ML17310B447

F. Burrows, Electrical Engineer,

Accompanying Persgqnel:

J. Ganiere,

Intern,

Approved:

er ins,

erector

Malnut Creek Field Office

a

e

Ins ection

Summar

Areas

Ins ected

Unit 2

Special,

announced

inspection of the circumstances

regarding

a reactor trip on May 28,

1994, which was caused

by water flow from

the refueling water tank to the containment

spray header.

The licensee's

response

to and assessment

of the event were evaluated;

included were

interviews with the personnel

involved in the reactor trip event.

Areas

Ins ected

Unit

1 and

3

No inspection of Units

1 and

3 was performed.

~R1<<UR

2

~

The licensee's

preliminary event investigation

int'o the root cause of

the event

was thorough

and objective.

The licensee's

review of the

event

had captured

the concerns

and weaknesses

identified by the

inspectors.

Licensee

management

involvement in the review of the event

was clearly evident.

9407iP200

050005ge

gp 9q07aa

PDR

ADOC

@DR

Q

,

I

1

J

l

I

t

1

0

e

~

The primary cause of the event

was that

an instrument

and control

(I&C)

technician

had

a mindset

and the technicians

failed to follow the

instructions of a work order when they were replacing

a relay in the

wrong cabinet.

Extra material

in the work package left one technician

with the mindset that the work was to be done in Train

B (incorrect

train).

However, there were also several

other contributing factors

which led the technicians

to work on the wrong relay

and the subsequent

reactor trip.

~

.

Communications

between

the

I&C technicians

and operations

crew were

poor:

(1) the pre-job briefing in the control

room was inadequate

in

that it did not specifically identify the train which would be worked

on;

(2) during the relay replacement

work,

an

I&C technician

entered

the

control

room to see if the work had caused

any unexpected

response,

but

did not speak with anyone regarding his intentions or the status of the

work;

and (3) when trying to understand

the cause of the containment

sump level increase,

operations

personnel

had

a mindset that,

since

power had

been

removed

from the containment

spray valve, the ongoing

work could not

be the cause,

and they failed to check

on the work being

done

by the technicians

even

though they were just outside

the control

room.

Management

expectations

regarding certain

aspects

of work control

and

conduct of work were not understood:

(1) the

ILC technicians

failed to

carefully review the work order;

one technician did not review the work

order until after the event

and the other technician

had

a mindset that

work was to be conducted

in Train 8;

and

(2) personnel

did not

understand

how to apply the Sensitive

Issues

Manual in the review of

work to be performed

(as

a policy document

implementing procedures

had

been considered

unnecessary).

~

Personnel

failed to maintain

an effective questioning attitude:

(1) the

I&C technicians

worked

on the wrong relay even though the work

instructions clearly specified the proper relay;

and

(2) the operations

crew focused

on the

steam generator

blowdown line as the source of the

water going to the containment

sump, did not conduct effective

questioning

or perform control board walkdowns to eliminate other

possibilities,

such

as the containment

spray

system,

and did not

investigate

the work bei.ng

done

by the

I&C technicians

although they

were just outside the control room.,

The licensee's

"re-engineering"

program

had

made

changes

to the work

process

which had not been effectively communicated

to plant personnel.

No longer did all work orders require .the workers to verify the train

and component

which was being worked on.

The work order

being performed

in this event did not have this verification step.

The removal of the

verification step

was not known to the operations

crew.

In addition,

the relay work was

moved

up from its original schedule without the

'

f

t

1

I

)

normal

scheduling interface

between

the unit schedulers

and those

on the

"re-engineering" pilot team.

~

The licensee's

preliminary corrective actions,

including department

meetings

which discussed

the event,

review of communication practices,

review of the changes

made in the "re-engineering"

program,

and

counseling of the technicians

involved in the event,

were appropriate.

~

The licensee's

review of the reactor coolant

pump electrical

and other equipment potentially affected

by the containment

spray

system

flow was thorough

and complete.

Other than the

damaged

connectors

and penetration

enclosure

box,

no other components

were found

to be adversely

affected

by the borated water.

Results

Units

1

and

3

Not applicable.

Summar

of Ins ection Findin s:

~

One violation was identified (Section 3.2.3).

t

Attachments:

~

Attachment

1 - Persons

Contacted

and Exit Heeting

~

Attachment

2

Acronyms

'

J

l

)

DETAILS

1

EVENT SUMMARY

On May 28,

1994, at

11: 15 a.m., while Palo Verde Unit 2 was operating

at

86 percent

power,

a reactor trip occurred

as

a result of a trip of Reactor

Coolant

Pump

18.

The cause of the reactor coolant

pump trip was

a phase-to-

phase fault caused

by water getting into the reactor coolant

pump junction box

inside containment.

The water flowed into .junction box when

a containment

spray

(CS) valve was inadvertently

opened

and allowed borated

water

from the

refueling water tank

(RWT) to flow by gravity through the

CS system

header

piping and auxiliary nozzles

in the lower elevations of containment.

I&C

technicians

had

removed

a relay in the wrong train of the engineered

safety

features

actuation

system

(ESFAS) which caused

the opening of the

CS system

valve.

The elevation of the

RWT provided gravity flow from the

RWT through the id

pump, inadvertently opening the

CS system valve,

and through the lower

elevation

CS nozzles.

For approximately

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 45 minutes,

while the

operations

crew was trying to identify the source of water going to the

containment

sump,

approximately

7000 gallons of borated water flowed to the

containment

from the

RWT ~

The reactor trip occurred while operations

personnel

were in the containment

looking for the source of water.

The

personnel

subsequently

identified the water coming through the

CS nozzles.

When alerted to the situation,

control

room personnel

identified the

inadvertently

opened

valve

and closed it at ll:31 a.m.

The licensee

concluded that the plant response

to the reactor trip was

uncomplicated.

Minor equipment

problems

were identified by the licensee,

such

as

a feedwater

economizer

and

a steam

bypass

control valve not going fully

closed

and

a control element

assembly

rod bottom light not illuminating as

quickly as the others.

These

issues will be addressed

in a routine resident

inspector

inspection report.

2

PURPOSE

OF

INSPECTION

The purpose of this special

inspection

was to review the circumstances

of the

reactor trip and to assess

the licensee's

response

to the event.

The

inspection

included

an independent

evaluation of the licensee's

root cause

evaluation,

interviews of personnel

involved in the event,

evaluation of the

performance of the reactor coolant

pump containment

which was

subjected

to the phase-to-phase

fault,

and evaluation of the inspection

and

repairs to equipment affected

by the

CS flow.

