ML17223A832

and

ANPS that

he

was

stopping

charging

pump

"A".

The

individual

looked

for

acknowledgement

from either

the

NPS or

ANPS;

however,

no

verbal

nor

non-verbal

acknowledgement

was

given.

During

complex

evolutions (i.e.,

the

turbine

over-speed

test

and

the

reactor

startup

on Unit-1),

communications

were

formalized.

Additionally,

the

ANPS

in the Unit-1 control

room displayed

good

control

and

focus of RTGB activities during

a reactor start-up.

On April 26,

1990,

the

ANPS

was closely monitoring control

rod manipulations

and

was

providing

effective

oversight

of

the

control

board

operator's

activities.

Control of access

to the

area

around

the control

boards

was

weak.

During

the first

week

of

the

inspection,

while

Unit I

was

performing

the initial

power

increase

after

the refueling,

there

were

fourteen

personnel

(at

least

four non-operations)

within the

area

of the

RTGB boards.

Although

signs

are

posted

stating

that

permission

is

required

for entry,

very

few

personnel

requested

permission.

The inspectors .noted that routine

access

is

not well

controlled.

This

was'videnced

when

five

- consecutive

non-

operations

persons

entered

the

.control

room

area

without

permission.

Additionally,

" the 'operators,

the

ANPS,

and

the

were facing the

and thus,

were not aware of these

individuals

nor their activities.

The

inspectors

also

noted that

hard

hats

were routinely worn in the control

room,

and

one

occasion

noticed

an

lean

over

the

RTGB several

times with his

hard

hat

on.

After this

issue

was

raised

with operations

management,

no other

individuals were observed

at the

RTGB with their hard hat on.

1

Plant

and

operations

management

were

routinely

and

consistently

observed

in the plant.

The inspectors

noted

management

within the

control

room,

as well as,

in less traveled

areas.

The

number

and qualifications

of watch

standers

consistently

met

or exceeded

NRC requirements.

The personnel

on shift were clearly

posted

by position within each

control

room.

To the facility's

credit,

they

have

a

Nuclear

Watch

Engineer,

who is

SRO

licensed

and

responsible

for activities

of

the

non-licensed

operators

outside

of the control

room,

as well

as,

assisting

the

by

performing

many of the

administrative

duties.

'The

NWE routinely

relieves

the

ANPS

and

assumes

the

command

and control

functions in

the

control

room.

In

accordance

with

10 CFR 55.53(e),

"..'.

To

maintain

active

status,

the

licensee

.[Part

55

license]

shall

actively

perform

the

functions

of

an ...

senior

operator

on

a

minimum of

seven

8-hour

or

five

12-hour

shifts

per

calendar

quarter."

The

NWEs

do

not routinely

stand

the

ANPS

watch to

maintain

an active license,

as defined

by

10 CFR 55.

The licensee

needs

to administratively defined

the

NWE position to substantiate

that

the

NWE meets

the

requirements

of

a

TS defined

watch.

This

is considered

as

an unresolved

item (UNR 50-335,389/90-09-02).

The reactor

operators

and

senior reactor

operators

are

licensed

on

both

units.

The

reactor

operators

and

non-licensed

operators

rotate

between

units

on

a

frequent

basis.

However,

the

ANPSs

do

not

rotate

on

as

frequent

a

basis.

The

team

considered

the

rotation of the

ROs

and non-licensed

operators

as

a

good practice

to enhance

operator

awareness

of plant conditions

and

to maintain

proficiency

on

both

units.

The

ANPSs'otation

practice

was

considered

an

area

the licensee

may want to review,

in that,

the

SROs

would

be

rotated

to

the other unit after

as

much

as

a year.

away, with only one watch under instruction

on the "new" unit.

It appears

that

the

operators

have

become

desensitized

to

the

number of alarms

and

PWO tags

(48 in Unit-2) in the control

room,

as well as,

equipment

which is in the warning

range

by indication.

This situation

was

exacerbated

by the

high

number of

PWO tags

on

the

RTGB,

as well as,

the operator's

inability to obtain

the

PWO's

correct

status

from

NJPS.

This

system

is the 'only semi-immediate

mechanism

that

was

in

place

for

the

operators

to

obtain

PWO

status'owever,

the inspectors

identified that this

system is not

promptly

updated

to reflect

accurate

PWO status.

See

paragraphs

c. l., c.2.

and Appendix A for additional details.

The

operators

are

slow to acknowledge

the annunciator

alarms

both

when

the

alarms initiate

and

when they reset.

This

was primarily

observed

in Unit-1

on resetting

alarms

with the

large

number

of

alarms

annunciating

and resetting

during

the Unit start-ups.

The

inspector

attributes

this

to

the

audible

portion of the

alarms

which automatically

ceases

after 3-5

seconds.

As

a result,

there

is

no

urgency

on

the

part

of

the

operator

to

immediately

acknowledge

or reset

an

annunciator.

The

inspectors

noted

cases

where

an

alarm

would continue

to flash for five to

ten

minutes

after the alarm had reset,

without operator

acknowledgment.

There

were

only

i sol ated

cases

where

an

incoming

alarm

would

continue

to flash after

alarming for more than

one minute.

