.

The inspectors

viewed the Unit

1 transformer yard,

12

kV 'Bus

D,

and reviewed

associated

licensee

inspections

and tests.

The inspectors

did not observe

any

damage

to

12

kV Bus

D or Circuit Breaker

52-VD-8.

The inspectors

noted that

the arcing contacts

of Circuit Breaker

52-VD-8 were not pitted

and that the

arc chutes did not exhibit any significant damage.

The inspectors

considered

that lack of damage

to this circuit breaker

supported

the licensee's

analysis

and data which indicated that

UA Transformer

1-1 internal faults interrupted

at least

most of the current flow to the

12

kV bus before Circuit Breaker 52-

VD-8 opened.

The inspectors

reviewed the licensee's

analysis that the

4

kV safety-related

equipment

was

undamaged

and agreed with the licensee's

conclusion.

The inspectors

reviewed

a summary of the tests

and repairs

performed

on Hain

Transformer

Phases

B and

C,

UA Transformer

1-2,

and associated

bussing.

The

inspectors

also reviewed the details of the tests

and repairs to

UA

Transformer

1-2.

Based

on these

reviews,

the inspectors

concluded that the

licensee

had

done conservative

inspections

and tests

to ensure that

any damage

to these

transformers

was identified and corrected.

In addition,

the

inspectors

reviewed the vendor

(Wagner)

manual for UA Transformer

1-1

and did

not identify any vendor

recommended

or required tests

or maintenance

that

was

not being performed

by the licensee prior to the transformer failure.

Although the inspectors

did not identify any immediate safety concerns with

the transformers

that

had limited capability to withstand faults,

the

-11-

i,."p~

~rs noted that the method

used to brace

the coi

s in these

transformers

may relax with time and cause

these

transformers

o fail at lower than

expected faults.

The inspectors

also discussed

with licensee

personnel

the

design of the

4

kV to

480.

V safety-related

transformers.

The licensee

was

considering

a review of both issues

at the

end of the inspection.

The

inspector did not identify any regulatory requirements

related to the fault

withstand capability of the transformers.

The licensee's

evaluation of site

transformers will be reviewed in

a future inspection

(Inspector

Followup Item 275/9517-01).

5

FIRE PROTECTION ASSESSMENT

5.1

Overview

Based

on the October

21,

1995,

UA Transformer

1-1 explosion

and fire, the

inspectors

reviewed the adequacy of the design

and installation of fire

protection

equipment

and the adequacy of the fire brigade response.

The

inspectors

compared

the existing transformer

area fire protection with the

licensee's fire protection

system design

as described

in the Updated Final

Safety Analysis Report

(UFSAR), Section 9.5.1,

including comparison with

Branch Technical

Position

APCSB 9.5-1

and the requirements

of 10 CFR Part 50,

Appendix R.

The inspectors

concluded that:

(1) the deluge

system for the

transformers

performed its design function,

(2) the oily water separator

(OWS)

was prevented

from functioning because

the drain to the receptacle

was

intentionally blocked

by personnel

because

of mistaken

environmental

concerns,

(3) the licensee's fire brigade training program

was good,

and (4) during the

loss of offsite power emergency,

lighting could

be improved in four rooms

because

the battery operated lights

(BOLs) did not energize

and the emergency

alternating current

(ac) fixtures in the

same

room did not provide sufficient

illumination.

5.2

Transformer Area Desi

n

The inspectors

found that all the Unit

1 transformers

and Unit 2

SU

Transformer

2-1 are located

in the open yard area

surrounding

the power plant

buildings at the

85 foot level,

as indicated in Attachment

4.

This yard area

is located north of the containment

and northeast

of the turbine building.

The four main transformers

(one spare)

are

a minimum distance of 50 feet from

the turbine building, the two UA transformers

are approximately

30 feet

away

from the turbine building,

and the three

SU transformers

are approximately

20 feet

away from the turbine building.

The nonvital

12

kV switchgear

room is located at the

85 foot elevation

in the

turbine building and the

4 kV switchgear

room is located at the

104 foot

e'levation of the turbine building.

The perimeter exterior walls are provided

with 2-hour rated fire barriers.

The ventilation openings

in the east

exterior walls of the turbine building are provided with fire curtains

designed

to close,

should

a fire propagate

in the vicinity of the east wall.