In particular,

the special

inspection

independently

assessed:

~

the cause of the

I&C technicians'emoval

of the relay in the wrong

train,

1

'

~

why the operations

crew took

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months 45 minutes to identify the source

of the water going to containment

sump,

~

the licensee's

assessment

of the root causes

of the event,

~

the

adequacy

of the licensee's

preliminary corrective actions,

~

the performance of the reactor coolant

pump containment electrical

penetration,

and

~

the status of other components

potentially damaged

by the

CS flow,

including the licensee's

evaluation of these

components.

3

EVENT FOLLOWUP

(92703)

3. 1

Summar

of Investi ation

NRC personnel

interviewed the 'two

I&C technicians,

the

I&C foreman,

and the

Unit 2 operating

crew that were involved with the event.

All personnel

were

cooperative

and candid during their interviews.

The work package

and other

supporting

information were also reviewed to determine

whether

inadequacies

in

the work instructions contributed to the event.

Based

on the review of the work package

and staff interviews,

the root causes

of the event were determined

to be:

(1)

human error caused

in part by

mindsets

and extra material

in the work package;

(2) inadequate

communications,

including ineffectively communicated

management

expectations

for both operations

and maintenance

personnel;

and

(3) failures to maintain

an

effective questioning attitude.

3.2

Rela

Work b

1&C Technicians

3.2.1

Background

On Hay 21,

1994,

l&C technicians,

who were assigned

to the

I&C "re-

engineering" pilot team, identified

a failed contact

on

an engineered

safety

features

actuation

system

(ESFAS) relay during surveillance testing.

It was

Relay K111, in the Train

A ESFAS,

which is normally energized.

The relay de-

energizes

on

a

CS actuation

signal

and

opens

the Train A CS isolation valve

(SIA-UV-672).

The technicians

identified

a failed contact

on the relay which

provided valve position indication to the quality safety parameter

display

system.

The failed contact did not affect the ability of Relay

K111 to open

the

CS isolation valve.

Prior to the event,

the licensee

had initiated

a program to "re-engineer" its

work processes

and work resources.

As part of this effort, the licensee

had

implemented

several

programs

designed

to increase

the efficiency of performing

maintenance

at the plant.

These efforts included:

(1) streamlining work

instructions,

(2) streamlining the work assignment

process,

and

(3)

implementation of

a "pilot" program

as

a trial of the

new work process

and

I

J

organization

changes,

which involved re-alignment of maintenance

work crews

by

plant system rather than

by unit.

Implementation of the "re-engineering"

pilot programs

began

in February

1994.

Discussions

with members of the licensee's

staff revealed that instructions

for writing work orders

were being revised

in the "re-engineering"

process.

The changes

were

made

based

on

an evaluation

performed

by four work planners

and were reviewed

by the maintenance

and work control organizations.

Discussions

with members of the licensee's

staff also revealed that work on

"critical" or "sensitive"

equipment

was generally pre-scheduled.

Pre-

scheduling

work on critical components

provided plant staff sufficient time to

assess

how such work would affect the plant co( iguration.

In addition,

the licensee

previously developed

and issued t'e "Sensitive

Issues

Nanual

(SIN)," which identified plant systems,

conditions,

or

activities that

have

a greater

impact

on safety

and, therefore,

need

a higher

level of management

attention.

The SIN states

that

a prejob briefing should

be held for any work involving equipment that may result in actuation of an

ESF system.

However,

because

licensee

management

intended

the

SIN to be

a

policy document,

implementing procedures

for the SIN had not been

developed.

In addition,

no specific training regarding

management's

expectations

of

worker use of the SIN had

been given to the personnel

involved in the event.

The operating

crew on duty during the event

had worked together for over

a

year

and were very experienced.

Although there

were three reactor

operators

(ROs)

on shift, the third

RO was undergoing on-the-job training in

preparation for becoming

an assistant shift supervisor

(SS).

The two

I&C technicians

involved with the event were participating in the

maintenance

department's

"re-engineering" pilot program.

The two technicians

were assigned

to the pilot team

when it was formed in February

1994.

They

worked with each other

on the back shift about

1 week per month

and were

familiar with each other's

work practices.

Both individuals

had extensive

experience

in I&C.

The lead technician's

(Technician

1)

ILC training was

current;

however,

the second technician's

(Technician

2)

I&C training had

lapsed.

Technicians

1

and

2 were also designated

in the Palo Verde

maintenance

organization

as the "independent"

and "dependent"

worker,

respectively.

Discussions

with members of the licensee's

staff revealed that

the designation

of "independent"

and "dependent"

workers

was

common

and only

served to identify whose training was current.

Both technicians

were familiar

with the scope of the relay replacement

work.

Both technicians

knew that the licensee

was evaluating its organizational

structure

and work processes

to increase efficiency in the performance of

maintenance

work.

The technicians

acknowledged

that this "re-engineering"

could lead to downsizing the work force later in 1994.

They also

knew that

the purpose of the "re-engineering" pilot program

was

a t}ial of the proposed

organization

and processes.

Technician

1 had worked

12 days in a row;

',

t

f

however,

he stated

that

he

was not fatigued

and did not feel

an abnormal

level

of stress.

No regulatory limits on worker overtime were exceeded.

Technician

2 had not worked any overtime

and stated that

he was neither

fatigued nor felt overly stressed

prior to working on Relay Kill.

The component designation

convention at Palo Verde generally identifies

components

for Trains

A and

B such that

a lower number is associated

with

Train A.

This would mean that

CS isolation Valves SIB-UV-671 and SIA-UV-672

would be expected

to be in Trains

A and

B, respectively.

However,

Valve SIA-

UV-672 is in Train

A and Valve SIB-UV-671 is in Train B.

Discussions

with

members of the operating staff revealed that experienced

operators

have to

remind themselves

of this inconsistency.

Also, the'elays

that actuate

Valves SIB-UV-671 and SIA-UV-672 for Trains

B and

A are both designated

as

Relay K111.

The controls for Trains

A and

B of the

CS system

are located

approximately

4 feet apart

on the control

room panel.

Train A is denoted

by

red labels with Train

B identified by green labels.

3.2.2

Planning

and Scheduling of Corrective Maintenance

On May 21,

1994,

Work Order

(WO) 00661592

was written to replace

Relay

K111

(located in the Train

A ESFAS cabinet).

The

WO identified that,

when

Relay

K111 was de-energized,

CS isolation Valve SIA-UV-672 would receive

an

open signal.

As

a precaution,

the

WO had

a step to ensure that power was

removed

from the valve to prevent it from opening.

The

WO was determined

to be Priority 3 (routine work) and

was scheduled for

July 11.