This

slow

acknowledgement

is

of

concern,

in that,

prompt

acknowl-

edgement

of

a potentially significant alarm could be'ecessary

to

mitigate or correct the alarm condition

Many of the

meter

faces

in the Unit

2 control

room are color coded

green/yellow/red,

signifying

normal/warning/alarm,

respectively.

However,

the color coding of the

meters

were

not consistent

with

the

actual

plant

conditions.

For

example:

on

the

circulating

water

pump

ammeters,

the

normal

readings

were

near

the high end of

the

yellow

range

on

the

meter

face,

with

one

meter

indicating

almost into the red.

The operators

were

trained

and

procedurally

.

instructed

to believe

indications

and

take

conservative

resultant

actions.

By routinely accepting

warning

and

alarm

indications

as

normal

or satisfactory indication,

the operators

become desensitized

to indications.

See

paragraph

3.d.

on

anomalous

indications

which

were not identified as abnormal.

In Unit-2,

a bearing

temperature

.alarm setpoint for the

IA reactor

coolant

pump

was, different

from the

identical

alarm

setpoints

on

the

other

reactor

. coo'lant

pumps.

The

reactor

operator

knew that

the

alarm setpoint

was

changed

to clear

the annunciator

window but

was

unable

to

determine

what, if anything,

had

authorized

the

'hange.

In fact,

the

change

was authorized

by

a maintenance

work

order

and

was

approved

by the

FRG.

The concern

of the inspector

was that the reactor

operator

did not

know what

had authorized

the

changing of the setpoint.

Evaluation of local plant operations

The

inspectors

routinely

toured

both

the

primary

and

secondary

sides

of the

plant

and

conducted

observations

of daily

rounds.

These

tours

and

observations

were

performed to identify potential

procedural

and

personnel

weaknesses,

as

well

as,

to

monitor

component/system

status

and performance.

During observation

of

NLOs performing daily rounds,

the operators

appeared

to

be

knowledgeable

with respect to'he

equipment

and

their respective

responsible

areas.

The facility has

three

levels

of qualification

for

the

NLOs,

with

the

most

senior

having

responsibility

for the majority of safety-related

equipment

needed

for reactor

protection.

During

the

plant

walkdowns

and

rounds

observations,

the following items/problems

were noted:

1)

Deficiency Tags

A large

number

of

PWO tags

existed

in both

the

respective

control

rooms

and

locally.

See

paragraph

2a.,

2c.,

and

Appendix A for details.

Housekeeping

General

housekeeping

appeared

to

be

adequate.

However,

the

inspector

noted

various

locations

within Unit-1

RCA

where

housekeeping

appeared

to

be

weak

(e.g.

trash,

booties,

gloves,

consumable

material,

etc.,

on

floors/equipment).

Recognizing

the

unit

was

restarting

from

an

outage,

the

inspector

re-evaluated

these

areas

at

a

subsequent

date.

With

exception

of

. the

rooms,

the . inspector

noted

expected

improvement.

In

the

rooms,

the

inspector

identified

numerous

housekeeping

items

such

as:

trash,

oil

leaks,

can

of anti-seize,

rags,

tape,

sandpaper,

etc.

The

inspector

noted

that

painting

was

occurring

in

the

rooms,

and

most of these

items

could

be attributable

to the

painters.

However,

stronger

control

is

needed

over their

activities.

This

is

further

exemplified

by

the

fact that

upon

subsequent

re-inspection

of

these

areas,

similar

housekeeping

items

existed.

Additionally,

the

inspector

identified

that

the

operating

procedure

had

been

removed

from its

location

on

the

local

panel

and

placed

on

the

third tier of steps

going

over

the diesel.

Evidently, its

rack

had

been

removed

for

painting,

making

the

procedure difficult to locate

during

an

emergency.

The

painting

crew

did

not

recognize

the

importance

of this

procedure

nor the necessity of having it readily accessible.

The inspector

also

noted that the

EDG barring device for the

1B2 diesel

was

placed

on the

EDG fuel oil

day

tank.

Normal

storage

location

is

under

the

EDG steps.

This

item is of

concern,

in that,

during

an

EDG start

or

a

seismic

event,

this

heavy

tool

could

possibly

brake

'the

day

tank

level

indicator

and/or

the oil

day

tank

level

alarm

indicator

switch

LIS-59-016B,

as .well

as,

lo-lo alarm indicator switch

LIS-59-017B.

This could result in loss of alarm for the

day

tank level'n the control

room.

Tran s i ent

Combu st ib1 es

While

performing

a

plant

walkdown,

the

inspector

observed

transient

combustible

paint thinner left in

two

open

buckets

while the

painting

crew

was

apparently

at

lunch.

There

was

unused thinner being stored in approved containers.

J

However,

"used"

thinner

was

left

in

the

open

buckets

approximately

one-foot

from

the

1A

fuel oil flexible

coupling.

Section

8.2'.5.

of

Administrative

Procedure

0010434,

Revision

22,

Plant

Fire

Protection

Guidelines,

states

that

"transient

combustible

material,

unless

stored

in approved

containers,

shall

not

be left unattended

during

lunch, shift changes

or any time for more

than

30 minutes."