Additionally, the slope of the grade at the east wall is directed

away from

the building, thus precluding oil accumulation

adjacent

to the turbine

0

-12-

bu:lding walls.

he F're protection features

proviJed for the Unit

1

4

kV and

12

kV switchgear

rooms are

such that

a fire sn the main bank or startup

transformer

areas will not impact the operability of the equipment

important

'to safety located within the turbine building.

Any spilled oil will drain

away from the turbine

and containment

buildings

and transformers

due to the

gravity flow to the

OWS drain system.

The transformers

were provided with

fully'utomatic deluge

spray

systems

with remote annunciation.

This area

was

also equipped with hose stations,

a yard hydrant with fully equipped

hose

houses,

and portable fire extinguishers.

The inspectors

found that the fire

protection deluge

system for the transformers

performed its intended

design

function even

though

one line above

UA Transformer

1-1

was broken

by the

transformer explosion.

The inspectors

determined that the Unit

1 transformer

area design

was

generally consistent with Branch Technical

Position

APCSB 9.5-1,

except for

one guideline,

which required

a 3-hour fire wall between buildings containing

safety-related

systems

and

any oil filled transformers

closer than

50 feet

from the building.

As discussed

above,

the Diablo Canyon design

had only

a

2-hour fire wall with UA transformers

closer than

50 feet to the turbine

building.

However, this design difference

was noted

and discussed

in UFSAR,

Table B-l, page 9.58-20.

The inspectors

concluded that the installed fire

protection

equipment

met the

UFSAR requirements.

5.3

Oil

Water

Se aration

S stem

The inspectors

reviewed the design capacity of the

OWS in the yard area for

Unit 1.

The capacity of the Unit

1

OWS was designed

to accommodate

22,000 gallons,

which was the contents of one main bank transformer.

The

OWS

was designed

to skim the oil from the surface of the water

and then discharge

the water to the outfall.

The oil was designed

to be retained

in

a

22,000 gallon receptacle.

During the October

21,

1995, event,

the

OWS was prevented

from functioning

because

the drain to the receptacle

was intentionally blocked with sandbags

by

licensee

personnel

because

of mistaken

environmental

concerns.

Licensee

personnel

removed

the sandbags

after fire brigade

personnel

determined that

the drain led to the

OWS, which was designed

to collect oil and water

spillage.

The licensee

stated that

a week prior to this event,

a full

discharge test of the deluge

system demonstrated

the adequacy of the

OWS

drain.

The licensee identified that intentional blocking of the

OWS drain was

caused

by

a weakness

in their general

employee training program.

The licensee

committed to upgrading their training program to include the purpose of the

OWS drain.

The licensee

also installed signs at the

OWS drains for both units

which indicated

the purpose of the drains

and provided instructions

not to

block them during

any oil spills.

The inspectors

also noted that because

of the blocking of the

OWS drain

numerous

oxygen bottles

were in the pool of oil and water,

which could have

made

the event significantly worse,

had the deluge

system not extinguished

the

-13-

fire external

to the transformer.

The licensee

imo odiately moved the bottles

and upgraded their procedures

to more specifically address

storage of

materials

in the transformer

areas.

5.4

Fire Bri ade

Res

onse

and Trainin

The inspectors

reviewed the licensee's fire brigade training program,

procedures,

and fire preplans,

including fire drills.

Based

on this review,

the inspectors

concluded that the fire brigade training program was considered

to be

a strength.

The inspectors

noted that

a drill scenario

on

a transformer

fire had

been

performed

a few weeks prior to the event.

The inspectors

also

noted that fire brigade

response

to the event

was prompt

and the fire was

extinguished

properly.

5.5

Emer enc

Li htin

The inspectors

evaluated

the adequacy of the emergency lighting in the

containment

and other effected

areas

when offsite power was lost.

The

licensee

conducted

a complete

walkdown of all emergency lighting (both

BOLs

and emergency

ac lights) in the Unit

1 turbine, auxiliary,

and fuel buildings.

As

a result of the walkdowns,

the licensee

determined

that emergency lighting

could be improved in four fire areas.

The emergency lighting in these

areas

was deficient because

the installed

BOL did not energize,

and the emergency

ac

fixtures did not provide sufficient illumination.

The licensee

credited

illumination from BOLs in these

four areas

to comply with Section III. J of

10 CFR Part 50, Appendix

R.