However,

on May 27',

1994,

the

I&C foreman included the job as work

for,the crew for the weekend

and the Unit 2 scheduling organization

was not

informed of the change.

Therefore,

the work was not included in the Unit 2

weekend

schedule.

While the

WO cover page specifically identified the correct relay to be worked

(Train A), the

WO did not have

a step to verify that the workers were working

on the proper equipment prior to starting work as

had

been stated

in the work

instructions

in the past.

The licensee identified that

a revision to the

maintenance

procedure writer's guide

was issued

in February

1994 that removed

the requirement for all

WOs to include such steps

in the

WO to verify the

proper train and equipment prior to starting work.

3.2.3

Sequence

of Events

At about

7 a.m.

on May 28,

1994, the lead

I&C technician

(Technician

1)

arrived in the

I&C shop

and reviewed the list of work for the day.

The higher

priority surveillance tests

available to be done could not be performed

due to

the existing plant conditions,

so the technician

decided to perform the

Relay Kill replacement

work.

The

I&C foreman

had given Technician

1

a list of

work which could

be done over the weekend;

however,

the foreman did not

conduct

a prejob briefing with the technicians prior to the start of the

Relay

K111 replacement

work.

Both

I&C technicians

had previously worked

on

similar jobs

and

knew that bench testing of the relay was required prior to

(

installation.

Technician

1 reviewed the work package.

Then Technician

2 went

to the

IKC shop to bench test the replacement

relay,

and Technician

1 went to

notify Operations

personnel

that the technicians

were going to replace

Relay K111.

During the interviews,

the technicians

stated that they preferred

to split the work with Technician

1 doing the paperwork

and Technician

2 doing

the bench testing

and gathering of equipment

needed

to perform the job.

Technician

1 directed the job activities

and Technician

2 did not review the

work package until after the event.

The work package

described

the replacement

of Relay Kill for Train A.

The

inspector's

review of the work package

revealed that,

although the majority of

the work instructions specifically addressed

Train A components,

the last few

pages

contained

work instructions for Train B.

Technician

1 stated that

he

remembered

looking at the work package

and

was convinced that the work was to

be done

on Train B.

At approximately 8: 15 a.m.,

Technician

1 went to the

control

room to get permission

from the assistant

SS to perform the work.

After, looking over the work package,

the

SS,

the assistant

SS,

and the third

RO noted that work on Relay

K111 could cause

the

CS isolation valve

(SIA-UV-

672) to go open.

They moved to the Train A portion of the control board,

which included the controls for Valve SIA-UV-672, and discussed

the potential

consequences

of Valve SIA-.UV-672 going open.

The

18C technician

was in the

immediate vicinity of the operations staff.

None of the individuals

interviewed

remembered

specifically stating that the component

was

on Train A.

The assistant

SS also noted that the

WO included

a precaution to ensure that

power was

removed

from Valve SIA-UV-672 to ensure

the valve remained

closed.

The assistant

SS realized that removing power from Valve SIA-UV-672 would

prevent the valve from performing its intended safety function if called

upon.

Therefore,

de-energizing

Valve SIA-UV-672 required entering the Technical

Specification Limiting Condition for Operation for one train of CS being

inoperable.

The

SS agreed to remove

power from Valve SIA-UV-672 and enter the

limiting condition for operation just before the technicians

were ready to

start the actual relay replacement.

Technician

1 then obtained

the relay

cabinet

keys, exited the control

room,

opened

the Train

B cabinet in error,

and returned

the keys to the control

room.

During this time, Technician

2 completed

the bench test of the replacement

relay

and proceeded

to the control

room.

Just outside the control

room,

Technician

2 noted that the Train

B ESFAS cabinet

was

opened

and

assumed

that

the work was

on Train B.

At approximately

9 a.m.,

the technicians

were ready

to start the relay replacement.

Both technicians

went into the control

room

and informed the assistant

SS that they were ready to have the power removed

from Valve SIA-UV-672.

The control

room staff determined

the correct power,

supply for the valve

and directed

an auxiliary operator to open the breaker

for Valve SIA-UV-672.

At 9: 12 a.m.,

the

SS declared

Train A of CS inoperable

when power was

removed

from Valve SIA-UV-672.

The assistant

and the

primary reactor operator

(PO) verified that power was

removed

from the correct

valve.

Since the power was

removed

from the valve,

a white safety

equipment

I

,

l

0

status

system

(SESS) indication was lighted

on control

room Panel

B02,

indicating that the valve would not open if an actual

CS actuation

signal

was

received.

At approximately

9,: 15 a.m.,

the assistant

SS then gave the

IKC technicians

permission to start work on the Relay Kill replacement.

When the

PO and

assistant

SS observed

the indicator light for Valve SIA-UV-672 go out, they

told Technician

1 that the valve was de-energized

and pointed towards

an

extinguished

valve indicator light.

Neither the Assistant

SS nor the

PO

recall specifically stating that they were de-energizing

the containment

spray

valve for Train A.

Although Technician

1 had received

some

systems training,

he was not familiar wi'th which section of the control

board contained

which

train.

Then the technicians left the control

room to start the relay work.

Both technicians

went to the Train

8 cabinet just outside the control

room

that

was previously opened

and

began

removing Relay

K111 using the work order

instruction.

In Step

3'.3 of the

WO, the technicians

were to document

the

orientation of the Train

A relay mounted in ESfAS Cabinet

J-SAA-COI.

However,

the technicians

were in Train

B Cabinet

J-SAB-COI.

This was

a violation of

Technical Specification 6.8. 1 for the failure of the technicians

to follow the

work order instructions (Violation 529/9423-01).

The next step in the

WO was to remove the power leads to the relay.

At

approximately 9:36 a.m.,

the technicians lifted the power leads

which de-

energized

Train

B Relay Kill. Technician

1 then entered

the control

room and

conducted

a visual

check for any unusual

operator activity.

The operators

seemed

to be acting normally,

so Technician

1 returned to the relay cabinet

and continued to work on the relay replacements

He did not speak to any of

the control

room personnel.

When Train

B Relay

K111 was de-energized,

the

Train

B valve (SIB-UV-671) opened

and the

RWT began to gravity drain into the

containment

through the Train

B

CS auxiliary (lower) spray nozzles.

The technicians

continued their work and

began to lift all the wires from the

various parts of Relay K111.

The technicians

had lifted about

50 wires

and

were about

75 percent

complete

when the reactor trip occurred at 11: 15 a.m.

During this time, the technicians

were not aware of the problem iy the control

room with containment

sump alarms.

3.3

Res

onse to Containment

Sum

Level

Increase

3.F 1

Background

At approximately

9:30 a.m.,

both the

and the shift technical

advisor

(STA)

left the control

room.

