ML17311B077

S urious Actuation

On June

13, at approximately Il:20 a.m., control

room operators

received

a

high priority trouble

and engine trip alarm for the Train

B EOG,

and

an

automatic start of the Train

B spray

pond

pump

and the Train

B

EOG building

essential

fans.

Control

room operators

investigated

the alarms

and determined

that the Train

B

EOG had not received

a valid start signal.

The licensee

declared

the Train

B

EDG inoperable

and

began troubleshooting activities.

Control

room operators

subsequently

performed the surveillance test

(ST)

procedure

used to demonstrate

operability of the remaining sources of AC power

when

one

EDG was declared

inoperable,

as required

by TS. 3.8. 1. 1.

The

ST

procedure

required

the licensee

to declare

both trains of a safety-related

component

inoperable if the Train A component

was unavailable while the

Train

B

EDG was inoperable.

The inspector

noted that these

requirements

were

more restrictive than the requirements

of TS 3.8. 1. 1.

During performance of the

ST, control

room operators

noted that the Train

A

essential

cooling water

(ECW)

pump,

the Train A auxiliary feedwater

(AfW)

pump,

and the Train A hydrogen

recombiner

(HR) were out of service for

maintenance

when the Train

B

EOG was declared

inoperable.

The shift

supervisor

subsequently

declared

both trains of FCW,

HR and

AFW inoperable,

and entered

TS 3.0.3

and Action b of TS 3.7. 1.2,

as required

by the

surveillance

procedure.

The most restrictive action statement

required the

plant to be in hot standby within 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

The inspector

noted good

involvement

by o'perations

management

in the review of the

TS and

ST

requirements.

The inspector

asked

the shift supervisor

and the shift technical

advisor

when

they planned to commence

a plant shutdown to ensure that the plant was safely

shutdown within the 6-hour time limit.

The operators

determined that it would

take approximately

3 hours3.472222e-5 days 8.333333e-4 hours 4.960317e-6 weeks 1.1415e-6 months to perform

a controlled shutdown,

and planned to

start

a shutdown at 2:30 p.m.

The inspector

concluded that the shift

supervisor's

actions to initiate

a planned

shutdown

were appropriate.

The licensee

restored all the Train

A equipment at approximately

2 p.m.

and

exited

TS 3.0.3

and 3.7.4.

The inspector

observed

good coordination

between

operations

and maintenance

to promptly restore

the Train A components.

The licensee

determined that

a faulted

speed

probe for the Train

B

EOG sent

an

erroneous

signal

to the start circuitry that the'engine

was running which

caused

the essential

fans

and spray

pond

pump to start.

The

EOG subsequently

received

a trip signal

due to actual

low lube oil and cooling water

temperatures

because

the engine

was not running.

The licensee

found

a crack

in the

amphenol

connector for the

speed

probe that caused

an electrical

short

in the circuit.

The licensee initiated

a condition report/disposition

request

(CRDR) to determine

the cause of the failure and to identify appropriate

corrective actions.

The inspector

observed

good troubleshooting efforts

and

agreed with the licensee's

conclusion that the

speed

probe failure initiated

I

the event

and would not have prevented

the

EDG from starting during

an

emergency.

3 OPERATIONAL SAFETY VERIFICATION

(71707)

3. 1

Control of Scaffoldin

Around Safet

During walkdowns of the Unit 2 auxiliary building and the Unit

1 main steam

support structure

on May 25, the inspectors

identified four instances

where

scaffolding in areas

with seismically qualified equipment

had tags

which

indicated that the scaffolding

had not been erected

to seismic criteria.

The

examples

were

as follows:

~

Both Unit

1

AFW pump rooms

had scaffolding erected

to support

modifications to the turbine driven

AFW pump steam drains.

~

Unit 2

ECW pump Train

B room had scaffolding erected

to support

evaluation of the seismic qualification of the

ECW process

radiation

monitors

and associated

piping.

~

Unit 2 120-foot elevation hallway had scaffolding erected.

The inspectors notified the Unit

1 shift supervisor

(SS)

and the Unit 2

control

room supervisor

(CRS).

The inspector

was promptly called

by the Civil

Engineering

Team

Lead

and informed that

CRDR 9-5-560

had

been initiated

and

that walkdowns of scaffolding in all units would be performed.

The licensee

subsequently

found that scaffolding

had

been erected

in the Units

1

and

3

ECW

Train

B pump rooms which was tagged

as nonseismically qualified.

The inspector

was informed the following day by the Site Shift Manager

(SSM)

that the Operations

Director had established

an investigation

team.

The

licensee

determined

that in all but two instances,

had

been

erected

to seismic criteria established

in licensee

Procedure

3ODP-9WP11.

The

two exceptions

were scaffolding in the Unit

1

AFW rooms

and the Unit 3

ECW

Train

8 pump room.

The scaffolding

was modified to meet the procedure

specifications.

In addition, licensee civil engineers

performed calculations

of the as-found conditions of the scaffolding

and determined that it would not

have

damaged

seismically qualified equipment during

a seismic event.

The inspector

reviewed the evaluation

and agreed with the licensee

that the

incorrectly installed scaffolding

had minimal safety significance.

Therefore,

the failure to follow the seismic criteria for installing the scaffolding

constitutes

a violation of minor significance

and is being treated

as

a

Noncited Violation, consistent

with Section

IV of the

NRC Enforcement Policy.

3. 1. 1 Corrective Actions

The licensee

performed

a cause

evaluation

and identified several

areas of

concern:

~

In some instances,

the carpenters

erecting

had applied

the seismic criteria of the component

to be worked on to the

I

I,[

f

scaffolding.

In the case of the scaffolding in the

ECW pump rooms,

work

was to be performed

on the non-seismically qualified process

radiation

monitors

(RU3).

However,

was erected

in close proximity

to seismically qualified

ECW equipment.

~

In the case of the Unit

1

AFW rooms,

had

been erected

during the refueling outage

when the

AFW system

was not required to be

operable.

The modification work order,

which included the scaffolding,

was being tracked

by the control

room as

a mode

change

hold.

However,

after the modifications

had

been

completed

and outage

management

emphasized

work order closeout during plant restart to support

mode

transitions,

the carpenters

closed

the step in the initial work order to

remove the scaffolding

and opened

a

new work order to remove the

scaffolding.

~

Individuals from Nuclear Assurance

Maintenance

had

used the

scaffolding,

and operations auxiliary operators

(AO) had routinely

toured the

rooms prior to the identification of concerns

by the

inspector.

Licensee

management

expectations

for both groups

was that

they should

have identified the scaffolding deficiencies.

~

The licensee identified several

seismic tag deficiencies.

Although the scaffolding issues

appeared

to be isolated to the practices of

one crew,

the licensee

conducted

a "stand-down" with all carpenters

to discuss

the findings and to clarify expectations.

In addition,

the licensee

has

initiated actions to clarify expectations

for Nuclear Assurance

personnel

and

AOs.

The inspector

concluded that the licensee

conducted

a timely and thorough

investigation of the issue

and that the corrective actions

were appropriate.

3.2

Radiolo ical Controlled Area Mat Lifted B

Wind

On May 22, during

a plant walkdown of the Unit 3 yard radiological controlled

area,

the inspectors

observed

a large rubber mat

become airborne

as

a result

of a sudden burst of wind.

The mat traveled

15 to 30 feet

and landed

on

an

adjacent radiological controlled boundary fence.

The inspector

noted that the

area

was unattended

and notified Radiation Protection

personnel.

The mat was

a rubber sheeting material,

approximately

90 by 90 feet in length,

used

as

a temporary chemical

cleaning

berm.

The berm was originally setup

by

contracting

personnel

for steam generator

chemical

cleaning which had

been

performed during the Unit 3 refueling outage

in April 1994.

The contractor

was in the process

of dismantling the

berm

and

was awaiting

a radiological

survey of the berm before it was removed.

They had dismantled portions of the

berm which were holding the mats

down.

The inspector estimated

that the

berm was within 100 feet of the essential

t

spray ponds.

The mat had

been carried north

and

away from the spray ponds.

However,

the inspector

concluded that the licensee

had not been sufficiently

i

sensitive

to the potential that the mat could have

been carried into the spray

ponds.

The inspector discussed

the potential of the mat landing in the spray

pond

with the contracting supervisor

and the system engineer.

They stated that

during setup

and tear

down periods, it had

been

expected

that the berm area

was not to be left unattended.

The system engineer

discussed

barriers that

are set in place to prevent material

from entering the spray

ponds

and the

procedure for controlling potential

tornado

borne missiles

in the outside

areas.

In response

to the inspector's

concerns,

the licensee's

project manager for

the steam generator

chemical

cleaning project conducted

meetings with the

contractor which had set

up the

berm area.

The licensee

discussed

its

expectations

regarding

coverage

oF tear-down activities 'and the necessity for

ensuring that potential

hazards

are secured.

The inspector

found these

actions to be appropriate.

3.3

Loose Electrical

Connections

on Safet -Related

E ui ment in the Auxiliar

~Bui1 din

On May 19, the inspector identified loose connections

on conduit pull boxes

and motor-operated

valves in the Unit 3 west mechanical

room.

The

inspector

also identified three conduit pull boxes that

had incorrectly

installed gaskets

and three junctions

boxes with missing screws

in the Unit I

auxiliary building.

The licensee

determined that these conditions did not

impact operability of the associated

safety related

equipment

because

any

moisture that entered

the system would go into the junction box and not the

end device (e.g.,

motors, transmitters,

solenoids,

etc.).

However,

the

licensee

concluded that these conditions did not meet the specifications for

installed conduit,

and initiated work requests

to correct the deficiencies.