The areas of concern

were the Class

lE 480 volt

Bus

F,

G,

and

H rooms

and the turbine-driven auxiliary feedwater

pump room.

The, licensee

reviewed the electrical

design

drawings for the

BOLs in these

rooms

and determined

that these

BOLs were set

up to energize

upon the loss of

the vital ac lights in the room.

In this event,

the

BOLs did,not energize

because

the vital

ac lights in the rooms

remained

energized.

As

a corrective

action,

the licensee

has

proposed

a design

change

to rewire these

and

similarly configured

BOLs to be energized

upon loss of offsite power.

When

offsite power was available,

normal lighting in the area

was sufficient for

operators

to perform required actions.

The licensee

was currently tracking

this design

issue

in

a nonconformance

report

(NCR).

The inspectors

concluded

that the corrective actions

taken

by the licensee

were appropriate.

5.6

Conclusions

The inspectors

concluded that the fire protection features

provided in the

yard area

and the prompt response

and actions

taken

by the fire brigade

were

excellent.

The inspectors

also concluded that the lighting deficiencies

were

being adequately

addressed.

0

0

-14-

6

ROOT CAUSE ASSESSHFNT

AND CORRECTIVE ACTIONS

6.1

Overview

The inspectors

reviewed

a preliminary version of the licensee's

root cause

analysis

summary for NCR N0001939,

"Auxiliary Transformer I-l Failure."

The

licensee

prepared

an event

and causal

factors. chart to analyze

the

human

performance

and programmatic

aspects

of the events

leading to the transformer

failure.

They determined that the event

was caused

by

a general

programmatic

failure to control ground buggies.

The licensee's

administrative controls

were ineffective in preventing energization of an electrical

bus with a ground

buggy installed.

The licensee

identified five primary causal

factors for the

ineffective controls of the ground buggies:

inadequate

written instructions,

lack of process

ownership,

inadequate

past

problem resolution,

poorly designed

tags

and labels,

and inadequate

transformers

design

(discussed

in Section 4).

While not identified as

a primary causal

factor, the licensee

also identified

that fatigue

was

a contributing cause.

The inspectors

considered

that the licensee's

preliminary root cause

evaluation

was generally thorough

and comprehensive.

6.2

Inade uate Controls of Ground

Bu

Installation

and

Removal

There are

a number of licensee

procedures

which control the installation

and

removal of ground buggies

at Diablo Canyon.

~

Inter-Departmental

Administrative Procedure

OP2. ID1,

"DCPP Clearance

Process,"

Revision 2, required that clear

and concise

clearance

points

be indicated for electrical

grounding points,

operators

perform all

switching required to return equipment to service

and operators

complete

all necessary

paperwork,

including independent verification of clearance

removal.

~

Operating

Procedure

OP J-5: III, " 12kV Bus

D and

E- Shutdown

and

Clearing," Revision 3, required that if work was to be performed

on the

bus, that the Electrical

Department install grounds

under the

observation of a qualified operator.

e

Operating

Procedure

OP J-5: IV, "12kV Breaker

Code Order," Revision 6,

required that

an approved switching form be used to track the

installation of a grounding device.

Operators

were also required to

observe

the electrician

complete

each switching step.

e

Technical

Services

Maintenance

Procedure

MP E-57.11B,

" Installing and

Removing

Grounds

from Deenergized

Power Plant Electrical

Equipment,"

Revision 8, required that ground installation

be included

on

a clearance

request,

"Ground Installed" tags

be installed

on the cubicle door,

a

Caution

Tag

be hung

on the ground

buggy

and the caution tag

be logged in

-15-

accordance

with Procedure

CF4. 105.

Maintenance

personnel

were also not

to report off of a clearance until all ground buggies

were removed,

o

Inter-Departmental

Administrative Procedure

CF4. ID5, "Control of Lifted

Circuitry, Process

Tubing and Jumpers

during maintenance,"

Revision 0,

required that the location of installed personnel

grounds

and the

installation of all tags not installed

by an approved written procedure

be recorded

on

a Status

Sheet

{Form 69-11636).

On October 5, electrical

maintenance

personnel

initiated work

order

{WO) R0084606 to perform Electrical

Mainten'ance

Procedures

HP E-63.3C,

"Maintenance of General Electric Metal-Clad

4

KV and

12

KV Switchgear,"

Revision

1,

and

MP E-63.38,

"Maintenance of Potential

Transformer Cabinets

in

General Electric Metal-Clad

4 KV and

12

KV Switchgear,"

Revision

1,

on

12

kV

Bus

D.