The Assistant

SS,

a licensed

senior

RO,

and three

reactor operators

(one with a senior reactor operator license)

remained

in the

control

room.

At approximately

9:35 a.m.,

upon completion of the

blowdown

evolution, the secondary

operator

(SO) initiated

a high rate

blowdown on Steam

Generator

(SG)

1.

Approximately

1 minute later,

the

IKC technicians

incorrectly removed the power from Train

B Relay K111, which caused

the

Train

B

CS isolation valve to open.

A Train

B

SESS

alarm was not generated

-10-

because

the valve responded

as expected

on the removal of power to Relay KI11.

The only indication available to the control

room operators

of the change

in

valve position

was the valve position indicator on control

room Panel

B02 that

went from closed

(green)

to open (red).

The

PO was entering

new constants

for

the computer

program that calculated

secondary

power due to performing the

high rate

blowdown in

1

and did not notice the momentary blue

SESS light or

the change

in valve position indication for the Train

B

CS isolation valve.

3.3.2

Sequence

of Events

At approximately 9:44 a.m.,

the east

containment

sump high level alarm

on

control

room Panel

B07 was received.

The

SO appropriately

responded

to the,

alarm.

Approximately

3 minutes later,

upon completion .of the

blowdown

evolution,

the

SO secured

the high rate

blowdown on

1

and returned to

a

normal rate

blowdown.

At about 9:52 a.m.,

the operators

received

an east

containment

sump

pump excess

alarm.

Control

room personnel

followed the alarm

response

procedure

and

began to evaluate

primary plant parameters

to determin~

if there

was

a reactor coolant

system

(RCS) leak.

The operators

believed

there

was not

an

RCS leak since all the primary system

parameters

were nor%

~

Because

the

SG high rate

blowdown was the last evolution performed before

receipt of the

sump alarm,

the

SO believed the source of the leak to be the

blowdown system.

Both the

PO and the

SO were focused

on blowdown

manipulations

and limited their investigations of plant status

to the primary

and secondary

systems.

Control

board walkdowns of neither the

ESFAS control

board,

which includes the

CS system,

nor the electrical control

boards

were

performed.

The Assistant

SS agreed with the SO's initial assessment

of a

probable

blowdown system leak

and

began to monitor containment

humidity,

temperatur'e,

and

sump levels.

The assistant

SS then

asked

the

PO whether the

CS system could

be the source of the leak

and the

PO responded

that

Valve SIA-UV-672 had

been de-energized

in the closed position.

Both

individuals glanced

over to the

CS system

panel

and noted that the indicator

for Train

A CS isolation Valve SIA-UV-672 was not lighted.

Neither of these

individuals looked at the indicator for Train B, which showed that

isolation Valve SIB-UV-671 was open.

The assistant

SS then directed

the third

RO to monitor containment

parameters

and to determine

the leakage rate,

At approximately

10 a.m.,

the

and the

STA returned to the control

room.

The assistant

SS informed the

SS of the excess

containment

leakage

and that

he

believed the source of the leak to be the

SG blowdown system.

While being

briefed

by the assistant

SS,

the

asked

about the status of the

CS system

and

was told that Valve SIA-UV-672 had

been verified de-energized

and shut.

No one questioned this statement

and

no further investigations

regarding

the

CS system

were performed.

The assistant

SS then directed the

STA to assist

with the trending of containment

parameters.

The

SS also directed his

attention to future actions with other systems,

such

as dealing with the

liquid radwaste

from the containment

sump.

Inspector interviews revealed that

the operators

did not perform any control

board walkdowns after this point.

No further discussions

regarding

the containment

spray

system were held until

after the reactor trip.

It is significant to note that the operations

crew

1

I

j

-11-

did not investigate

the work being performed

by the

18C technicians

even

though they were just outside the control

room.

At approximately

10:07 a.m.,

the

SO isolated

the

1 blowdown line.

At this

time, the operators

did not observe

a change

in the rate of increase

in the

containment

sump level.

The third reactor operator

determined that the leak

rate

was about

50 gallons per minute

(gpm).

At approximately the

same time,

the assistant

and the

SS again verified that they did not have

any

indication of an

RCS leak.

The Assistant

SS then decided to make

a

containment entry to determine

the source of the leak.

At approximately

10: 16 a.m,,

the

SO isolated

blowdown from

2 and the

operators

observed

sump level rising more rapidly.

Based

on this information,

the

SO reasoned

that isolation

oF the blowdown increased

system pressure,

thereby increasing

the leak rate.

As

a result,

the control

room operators

decided

to open the

blowdown isolation valves

and align the blowdown system

for normal operation.

At approximately

10:35 a.m.,

the Assistant

SS exited the control

room to

participate

in the briefing for the containment entry.

Prior to entering the

containment,

the assistant

SS returned to the control

room and

was

informed

that the leak rate remained

at about

50 gpm.

The sssistant

and three other

personnel

entered

the containment

at approximately

11:08 a.m.

A reactor trip

occurred

at approximately

11: 15 a.m., shortly after the

team entered

the

containment.

At the

same time, the personnel

in containment

heard

a loud

bang,

which was the failure of the Unit 2 Reactor

Coolant

Pump

1B electrical

enclosure

box.

When the assistant

SS called the control

room

seeking further directions,

the

SS directed

him to continue looking for the

source of the leak.

The personnel

in containment

then identified that water was coming out of the

CS header

at the

120 foot elevation

and notified the control

room.

Approximately the time that the source of the leakage

was identified by

personnel

in containment,

Unit

1 operators

arrived in the Unit 2 control

room.

The Unit

1 operators

noted that the Train

B CS isolation valve (SIB-UV-671)

was

open

and

announced

that fact to the Unit 2 crew.

Simultaneously,

the

personnel

in containment notified the Unit 2 control

room of the source of the

leak.

At 11:31 a.m.,

the third reactor operator

closed Train

B

CS isolation

Valve SIB-UV-671.

With only minor exceptions,

all other plant systems

responded

as expected

and

the operators

followed the emergency

operating

procedures

in order to maintain

the plant in hot standby conditions.

3.4

NRC Investi ation of Human Performance

As ects of the Event

3.4. 1

Analysis of Human Performance

During the Event

The licensee

was in the process

of "re-engineering" its organization

and

had

implemented

several pilot programs

to evaluate

changes

in both work and

f

J

I

-12-

resource

allocations.

In the case of the replacement

of Relay Kill, the work

instructions,

the method of work allocation,

and the areas of work assignments

had all recently

been revised.

However,

management

expectations

regarding

the

responsibilities of plant staff related to these

changes

were not effectively

communicated

to the individuals involved in the event.