As this

appeared

to

be

an isolated

occurrence,

this issue

is

only being

addressed

as

a

weakness.

When

the situation

was

brought

to

the

licensee's

attention,

the

condition

was

promptly corrected.

Local Alarm/Annunciator Testing

During

a

plant

tour with

one

NLO, it

was

noted

that

the

local

alarm

panels

were

not periodically

lamp

tested

(as

with

the

control

room

panels).

When

this

condition

was

brought

to

the

attention

of

operations

management,

the

operations

supervisor

recognized

this

testing

omission

as

an oversight.

It was

entered

in the night order

book

as

an

addition to the shiftly surveillances

for the

NLOs.

Industrial Safety

It appeared

that

the

licensee

has

an

aggressive

personnel

safety

program.

Safety

requirements

and

reminders

are

conspicuously

posted

throughout

the

site.

Compliance

with

safety

practices

appeared

to

be

good.

However,

at various

times

personnel

were

observed

not

utilizing

hearing

protection

in posted

areas.

The

inspectors

observed

routine

and

prudent

safety

belt

usage,

with

the

only

exception

being

an

individual

working

on

top

of

a

heater

with no safety belt.

Danger

tags

were

hung,

when

the

PWO

was

completed.

This,

coupled

with the

high

number

of

PWO

tags,

could

be

distracting

or

misleading

for

equipment

operation

during

a

transient/emergency.

The

controlling

procedure

fo'r the.

PWO

tagging

processes

is

AP

001043,

"Nuclear Plant Work Orders",

Revision

41.

A

walkdown

was

performed

on

May

10,

1990

of

the

Unit-2

control

room

comparing

a

tagging

printout

versus

control

room tag status.

The following discrepancies

identified:

Control

Room

PWO Ta

s Missin

TAG¹

a)

C 30950

b)

C 31252

c)

C 40043

d)

C 40097

e)

C 43114

f)

C 43556

XA 890502202034

XA 890415132346

XA 900128141548

XA 900115080808

XA 891221194646

XA 900404204933

PWO¹

5588

7956

3094

7662

7483

6073

Section

5.2

of

AP-001043

requires

that

the

immediate

supervisor/foreman

for

the

person

originating

the

NPWO is

responsible

for

ensuring

a

deficiency .tag

is

hung, if

appropriate

~

Section

8.1

delineates

deficiency

tag

hanging

requirements.

There

were

also

five

PWOs

which

had

been

completed

six to

seven

days

earlier.

However,

their

status

was

listed

on

NJPS

as

code

45 (ready to work).

TAG¹

WR¹

PWO¹

a)

C 32252

b)

C 32228

c)

C 43407

d)

C 43457

e)

C 43700

XA 900414003612

XA 900426054952

XA 900410174239

XA 900426054520

XA 900228005856

6106

6209

6099

6211

7914

The

status

of

the

above

five tags

is

not critical

as

the

work

had

been'ompleted.

However,

on

May

10,

1990,

these

NPWOs

were listed

as

ready

to

be

worked

when

in fact

they

had

been

worked

six to

seven

days earlier.

The

NJPS

system

is not promptly

updated,

and

is

the

only

immediate

method

the

operators

have

available

for deficiency

status.

By not

having

an

accurate

status

available,

the

. potential

exists

for misleading

an

operator

as

to

what

equipment

has

been

fixed

and

is

actually

available

for

support

of

normal/emergency

operations.

See

paragraph

C.2.

and

Appendix

A for

additional

details

and

examples

of this

problem.

There

were

three

PWO

tags

located

in the control

room which

did'ot

have

the

proper

"C" designation,

as

required

by

Section

B.2. 11

of

AP-001043

and

thus

were

not routinely

checked

for tag

status.

These

PWOs

included:

PWO

6081

(XA

900408200606)

PWO

6315

(XA

900504215725)

PWO

6306

(XA

900507103018).

There

was also

an

instance

where

the

PWO

had

been

canceled;

yet

the

tag

remained

inside

the

(Tag

C32069).

The

only

information

available

to

the

operator

from

NJPS

was that this

PWO

was

canceled.

The operator

has

no alternative

means

by which to verify whether

the

tag

is

valid.

Subsequent

to

the

walkdown,

a

new

PWO

was

generated

for this

item.

The

above

examples

indicate

a failure to

follow procedures.

This

is

considered

to

be

an

apparent

violation (VIO 50-335,389/90-09-01).

Emergency

Diesel Generators

During

a

walkdown

of the

Unit-2

EDGs

on

May 8,

1990,

the

inspectors

compared

a

current

listing

of

active

PWOs

(obtained

from

NJPS

in Unit-2 control

room) to status

in the

field.

Section

5.2

of

AP-001043

requires

that

the

immediate

supervisor/foreman

for

the

person

originating

the

PWO

is

responsible

for

ensuring

a

deficiency

tag

is

hung, if

appropriate.

Section

8. 1

delineates

deficiency

tag

hanging

requirements.

During

the

walkdown

numerous

tagging

discrepancies

were

identified.