Procedure

HP E-63.3B,

Step 5.3.1,

required that

a ground buggy be

installed for the

12

kV switchgear

work.

As discussed

in the following sections,

licensee

personnel

failed to follow

their procedures

for the installation

and removal of the ground

buggy

installed in the location for Circuit Breaker 52-VD-4.

6.2. 1

Clearance

Order Specifications

In preparation for 12

kV Bus

D work, the licensee initiated

Clearance

CR00049276,

"12kV Bus D-Outage."

The clearance listed the

installation of ground buggies at Circuit Breakers

52-YD-8 and 52-VD-4, "if

necessary."

This appears

to be contrary to Procedure

OP2. ID1, Step 4.4.3, for

providing clear

and concise

clearance

points for grounding points.

6.2.2

Ground

Buggy Installation

In accordance

with Procedure

OP J-5: IV, operations

personnel

prepared

a

switching log for the installation of a ground

buggy

on

12

kV Bus

D.

Operations

personnel

incorrectly specified

on the'switching*form that the

ground

buggy

be installed

on the load side of Circuit Breaker 52-YD-4.

The

operators

should

have specified installation of a ground

buggy on the

bus side

of 12

kY Circuit Breaker 52-VD-4.

Installation of the ground

buggy

on the

load side would have resulted

in equipment

damage

and potential

personnel

injury, since the secondary

side of SU Transformer

1-1 was energized.

On October 6,

1995,

an electrician installed the ground

buggy for Clearance

CR00049276

on the

bus side of 12

kV Circuit Breaker

52-VD-4.

This was the

correct installation for the given plant conditions.

However,

instead of

stopping

the work and correcting the switching log,

he inappropriately

signed

the switching form indicating that the ground

buggy had

been installed

on the

load side of 12

kY Circuit Breaker

52-VD-4.

This appears

to be contrary to

Procedure

OP J-5:IV, Step 6.5 because

the switching form incorrectly specified

installation of a load side ground buggy.

-16-

6.2.3

Verification of Ground

Buggy Installation

The switching log for Clearance

CR00049276 required

an operator

sign

verification for proper installation of the grounding device.

On October 6,

1995,

a ground

buggy was installed

by electrical

maintenance

personnel

in

12

kV Bus

D in accordance

with

WO R0084606.

The electrician

signed all the

independent verification blocks which should

have

been

signed

by operations

personnel.

As

a result,

operators

did not verify the installation of the

ground buggy.

This appears

to be contrary to Procedures

OP J-5: III, Step 6.5,

and

OP J-5: IV, Step 6.5, which required operations verification of ground

buggy installation.

6.2.4

Equipment Location

and Caution

Tag Logging

Electrical maintenance

personnel filled out and installed

a caution tag for

the ground

buggy

on the cubicle door;

however,

they did not record the

location of the ground

buggy or log the caution tag

on the status

sheet.

This

appears

to be contrary to Procedures

CF4. ID5, Step 5.2.4,

and

HP E-57. IIB,

Step

7. 1.22 which required the recording of equipment location

and the logging

of the installed caution tags.

6.2.5

Work Order Completion

On October 21,

1995, after work was completed

on

WO R0084606

and associated

WOs under the

same clearance,

an electrical

maintenance

foreman signed

electronic verification that all work on the

WO was complete,

although the

ground

buggy was still installed.

This appears

to be contrary to

Procedure

HP E-57. IIB, Step 2.2, which required all ground buggieq to be

removed prior to reporting off the clearance

after work was complete.

6.2.6

Operations

Return to Service

When operations

personnel

received

the verification that work was complete,

they completed

the clearance.

Clearance

CR00049276,

Section

V; 1'sted

the

possible installation of ground buggies for Circuit Breakers

52-VD-4 and

52-VD-8 and required verification of removal.

However, operations

personnel

restored

the clearance

without these verifications being made.

This appears

to be contrary to Procedure

OP2. IDI, Step

5. 11.7,

which required that

operations

return the system to service

and verify ground

buggy removal

as

specified

by the clearance.

During

a tailboard, prior to energizing

12

kV Bus D, operations

personnel

noted there

was

a caution tag

on the control switch For Circuit

Breaker

52-VD-4 indicating

a ground

buggy was installed in the cubicle for the

circuit breaker.