Interviews revealed

that both operations

and maintenance

staffs were unclear

as to their

responsibilities

in the conduct of maintenance activities.

Specific areas of

confusion

included the

use of the SIN, duties

and responsibilities

of the

dependent

and

independent

workers,

and which department

was responsible

for

notifying management

of rescheduled critical work.

Both the maintenance

and operations staff made erroneous

assumptions

and

became

locked into them.

I&C Technician

1 was'convinced

that

he was to work

on Train "B" and the operating

crew believed the leak was associated

with the

SG blowdown lines.

In both cases,

a questioning attitude

and independent

verification of assumptions

could have prevented

the inadvertent

opening of

the

CS isolation valve and subsequent

reactor trip.

3.4. 1. 1

Work Scheduling

In the area of work allocation,

the licensee's

expectation

was that the unit

scheduling staff should

be informed when the work group supervisor

moved

up

previously scheduled

work.

Therefore,

the

I&C foreman's decision to move

up

the scheduled

date

from the original date in July without informing the unit

scheduling organization

was not in accordance

with the licensee's

expectatio'n.

Discussions

with members of the maintenance staff indicated that the

guidelines for rescheduling critical work are not well understood.

, Additionally, the re-engineering

group

has

a scheduler

who must interface with

the existing unit scheduling organization during the transition to the

new

organization.

Confusion regarding

the

scope of the re-engineering effort and

responsibilities

for the individuals participating in the pilot program

may

also

have contributed to the improper handling of the change

in schedule for

the Relay

K111 replacement

work.

3.4. 1.2

Work Order Weaknesses

A contributing factor to the

I&C technicians

working on the wrong relay was

the inclusion of Train

8 specific'instructions

in the work package,

although

only Train A work was to be done.

Technician

1 stated that

he was convinced

that

he would be working on Train

B in part because

some of the pages

specifically addressed

components

in Train B.

The inspector

noted that

equipment identifiers at Palo Verde contain both the unit and train of the

component;

however,

the information is imbedded in an alpha-numeric

character

string.

The train is not readily apparent.

Work package

cover sheets

do not

specifically highlight which unit or train is involved and color coding is not

used

in the

WOs to designate

the affected train,

as is the practice at

some

facilities.

The

WO did not include instructions to verify that work was being

done

on the

correct piece of equipment

as

was the licensee's

previous practice.

The

I&C

I

f

0

1

-13-

technicians

were aware that the instructions

were not included in the work

package;

however,

members of the operating

crew stated that they thought

equipment verification was still included in the work package.

The operations

crew involved in this event were unaware of the revision to the maintenance

work instructions

which changed this requirement.

One of the technicians

involved in the event stated that the event might have

been

avoided

by the

inclusion of the verification step in the work instructions.

Operations

personnel

also noted that previous work involving critical or

sensitive

equipment

sometimes

had

a step

on the

WO to conduct

a prejob

briefing with specified

members of the operations staff such

as the

STA.

The

work package for replacement

of Relay

K111 did not require

such

a prejob

briefing with operations'n

this case,

the

STA first became

aware of the

work on the containment

spray

system after the reactor trip.

Therefore,

his

ability to function in an oversight role was compromised

by his lack of

knowledge regarding

the Relay

K111 replacement.

3. 4. 1. 3

S IM Use

0

In February

1993,

the licensee

issued

the

SIM and,

although the personnel

involved in the event were

aware of the existence

of the SIM, none of them had

a clear idea of the purpose of the SIM. 'nterviews

revealed that the Unit'2

operating

crew did not understand their responsibilities

regarding the SIM,

and the

I&C technicians

were

unaware of the existence of the document.

The

inspectors

noted that the

SIM defined evolutions that may, if incorrectly

conducted,

cause

an

ESFAS actuation

as sensitive

issues.

These evolutions

would require plant management

approval

and

a detailed prejob briefing prior

to starting the work.

Licensee

management

stated that the operations staff

were expected

to question

any work on critical systems

that was not

prescheduled

and to discuss

such work with plant management

before authorizing

this type of work activity.

This expectation

was not understood

by the

licensee staff involved in the event.

No one

on the operating

crew notified

senior plant management

about the replacement

of Relay

K111 prior to work

authorization,

Interviews revealed that the operations

crew relied

on the

step in the

WO to determine if the work was

a sensitive evolution and,

therefore,

required

a formal prejob briefing.

In this case,

the operations

crew did not check whether

an evolution was covered in the SIM, and relied

on

the

WO to call it to their attention.

3.4. 1.4

Work Package

Review

Licensee

management

expected

both

IKC technicians

to review the work package

and independently verify the work and actions of the other.

This expectation

was not met by the two ILC technicians

involved in the event.

The work was

divided between

Technicians

1

and 2,

and Technician

2 did not review the work

package until after the reactor trip.

A clear definition of the work order

review responsibilities of an "independent

worker" and

a "dependent

worker"

was not effectively communicated

to the two ILC technicians

in this case,

l

-14-

3.4. 1.5

Communications

between

the

members of the operating

crew and the two

I&C

technicians

were not detailed

enough to identify the misunderstanding

of which

train was to be worked on.

The inspectors

noted that communications

among

operations staff were

much more detailed

than those

between operations

and

maintenance

personnel

during the event.

Both groups

understood

that they were

working on Relay Kill for a

CS isolation valve,

but

no one specifically

mentioned

the affected train.

A contributing factor was the understanding

on

the part of the operators

that the work instructions

included

a step to verify

what equipment

would be worked on.

Another contributor to the confusion

was

the inconsistency

in identifying

CS Valves SIB-UV-671 and SIA-UV-672, with

regard to train designation with lower numbers usually associated

with

Train A, except

in this case.

During the initial stages

of the event, briefings of the control

room staff,

similar to those routinely conducted

in the plant specific simulator during

training sessions,

were not held.

Interviews revealed that,

when control

room

briefings were held in the latter stages

of the event,

the content

included

assumptions

as well

as facts.

The assertion

that there

was

a leak in

containment

apparently

due to manipulations of the

SG blowdown system

reinforced the crew's conviction that the leak was related to the

blowdown

system.,

This may also

have contributed to the operators

not walking down the

other control panels.

It was not until the call from the personnel

in

containment,

simultaneous

with the identification of the open valve by

individuals from Unit 1, that the control, room staff became

aware that the

Train

B

CS isolation valve was open.

When asked

whether they had

been trained

on the identification of leaks in containment,

several

Unit 2 operators

stated

that they had

been

and that it had always

been

a precursor to either

a main

steam, line break or

a loss of coolant accident

in containment.

It is unclear

whether this also contributed to the operators

overly focusing

on the blowdown

system.