The inspector

concluded that although the loose electrical

connections

in

Unit 3 and the material deficiencies identified in Unit I were not operability

concerns,

they were indications of poor material condition

and inattention to

detail.

The licensee

decided to discuss

these

problems with electricians

and

emphasize

the need to perform detailed

walkdowns after

an outage to identify

and correct these

types of deficiencies.

The inspector

concluded that the

licensee's

response

was appropriate.

3.3.1

High Energy Line Break

(HELB) Analysis

The inspector

reviewed the licensee's

analysis of a

HELB in the auxiliary

building to verify that the loose electrical

connections

did not adversely

impact the operation of safety related

equipment during this event.

The

inspector

noted that the licensee

calculated

a peak pressure

in the mechanical

room of 'less

than

3 psig from this event.

The inspector

reviewed

the environmental qualification (Eg) program manual

and noted that the

licensee

had done

a study concerning

the sealing

requirements

for electrical

connections

exposed

to

a

HELB environment

and determined that for accident

0

4

I

pressures

less

than

3 psig the connections

do not need to be sealed

to

preclude moisture intrusion provided:

~

The conduit

and junction box systems

connected

to the equipment

were

designed

to facilitate condensate

drainage;

and,

~

The integrity of the equipment

enclosure

was maintained

in accordance

with the tested

equipment configuration (e.g.,

use of proper cover

torque

and cover screw/o-ring

and gasket configuration).

The inspector

noted that the study included actual tests

on various types of

electrical

enclosures

to support

the conclusions.

The inspector

concluded

that the licensee's

study supported its determination that the loose

electrical

connections

in the auxiliary building were not safety significant.

The inspector

conducted

walkdown of the mechanical

rooms in the

Unit

1 auxiliary building to determine if the electrical junction boxes

had

weep holes to provide for condensate

drainage,

and if the covers for the

electrical

devices

(e.g.,

motors, transmitters,

solenoids,

etc)

were

appropriately

secured

and sealed.

The inspector verified that the covers for

the electrical

devices

were properly installed

and that all the safety-related

junction boxes

had

weep holes to allow for condensate

drainage.

The inspector also noted that

Eg engineering

was conducting field

verifications of the installation of electrical

conduit in the auxiliary

building to verify the assumptions

used

in the

HELB analysis.

The inspector

concluded that

Eg engineering

had conducted

a thorough, detailed evaluation of

the effect of a

HELB on the electrical

components

in the auxiliary building

and that the licensee's

actions to conduct field verifications were prudent.

3.4

Leakin

Air Re ulator for Atmos heric

Dum

Valve - Unit

1

On June

4, the inspector

noted

a buzzing noise

from an air regulator

associated

with the pneumatic operator for Unit

1 atmospheric

dump Valve

(ADV)

SGB-179.

18C technicians

subsequently

investigated

the noise

and determined

that the air regulator

appeared

to have

a leak past its diaphragm.

The

SS

declared

ADV SGB-179 inoperable

and II C technicians

replaced

the air

regulator.

Operators

then satisfactorily performed

a post-maintenance

pressure

drop test

on the air system for the

ADV and declared

the

ADV

operable.

The licensee initiated

CRDR 1-5-0145 to determine

the cause of the leaking air

regu'lator.

The evaluation

had not been

completed at the

end of the

inspection.

The inspector will review the licensee's

evaluation

when it is

completed.

3.5

Emer

enc

0 eration

Procedure

Trainin

The licensee

implemented its revised

emergency

operating

procedures

(EOP) at

the

end of the inspection period.

The

EOPs were revised to be consistent

with

Combustion

Engineering

owner's

group guidance

(CEN 152).

The inspector

observed

portions of the "high intensity team" training conducted for each

l

1

~

I,

-10-

crew in preparation for the implementation of the

EOPs.

The inspector

observed

one crew respond to

a steam line break event

and

a steam generator

tube rupture event.

The inspector

noted that the

EOPs

enhanced

crew performance

and allowed for

greater flexibility in responding

to events.

As

an example,

during the steam

generator

tube rupture event,

the crew was able to isolate the faulted steam

generator within 14 minutes

From the start of the event.

In contrast,

during

the March

1993 Unit 2 steam generator

tube rupture event,

operators

isolated

the steam generator

in approximately three hours,

in part due to restrictions

in the

EOPs

used at the time.

The inspector

observed

good trainer performance

in that they closely observed

crew performance

and performed detailed

and critical post-scenario

reviews.

The inspector also interviewed several

crews following the training and found

that they were consistently

pleased

with the

new EOPs.

They found the

procedures

to be easier to use

and allowed them to concentrate

on plant

performance.

3.6

Walkdown of EDGs - Units

1 and

2

On June 8, the inspector

performed

a walkdown of the Units

1 and

2

EDGs.

The

inspector

noted that the housekeeping

of the Unit

1

EDGs was adequate

and that

the housekeeping

of the Unit 2

EDGs has greatly improved, especially

in the

area of the auxiliary skid.

The inspector

noted that starting air cross-tie

Valve DGN-V238 in Unit

1 on

the Train

A EDG was not in its normal position

as indicated

by plant

procedures.

The valve had

been

opened to keep both starting air receivers

pressurized

during air dryer maintenance.

The change of the valve's

normal

position was not documented.

The inspector discussed

the valve position with

the system engineer

and determined that the valve was in the nonsafety-related

portion of the system

and that there

was

no safety significance in leaving the

valve in the open position.

The inspector

informed the Unit

1 operations

department

leader

about the

position of DGH-V238 and the inspectors

concern for the conFiguration control

of the valve.

The operations

department

leader

agreed that there

was

a

configuration control weakness

and attached

a caution tag to the valve to

ensure it was returned to the desired position

upon completion of the

maintenance.

The inspector

concluded that the licensee's

response

was

appropriate.

3.7

EDG Governor Control

Fre uenc

- Unit

1

On May 23,

the inspector

observed

that the Unit

1 Train A EDG was providing

the only source of power to the vital 4160 volt bus,

due to insulator repair

on the associated

startup transformer.

The inspector

noted that the

EDG was

operating

in the isochronous

mode at 60.8 hertz,

and questioned

the operators

about the

EDG frequency

because

the

EDG usually operates

at 60.0 hertz.

The

inspector

was concerned

that the operators

had not questioned

the

frequency

and were unable to effectively respond

to the inspector's

concern

that the observed

indication

may represent.

a problem or an unfavorable trend.

'i

J

1

I

i

li

,

I

-11-

The inspector

noted that

a similar concern

was raised

in February,

1995

(NRC

Inspection

Report 50-528/95-03;

50-529/95-03;

50-530/95-03),

when operators

did not demonstrate

a questioning attitude

when they noted,

but failed to

investigate,

an off-normal indication in safety injection line pressures.

The

inspector

also noted that the licensee

procedures

being used to operate

the

EDG, 410P-lDGOl,

"Emergency Diesel

Generator A," and 410P-lPBOl,

"4. 16kV Class

1E Power (PB)," did not specify that the

EDG should

be operated

at

60 hertz.

The inspector

informed the

EDG system engineer

about the inspector's

observation

and questioned

the performance of the woodward governor.

The

engineer

investigated

the

EDG performance

and responded

that the governor

was

performing

as designed.

The inspector evaluated

the engineer's

conclusion,

agreed that the

EDG was performing

as designed,

and concluded

that the

engineer

had responded

quickly and thoroughly to the inspector's

concern.

The inspector

informed the operations

department

leader

about the

observations

and the licensed

operator

response.

The operations

department

leader

agreed with the inspector's

concern,

and issued

a

memo to all licensed

operators

emphasizing

management's

expectation for control board

awareness

and

for the operators

to monitor and question

any abnormal

indication.

In

addition,

the operations

department

leader

issued

an instruction

change

request

to change

the 4.16kV Class

1E Power procedure

in all three units to

provide guidance

on

EDG frequency control.

The inspector

concluded that the

operations

department

leader's

corrective actions

were appropriate.

4

MAINTENANCE OBSERVATIONS

(62703)

4. 1

AFW

S stem Governor Valve

Unit

1

On May

13

and

May 15, the Unit

1 steam driven

AFW pump turbine tripped

on

overspeed

during uncoupled

runs performed

as pa'rt of postmaintenance

testing.

The postmaintenance

testing

was performed following the replacement

of the

valve stem

and packing.

The licensee

observed that the governor valve failed

to properly respond

to control signals,

resulting in the overspeed trips.

The

inspectors

observed

mechanical

maintenance

engineers

disassemble

the governor

valve,

interviewed maintenance

personnel,

reviewed the licensee's

evaluation

of cause,

and assessed

the licensee's

planned corrective actions.

The licensee

determined that the overspeed trip was caused

by binding of the

governor valve stem,

which prevented

the valve from stroking freely.

The

licensee

determined

that the binding resulted

from deficiencies

in the inner

packing of the governor valve.

The licensee

speculated

that the stuffing box

had not been

adequately filled, resulting in broken carbon

spacers

and cocked

stainless

steel

washers.

The licensee

concluded that the improper assembly

was

caused

by inattention to detail

by the mechanical

maintenance

technicians.

The inspector

concluded that the licensee

had not been rigorous in its cause

eva'luation,

and

had not performed sufficient review to determine that packing

deficiencies

caused

the valve to stick.

Additionally, the inspector

concluded

that weak work instructions

were

a significant contributor to the packing

deficiencies,

and that there

had

been prior opportunities to enhance

the work

instructions.

0

-12-

4.1.1

As-found Condition

The stuffing box for the governor valve contained

the inboard

and outboard

valve packing assembly.