The licensee

determined

that operations

personnel

reached

an

erroneous

conclusion that the ground

buggy was

on the load side of the

breaker,

based

on the fact that maintenance

personnel

had reported that the

WO

for the

bus

was complete.

-17-

6.2.7

Inspectors'onclusions

There were

a number of licensee

documents

applicable to installation

and

removal of ground buggies.

From

a review of these

procedures,

the inspectors

concluded that although

some of the procedures

were for operators

and

some of

the procedures

were for maintenance

personnel,

most of the procedures

were

clear

as to the actions required.

Diablo Canyon Technical Specification 6.8. 1 states,

in part, that written

procedures

shall

be established,

implemented,

and maintained

covering the

applicable

procedures

recommended

in Appendix

A of Regulatory

Guide 1.33,

Revision

2, dated

February

1978.

Appendix

A of Regulatory

Guide 1.33,

Revision

2,

recommends

procedures

for equipment control

and the startup

and

operation of offsite and onsite electrical

systems.

The inspectors

determined

the licensee

procedures

for control of ground buggies

were not properly

implemented,

resulting in a loss of offsite power, loss of operating safety-

related

systems

(loss of shutdown cooling),

and

an unnecessary

challenge

to

safety

systems

(start of EDGs).

The six examples

noted

above of failure to

~

properly implement procedures

for the installation

and removal of a ground

buggy is

an apparent violation of Technical Specification 6.8. 1.

6.3

Lack of Process

Ownershi

Procedure

Adherence

and

ualit

Licensee root cause

personnel

informed the inspectors

that their preliminary

review of this event indicated that it was typical for operations

personnel

not to perform the required verifications of ground

buggy installation

and

removal.

They also determined that failure of electrical

maintenance

personnel

to properly log installation

and removal

was also typical.

The licensee's initial assessment

of the root cause

was site-wide acceptance

by operations

and electrical

maintenance

workers

and supervisors

of ground

buggy installation

and verification practices

that were different than

specified

in the applicable

procedures.

The licensee

determined that

technical

mai

tenance

personnel

thought operations

persorael

were responsible

for ground buggies

and operations

personnel

thought technical

maintenance

personnel

were responsible

for ground buggies.

The licensee

defined this

situation

as

a lack of process

ownership,

which they determined

to be the

fundamental

underlying cause of the event.

The licensee's

planned corrective actions

were intended to determine

the

eXtent of deviations

from procedures

and whether there

were other situations

where organizational

interfaces

were unclear.

Licensee

management

(including

the Senior Vice President

and General

Manager of Nuclear

Power Generation

and

the recently

announced

head of all electrical

generation

for

PGKE) conducted

a

series of meetings

to discuss

the event,

the causes

of the event,

and the

importance of identifying any other areas

of potential

concern.

Licensee

personnel

were

asked to identify other problem areas

to their supervision for

further evaluation.

The inspectors

attended

a sample of the meetings

and

determined

that the key points were discussed.

-18-

The inspectors

concluded that the procedures

and mechanis--, established

to

control the installation

and removal of ground buggies

had

some

areas

that

were unclear

and subject to misinterpretation of the expectations.

The

inspectors

noted that the clearance

procedure

referred to electrical

grounds

as clearance

points,

but did not specifically call out electrical

grounds

in

the definition of a clearance

point.

Licensee

personnel

stated that from a

site perspective

ground buggies

were not viewed

as clearance

points.

However,

the inspectors

identified clearances

where ground

buggy installation

and

removal

were treated

as clearance

points

and properly verified by operations.

The inspectors

concluded that proper conduct of the procedures

should

have

prevented

the event.

The inspectors

agreed that site practices

had

become

different than those specified

in the procedures.

The inspectors

noted that

the licensee's

evaluation

emphasized

the programmatic

problems rather than

individual procedure

adherence.

However,

the inspectors

considered

the

licensee's

overall effort to be

a thorough

and complete root cause

analysis.

6.4

Inade uate

Past

Problem Resolution

On October 5,

1994,

the licensee left a ground

buggy attached

to the output of

EDG 2-1 during postmaintenance

testing.

The licensee tried to load the

EDG

twice before discovering

the ground.

Electrical maintenance

personnel

were

required to remove the ground

buggy prior to starting the testing,

but did

not.