The

discrepancies

included

but are not limited to the following:

PWO Ta

s Missin

, in the Plant

TAG¹

a)

22170

b) 41681

c) 40869

WR¹

XA 891016122630

XA 891104132451

XA 900321162206

PWO¹

Not- Avai l abl e

3060

Not Available

PWO Ta

s Not Hun

WR¹

PWO¹

a)

XA 891026171224

7253

b)

XA 891220193035

5858

c)

XA 891227133648

7489

d)

XA 900207130804

3107

e)

XA 900404191500

5065

f) XA 900502033049

Not Available

Additionally, there

were

three

PWOs for which tags

were

hung

on

the

EDGs

which

had

been

closed

out;

the

tags

were

not

removed

after

work

completions

Section

8.6.9.

of

AP-00143

requires

that

after

completing

the

work,

the

Journeyman/Technician

removes

the

deficiency

tag.

These

tags

included:

PWO Ta

s Still Hun

Subse

uent to

NPWO Closure

TAG ¹

WR¹

PWO¹

END DATE

a)

43110

b) 43788

c) 32711

XA 891224174555

7512

01/05/89

XA 900207172006

7819

02/12/90

XA 890316153313

7622

05/24/89

There

was also

an

PWO (tag ¹32268,

WR¹

XA 900418170923),

hanging,

the

NPWO for which

had

been

canceled.

PWO 5057

(XA

900404192920)

was

statused

on

NJPS

as

being

ready

to

be

worked.

However,

the

work

completion

and

tag

removal

evidently

occurred

on

May

2,

1990.

Subsequent

to

the

inspection,

tags

43110

and

43788

were

removed

and apparently

the

IEC supervisors

were instructed to review the

requirement

to remove tags

subsequent

to work completion.

10

Additionally,

the

licensee

stated

that

subsequent

to

the

inspection,

"I 5

C training

has

been

sent

a

memo to include

this

item in their periodic training for journeymen."

These

tags

would have

been

removed if the

requirement

for attaching

the tag to the applicable

NPWO (section

8.6.9 of AP-00143)

was

observed.

However,

neither

plant

NPWO tags

nor control

room

tags

are attached

to

NPWOs as required.

In

summary,

these

. discrepancies

(identified

above)

are

significant

based

on

the fact they demonstrate

a significant

deficiency

in

the

tagging

process,

as

well

as,

making it

difficult for

operators

and/or

maintenance

personnel

to

ascertain

whether

or not

equipment

is deficient.

This

could

'otentially

to operation

of defective

equipment

and/or

non-operation

of equipment

which is actually fully operative

(due

to

a

tag

which

was

not

removed).

Based

on

the

above,

this

item 'is

considered

as

further

examples

of

apparent

violation 50-335,389/90-09-01

d.

Surveillance

Testing

The

inspection

team

reviewed

the

p'rocedures

for and monitored the

operations

and

I8C department

perform surveillances

'on

( 1) channel

functional test of the

Engineered

Safeguards

Actuation

system,

(2)

Auxiliary

Feedwater

System

flow indicator calibration

(Unit-2),

(3)

the

turbine

over-speed

test

for

unit 1,

(4)

monthly

calibration

of the

NIs,

and

(5)

monthly functional test

of the

Reactor

Protection

system.

All

of

the

survei llances

were

performed

satisfactorily

and

in

accordance

with

the

respective

procedure.

There

were

two

surveillances

(discussed

below)

in

which weaknesses/discrepancies

were identified by the inspectors:

1)

Engineered

Safeguards

Systems

On

May

9,

1990,

the

inspector

witnessed

the

channel

functional

testing

of

Engineered

Safeguards

System.

This

testing

was

performed

in

accordance

with

18C

Procedure

2-

1400052,

Engineered

Safeguards

Actuation

System

-

Channel

Functional

Test,

revision

16.

This test

was

professionally

conducted

by

skilled

I&C 'echnicians,

with

no

test

anomalies

identified.

The

technicians

were

cognizant

of the

potential

impact

of

improper

test

performance

(i.e.

safeguards

actuation

or

potential

trip)

and

were

very

conscientious

in

procedural

adherence,

as

well

as,

anticipatory

of any

expected

annunciations/alarms.

One test

weakness

was

observed

however,

in that,

the

control

board

operators

and

the

technicians

performing

the test

were

not

verbally

communicating

prior

to

test-induced

alarm

annunciation

on the

RTGB.

When

the

inspector

questioned

the

operator

as

to

how

he

knew that

the

functional

testing. was

the

alarms'/source,

he

stated

that

he

expected

safeguards

alarms

since

he was aware the test

was being conducted.

11

Upon

discussion

with

other

operators,

they

informed

the

inspector

that

other

redundant

indication

was

available

to

indicate

that

the

alarm

was

test-induced.

The

operator

acknowledging

the

alarms

agreed

that this verification, with

other

indications,

should

be

accomplished

prior

to

alarm

acknowledgement.

Additionally,

the

inspector

questioned

why

the

operator

could

not informally follow the

expected

alarm

sequence

in the

procedure,

or

more closely

communicate

with

the

technicians

during

the

testing.