The assembly

provided

a labyrinth seal with the

combination of carbon

spacers

and stainless

steel flat washers,

followed by

the guide bushing

and the retaining ring.

Prior to disassembling

the governor valve,

mechanics

attempted to move the

valve stem.

With the stem in

a horizontal orientation

(as installed),

they

could not move the stem.

With the stem in a vertical orientation,

the stem

could

be moved easily.

Mechanical

maintenance

personnel

subsequently

disassembled

the governor valve stuffing box on May 17,

and found several

of

the carbon

spacers

broken in half, chipped

and pulverized.

In addition,

the

number of sets of carbon

spacers

and steel

washers

removed

was determined to

be one set less

than the

amount

needed

to completely fill the stuffing box.

The licensee

measured

the stuffing box and determined that

22 sets

plus

one

extra washer

was required to completely fill the stuffing box.

The licensee

repacked

the stuffing box accordingly,

and noted

a gap of 0.025 inches

between

the guide bushing

and the retaining ring.

This gap

was determined to be

acceptable.

The postmaintenance

test

was repeated

and the governor valve

responded

appropriately.

4.1.2

Licensee's

Apparent

Cause

Determination

The licensee

determined that the governor valve had failed due to the stuffing

box not being completely full.

This allowed the packing assembly to have too

much free play and the licensee

speculated

that this allowed the steel

washers

to become

cocked.

Additionally, when force was applied to the valve stem,

the

cocked steel

washers

placed additional friction on the carbon spacers,

causing

the carbon

spacers

to break.

The licensee

concluded that this would have

explained

why the valve stem locked

up in the horizontal orientation

and not

the vertical orientation.

Additionally, one mechanical

maintenance

engineer

noted that during

a past

packing job he had cocked

one of the washers.

This was discovered

when

he

noted that there

were washers

and spacers left over when the stuffing box was

full.

This observation

supported

the licensee's

conclusions that

a cocked

washer

may have contributed to the inadequately full stuffing box.

The licensee

determined

that inattention to detail

by mechanical

maintenance

personnel

was the apparent

cause of the failure to completely fill the

stuffing box.

l

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-13-

4.1.3

Licensee's

Planned

Corrective Actions

The inspector

reviewed the licensee's

proposed corrective actions

described

in

the

CROR,

The licensee

planned to implement the following corrective actions

prior to the next refueling outage:

~

Enhancements

to the master work instructions

and preventative

maintenance

(PH) tasks to include more quantitative instructions

on

packing the valve.

~

Additional training for proper assembly of the governor valve stuffing

box using

a mockup of the governor valve.

4.1.4

Inspector's

Review of Cause

Determination

The inspector questioned

the state of the carbon

spacers

found in the past

when disassembling

the governor valve.

Both the mechanical

maintenance

engineer

and the maintenance

technicians

stated that it was

common to find

broken carbon

spacers

during valve disassembly.

However, they noted that it

had never caused

the valve stem to bind.

The inspector questioned

whether

the

discovery of broken carbon

spacers

had ever been evaluated.

The licensee

determined that it had not.

The technicians

also stated that the carbon

spacers

could be easily chipped or

broken

when the packing

was assembled.

The threads

on the

end of the valve

stem

may contain tiny burrs that

may chip the inside diameter of the spacer

during installation or removal.

Whi'le the installation

and removal of the

carbon

spacers

could have resulted

in some chipping,

the inspector determined

that this would not explain the amount of breakage

observed

during

a typical

disassembly.

The inspector

considered

that the licensee

had not been

appropriately sensitive

to previously observed

carbon

spacer deficiencies.

The inspector

reviewed the

PH task work order which controlled the original

replacement

of the valve stem

and packing,

and

compared it with the

instruction provided in the vendor technical

manual

(VTH).

Both contained

instructions for repacking

the stuffing box assembly.

The work instructions

in the

PH task,

which duplicated

the

VTH instructions,

stated

in part:

"Starting with a carbon

spacer,

alternate

stacking the carbon

spacer

and

flat washer until the stuffing box is full and the guide bushing

and

retaining ring can

be installed.

Use additional

washers

to finish

filling the stuffing box.

The complete stack should not be tight,

some

play is required".

The inspector questioned

the mechanical

eng-'neer

as to what the required

amount of play was

and what does it mean

when the stuffing box was full.

The

engineer

stated that it was

common maintenance

practice to fill the stuffing

box until no further carbon

spacers

(0. 125 inch thick) could

be added,

and

then fill the remaining

space with additional

washers

(0.062 inch thick).

As noted previously,

the proper as-left gap

was 0.025 inches.

Using this

value,

the inspector determined

that the as-found

gap with one spacer

and

two

f)

I

0

-14-

washers

missing would be approximately I/4 inch.

The inspector questioned

whether

a I/4 gap could

be

seen

by the mechanics

as providing

a full stuffing

box meeting the ".

. .not tight,

some play.

. ." criteria.

The mechanical

maintenance

team leader concluded that it would have

been too loose.

However,

the team leader

noted that the gap could have

been

measured

between

the last

washer

and the bushing.

During the

Hay reassembly it was noted that the

bushing

shoulder

appeared

to have

eroded

which allowed the bushing to set

lower in the stuffing box, reducing the clearance

between

the bushing

and last

washer.

This also

increased

the gap between

the bushing

and the

snap ring.

The licensee

discussed

the various

ways to measure

the stuffing box gap with

the vendor.

The vendor noted that the total

gap established

was the critical

dimension.

The inspector

concluded,

however, that

had the mechanics

measured

the gap between

the bushing

and the last washer,

and not considered

the gap

between

the bushing

and the snap ring, they could have reasonably

concluded

that the stuffing box was full with some play.

The technicians

stated that they were confident that they had packed

the

stuffing box in accordance

with the work instructions.

After the technicians

assembled

the valve, they checked for valve freedom of movement,

as required

by the work instructions.

However,

the technicians

pointed out that there

was

no quantitative

acceptance

criteria for the valve's length of stroke.

If a

spacer

had

been

cocked, it would have

been possible for the stem to have

some

movement.

The inspector considered

that valve stroke length

was

a significant

parameter

which should

have

been

included in the work instructions.

4. 1.5

Evaluation of Licensee's

Cause

Evaluation

Process

The inspector

noted that the licensee

considered this problem to be

an

"Adverse" condition,

as identified by its

CRDR process.

The event

was

determined

to not be "Significant," primarily due to the fact that it was

discovered

during postmaintenance

testing

and not while the

pump was

considered

operable.

Consistent with its program,

mechanical

maintenance

did

not perform

a formal root cause

evaluation,

and planned only to identify an

"apparent

cause."

The inspector

noted that while the classification of "adverse"

was consistent

with licensee

procedures, it did not appear to be prudent,

in that the

licensee

has experienced

a significant history of AFW turbine overspeed

events.

Additionally, there

have

been several

recent industry events

highlighting concerns

with the governor valve stem

and its packing.

Given

these

events

and the risk-significance of the turbine driven

AFW pump at Palo

Yerde,

the inspector

considered

that it would have

been prudent to have

performed

an in-depth root cause

evaluation.

The inspector

met with licensee

maintenance

personnel

and management

several

times during the inspection period,

and noted that maintenance

personnel

seemed

to be learning

new information from each other.

In addition,

the

inspector consistently

found

new and sometimes conflicting information during

followup inspection.

It also

appeared

that plant management

had

a greater

expectation of the cause

evaluation

than those.-at

the working level

and that

these

expectations

had not been well communicated.

r

i'

-15-

The inspector concluded that,

although the evidence

appeared

to qualitatively

support

the licensee's

conclusion that the stuffing box had

been

inadequately

packed,

these

conclusions

were not supported

by rigorous quantitative

evaluation,

such

as using mockups with a spare governor valve, or specific

measurement

of how much space

was necessary

to allow a washer to cock.

At the exit meeting,

the Director of Maintenance

agreed with the inspector

that communications

could

be improved and that

a more rigorous root cause

evaluation

should

have

been performed.

The licensee

also agreed

to assess

the

adequacy of the

CRDR process

which lead the engineers

to only conduct

an

apparent

cause

evaluation.

4.2

Leakin

Safet

In'ection

S stem Check Valve - Unit

1

On May 18,

a high pressure

safety injection (HPSI) system

check valve in

Unit 1, SIA-V113, failed

a postmaintenance

reverse

flow seat

leakage test.

SIA-V113 was

a 3-inch Borg Warner swing check valve

and functioned

as the

inside containment isolation valve for the

HPSI injection line to reactor

coolant

Loop 2B.

The reverse

flow seat

leakage test

was required after the

valve was disassembled

and inspected

on April 13.

The licensee

subsequently

disassembled

SIA-V113 to determine

the cause of the

excessive

seat

leakage.

The licensee

determined that the bonnet

assembly

was

installed too high which resulted

in the valve disc not being centered

in the

valve seat.

On May 22, the licensee

aligned the valve disc

and seat,

and

SIA-V113 passed

the postmaintenance

seat

leakage test.

The licensee initiated

a

CRDR to determine

the cause of the leakage

and to identify appropriate

corrective actions.

The inspector

reviewed the model

maintenance

procedure for disassembly

and

reassembly of Borg Warner check valves,

reviewed the

VTM, and

had several

discussions

with the check valve engineer.

The purpose of this inspection

was

to determine if the model

maintenance

procedure

was adequate

to detect

and

correct

a check valve alignment problem.

4.2. 1

Vertical Alignment Determination

The inspector

noted that the check valve maintenance

procedure

required the

mechanics

to measure

and record the distance

from the top of the seat

retaining ring to the valve body prior removing the check valve internals.