In addition,

some of the operators

knew that

a ground

buggy was still

installed,

but assumed

that it would not be connected

to the

EDG during the

test.

The licensee's

corrective actions

were documented

in NCR N0001856.

The

licensee's

corrective action

was to revise Inter-Departmental

Administrative

Procedure

CF4. ID5, "Control of Lifted Circuitry, Process

Tubing

and Jumpers

During Maintenance,"

to include personnel

grounds

as jumpers/lifted leads.

Licensee

personnel

indicated that this procedure

change

was confusing in that

it was difficult to conceptualize

that

a ground

buggy was similar to

a jumper.

In addition, licensee

personnel

indicated that this procedure

revision was

ineffective in that licensee

personnel

never interpreted it to mean that the

ground

buggy itself should

be ',ogged

as

a jumper.

The inspectors

reviewed the root cause

analysis for NCR N0001856 (for the

October

1994

EDG event)

and compared

the causes

of this event with the recent

ground

buggy error

and found them to be similar.

In both events,

maintenance

personnel

lost track of the fact that the ground

buggy was still installed.

In both events,

operations

personnel

incorrectly evaluated

the impact of the

ground

buggy remaining installed.

The incorrect evaluation

was rooted in the

lack of a full understanding

of the electrical configuration at the shift

foreman level.

The inspectors

considered

that

many of the root causes

of the

ground

buggy being left installed in

12

kV Bus

D were present

in the October

1994

EDG 2-1 event,

but were not effectively corrected

to prevent recurrence.

The inspectors

agreed with the licensee's

determination that they had

an

opportunity to correct the situation after previous similar occurrences

in

1994.

The licensee

stated that interface

problems

between operations

and

maintenance

prevented either organization

from effectively resolving the

-19-

r att"; in 1994.

The in:pectors

concluded that li~er s

management

missed

an

opportunity to take effective corrective action

<<'iicn could have precluded

leaving the ground

buggy in

12

kV Bus

0 on October 21,

1995,

and the ensuing

transformer explosion,

loss of offsite power,

momentary loss of shutdown

cooling,

and

damage

to offsite power supply components.

6.5

Poorl

Desi

ned

Ta

s

Labels

and Terminolo

The licensee

determined that

human factors considerations

contributed to this

event in that terminology practices

provided

an inadequate

level of

information for personnel

to evaluate

situations

and

make informed decisions.

6.5.

1

Ground

Buggy Terminology

At Diablo Canyon,

ground buggies

were installed

as

needed

in the

12

kV and

4

kV system.

The ground buggies

consisted

of frames with one set of three

breaker

stabs,

which could be inserted

into the cubicle,

in the space of a

removed circuit breaker.

"Bus" ground buggies

were oriented with stabs

to

connect directly to the switchgear

busses

and "load" ground buggies

were

oriented with stabs

to connect to the external

cables/devices

for individual

circuits.

The buggies

were clearly labeled

when viewed from the front (with

the words

bus or load).

The term "load" was also routinely used

by operators

and electrical

personnel

to indicate the direction of power flow.

Since

power flowed from SU

Transformer

1-1 via Circuit Breaker

52-VD-4 to

12

kV Bus

D, the bus side of

the

12

kV switchgear

could also

be viewed

as

a load for the

SU transformer.

The licensee

determined that the operators

were confused

when they prepared

the switching order for the installation of the ground

buggy in the location

of removed Circuit Breaker 52-VD-4.

As

a result,

they incorrectly completed

the switching log to indicate the ground

buggy was to be installed

on the

"load" side

when they should

have specified

"bus" side.

This error

contributed to the incorrect decision to energize

the switchgear with the

ground

buggy still installed.

Operations

personnel

stated that they were

aware of the switching log which

showed that

a ground

buggy was installed in the location of Circuit

Breaker 52-VD-4.

As discussed

in Section 6.2

an operator questioned

the

configuration of the ground

buggy during the tail board conducted prior to

reenergizing

the

12

kV switchgear.

The operators

discussed

the ground

buggy

location

and

assumed

that the ground

buggy was installed

on the load side.

On

that basis,

operations

personnel

considered

that the

bus could

be safely

energized

from UA Transformer

1-1 with the ground

buggy still installed.

This

decision

would have

been correct if the buggy had

been

on the load side of the

cubicle.