Subsequent

to

this

discussion,

the

IEC technicians

performing

the test

gave

a

verbal

warning

to

the

control

board

operator

prior

to

generating

an alarm.

The inspector

noted

a strength

during the test,

in that,

one

of the

technicians

routinely conducts

the

Unit-2 safeguards

channel

functioning

testing.

As

a

result,

he

was

very

familiar with test

methodology,

as

well

as,

test

sequence.

This practice

should

preclude

most

problems

encountered

due

to

inexperienced

test

personnel

and

also

increased

test

efficiency.

The

inspectors

noted

that

during

performance

of the

monthly

NI

calibration

that

the

I&C

technician

and

the

operators

effectively

communicated

throughout

the

test.

The

technician

alerted

the

operators,

to

alarms

prior to

initiation

and

the

operators

routinely

acknowledged

this

communication

when

the

alarms

annunciated.

During

the

NI

calibration,

the

18C supervisor

noted that

one of the

meters

did

not

return

to

normal

indication after

the calibration

and

stopped

the

technicians

from

proceeding.

He

notified

the

ANPS

and

recommended

a

PWO

be initiated to correct

the

problem

prior to

continuing

with

the

calibration

of

the

other channels.

Auxiliary, Feedwater

System

During

an

evaluation

of the

records

associated

with Unit

1

initial

startup

from

the

1990

refueling

outage,

the

inspector

reviewed

the April 13,

1990,

"Auxiliary Feedwater

Period

Test",

Operating

Procedure

1-070050,

Revision

29.

During this

evaluation,

the

inspector'oted

that

discharge

pressure

generated

by

the

1C

(SDAFW)

pump

was

1350

psig.

The

TS

required

minimum

pressure

per

4.7. 1.2 a.2.

is

1342

psig.

Due to the

small

degree

by which the

pump

passed

its

surveillance,

the

inspector

inquired

as

to

the

discharge

pressure

gauge's

(PI-09-7C)

accuracy.

PI-09-7C

is

a locally

mounted,

2500

psig,

Ashcroft

Duragauge

pressure

indicator

with

a

plus

or minus

.5 percent

(12.5

psig)

accuracy.

The

inspector

attempted

to verify that

this

plus

or

minus

.5

percent

instrument

accuracy

was

included

in the

TS

value

of

1342

psig,

as

the

pump

may

have

been'roducing

only

1337.5

psig

discharge

pressure

when

a

conservative

error

(-12.5

psig)

was taken into account.

12

The inspector

was

informed that the

TS

minimum value of 1342

psig

includes

a

10.9

percent

margin

from

the

applicable

accident

analysis.

Pe'r

a

memo

from

JPN

to the site,

"This

10.9

percent

margin

more

than

accommodates

for

the

1/2

percent

instrument

inaccuracy

associated

with the

local

1C

pump

discharge

pressure

gauge".

'The

inspector

agreed

that

even

at

1337.5

psig

the

accident

analysis

could easily

be

met.

However, it was

not determined

whether

or

not

the

pump

actually" developed

greater

than

1342

psig

discharge

pressure

as

required

by

TS.

The

inspector

questioned

the

lack

of

administrative

margin

between

the

TS

and

the

periodic

test

and

noted

that

the

Unit

2

periodic

test

contains

a

minimum discharge

pressure

which is greater

than

that of TS.

Upon

review of the

pump's

performance

for the past year

and

five

months,

it

was

noted

that

the-

discharge

pressure

developed

during

the

April

13,

1990,

test

was

the

lowest

over that time interval.

The

inspector

then

reviewed

the calibration

records

for the

instrument

subsequent

to its

replacement

in. December

1988.

On January ll,

1989,

the

read

from

5 to

15 psig

high

on all

but

the

bottom

(0 psig)

and full scale

(2500

psig)

calibration

points.

In less

than

one

month,

the

had

exceeded

its plus or minus

12.5

psig

tolerance

for

two test

points.

The

only

adjustments

made

to

the

were

to

bring the

two test points to 2.5 psig within tolerance (i.e.

as=fourid

indicated

15

psig

high, as-left indicated'0

psig

high).

On April

11,

1989,

the

was

again

found to

be

out of tolerance

at. two test points

(15 psig high),

and

was

adjusted

to read

0 psig to

10 psig

low

on all

but

one test

point (as-left

for this

point

was

plus

5 psig).

In less

than

five months

from installation,

this

exceeded

its

specified

accuracy

prior

to

two

calibrations

(only

three

months

apart).

The

required calibration

frequency

is

an

18

month interval.

On April 2;

1990,

the

was calibrated

with the

greatest

differential

between

desired

output

and

actual

at

plus

10

psig.

This test

point

was left "as-

found".

However,

When

thi s

point

was

left

at

plus

10

psig

on

January

11,

1989,

three

months

later it

had

exceeded

its

plus or minus

12.5 psig tolerance.

As

a result of the

above,

three

weaknesses

associated

with the

Periodic

Test

and

the

gauge,

were identified.

The first and

second

test itself,

in that

the

pressure

(20 psig

increments)

can

only

be

read

to

the

nearest

10

psig

mark.