This measurement

was recorded

as the as-found

Dimension

A.

When the valve was

reassembled,

the procedure

required the mechanics

to thread the seat retainer

into the valve body until the as-left Dimension

A was .the

same

as the

as-found

Dimension

A.

The inspector

noted that using this procedure

ensured

that the valve disc was reinstalled

in the

same vertical location

on the valve

seat.

The inspector

noted that Appendix 0 of the procedure

included instructions for

determining if the valve disc was centered

on the valve seat.

Using these

instructions

the mechanics

could measure

the distance

from the top of the

valve body to the center of the valve seat

and the distance

from the top of

the valve bonnet to the center of the valve disc,

and then calculate

an

'(

I,l

-16-

as-left Dimension

A that would ensure

the valve disc was centered

in the valve

seat.

The licensee

was required to perform the alignment

check in Appendix

D if the

results of previous

seat

leakage

tests

were higher than normal, or if there

were abnormal

wear marks

on the valve seat during the check valve inspection.

The licensee

did not perform the Appendix

D alignment

check

prior to

reassembling

SIA-V113 because

the last reverse

flow test

was well within the

acceptance

criteria and there

were not any abnormal

wear indications

on the

valve disc

and seat.

The inspector

concluded that the licensee

had complied with the applicable

check valve maintenance

procedure.

The inspector also concluded that, prior

to the observed

valve leakage

problem,

and based

on the licensee's

with these

va'ives

and existing vendor manual

guidance,

the procedure

requirements

For ensuring

proper valve assembly

appeared

to have

been reasonable.

However,

based

on the observed

problem,

the inspector

concluded that additional

procedure

guidance

to ensure

proper valve assembly

was warranted.

4.2.2

Corrective Actions

The licensee

determined that differences

in measuring

the Dimension

A

contributed to the valve bonnet for SIA-V113 being set higher than other

similar check valves.

The licensee

subsequently

disassembled

SIA-Yll3 and

calculated

a new Dimension

A using Appendix D.

The licensee

reassembled

the

valve

and set the vertical alignment using the

new Dimension

A and the valve

successfully

passed

the reverse

flow test.

The licensee initiated

an evaluation of whether Appendix

D should

be performed

to verify the proper vertical alignment of the check valves

as part of every

check valve inspection.

The licensee

also planned to disassemble

a spare

check valve

and determine

an optimum method to measure

the dimensions

used to

center

the valve disc

and seat.

The inspector

concluded that these corrective actions

were appropriate.

However,

the inspector

was concerned

that the licensee's initial corrective

actions did not include

an appropriate

acceptance

criteria for when the

vertical alignment of the valve would be adjusted

based

on the calculated

Dimension

A using Appendix D.

The inspector discussed

this concern with the

check valve engineer

who agreed

to include

an action to quantify this

acceptance

criteria.

The inspector

concluded that the licensee's

response

was

appropriate.

4.3

Instrumentation

and Controls

I8C

Technicians

Workin

on Wron

Valve-

Unit I

On March 23,

1995, while in containment

to perform work on pressurizer

spray

Valve 100E,

an

I8C technician

tightened

a jam nut on the booster relay for the

valve, resulting in spurious closure of the valve.

Since

spray Valve 100F was

the valve in service maintaining

RCS pressure,

its closure

caused

RCS pressure

to increase

to 2274 psia.

Operators

had

been maintaining the spray valve open

with pressurizer

heaters

on to provide boric acid equalization

between

the

RCS

1

I

-17-

and the pressurizer.

Operators

were alerted to the condition by a control

room alarm

and stabilized

RCS pressure

by turning off pressurizer

heaters.

The

I&C technicians

returned to the control

room and were questioned

by the

operators

as to what work they had performed

and whether it could have

impacted

Valve lOOF.

The

I&C technicians

stated that they had tightened

the

jam nut and recognized that

an associated

adjustment

screw

may have turned

with the nut.

I&C technicians

returned

to containment

and readjusted

the jam

nut, restoring the operation of the spray valve.

After the event,

the

SS

initiated

CRDR 1-5-133.

The inspector discussed

this work with the

I&C department

leader,

section

leader

and

team leader.

They noted that there

was

an open work order for the

spray valve covering the proper adjustment of the booster relay.

They stated

that the technicians

had not anticipated that tightening the jam nut would

have turned the adjustment

screw.

However,

they concluded that it would have

been appropriate for the technicians

to inform the control

room prior to

performing the adjustment

and they subsequently

counselled

the technicians.

I&C management

also discussed

lessons

learned

from this event with I&C

personnel.

The inspector

found these

actions to be appropriate.

4.'4

Wron

Tor ue Values

Used

on Unit

1

and

2

S ra

Valves

During the Unit

1 refueling outage,

the actuators

of both

RCS spray valves

were replaced with larger actuators.

In addition, the body to bonnet gaskets

were replaced.

The gasket for RCS spray Valve RCE-PV-100E

began to leak

as

RCS pressure

was increased

during the Unit restart.

Mechanical

maintenance

increased

the body to bonnet bolt torque

by

10 percent

in an attempt to stop

the leakage.

When the leakage failed to stop,

the licensee

discovered that

the bolt torque

used

was significantly lower than the appropriate

torque value

for valves

in this service.

The licensee

took concurrent actions to perform calculations to determine

appropriate

torque values

and to contact the vendor,

Fisher Controls.

The

initial torque value

had

been

130 ft-lbs.

The licensee initially calculated

a

torque value of 345 ft-lbs.

The vendor subsequently

recommended

a torque

value of 540 ft-lbs.

The licensee

applied its calculated

torque values to

both Unit

1 spr ay valves.

In addition,

the licensee

entered

both Units

2

and

3 containment buildings with the units at full power to retorque

the spray

valve body-to-bonnet bolts.

They noted bolt movement

in the Unit 2 valves,

which had

been modified during

a February

1995 refueling outage.

However,

no

bolt movement

was noted in Unit 3.

4.4. 1

Cause

Review

The licensee

determined that the following factors contributed to the

inadequate

torque of the Units

1 and

2 spray valve body to bonnet bolts:

~

The licensee

index for the Fisher Controls

VTMs referenced

the wrong

manual for the spray valves.

The referenced

VTM covered

a similar valve

body model, rated for 600 psi,service,

which required only 130 ft-lbs

torque.

The licensee

concluded that

an error was-made

when the

VTM

(Ij

-18-

index was created.

They speculated

that

a note in the vendor drawing

for the valve contributed to confusion in that it indicated the valve

weight of 600 lbs.

~

Fisher Controls identified during its discussions

with the licensee that

the spray valves

were

4 inch bodies with 3 inch ends.

The vendor

drawing did not indicate this fact.

The licensee

subsequently

found

that

a purchase

specification did confirm that the spray valves

were

4-inch bodies.

The vendor

body to bonnet torque specification for

4-inch bodies

was

540 ft-lbs versus

404 ft-lbs for 3-inch valves.

Licensee

work records

indicated that prior to the development of the

VTN

index,

the valves

had

been

torqued to 404 ft-lbs.

~

Fisher Controls identified that the

540 ft-lbs specified for the 4-inch

valves

was

a maximum torque value to use in problem valves.

The

licensee

confirmed this with its

own calculations

in that torque values

this high could produce

high bonnet stresses.

The licensee

determined

that optimum bolt torque would be between

350

and

405 ft-lbs.

~

A chance to identify these

problems

was missed during the Unit 2 outage.

One of the Unit 2 spray valves

had initially leaked after having

been

torqued to

130 ft-lbs.

It was subsequently

torqued to 143 ft-lbs and

stopped

leaking.

t

The inspector discussed

the licensee's

findings with maintenance

engineering

and found them to be appropriate.

4.4.2

Safety Significance of As-Found Condition

The licensee identified that Unit 2 had operated

for greater

than

30 days with

the low spray valve body to bonnet bolt torques.

They performed

an as-found

condition calculation to determine

whether there

had

been sufficient preload

on the bolts to prevent cyclic stresses

during all operational

conditions.

The calculation,

which considered

temperature,

pressure,

and seismic

influence,

determined that while a substantial

amount of preload could be

lost, sufficient joint compression

remained.

Additionally, the licensee

evaluated

the potential for loss of gasket

crush to determine

the potential

maximum body to bonnet

leakage.

They calculated that the maximum leak would

be

a fraction of the makeup capacity for one charging

pump.

The inspector

reviewed the

scope of the calculations

and the calculation

assumptions

and found that they were appropriate.

4.4.3

Corrective Actions

The licensee initiated plans to re-torque all bolts to 375 ft-lbs.

This was

completed

in Units I and

3 with plans to torque Unit 2 bolts in early July.

The licensee initiated

an action to revise the

VTH and appropriate

drawings to

reflect the results of its investigation.

In addition, the licensee

had

asked

the vendor to clarify its conclusion that the torque values for the spray

valves

as indicated

in the

VTN were

maximum values.

This was not clear in the

I

'

0

-19-

VTH and could have

an impact

on the torque applications for other valves.

The

inspector will follow the licensee's

evaluation during routine inspection.

The inspector

found that although the licensee

had initially missed

the

opportunity to identify these

problems in Unit 2, the subsequent

corrective

actions

were appropriate.

The licensee's

review of the issue

and the response

to deficiencies

were thorough

and prompt.

'I

4.5

S ent Fuel

Pool

S acer

Removal - Unit 3

On June

13, the inspectors

observed refueling

and maintenance

services

(RAHS)

personnel

remove spent

fuel rack blocking plates

from the spent

fuel pool.

This design

change

would modify the current checkerboard

mode of storage

to

a

different storage

mode to allow for more fuel assembly

storage

space.