I

During the inspection,

the licensee

revised

the terminology for labeling

ground buggies to bus

and line.

Bus ground buggies

had stabs

which could be

connected directly to the switchgear

busses,

and line ground buggies

had stabs

-20-

tc connect to the ex'.~mal

cables/devices

for indi"',dual circuits.

The

inspectors

determined that this was

an important clarification.

6.5.2

Ground

Buggy Caution

Tags

Prior to the October

21,

1995, event,

the maintenance

foreman performed

a

walkdown of the

12

kV switchgear prior to reporting off the clearance.

During

that walkdown,

he overlooked the caution tag which indicated that the ground

buggy was still installed in the cubicle for Circuit Breaker 52-VD-4.

The

licensee

determined

that the caution

tag could have

been

covered

by several

other tags of similar sizes that were hanging

on the

same cubicle.

Licensee

personnel

also noted that the caution tags

were yellow, which was not

consistent with industry convention to use green to indicate

a ground.

They

also noted that the caution tags did not include information to determine

the

configuration (load or bus) of the ground buggy.

To address

these

weaknesses,

the licensee

revised

the ground

buggy tagging instructions to specify use of a

larger green

tag which included ground

buggy configuration information (line

or bus).

The licensee

indicated

the

new tags will be more visible.

The inspectors

determined that the licensee's

planned

changes

to the tags

and

labels

used

in the control of ground buggies

would improve their

effectiveness.

6.6

~Feti

ue

The licensee

determined that work schedules

had resulted

in reduced levels of

alertness

for personnel

involved in the event.

Specifically, licensee

personnel

determined that fatigue contributed to the maintenance

foreman's

error.

As discussed

above,

he performed

a walkdown of the

12

kV switchgear

prior to reporting off the clearance

and did not identify that the ground

buggy was still installed.

Licensee

management

stated that they planned to

reevaluate

the site policy for scheduling

overtime.

Licensee

personnel

stated that the maintenance

foreman involved did not work

in excess

of any Technical Specification requirements

for overtime

use during

the refueling outage.

The inspectors

independently

determined that this was

correct.

However,

the inspectors

reviewed overtime records for the month of

October

1995 for other personnel

in the Technical

Maintenance

Section

and

noted that several

personnel

had

been repeatedly

authorized

to work more that

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />

in

a 7-day period.

The inspectors

determined

that

44 percent of the

temporary personnel

in the Technical

Maintenance

Section

exceeded

the overtime

guidelines for work during the refueling outage.

Depending

on the type of

personnel,

25 - 30 percent of the permanent

personnel

in the Technical

Maintenance

Section

also

exceeded

the overtime guidelines for work during

a

refueling outage.

Based

on

a review of the overtime authorization

documents

and interviews with licensee

personnel,

the inspectors

determined that

-21-

Technical

Maintenance

Section

personnel

were bein<

authorized

each

week

repeatedly

to perform safety-related

work which was within the scope of

Technical Specification 6.2.2.f.

Diablo Canyon Technical Specification 6.2.2.f states,

in part,

"

.

.

. during

extended

periods of shutdown for refueling

.

.

. the following guidelines

shall

be followed:

.

.

.

An individual should not be permitted to work

.

more than

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in any 7-day period

.

.

. excluding shift turnover time

.

. Routine deviation from the

above guidelines

is not authorized."

Inter-

Departmental

Administrative Procedure

OM14. IDI, "Overtime Restrictions,"

Revision

3A, Step 5.2.3,

stated that routine deviation from Technical Specification 6.2.2.f limitations shall

not be authorized

and that blanket

approval of overtime assignments

shall not be authorized.

The inspectors

considered

that the licensee

management's

repeated

authorization of Technical

Maintenance

Section

personnel

to work more than

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> in

a 7-day period constituted routine deviation from the provisions

of Technical Specification 6.2.2.f.

This is

an apparent violation of

Technical Specification 6.2.2.f.

Technical Specification 6.2.2.f also stated that overtime extensions

should

be

approved

by the plant manager,

his designee,

or higher levels of management.

The licensee

designated

that overtime extensions

could

be approved

by

department

managers,

section directors, shift supervisors,

and general

foremen.

All of the overtime extension

requests

reviewed

by the inspectors

were approved

by general

foremen.

The inspectors

were concerned that the

licensee

had designated

various lower levels of supervisory personnel,

including general

foremen,

to sign for the plant manager.