The

test

specified

1342

psig

as

the

minimum acceptable

value which is

difficult to discern

from the

gauge.

Associated

with this

inability to

read

this specific

value,

is

the fact that

on

the calibrations,

the

is

sometimes

read

to

the

5 psig

increment.

13

The

second

weakness

is that

the

surveillance

test

does

not

contain

an administrative

margin

from the

min.imum

TS value.

As

discussed,

Unit-2

TS

does

contain

an

administrative

margin

as

does

standard

industry

practice

in

this

area.

The'hird

weakness

is that

the

technicians

performing

the

calibrations

often

do

not

adjust

the

toward

the

desired

pressure,

i.e.

the

is often left at

the

"as-

found"

reading,

thus

eliminating

the

amount

of margin

for

drift/change

between. calibrations.

In

summary,

the

degree

and

frequency

by which this

has

consistently

read

high

.during

calibrations,

coupled

with

non-conservative

calibration

practices,

does

not

provide

a

high degree

of confidence

that this

gauge will maintain its

specified

accuracy

between

tests

and/or

calibrations.

Additionally,

the

concern

is that

at

the

lower

discharge

pressures

(e.g.

1350

psig)

the

SDAFW

pump

may

not

be

actually

generating

a

discharge

pressure

greater

than

1342

psig,

as required

by TS.

Additionally,

the

Unit-1

turbine

overspeed

test

was

well

coordinated,.

with

effective

communications

(repeat-backs)

within the

control

room with activities

in the

control

room

being

well

controlled

during

the

test.

This

item

is

considered

as'n

inspector

follow-up

item

(IFI

50-

335,389/90-09-04)

Interviews

The control

room operators

stated

during interviews that

some

STAs

would

go

an entire shift without entering

the control

room unless

specifically

called.

Discussions

with the

STA

supervision

and

operations

supervision

indicated

that

the

STA is

by design,

an

independent

entity,

and that

STAs

do

go into

each

control

room

periodically during the shift.

There is not

a requirement

for the

STA to enter

the control

room,

only that

they

be

aware

of plant

status.

The

problem

may

be that

the

STA is

in fact,

performing

the

appropriate

duties

and

routinely entering

the

control

room.

However,

the visibility of the

STA may need to be heightened.

During

the

interviews

with

licensed

RO

and

SRO

operators,

the

inspector

asked

questions

of

the

operators

to

determine

their

ability to

use

the

off-normal

and

emergency

procedures.

The

operators

demonstrated

adequate

procedural

knowledge

with

one

exception.

Two of seven

operators

incorrectly

used

the Diagnostic

Flow Chart

contained

within EOP-l,

"Standard

Post

Trip Actions".

The diagnostic

flow chart

in

EOP-1 is not consistent

with the

CE

Owners'roup

guidance

shown

in

CEN-152,

Revision

3,

"Combustion

Engineering

Emergency

Procedure

Guidelines",

with respect

to the

transition

to the

FRP if the reactivity control

safety

function is

not

met.

The

licensee's

basis

for the difference

was

acceptable

and was addressed

in training.

14

However,

two operators

did not

use

the

flowchart correctly

when

placed

in

a scenario

condition requiring

a transition to the

FRP.

The facility has

stated

that they

intend to revise

the

procedure

and reemphasize

the proper

use of the flowchart in training.

f.

Observe on-the-spot

changes

Control

of

TCs

to

procedures

was

reviewed

in both control

rooms.

The controlling

procedure

requires

temporary

changes

to

be

incorporated.

into the

respective

procedure

within

90

days.

Of the eight

TCs

reviewed

that

were

greater

than

90

days old, three

had not been

incorporated

into the respective

procedures.

The

ANPSs

promptly

took corrective

action

and

voided the outdated

TCs.

The facility stated that

a

new system

had

been

implemented for control of temporary

changes

and that

an oversight

had occurred,

in that,

the, responsible

department

heads

were not being notified of the

needed

change.

The

TC

system

had

been

recently audited

by the site quality assurance

department

(Audit

Report

QSL-OPS-90-731,

exit

date

April 19,

1990)

and the

same

problem,

was identified.

However,

licensee

corrective action could not be evaluated

since corrective

actions

were still on-going.

This

item is

considered

as

an

inspector follow-up item (IFI 50-335,389/90-09-05).

2)

During

the

review of the

temporary

change

system, it

was

noted

that

the facility's periodic

review of procedures

did

not

appear

to

be

in compliance with their commitment in the

FSAR and

TS.

The

FSAR,

section

17.2,

cites

the

FPL

TQA as containing

the

details

of the Quality Assurance

Program for St.

Lucie.

The

TQAR (Appendix

C,

Revi sion

7)

commits

to

Regulatory

Guide

1. 33,

Rev.

2,

which

endorses

ANSI

N18. 7-1976

(page

2),

and

further

states

that

FPL's

method

of

addressing

specific

paragraphs

of ANSI-N18.7 is

addressed

in

TS Section

6 (page

4).

TS section 6.8.2

(page

6-13)

states,

in part,

"Each

procedure

...

above,

...

shall

be

reviewed periodically

as

set

forth

in

administrative

procedures'."