The inspector

noted that the work package

was not present

at the work site.

The inspector questioned

one of the

RAHS personnel

and

was told that the work

package

was back in the

RAHS office.

The inspector

went to the office to

review the work package.

The inspector

noted that the work was being

performed in accordance

with the work instructions

however,

not having the

work package

in the field could lead to procedure

noncompliance

problems.

The team leader stated that the inspector's

observation

did not meet

management's

expectations.

The inspector

reviewed the "Principles of

Haintenance"

issued

by management

and noted that, principle number

2 states,

"maintain the work document/procedure

at the work site.

. ."

The inspector

noted that

a previous

example of work being performed without the work package

in the field was documented

in

NRC Inspection

Report 50-528/95-10;

50-529/95-10;

50-530/9510,

Section 4.2.

The inspector

was concerned

that

these

examples

may indicate

a need to emphasize

management's

expectations

for

the use of work packages

in the field.

The inspector

noted that the licensee

had initiated

an evaluation of

procedures

to determine

the need to emphasize

management

expectations

or to

provide appropriate

guidance for the use of work orders

in the field.

The

licensee

planned to present

these

expectations

to all maintenance

personnel.

The inspector

concluded that the licensee's

response

was appropriate.

4.6

Feedwater

Heat

Exchan er Leak

Re air

Unit 3

On June

6, the inspector

observed

mechanical

maintenance

technicians

repair

tube leaks identified on Feedwater

Heat Exchanger

IA.

The inspector

noted

that the technician did not have

an oxygen monitor inside the heat

exchanger.

Sometime later,

another technician obtained

the oxygen monitor and gave it to

the technician working inside the heat exchanger.

The inspector

reviewed the procedure

for confined

space entry

and its

requirements

for an oxygen monitor and discussed

the requirements

with the

maintenance

team leader responsible

for the job.

The maintenance

team leader

stated

that there

was

no immediate threat or danger to the technician

inside

the heat

exchanger

since there

was continuous ventilation provided

by

a

portable blower, but he was unsure of the requirement

to have

an oxygen

monitor.

i

O

1

-20-

The inspector discussed

the concerns with nuclear

assurance

and the

maintenance

section

leader.

The oxygen monitor was not required

because

the

feedwater

heat exchanger

was classified

as

a non-permit required confined

space

area,

however,

the maintenance

team leader

was unsure of the

classification.

The inspector

concluded that although the oxygen monitor was

not needed

in this case, it was apparent

that th'e confined

space

requirements

were not well understood

by the acting

team leader

when challenged

by the

inspector.

The licensee

discussed

requirements

concerning confined

space

areas

with all of the maintenance

crews.

The inspector

concluded that the

licensee's

response

was appropriate.

5

SURVEILLANCE OBSERVATION

(61726)

5. 1

Safet

In 'ection

S stem

Check Valve Leaka

e Testin

- Unit

1

On Hay 23, the inspector

observed

the licensee

perform portions of

Surveillance

Test 73ST-9SI03,

"Leak Test of SI/RCS Pressure

Isolation Valves".

The purpose of the test

was to satisfy surveillance

Requirement 4.4.5.2.2 of

Technical Specifications

by verifying that SI/RCS check valve leakage

was

within limits.

The inspector

noted that the licensee

did not perform the procedure

as

written.

Specifically, the licensee did not install the drain rigs in

accordance

with the procedure

and did not drain the water from the 3-inch

headers

upstream of check Valves SIA-V523 and SIB-V533,

as directed

by the

procedure.

Instead,

the licensee

installed the drain rigs with a loop seal

to

keep the headers full.

The failure of the licensee

to follow procedures

is

a

violation of TS 6.8.1 (Violation 528/9512-01).

The inspector

informed the

CRS about the observations.

The

CRS discussed

the

procedure

performance with the test director.

The

CRS noted in the

surveillance test log that the test director had chosen

not to perform the

procedure

as written due to difficulty in draining

and subsequently refilling

the header,

which did not include

a vent valve in that section of pipe.

The

CRS noted that the test

was performed for 10 minutes,

no leakage

was noted,

and,

thereFore,

the one

gpm limit was not exceeded.

The inspector questioned

the licensee

about the performance of the

surveillance test.

The licensee initiated

a

CRDR to evaluate

the technical

adequacy of the method

used

by the test director.

Engineering calculated

the

volume of the pipe

and hose,

used

worse

case conditions

by assuming that the

piping was initially empty,

and calculated that to fill the piping and

hose in

a 10-minute period,

the leak rate past the check valves would be 0.66

gpm.

Accordingly the licensee

concluded that the check valve leakage did not exceed

the

TS limit of 1.0 gpm.

The inspector discussed

the performance of the test with the test director

and

reviewed the test director's

statement

about the event.

The inspector

noted

that the test director thought that the procedure

had

been

changed

to place

a

loop seal

in the drain hose

and

was not aware of the actual

requirements

of

Appendix D.

i

-21-

The licensee

discussed

with the test director the expectation for procedure

use

as well

as the conduct of complete

and accurate

prejob briefings.

In

addition,

the licensee

submitted

an instruction change

request

to revise the

Appendix 0 leak rate testing

method.

The licensee

indicated that the change

would be incorporated prior to the next use of the procedure during the Unit 3

refueling outage.

The inspector

concluded that the safety significance of the failure to follow

the procedure

was low.

However,

the inspector

concluded that the test

director did not refer to the procedure prior to or during performance of the

test

and,

as

a result,

made incorrect assumptions

about the requirements

of

the procedure.

5.2

Other Surveillance

Observations

The inspectors

observed

the following surveillance test

and determined that it

was performed acceptably:

~

EDG A Monthly Surveillance

Test

Unit 3.

6

ONSITE ENGINEERING (37551)

6.1

E

Life of S

G 81owdown Isolation Valves

During

a routine tour of the mechanical

room of the Unit 2

auxiliary building, the inspector

noted that the

steam generator

blowdown line

sample valves were continuously energized

Valcor solenoid operated

valves

(SOVs),

and were in contact with hot process fluid.

The inspector

noted that

the licensee

had previously identified solenoid valves in similar applications

where the service

temperatures

of the solenoids

were higher than the

temperatures

used

in the

Eg test report

used to qualify the solenoids.

The inspector

asked

the

Eg engineering

group to identify the critical

components

of the Valcor

SOVs, the temperatures

used

in the qualification test

report for these

components,

and the service

temperatures

of these

components.

The licensee

was

aware that these

valves were susceptible

to potential

hot

spots,

but they had not previously compared

actual field conditions to the

assumptions

in the

Eg binder.

In response

to the inspector's

questions,

the

licensee

reviewed the

Eg binder,

determined

the qualified temperatures

of the

critical components,

and took inservice

temperature

readings of these

components.

The licensee

concluded that the service temperatures

of the

Valcor SOVs were

much lower than the temperatures

used

in the qualification

report

and that there

was not

a safety concern with the valves.

The inspector

was concerned

that the licenseo

had not yet determined

which

Eg

components

were the most susceptible

to hot spots

from process fluid heating,

and evaluated

these

components

to determine if there

was

a qualification

concern for these

components.

The inspector

reviewed the licensee's

thermal

monitoring program in

NRC Inspection

Report 50-528/95-10

and noted that the

licensee

measured field temperatures

of target rock SOVs

and

Namco limit

switches

in the main steam support structure,

and verified that the qualified

life oF these

components

were appropriate.

f

II

f

"1

I f

~

I

~ ~

tl

-22-

The inspector discussed

this concern with the supervisor of Eg engineering

and

noted that the licensee

had identified five components

that were

a potential

concern during the process

of developing the

scope of the thermal monitoring

program.

The licensee

had previously taken temperature

readings

on two of

these

components,

Target

Rock

SOVs and

Namco limit switches,

because

of actual

performance

problems.

The licensee

revised

the

Eg life of these

two

components

as

a result of these

reviews.

The licensee

evaluated

the Valcor

SOVs in response

to the inspectors

questions.

The licensee

had not measured

service temperatures

to validate the

Eg life of the remaining

two components,

Asco

and Skinner solenoids.

The inspector

asked

the

Eg engineering

supervisor

why they had not performed

a

preliminary assessment

of all the components

susceptible

to hot spots

in the

main steam

support structure,

the auxiliary building,

and in the containment

building,

The

Eg supervisor stated

that they planned to monitor the

temperatures

of the Valcor SOVs

and the Asco and Skinner solenoids later in

1995,

when the formal thermal monitoring program

was

implemented.

The

licensee

made this decision primarily because

there

had

been

no performance

problems with these

components.

The inspector

concluded that the licensee

was shortsighted

.by only using

known

performance

problems

as the criteria for validating the service temperatures

of these

components.

The inspector

based this conclusion

on the fact that the

absence

of known performance

problems

does

not mean that

a component with a

qualified life will perform adequately

during

a design basis

event.

The

inspector

also concluded that the licensee

should

have validated the service

temperatures

used to qualify these

components

as

an interim corrective action,

prior to implementation of the formal thermal monitoring program.

The inspector discussed

this observation with the

Eg section leader

who agreed

with the inspector that

a preliminary assessment

of all the susceptible

components

would have

been appropriate

and committed to measure

the service

temperatures

of a representative

sample of the remaining

components

and

evaluate

the adequacy of its qualified life.

The inspector

concluded that

these

actions

were appropriate.

6.2

Crackin

in

RCS

Sam le Valves

In January

1994,

the licensee identified internal

cracks in the bodies of RCS

hot leg sample valves in Unit 2

(NRC Inspection

Report 50-529/94-02).