3.4. 1.6

Lack of Effective guestioning Attitude

Members of the operations staff were overly focused

on the blowdown system

as

the source of the containment

sump level increase.

Since the last evolution

conducted

immediately before receiving the

sump level high alarm involved the

blowdown system,

they suspected

a leak in one of the blowdown control valves.

Convinced that the

IKC technicians

had disconnected

Train A Relay

K111

20 minutes before receiving the

sump alarm,

and that the Train A CS isolation

valve was de-energized

in the closed position,

the operations

crew did not

verify the status of equipment

on that portion of the control board,

Hembers

of the operating

crew did not maintain

a questioning attitude

and did not

reassess

the condition of all plant systems.

Hembers of the operations staff

offered that they

may have

checked

the status of the containment

spray

system

if they

had

been notified at the time Relay

K111 was disconnected.

No member

of the operating

crew noticed Technician 1's entry into the control

room

immediately after Relay Kill was disconnected.

Further,

the operations

crew

'

I

-15-

did not investigate

the work being done

by the technicians

even

though they

were just outside

the control

room.

3.4. 1.7

"Re-Engineering" Considerations

The inspectors

noted that the streamlining effort included in the licensee's

re-engineering

program

had resulted

in removal of work instructions

deemed

to

be unnecessary,

provision for assignment

of work by shop foremen,

and

reassignment

of work crews.

In the case of the work package,

the step to

verify that work was being perFormed

on the correct

equipment

was not

included.

The inspectors

noted that,

although

the, licensee

is conducting

a site-wide

"re-engineering" effort, additional attention

should

be taken in revising

instructions,

procedures,

and work processes.

It's important to understand

how and

why the instructions,

procedures,

and work processes

were developed

before deleting or modifying specific items.

Specific procedural

steps

may

have

been

included

as

a result of previous incidents,

and removal of these

steps

may remove

a barrier to failure.

Similarly, for work practices

the

requirement

to notify management

of schedular

changes

for work on critical"

equipment

may have

been the result of a prior event at the plant.

There

should

be

a careful consideration

of the balance

between facilitating greater

work process efficiency and assuring that work quality is maintained.

In

addition,

the licensee

should assure

that the expectations

for plant staff

have

been effectively communicated.

This should include

a method to determine

whether these

expectations

are in fact being met.

3.5

Evaluation of the Licensee's

Investi ation

The licensee classified

the event

as serious

and initiated

a formal Category

2

investigation.

The station operating

experience

department

formed

an

investigation

team that included

management

personnel

from the operations,

maintenance,

and engineering

organizations.

The team gathered

the relevant

facts of the event, identified pertinent restart

issues,

and conducted

several

management

review team meetings to review the event

issues

and findings of the

investigation.

Although the licensee's

event investigation

was not complete at the

end of the

inspection,

the licensee's

event

and causal

factors diagram

was reviewed to

assess

the scope

and findings of the licensee's

investigation.

The inspectors

found that the licensee's

investigation

was thorough

and objective.

Almost

all of the concerns identified by the inspectors

had been'aptured

in the

licensee's initial investigation

summary.

The investigation

team

had also

captured

many of"the recommendations

and lessons

learned

suggested

by the

individuals involved in the event.

The licensee

took immediate corrective actions

as

a result of the

investigation,

which included:

J

i

I

'0

-16-

Conducting

Maintenance

Department

stand-down

meetings

which emphasized

communications

and prejob briefings,

Initiating a formal communications

standards

team to evaluate

the

communication

problems

and develop

a standard

practice,

~

Writing Operations

department

night orders

and conducting briefings,

Initiating a re-assessment

of the "re-engineering"

process,

and

~

Counseling

and issuing positive discipline to the

I&C technicians.

The licensee

stated that it intended to closely scrutinize its current plans

for "re-engineering"

to assess

whether the

scope of the effort should

be

modified.

4

ELECTRICAL PENETRATION ASSEMBLY PERFORMANCE

4.1

RCP Electrical Penetration

Assembl

The Unit 2

18 electrical

(2ENANZ44) is

a medium voltage

manufactured

by Conax

and is located

on the

100 foot level of the

containment.

The electrical

assembly

contains three

1500

MCM bus

bars for the three-phase

13.8 kilovolt (kV) power to

RCP 18.

These

bus bars

are connected,

via 1500

MCM connectors

and ceramic terminal bushings,

to bare

terminal lugs.

The attached electrical

power cables that go to the

18

motor are three-conductor,

250

MCM, shielded

cables

rated for 15 Kv.

A

termination junction/enclosure

box is attached

to the

end of the electrical

assembly

inside containment.

The power cables

run From the

terminal

lugs

up through holes in the top cover of this enclosure

box'.

1. 1

Event Circumstances

and Assembly

Damage

As

a result of the inadvertent

opening of the

CS isolation valve

and the

partial

CS inside containment,

borated water leaked into the, enclosure

box and

onto= the bare terminal lugs.

This caused

arcing inside of the enclosure

box

and eventually resulted

in

a Train

A phase-to-ground

fault followed by a

phase-to-phase

fault.

18 tripped

on overcurrent

as

a result of the phase-

to-phase fault.

The maximum asymmetrical fault current

was 34,890

amperes

(amps).

The enclosure

box blew open

and suffered extensive

damage

as

a result

of the temperature/pressure

increase

caused

by the arcing

and the fault.

There were

no missiles

developed

as

a result of the explosion;

however,

many

of the enclosure

box cover fasteners

were missing

and the cover panels

had

significantly separated

along th'e'edges

from the

box frame.

Upon inspecting

the penetration

aFter the fault, the licensee

noted extensive

damage to the enclosure

box and its internals.

The enclosure

box frame was

bent

and the front and side covers of the

box were

bowed outward, with over

70 percent of the fasteners

missing

as

a result of the explosion.

The top and

,

J

'

f

1

e

-17-

bottom covers of the enclosure

box were also

bowed.

The entire enclosure

was

carbonized,

including the melamine insulating spacer

and the heatshrink tubing

over the ceramic terminal

bushings of the penetration

assembly.

The power

cables

inside the enclosure

box exhibited

damage

ranging from carbonized

stress

cones

to splitting of the stress

cones.

In addition,

the )500

HCH

connectors

and the cable connectors

were damaged.

4. 1.2

Evaluation of Original Design Adequacy of the

RCP Penetration

During the inspection,

the inspectors

reviewed the original design of the

electrical

enclosure

boxes

and of the Class

IE electrical

enclosure

boxes.

The termination enclosure

boxes for the

electrical

penetrations

are not environmentally qualified.