Administrative

procedures

(QI 5-1

and

QI 5-5)

state

(paragraphs

5.10.1

and

5.3.7.A,

respectively)

that

procedures

shall

be

reviewed

at

least

once every

36 months (+/- 6 months).

USNRC

Regulatory

Guide

1.33,

Rev

2,

endorses

ANSI

N18.7-

1976Property "ANSI code" (as page type) with input value "ANSIN18.7-1976" contains invalid characters or is incomplete and therefore can cause unexpected results during a query or annotation process.;

paragraph

5.2. 15 of ANSI .N18..7 states,

in part,

"Plant

procedures

shall

be

reviewed

...

no

less

frequently

than

every two years

15

The

Standard

Review

Plan

(NUREG-0800,

formerly

NUREG-75/087)

for section

17.2 of the

FSAR states;

in paragraph II:

acceptance

criteria [for the

gA program]

include

commitments

to

comply

with

the

regulatory

positions

presented

in

he

appropriate

issue

of the

Regulatory

Guides

...

Exceptions

and

alternatives

to

these

acceptance

criteria

may

be

taken

provided

adequate

justification is

given'

"

Section

17.2

references

section

17. 1;

paragraph

2.8.3 of 17. 1 states

"The

applicant ...

commits to comply with the

regulatory

position

in the

appropriate

issue

of the

Regulatory

Guides;

...

Any

alternatives

or

exceptions

are

clearly

identified

and

supporting information presented

in the docket."

A review of the facility's records

indicated that procedures

had

been

reviewed within three

years;

the facility appears

to

be

properly

implementing

their

procedure.

However,

the

licensee's

administrative

documentation

does

not

appear

to

address

the

justification

for

not

performing

a

24

month

review

vice

a

36

month

review.

The

NRC will

review

historical

documents

covering

the

period

of

NRC

acceptance

of the licensee's

TgA to verify this exception,

this

item is

considered

as

an unresolved

item (UNR 50-335,389/90-09-3).

g.

Over time

The inspectors

verified that Operations

management

is'ognizant

of

excessive

overtime utilization

and

pre-approve

excessive

overtime

when

required.

The

inspector

reviewed

overtime pre-authorizations

dated January

20,

1989,

and January

29,

1990,

to verify a proactive

cognizance

of

excessive

overtime.

NRC

Inspection

Report

90-02

performed

a detailed

review of selected

individual's

overtime

and

this aspect

was not reviewed during this inspection.

h.

Critical Systems

Monitoring Parameters

The

licensee

has

instituted

a

mechanism

by

which

to

monitor

critical

system

parameters

for

possible

trends.

This

system

trends

such

parameters

as:

bleedoff

flow,

containment

particulates,

RCS,

leakage,

bearing

temperatures,

condenser

backpressures,

charging/letdown

mismatch,

and

CCW

HX differential

pressure.

This

system

has

proven

beneficial

to

the

licensee,

in that 'they

have

been

able

to Inonitor

and

prevent

potential

component

fai lures/intolerabilities.

For

example,

a

trend

with

Unit-2

2A2

RCP bleedoff

flow had

shown

an

increasing

trend

from

March

2 to April 21,

1990,

thus allowing the operations

department

time

to

examine

potential

root

causes

and

applicable

corrective

action -on

a

more

proactive

basis.

The

inspector

considered

this

program

to

be

a strength

and exemplifies

proactive

involvement in

equipment/plant

performance.

16

Licensed Operator Requalification

10 CFR 55

paragraph

55.59(a)(2)

requires

licensed

personnel

to

participate

in requalification

and

to participate

in the

annual

examinations.

In 1988

and

1989,

three

licensed

personnel

from the

training staff were

exempted

from all or portions of the required

examinations,

based

on participation

in

the

preparation

and/or

administration

of

the

examinations.

Although

the

facility's

current

program

may allow. this,

NUREG-1262,

"Answers to Questions

at

Public Meetings Regarding

Implementation of Title 10,

Code of Federal

Regulations,

Part

55

on Operators'icenses",

NUREG-1262,

Question

345

(pg

94)

states,

in part:

"... will the

SRO

who writes

the

performance

exam,

and is thus

exempt

from taking the

exam for that

'ear,

comply with this [55.59(a)(2)]

requirement?"

Answer -" it is

the

Commission's

intent that all licensed

operators

be enrolled in

the

requalification

program

and

take

the

requalification

exams;

further,

an individual must take

an

exam that

he did not write or

review."

Specifics

of

the

exemptions

for. personnel

who

passed

licensing

examinations

during

that

year;

who

did

not

take

the

requalification

exams is listed as'ollows:

1)

Trainer

A

in

1988,

exempted

from the operating

portion of

the

examinations

based

on

participation

in

the

development

,and administration of those

exams.

2)

Trainer

B -

in

1988,

exempted

from all

portions

of the

examinations,

written

and

operating,

based

on participation

in the

development

and- administration

of the

exam.

In 1989,

exempted

from

the

written

examination

and

the

walkthrough

part of the

operating

examination

based

on participation

in

the

development

and

review

of

the

examinations,

and

administration of the walkthrough portion.