The two

solenoid operated

sample valves,

supplied

by Valcor, were the inside

and

outside

containment isolation valves for the

RCS hot leg sample line.

The

valves

were removed

and replaced.

The licensee

had contracted with the

Southwest

Research

Institute laboratories

to perform failure analysis

and

metallurgical

inspection.

The valves

are constructed

from a 4-inch block oF stainless

steel

with inlet

and outlet penetration

ports.

The valve internals

are threaded

and seal

welded into an approximate

2-inch diameter,

2-inch deep cylindrical bore.

The

cracks,

identified when the internals

had

been

removed for inspection,

formed

along the

base of the cylindrical bore

and along the inlet port.

The cracks

were not through-wall.

I

1'

~

14 W'

%%A 4r

-23-

The failure analysis

indicated that the cracking

had resulted

from low cycle

thermal fatigue.

The valves

had

seen

approximately

3000 to 5000 cycles of

ambient to 600'F temperature

changes.

The failure analysis

concluded that the

valves would have remained functional for over

20 years

in that service

environment.

The licensee

reviewed industry data

and discussed

the findings with the valve

vendor but did not identify any similar instances

of cracking.

The licensee

documented

the results of their findings in Nuclear Plant Reliability Oata

System.

The licensee

inspected

Units I and

3

RCS sample valves during the respective

refueling outages,

and discovered similar cracking in the hot leg sample

valves.

In addition,

the licensee

discovered

cracking in the inside

containment pressurizer

steam

space

sample valves in both Unit I and Unit 3.

These

valves

had

been

subjected

to fewer thermal cycles,

and the cracking

was

less

pronounced.

The inspection

and replacement

of the Unit I valves

was

completed

in Hay 1995.

Since the initial finding, the licensee

has initiated studies to determine

long term corrective actions to eliminate the stresses

which cause

cracking.

The licensee

had worked with the vendor to perform postfabrication

changes

to

the valves to reduce

thermal

stresses,

such

as reducing the mass of the

valves.

Additionally, the licensee

has explored installing

a heat

exchanger

upstream of the valves to reduce

the magnitude of thermal cycling.

At the end

of this inspection,

the licensee

had not identified

a long-term solution.

Currently,

the licensee

intends to replace existing valves at

a frequency

consistent

with the rate of crack propagation.

Although the licensee's initial survey would indicate that this issue

may be

isolated to Palo Verde, it would appear that these

model valves

are

used in

similar applications

at other sites.

The licensee

informed the inspector that

they would issue

a notice to other sites

on

a industry information network.

6.3

Potential for Auxiliar

Feedwater

Pum

Tri

Followin

an Excess

Steam

Oemand

Event

In March 1995,

the licensee

identified, during

a modification review of the

AFW turbine driven pump, that under certain conditions following an excess

steam

demand

(ESO) event,

such

as

a steam line break,

operators

could

unintentionally cause

the

pump to trip.

In addition,

they identified the

possibility that during

some

steam line break events

an automatic actuation

could cause

the

pump to trip.

The licensee's

evaluation

was documented

in

CROR 9-5-0200.

Following an excess

steam

demand

event,

level in the faulted

steam generator

could drop to the auxiliary feedwater actuation

signal

(AFAS) level for the

generator.

For

a moderate

break,

the

AFAS in the faulted generator

would

initiate

a start of the

AFW turbine driven

pump by opening

a steam

supply from

the faulted

steam generator.

At some point, operators

would have to transfer

the

steam supply from the faulted generator

to the intact steam generator

to

provide continued

AFW turbine operations.

The licensee

determined that it was

,

I

likely that if the transfer

was done without resetting

the

AFW turbine

governor logic, the

AFW turbine would trip on overspeed.

Prior to the transfer,

the turbine governor valve would be open wide to allow

the relatively low pressure

steam of the faulted generator

to maintain turbine

operation.

If the nonfaulted

steam

supply was

opened without resetting

the

governor valve to maintain

a lower speed,

the governor valve would not have

time to compensate

before the turbine reached

the overspeed

setpoint.

The

licensee

used

the operator training simulator to verify the possibility of

this event.

The circumstances

would not occur

on

a larger

ESD, since

a differential

pressure

lockout of an

AFAS would actuate

before the

AFAS signal.

On

a

smaller

ESD,

steam line pressure

would not degrade

to the point

a transfer

would cause

a turbine overspeed

event.

The steam

supply transfer

can

be accomplished

successfully if the faulted

steam supply valve is closed before the nonfaulted

steam supply is opened.

This sequence

causes

the governor logic to reset

and

demand

a lower speed.

The licensee

took action to cover this change

in operator training,

procedures,

and

EOP implementation.

The inspector

observed

the implementation

of this training during

EOP training

and found it to be appropriate.

The licensee identified that there

was the possibility that

a design

basis

event could cause

the failure of the

AFW turbine driven pump.

The design

basis requires that

no operator action

can

be

assumed

to take place for the

first 30 minutes.

The

ESD would have to be of a magnitude

such that the

AFAS

on the faulted generator

occurred

before the differential pressure

lockout,

and

an

AFAS on the intact generator

occurred within 30 minutes.

Although

considered

to be highly unlikely, licensee

engineers

were able to cause this

to occur

on the plant simulator for a steam line break of approximately

22.5 percent of full power.

The licensee initiated

a more detailed

study of the event to determine

the

probability of the events

The inspector

noted that these

studies

were

scheduled

to be completed at the end of July 1995

and found this to be

appropriate.

The inspector will follow the results of the analysis

in

a

future inspection.

The inspector discussed

this issue with licensee

management

and noted that they should

keep in mind the potential

generic

aspects

of this event.

6.4

Tar et Rock Valves with Weak

S rin s

During

a routine review of an industry events bulletin, the licensee

found

that Target

Rock Corporation,

a vendor of solenoid operated

valves,

had

identified that

some valve springs

had

been provided to Entergy Operations for

the River Bend site which did not meet Target Rock's spring force

specifications.

The licensee

contacted

Target

Rock and determined that the

valve springs

from the

same lot had

been delivered to Palo Verde

as

replacement

parts.

The valve springs,

which assist

solenoid valve closure,

were provided

by

a sub-supplier for I and 2-inch valves.

i

-25-

Target

Rock had performed testing which identified that the lower spring

forces did not affect the operation of the solenoid valves at River Bend.

However, following discussions

with Arizona Public Service,

Target

Rock

initiated site-specific testing to determine

whether the lower spring forces

would have

an impact at Palo Verde.

At the

end of the inspection period,

the

study

had not been completed;

however,

the licensee

had

a high degree of

confidence that the lower spring force would be determined

to be adequate

for

the Palo Verde applications.

In the interim, the licensee

identified ten safety-related

installed valves

which could potentially have the suspect

springs

and performed

an operability

determination,

which concluded that the installed valves

had either

been

satisfactorily tested

at design basis

pressures,

or did not have

a design

function to close.

In addition,

replacement

springs

in the warehouse

were

quarantined.

The inspector

reviewed the operability determination

and found

it to be appropriate.

The inspector will review the assessment

of the valve

springs

by the vendor

when it becomes

available.

7

FOLLOWUP OPERATIONS

(92901)

7. 1

Violation 530 9413-02

CLOSED

Circuit Breakers

Not Pro erl

Racked

Out

This violation occurred

when the inspector

observed

various circuit breakers

which were not racked out in accordance

with operating

procedures

and,

as

a

result,

may not have

been seismically restrained.

The licensee's

corrective

actions

included revising circuit breaker operating

and maintenance

procedures

to define appropriate

breaker positions

and to require that the control

room

be informed of final breaker

status after racking operations.

The licensee's

training department

also developed job performance

measures

for breaker

racking operations,

and this event

was reviewed with operators.

The inspector

reviewed the licensee's

root cause

evaluation for this violation, the

operating

and maintenance

procedure

changes,

and the job performance

measures.

The inspector

found the licensee's

corrective actions

to be adequate.

During

plant walkdowns,

the inspector

observed that breakers

were properly

positioned.

8

FOLLOWUP MAINTENANCE (92902)

8.1

Follow u

Item 529 9437-01

Closed

Multi le

Emer enc

Diesel

Generator

~Tri

s

This item involved several

nonsafety-related

trips of the Unit 2 Train

B

between

December

14

and

16,

1994.

The inspector

was concerned

that

inappropriate

maintenance

may have contributed to

some of the trips

and that

the

EDG was unavailable for over

20 hours2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months for repair.

This item was

opened

to

review the licensee's

root cause

evaluation

and corrective actions.

The licensee

performed

a root cause

investigation of this event

and determined

that the

EDG tripped twice during the start

sequence,

twice during the

cooldown cycle,

and failed to stop once.

The licensee

determined that one of

the trips was caused

by

a high resistance

contact

in

a continuously energized

Agastat relay,

two of the trips were caused

by leaking check valves,

and

one

of the trips was caused

by

a leaking temperature

control valve.

The failure

ft

to stop

was caused

by the installation of capillary tubing during

troubleshooting activities that subsequently

restricted air flow to the

shutdown valve.

8.1.1

Corrective Actions

The licensee

determined that the leaking check valves

were caused

by pieces of

teflon tape that were caught

on the valve seat.

The licensee

determined that

the debris

was introduced during the troubleshooting

eFforts.

The licensee

already

had corrective actions in place to replace

the check valves with a new

design that

had

an internal filter and

a stronger spring to minimize the

leakage

from the valve.

In addition,

the licensee

conducted

a training class

on

EDG troubleshooting

and emphasized

the importance

oF maintaining

system

cleanliness.