However,

the

enclosure

was originally designed

to be drip-tight

(NEHA type 4) to prohibit

direct spray

impingement

and water intrusion into the

box and onto the

conductors.

By design,

each entry point into the

box is sealed

to

prevent moisture intrusion,

and all of the covers

have gaskets.

The enclosure

box for RCP

18 has cable entering

from the top.

Although the cable

hubs

located at the top of the enclosure

box should

have

been

sealed,

there is

evidence that borated water

may have leaked

by the hubs.

However,

upon

inspecting

the enclosure

box, the licensee

determined that the root cause of

the water intrusion

was

due to field installed,

ground strap cable clips that

were bolted through the top cover of the enclosure

box without any sealant.

The lack of sealant

around

these

bolts negated

the manufacturer's

drip tight

qualification of the enclosure.

The inspectors

questioned

whether or not the

same type of water intrusion

could occur within Class

IE electrical

penetrations.

The licensee

confirmed

that all non-Class

IE,

as well as all of the Class

IE, penetrations

in

containment,

have drip-proof,

NEHA Type

4 enclosures

in order to prevent

faults caused

by water intrusion,

and that the Class

IE penetration

assemblies

~are environmentally qualified without taking credit for the waterproof

enclosure

box.

The Class

lE penetrations

are environmentally qualified with

Raychem splices

covering the terminal

lugs

and other connections

and were

tested without enclosure

boxes.

As

a extra measure,

the enclosure

boxes

are

designed for bottom cable entry only with no holes in the top or sides.

Starting in June

1992,

the licensee

performed

a complete

walkdown of these

environmentally qualified penetrations

and verified that the configuration of

the enclosure

boxes

was in compliance with the qualification requirements.

The inspectors

concluded that the Class

lE and non-Class

lE penetrations

were

designed, not to be susceptible

to faults caused

by water intrusion into the

enclosure

box and, therefore,

properly installed penetrations

should not be

adversely

affected

by containment

spray.

The licensee's

design of electrical

assemblies

conforms to

Regulatory

Guide 1.63,

Revision 2, "Electric Penetration

Assemblies

in

Containment Structures for Light-Water-Cooled Nuclear

Power Plants,"

which

endorses

IEEE Standard

317-1976,

"IEEE Standard for Electric Penetration

Assemblies

in Containment Structures

for Nuclear

Power Generating Stations."

The regulatory guide states

that the electrical

should

be designed

t

i

-18-

to withstand,

without loss of mechanical

integrity, the maximum fault current

versus

time conditions that could occur

as

a result of single

random failures

of circuit overload devices.

As

a result, this electrical

is

provided with redundant

(primary and backup)

conductor overcurrent protective

devices.

Primary protection is provided

by the individual

1B load circuit

breaker

(2E-NAN-S02L) and

backup protection is provided

by the main bus feeder

breaker

(2E-NAN-S02A or 2E-NAN-S04B).

Additional industry guidance

concerning

the coordination

between

the primary and backup overcurrent protective devices

is contained

in ANSI/IEEE Standard

741-1986.

The licensee

has followed the

guidance

in Regulatory

Guide 1.63

as amplified in ANSI/IEEE Standard

741-1986.

Proper primary and

backup penetration

protection device coordination

and

response

times

has

been

demonstrated

by the licensee

per Bechtel

Calculation

13-EC-NA-220 and the corresponding 'coordination

curves for the

primary and backup protection devices.

During the event,

the fault was picked

up by the primary overcurrent

protection device.

The fault current energized

the instantaneous

element of

the

250/251M phase

overcurrent relay which has

an instantaneous

trip setpoint

of 6000

amps.

As

a result,

Breaker

2E-NAN-S02L relayed out within five

cycles.

The relay/breaker

response

time of five cycles

was within the rated

timing characteristic

of this combination.

The breaker coordination for the

event

was evaluated

by licensee

engineering

personnel

and concluded to be

adequate.

The maximum symmetrical fault current of approximately

24,000

amps

that existed for a short time was below the current/time

thermal capability

curve for the penetration,

indicating that the fault did not damage

the

penetration.

The inspectors

were concerned

that the fault might have

reduced

the qualified life of the penetration.

However,

Conax confirmed that the

fault experienced

was within the penetration

test values

and

was under the

damage

curve.

Therefore,

the licensee

and

Conax concluded that the event

would not have

an impact

on the 40-year qualified life of the penetration.

4.2

Evaluation of Testin

and Corrective Actions

4.2. 1

Electrical Penetration

Assembl

The licensee

performed

a local leak rate test

on the electrical

and determined that the containment

pressure

boundary integrity was not

breached

as

a result of the fault and explosion.

The leak rate

was less

than

10 standard

cubic centimeters

per second

and, therefore,

met the leak test

acceptance

criteria.

In order to verify the electrical integrity of the

penetration,

the vendor technical

manual

recommended

performing

a megger test

at

a minimum value of 500 volts with a minimum acceptance

value of

1,000

megaohms.

The licensee

performed

a

5

kV dc megger test

on the

and obtained

a resistance

reading of 100,000

megaohms.

Based

on

the results of the local leak rate test

and the megger test,

the licensee

concluded that the penetration

was not degraded

as

a result of the fault and

resulting explosion.

Due to the visible damage of the

Raychem stress

cones,

the licensee

also

performed

a dc high potential test of the cable

from the penetration

to the

)

l

1

t

-19-

18 motor.

Components

in the enclosure

box such

as the bushings

and

terminals

were cleaned,

and the

damaged

stress

cones

were replaced.

4.2.2

1B Motor

The licensee

performed

a visual

examination of the

RCP motor and completed

a

doble test at the

RCP motor leads.

The licensee

compared

the doble test

results

to previous doble results

and found no evidence of degradation.

Other

tests

included

a

5 Kv dc megger test of the

RCP motor with the motor power

leads

disconnected,

a polarization

index test of the motor,

and

an over-

voltage test of the

1B surge capacitors.

A 5 Kv dc megger test of the

cables

between

the penetration

and the

1B motor was also completed.

The

results of these tests

met all of the acceptance

criteria

and the licensee

concluded that the motor

and leads to the motor from the penetration

were not

degraded

or damaged

as

a result of the event.

4.2.3

Breaker

The licensee

inspected

the circuit breaker/switchgear

cubicle that tripped

on

overcurrent

and

found

no evidence of degradation

or damage.

A 5 Kv dc megger

test of the cables

between

the penetration

and the switchgear cubicle was also

completed, with satisfactory results.

4.2.4

Walkdowns

and

Ins ections

Engineering

performed

a complete

walkdown of the electrical

components

in

containment that appeared

to have

been

subjected

to the inadvertent

CS.