The inspectors

discussed

the approval of overtime with licensee

management.

The licensee

acknowledged

the inspectors'oncern.

6.7

Corrective Actions and Conclusions

The inspectors

concluded that the licensee's

root cause

was effective

and

thorough in identification of the root causes

of the event.

Following the event,

the licensee

developed

an interim policy for removing

grounding devices

and energizing

dead

busses

or transformers.

Licensee

personnel

stated

that they intended to use the interim policy while they

completed their root cause

investigation

and completed

appropriate

long-term

procedure

revisions.

The inspectors

reviewed the policy memorandum

and interviewed the clearance

coordinator regarding its implementation.

The clearance

coordinator stated

that prior to the event it was the responsibility of operations

to list ground

buggies

on the clearance

and to verify the removal of ground buggies.

He

noted that the removal verification was

sometimes

cross-referenced

to

a

release-off-for-test

form.

He stated

that the interim policy clarified the

responsibilities

for maintaining ground

buggy configuration.

Under the

interim policy, operators

were required to verify both installation

and

0

-22-

removal of ground buggies

on the clearance

form, i.e.,

ground buggies

were

treated

as

a clearance

point.

Under the interim policy, maintenance

personnel

track personal

grounds

on the Lifted Circuit and

Tag Control Status

Sheet.

The interim policy a'Iso called for additional field walkdowns

and management

oversight.

The inspectors

determined

that the interim policy provided

an

adequate

level of increased

control of grounding devices during the completion

of the root cause

analysis.

4

ATTACHMENT 1

1

PERSONS

CONTACTED

1.1

Licensee

Personnel

¹M. Angus,

Manager,

Regulatory

and Design Services

• J.

Becker, Director, Operations

• D. Cosgrove,

Supervisor,

Fire Protection

• F.

De Peralta,

Fire Protection

Engineer

• C. Dougherty,

Senior equality Assurance

Engineer

¹T. Fetterman,

Director, Electrical

and Instrumentation

and Control

Systems

¹W. Fujimoto, Vice President

and Plant Manager,

Diablo Canyon Operations

• ¹T. Grebel, Director, Regulatory

Support

• J.

Gregerson,

Fire Protection

Engineer

• S. Hamilton, equality Assurance

Engineer

• D. Hampshire,

Senior Engineer

¹C. Harbor,

Engineer,

Regulatory

Support

¹C.

Herman,

Supervisory

Engineer,

Instrumentation

and Control

¹A. Jorgensen,

Engineer,

Nuclear Safety Engineering

¹M. Lepple,

Engineer,

Regulatory Support

• ¹D. Miklush, Manager,

Operations

Services

• D. Oatley, Director, Mechanical

Maintenance

• ¹H. Phillips, Director, Technical

Maintenance

¹R.

Powers,

Manager,

equality

Services

¹G.

Rueger,

Senior Vice President

and General

Manager

J. Shiffer, Executive Vice President

• D. Sisk,

Engineer,

Regulatory

Support

• D. Smith,

Engineer

• D. Taggart, Director, Nuclear Safety Engineering

¹L. Womack,

Vice President,

Nuclear Technical

Services

1.2

NRC Personnel

• ¹D. Acker, Project Inspector

¹S.

Boynton,

Resident

Inspector

• ¹J. Dixon-Herrity, Acting Senior Resident

Inspe'ctor

¹K. Perkins,

Director, Walnut Creek Field Office

J. Russell,

Acting Senior Resident

Inspector

• A. Singh, Fire Protection Specialist,

Office of Nuclear

Reactor Regulation

• L. Smith, Reactor

Inspector

• ¹H. Wong, Chief, Reactor Projects

Branch

E

• Denotes those attending

the preliminary exit meeting

on November

17,

1995.

¹Denotes

those attending

the telephone exit meeting

on December

8,

1995.

In addition to the personnel

listed above,

the inspectors

contacted

other

personnel

during this inspection.

2

EXIT MEETING

A preliminary exit meeting

was conducted

on November

17,

1995,

and

a final

exit meeting

was conducted

on December

8,

1995.

During these

meetings,

the

inspectors

reviewed the

scope

and findings of the

eport.

The licensee

acknowledged

the inspection findings documented

in this report.

The licensee

did not identify as proprietary

any information provided to, or reviewed by,

the inspectors.

ATTACHMENT 2

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