The licensee

also discussed

appropriate

precautions

when

installing test

equipment during troubleshooting activities during the

training class.

The licensee

determined that the leaking temperature

control valve was not

identified during installation

because

the procedure

did not require the valve

to be leak tested after the valve was calibrated.

The licensee

updated

the

calibration procedures

to require the valves to be leak tested.

The licensee

also

had corrective actions

in place to replace all continuously energized

Agastat relays during the Unit 2 outage

in Harch

1995.

The inspector concluded that the licensee

conducted

a thorough root cause

evaluation

and identified appropriate corrective actions to reduce

the

amount

of nonsafety-related

EDG trips.

8. I.2

Additional

EDG Trips

On June

7, the Unit 2 Train

B

EDG tripped during

a surveillance test run due

to

a faulty low turbocharger

lube oil pressure

relay.

This relay was replaced

during the last outage

in Harch

1995

as part of the corrective actions listed

above

and

was found to have

an internal fault which caused

the relay to open.

On June

8, the Train

B

EDG tripped during

a postmaintenance

test run after

installation of a new low turbocharger

lube oil pressure

relay.

The licensee

initially suspected

an intermittent problem with some of the continuously

energized

relays in the shutdown circuit

The technicians

checked

three of

the most probable relays

and did not identify any high resistance

contacts.

The inspector

observed

the troubleshooting efforts

and verified that the

relays

had

been

replaced during the last outage

in Harch

1995.

The inspector

also noted effective interaction

between

the technicians,

the maintenance

engineer,

and nuclear

assurance

evaluator during the troubleshooting

activities,

and that the procedure

specified appropriate

acceptance

criteria

for replacing the relays,

The licensee

determined

that the June 8,

EDG trip was caused

by

a broken

contact

on the base of the low turbocharger

lube oil pressure

relay.

The

licensee

determined that when the

new relay was installed it was inserted

and

removed

several

times into the relay base until good contact

was

made.

The

relay base

also

needed

to be filed to allow good contact

between

the relay

and

the base.

The licensee

believed that during these

repairs

the base of the

f

I'

I

!

1

l

0

-27-

relay was

damaged.

The licensee

subsequently

replaced

the relay base

and the

Train

B

EDG was satisfactorily tested.

The inspector

concluded that although the licensee

had reduced

the number of

nonsafety related

EDG trips, the problems with relay bases

highlighted the

need for continued attention to the maintenance

of the nonsafety related

control

system.

The licensee initiated another

CRDR to evaluate

the cause of

the relay problems.

The inspector will monitor the adequacy of the licensee's

corrective actions.

8.2

Unresolved

Item 528 9434-03

Closed

Poor Work Orders

on Tar et Rock

Valves

This item involved the adequacy of a work order used to disassemble,

reassemble,

and set the stroke of certain Target

Rock solenoid-operating

valves.

Specifically, the inspector questioned

the quality of the work order

in that mechanics

had to rely heavily on the vendor technical

manual

instructions for setting the stroke of the valve.

The inspector's

observations

were similar to earlier observations

documented

in

NRC Inspection

Report 50-530/94-26,

for which the licensee

had initiated

an action to revise

the work order.

The inspector

reviewed

Model Work Order 002002 for the disassembly,

rework,

and reassembly

of Target

Rock Model

76HH-008 solenoid-operating

valves.

The

inspector

found that the revised

work order included

more vendor technical

.

manual

information for setting the valve stroke than the previous work order.

However,

the inspector

noted that mechanics

would still need to refer to the

vendor technical

manual for the adjustment of disc-to-bonnet

Clearance

A, as

the work order did not define the clearance,

and earlier work order steps

defined

a different Dimension A.

The inspector

also

found that partial

disassembly

of the valve internals

was required .to obtain

a disc-to-body

Measurement

B, although the work order steps did not specify disassembly,

and

previous work order steps

completed

the assembly of the internals.

Finally,

the inspector

found that one work step did not list part reassembly

in a

logical sequence,

and that

some work order steps referred to valve part

numbers specified

in drawings while other steps

did not identify the part

numbers.

The inspector

concluded that the revised

work order was usable

but

could still be improved.

The inspector discussed

the work order

comments with a valve services

engineer,

who acknowledged

the

comments

and indicated that valve services

was

working with mechanics

to review and revise the model work order.

9

FOLLOWUP ENGINEERING/TECHNICAL SUPPORT

(92903)

9,1

Unresolved

Item 530 9503-01

CLOSED:

0 erabil it

Evaluation of

Essential

Coolin

Water

Inspection

Report 50-530/95-03 identified that the licensee

had not completed

an evaluation of the operability of the

ECW system during

a period

between

1992

and April 1994 for the impact of a seismic qualiFication deficiency.

i

-28-

The

ECW system

was initially designed

to rely on the seismically qualified

condensate

transfer

(CT) system to provide makeup

from the condensate

storage

tank.

The

ECW process

radiation monitors

and associated

instrumentation

were

not seismically qualified.

Initial design calculations

demonstrated

that the

CT system would provide sufficient makeup to the

ECW system following a

seismic

event which ruptured the instrument lines.

In 1992, for a number of reasons

discussed

in

NRC Inspection

Report 50-530/95-03,

the licensee

disabled

the

CT system

makeup to the

ECW

system.

However, until April 1994,

the licensee left the

ECW radiation

monitors in service.

Therefore,

during this period, if the nonseismically

qualified instrument tubing had failed following a seismic event,

the

ECW

surge

tanks for both trains could have drained

and the

ECW pumps could have

lost net positive suction

head.

The licensee

recognized

in April 1994 that the condition was potentially

reportable

under

10

CFR 50.73.

However,

at the time of IR 50-530/95-03,

the

licensee's

evaluation

had not been completed.

The evaluation

was dependent

on

an assessment

of the ability of the nonseismically qualified radiation monitor

instrument tubing to withstand

a seismic event.

The licensee

made

a 4-hour nonemergency

report to the

NRC in accordance

with

10

CFR 50.72

on June

22, concluding that the system

was not seismically

qualified.

However, this conclusion

was

made

based

on field walkdowns that

indicated that the installed configuration of the radiation monitor

instrumentation

did not meet installation specification.

The licensee

subsequently

performed

computer modeling of the as-found configuration of the

instrumentation,

which demonstrated

that actual

stresses

would have

been

significantly lower than

code allowable stresses.

The

10

CFR 50.72 report was

retracted

on June

29, after computer modeling

was completed.

The inspector

reviewed the bases

of the licensee's

evaluation

and found them to be

appropriate.

9.2

Unresolved

Item 528 9437-02

Closed

Main Steam Safet

Valve

MSSV

Information Notice

This item involved the licensee's

response

to information notice (IN) 94-61,

"Potential Overpressurization

of Main Steam System",

issued

on August 22,

1994.

Unit

1 was operating

at

98 percent

power with two MSSVs inoperable,

as

allowed by TS 3.7.2,

when the licensee

received

IN 94-60.

The licensee

did an

initial review of the

IN as part of a

TS submittal to allow Unit

1 to return

to

100 percent

power with the two inoperable

MSSVs.

The licensee

concluded

that the concerns

identified in the

IN did not affect the

amendment

request,

and

on December

14, the

TS amendment

was approved

and Unit

1 returned to 100

percent

power.

The inspector

reviewed the licensee's

evaluation

and

had additional

discussions

with nuclear fuels engineering

personnel.

8ased

on these

discussions,

the inspector

had the following observations:

~

The licensee

reviewed the specific concern

discussed

in the

IN and

found

that Combustion

Engineering,

Inc.

(CE)

made the

same

assumption of a

-29-

linear reduction in power with inoperable

HSSVs.

The licensee

subsequently

used

the existing

CE simulation

and modeled the specific

core conditions in Unit

1 with one

HSSV inoperable

per

SG and found the

peak secondary

pressures

were acceptable.

~

The

IN stated

that the potential for problems

was greater at lower power

levels,

since there

was

more time to add heat to the secondary

before

a

reactor trip occurred.

The licensee

reasoned

that since Unit

1 was

returning to

100 percent

power, the concerns

in the

IN were not

applicable to the

TS amendment.

The inspector

subsequently

concluded that the licensee

adequately

addressed

the concerns

in the

IN prior to the Unit

1

TS submittal for raising

power to

100 percent.

In December

1994,

the licensee

conducted

a preliminary analysis of the

concerns

in 94-60

and determined that operating with one or more

HSSVs

inoperable

may cause

overpressurization

of the secondary

system.

The licensee

also determined that CE's analysis of the loss of condenser

vacuum accident,

used to allow operation

at

100 percent

power with one inoperable

MSSV, did not

explicitly analyze

the secondary

side pressure

with the most conservat'ive

parameters

of the TS.

The licensee

subsequently

performed

a detailed evaluation of the secondary

pressure

overpressurization

event using the actual

core conditions in Unit

1

at

100 percent

power with one inoperable

HSSV in both

SGs.

The licensee

determined that the actual

conditions in Unit

1 did not result in exceeding

110 percent of the design

maximum secondary

pressure.

The inspector

concluded

that the licensee

had performed

an adequate

evaluation to determine

the

potential

problem with the

CE simulation.

The inspector

noted that the licensee

conducted

additional calculations of all

the possible

combinations of inoperable

HSSVs

and the actual

and projected

core conditions of all three units

and found that the peak secondary

pressures

were acceptable.

However,

the licensee

determined that

a modification to the

TS for inoperable

HSSVs

was required to ensure that the actual

core moderator

temperature coefficient was negative.

The inspector

concluded that the

licensee's

corrective actions

were appropriate.