The

components

that were identified during the walkdowns were inspected for

internal

leakage

and

damage.

There

was evidence of water leakage

into one

junction box and into one nozzle

dam panel

located

in the affected

area;

however,

there

was

no evidence of damage

found.

During an inspection of the other

RCP enclosure

boxes,

the licensee

found that

the

1A electrical

enclosure

box also

had ground strap cable

clips bolted through the top cover.

There

was evidence of moisture intrusion

into the

1A enclosure

box and of minor arcing inside the box.

The

2A

and

2B electrical

enclosure

boxes did not have field installed

bolts in the top cover

and did not show signs of moisture intrusion.

Corrective actions

included sealing the cable

hubs in the top cover of all of

the

RCP electrical

enclosure

boxes

in each unit and sealing

around

the bolts that were installed in the two enclosure

boxes.

The licensee

performed

walkdowns of all other electrical penetration

enclosure

boxes in all three units to verify that there

were

no bol'ts or other objects

protruding through the top of any penetration

enclosures,

The inspections

revealed that there

were

no other non-Class lf enclosure

boxes that

had cable

entrances

through the top cover.

However,

some of the boxes did have

conditions that indicated that they may not

be completely drip-tight.

The

licensee identified and replaced

missing screws

on the top cover of three

non-

-20-

Class

1E enclosure

boxes

in Unit

2 and sealed

other components

that protruded

through the top cover in three other non-Class

1E enclosures.

4.3

Conclusions

The inspectors

concluded that the licensee

adequately

tested

the electrical

assembly

and all of the other separate

components

in the

1B

power circuit that could have potentially been

damaged

or degraded

as

a result

of the fault.

In addition,

a final megger test of the entire circuit from the

switchgear cubicle

up to and including the

1B motor provided additional

assurance

that the integrity of the entire

power circuit was not

compromised'he

licensee will perform

a doble test

and polarization

index test

from the

switchgear cubicle to the

1B motor during the next Unit 2 refueling

outage.

The doble test results will be compared

to historical test data in

order to further evaluate

any possible degradation

to the power circuit.

The inspectors

also concluded that the licensee

promptly and adequately

inspected

and evaluated

the effect of the inadvertent

containment

spray

on all

other components

in the affected

area.

The licensee

performed

a detailed

walkdown

and inspection of the electrical

enclosure

boxes

in all

three units

and completed

the necessary

corrective actions in order to assure

water tightness of the boxes.

5

OTHER CONPONENTS

POTENTIALLY AFFECTED

5. 1

Licensee

Walkdowns

and

Ins ections

As

a result of the partial containment

spray,

licensee

personnel

performed

walkdowns of the areas

inside containment

which had

been wetted

down on the

80,

100,

and

120 foot elevations

~

They noted for followup action

and

evaluation

those

components

(electrical

and mechanical)

which had indications

of being

sprayed

by the borated water from the

RWT (boric acid crystals

evident).

The components

inspected

and reviewed included junction boxes,

emergency lights, instrument racks,

valves,

cable pull boxes,

cable,

Thermo-

Lag, snubbers,

and pipe insulation.

The licensee

used the evaluations

of a

previous containment

spray actuation

event

(EER 91-SI-088)

in Unit 3 in 1991,

which occurred while the unit was operating

at

100 percent

power.

In certain cases,

equipment

enclosures

were opened to determine

the extent of

water entry.

If signs of water or boric acid crystals

were evident,

licensee

personnel

dried

and cleaned

the equipment.

The licensee

evaluated

the various

components

affected

and documented their evaluation

in

a memorandum

dated

June

1,

1994.

The licensee

concluded that,

except for the

RCP IA and

1B

electrical

connections,

no damage to containment

components

had

occurred

as

a result of the containment

spray event.

In a few cases,

some

boric acid crystals

were cleaned

and removed,

but in no case

was there

a need

for replacement

of components.

j

I

l

I

l

-21-

5.2

Conclusions

The inspectors

conducted

tours of containment

on the day of the spray event

and also during the week following the event.

The inspectors

observed

the

area

which had

been wetted

by the spray,

the equipment that was potentially

affected,

and licensee

personnel

performing walkdown inspections.

The items

identified to be potentially affected

by the licensee

were in agreement

with

the inspectors'bservations.

The licensee's

evaluation of the negligible

affects

from the spray

was reviewed

and the evaluation

appeared

appropriate.

It was noted that there

have

been

no indications of any equipment

problems

following a Unit 3 inadvertent

containment

spray actuation

event in 1991.

l

j

,

I

ATTACHMENT 1

1

PERSONS

CONTACTED

1.1

Licensee

Personnel

I

t

R

J

R

M.

D

R.

B

M.

D

J

D

G

J

R

G

p

D.

Adney, Plant Manager,

Unit 3

Bailey, Vice President,

Nuclear Engineering

Flood, Plant Manager,

Unit 2

Friedlander,

Manager,

Unit

2 Work Control

Garchow, Director, Site Technical

Support

Gouge, Director, Plant Support

Grabo,

Supervisor,

Nuclear Regulatory Affairs

Hypse, Acting Manager, Electrical

and

IEC Engineering

Kanitz, Senior Engineer,

Nuclear Regulatory Affairs

Levine, Vice President,

Nuclear Production

Mauldin, Director, Maintenance

Overbeck, Assistant to Vice President,

Nuclear Production

Reynoso,

Incident Investigator,

Nuclear Assurance

Roberson,

Senior Engineer,

Nuclear Regulatory Affairs

Rogalski,

Engineer,

Nuclear Regulatory Affairs

Seaman,

Director, Nuclear Assurance

Shanker,

Department

Leader,

Nuclear Assurance

Wiley, Manager,

Unit 2 Operations

Withers,

Primary Discipline Engineer,

Electrical

Engineering

1.2

Other Personnel

.* F. Gowers, Site Representative,

El

Paso Electric Company

R. Henry, Site Representative,

Salt River Project

1.3

NRC Personnel

F. Burrows, Electrical

Engineer,

P.

Eng, Senior Operations

Engineer,

J.

Ganiere,

Intern,

K. Johnston,

Senior Resident

Inspector

A. MacDougall, Resident

Inspector

H.

Wong, Chief, Reactor Projects

Branch

F

Attended Exit Meeting

on June

3,

1994

2

EXIT MEETING

An exit meeting

was conducted

on June

3,

1994.

inspectors

summarized

the scope

and findings of

acknowledged

the inspection findings documented

did not identify as proprietary

any information

the inspectors.

During this meeting,

the

the report.

The licensee

in this re'port.

The licensee

provided to, or reviewed by,

,

I

ATTACHMENT 2

ACRONYHS

amps