9.3

Deviation

528 9431-07

CLOSED

Boric Acid Pro

ram Commitments

Not

Followed

This deviation occurred

when the licensee's

boric acid prevention

program did

not incorporate

Generic Letter 88-05 commitments to list potential

leak

locations

in procedures.

The inspector

reviewed Revision

8 to

Procedure

73TI-9ZZ13, "Visual Examination for Leakage,"

and found that the

licensee

added

Appendix

B to the procedure

to provide

a boric acid walkdown

checklist with walkdown attributes

and specific locations

where leakage

could

cause

degradation

of the reactor coolant

system pressure

boundary.

Subsequently,

the licensee

issued

Procedure

70TI-9ZC01, "Boric Acid Corrosion

Prevention

Program,"

which further defined

program requirements

and the list

f

-30-

of potential

leak locations.

The inspector

concluded that the licensee's

corrective actions

were appropriate.

10

ONSITE REVIEW OF LICENSEE

EVENT REPORTS

(LERs)

(92700)

10.1

0 en

LER 528

529

530 93-011

Revision

1:

Potential

Safet -Related

E ui ment Problems

Due to De raded

Grid Volta e and

0 en

LER 528 95-

01

Revision 0:

Entr

Into TS 3.0.3

Due to

De raded Volta e

10.1.1

Licensee's

Reports

LER 93-011,

Revision

1',

was issued

February

6,

1995,

and noted that

a

previously unanalyzed

condition could occur due to low grid voltage.

The

unanalyzed

condition involved double sequencing

of safety-related

pumps during

an accident.

Following an emergency

safety features

actuation,

the licensee

noted that the potential existed to not only start

sequencing

safety-related

equipment

onto preferred offsite power,

but also to initiate load shedding

due

to the Class

1E 4. 16kV undervoltage

relays dropping out and not resetting,

and

then resequencing

the equipment

onto the emergency

diesel

generator.

The licensee

stated

in LER'93-011,

Revision

1, that if grid voltage

was kept

above 99.5 percent,

its calculations

indicated that the double

sequencing

would not occur.

The licensee

also discussed

long term corrective actions

and

stated that pending completion of these

actions the grid would be kept above

100 percent.

However,

on February

15,

1995,

the licensee

entered

TS 3.0.3,

due to grid voltage falling below 100 percent during planned

switchyard

evolutions.

The licensee

and Energy Control Center

(ECC) personnel

restored

the voltage

by increasing

the reactive voltampere

(VAR) output of the main

generators

at the site.

The licensee

issued

LER 95-001,

Revision 0,

on

March 15,

1995, to report the February

15,

1995, occurrence.

10. 1.2

Licensee's

Actions

The licensee

determined that its corrective actions for LER 93-011,

Revision

1,

had not been effective to maintain grid voltage

above

100 percent.

The licensee

provided further instructions

and guidance to its control

room

operators

and to personnel

in the

ECC in Phoenix,

who control the Palo Verde

grid.

The licensee

also

issued

a

new procedure for operator actions

in

response

to

a degraded grid and

added

degraded grid voltage to the Unit

1

Plant Honitoring System displays.

The licensee

stated that the following long

term corrective actions

would make all three units operable

above

98 percent

grid voltage.

Removal of loads

from Unit 1, the most heavily loaded unit

Addition of an accurate grid voltmeter in Unit 1,

so licensed

operators

will have ability to routinely monitor grid voltage

Transformer

upgrades

and sequencer

changes

Automatic block of fast

bus transfer

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10.1.3

Inspector's

Actions During the Present

Inspection

The inspector

reviewed both

LERs, the licensee's

procedure for response

to

degraded grid voltage,

the licensee's

review of the potential for further

occurrences

for degraded grid voltage,

the licensee's

long term corrective

actions,

and the requirements

the licensee

provided to the

ECC.

In addition,

the inspector

toured the

ECC,

reviewed the grid information available at the

ECC and discussed

the Palo Verde site voltage requirements

with

ECC personnel.

The inspector also reviewed

use of site

VARs to restore grid voltage,

in that

during

a future event,

none of the site main generators

may be operating.

The inspector

noted that the Palo Verde site did not have accurate

on-line

capability to monitor grid voltage.

Unit

1 has

a meter,

but it was not

accurate

enough to detect

small

changes

in grid voltage..

The inspector

had

taken part in discussions

between

the licensee

and regional

and Office of

Nuclear Reactor Regulation

(NRR) staff personnel

subsequent

to the

February

15,

1995,

TS 3.0.3 entry.

NRR personnel

reported

they were reviewing

a licensee

request

to change

the

TS degraded grid voltage relay setpoint

and

range.

The inspector reviewed

Procedure

41A0-1ZZ57,

"Degraded

Grid Voltage,"

Revision 4.

This procedure

provided operator

guidance for all three units for

response

to degraded grid voltage in various plant modes.

The basic action

was to restore

one emergency

bus in each unit by blocking the fast

bus

transfer of nonsafety-related

loads to the startup transformers

which supplied

the safety-related

loads.

The inspector

reviewed the affect of blocking the

fast

bus transfer

and determined that licensee calculations

indicated this

block would allow safety-related

voltage to. remain

above the degraded

voltage

relay setpoint.

The inspector determined that grid voltage, current,

and

VAR information were

readily available in the

ECC.

The inspector discussed

the February

15,

1995,

event with

ECC personnel.

ECC personnel

indicated that operators

were

aware

that their actions

could lower grid voltage

and they were prepared

to raise

the voltage

as necessary.

Based

on discussions

with the licensee,

ECC

personnel

stated that in the future they would raise grid voltage first before

taking actions similar to those of February

15.

The inspector

reviewed

licensee letter File 95-005-419.8,

"PVNGS Expectations

Regarding

Evaluations

Potentially Affecting Grid Voltage

Range Limits," dated

February

23,

1995,

and

ECC internal instructions,

and noted that operational

expectations

were

clearly stated.

In addition,

the inspector

noted that the

ECC had in place

an

audible

alarm for when grid voltage at the site

approached

100 percent.

The inspector

noted that the licensee

had

used the site main generators

to

raise grid voltage during the February

15, event

and questioned

the licensee

as to whether

ECC personnel

could have raised this voltage external

to the

site

on February

15, or during future occurrences

when there

was

no site

generation.

The licensee

provided the inspector

a grid study titled,

"PVNGS

525kY Voltage Regulation

Study Report."

This report concluded that the grid

could reliably be maintained

above

98 percent,

without site generation

support.

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-32-

Based

on the discussion

above,

the inspector

concluded that the licensee

had

taken reasonable

corrective actions to identify when

a low voltage condition

existed

on the grid,

and what actions to take to ensure that Palo Verde units

remained

operable

and complied with TS shutdown criteria.

The inspector also

noted that most of the calculations

associated

with these

LERs were

based

upon

a

new

TS setpoint

and range of operation of the degraded grid relays which

were currently under review by the

NRC staff.

These

LERs will remain open,

pending

NRC staff approval of the degraded grid

relay

TS change,

inspector review of associated

calcu'lations,

and review of

completed

or committed long term corrective actions.

1 1

IN-OFFICE REVIEW OF LERs

(90712)

The following LERs were reviewed in-office and determined

to be acceptable:

LER 528/95-05:

EOG inoperable

due to debris in cooling water heat

exchanger.

This issue

was reviewed in detail in NRC Inspection

Report 50-528/95-06;

50-529/95-06;

50-530/95-06.

LER 528/95-08:

Reactor Trip on low SG level

due to the inadvertent

closing of a feedwater isolation valve (Section

2>>1).

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ATTACHMENT 1

1

Persons

Contacted

1. 1

Arizona Public Service

Com an

T. Cannon,

Acting for Director,

System Engineering

B. Grabo,

Section

Leader,

Nuclear Regulatory Affairs

J. Hesser,

Director, Design

8 Projects

Engineering

W. Ide, Director, Operations

A. Krainik, Department

Leader,

Nuclear Regulatory Affairs

J.

Levine, Vice-President,

Nuclear Production

R. Lucero,

Department

Leader,

Electrical Maintenance

D. Mauldin, Director, Maintenance

J. Minnicks, Department

Leader,

Maintenance

Valve Services

W. Montefour, Senior Representative,

Strategic

Communications

M. Muhs, Section

Leader,

System Engineering

G. Overbeck,

Vice-President,

Nuclear Support

M. Radspinner,

Section

Leader,

Design Engineering

F. Riedel,

Department

Leader,

Operations

Unit 2

M. Salazar,

Section

Leader,

Maintenance

Valve Services

C. Seaman,

Director, Nuclear Assurance

D. Smith,

Department

Leader,

Operations

Unit

1

W. Stewart,

Executive Vice-President,

Nuclear

R. Stroud,

Regulatory Consultant,

Nuclear Regulatory Affairs

J. Taylor, Department

Leader,

Operations

Unit 3

P. Wiley, Department

Leader,

Operations

1.2

NRC Personnel

K. Johnston,

Senior Resident

Inspector

D. Garcia,

Resident

Inspector

A. MacDougall,

Resident

Inspector

1.3

Others

J. Draper, Site Representative,

Southern California Edison

F. Gowers, Site Representative,

El

Paso Electric

R. Henry,

Site Representative,

Salt River Project

Denotes those

present

at the exit interview meeting held on June

29,

1995.

The inspector also held discussions

with and observed

the actions of other

members of the licensee's

staff during the course of the inspection.

2

EXIT MEETING

An exit meeting

was conducted

on June

29,

1995.

During this meeting,

the

inspectors

summarized

the scope

and findings of the report.

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.

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ATTACHNENT 2

LIST OF ACRONYNS

AOY

CROR

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ECC