3)

Trainer

C - in

1988,

exempted

from the operating

portion of

the

examinations

based

on

participation

in

the

development

and

administration

of the

exams.

In 1989,

exempted

from the

written

examination

and

the

walkthrough

part

of

the

operating

examination

based

on

participation

in

the

development

and

review

of

the

examinations

and

administration of the walkthrough portion.

The

licensee's

practice

of

allowing

licensed

personnel

who

participate

in all

phases

of the

requal

exam

process

to

be

exempted

from portions

of the

exams

does

not

meet

the intent of

10 CFR 55 paragraph

55.59 (a)(2)

and

as further interpreted

by

NUREG 1262

answer

to

question

number

345.

The

licensee

needs

to

strengthen

administrative

guidance

in this area

prior

to the

exam.

This

item is considered

as

inspector

follow-up item

(IFI 50-335,389/90-09-06).

17

Sur vei 1 1 ance/IST/Cal ibrati on

/

The

inspectors

observed

a

number of surveillance

tests

being

per formed

by licensee

personnel

in the mechanical,

electrical,

and instrumentation

and control

maintenance

groups.

The

purpose

was

to verify required

administrative

approvals

were

obtained

before

testing

was

started,

testing

was being accomplished

by qualified personnel

in accordance

with

current

approved

procedures

and

the

procedures

were adequate

to meet the

TS requirements.

Also,

were test

instruments

calibrated,

test

results

met

specification

acceptance

criteria,

test

discrepancies

or

problems

were documented

and properly resolved in

a timely manner.

a.

Observation of surveillance test performance:

The

inspector

witnessed

the

performance

of

Electrical

Procedure

0960068,

"125 Volt

DC

System

Weekly Maintenance",

Revision

0,

for

Battery

2D,

and

Electrical

Procedure

0960163,

"125 Volt

DC

System

Weekly

Maintenance",

Revision

2, for Battery

2A.

These

procedures

were

not

accomplished

in

the

approved

step

sequence.

The inspector'as

informed

that

the

procedures

were

generally

performed

in

the

step

sequences

witnessed.

Due

to

the

awkward

nature

of

the

written procedural

steps; it was

not efficient to follow the

step

sequence.

Additionally,

the

installed

amperage

and

voltage

did not

have

a

scale

that

could

be

read

to"

the

precision

required

by the

procedure.

The

DVOM reading

was

more

prec'ise

and

the installed

were

only usable

for

general

readings.

Goggles

were

not

worn

during

the

performance

of these

procedure

as

required

in the

Limits and

Precautions

sections

of this procedure.

2)

The

inspector

witnessed

the

Unit

2

control

room

actions

associated

with

18C

Procedure

2-1400064P,

"Installed

plant

instrumentation

calibration

(pressure)"

-

Revision

6,

pages

19

and

20,

which

pertained

to

Flow Calibration.

The

inspector

noted

that

the

upper

range

readings

were off scale

high

on

the control

room

chart

recorders

and

main

control

board

indicators.

The

technician

recorded

values

for these

reading

that

were

obtained

from over-ranged

instruments

in

the

work

package.

The

ILC technician

amended

the

reading

for

FR-09-2A2 to

read

400+ to reflect off 'scale

high

and

stated

that

a

PWO would

be written.

The

inspector

reviewed

the

completed

work package

and noted'hat

the

reading

for

FR-09-2B2

was

recorded

as

400,

however

the

.control

board

indication

was

above

the

scale

markings

when

the

test

was

run.

The

inspector

questioned

IEC

management

about

the

accuracy

of

instrument

reading

in

the

upper

range

of the

.

scale

and

about

the

generic

implication of this situation.

The inspector

was

informed that specialists

were

not

allowed

to take

data

points

that

were

above

or below scale

readings

and

that

the

appropriate

manager

would

investigate

this

question

further

and

take

the

actions

necessary

to prevent

this from happening

in the future.

18

3)-

The

inspector

witnessed

the Unit

1 local

actions

associated

with

Step

8.3

of

Operating

Procedure

0010133,

"Reactor

Engineering

Power

Ascension

Program",

Revision

8,

Turbine

Overspeed

Trip

Test.

The

procedure

step

required

conforma'tion

that

the trip point

was

below. 1998

rpm.

The

licensee

attached

a

temporary

on

the

turbine

front

standard

to verify this

reading

locally.

The

inspector

noted

that.

pages

11

through

16 of the

procedure

were all

incorrectly identifi.ed as

page

21.

b.

Review of completed surveillance test

packages

The

Inspector

reviewed 'the

performance'f

the

surv'eillance

'rocedures

associated

with

work

request

XA880516142036,

motor

overhaul,

for

auxiliary

pump,

which

was

accomplished

in

accordance

with

maintenance

procedures

090062,

"Grounding

or

Testing

of

High

Voltage

(4. 16

or

6.9KV) Motors",

Revision

5,

and

1-0950161,

"The

Overhaul

of

Auxiliary Feedwater.

Pump

Motors

PP

1A and

1B",

Revision

0.

Comments:

2)

3)

Procedure-

1-09050161

step

9. 1. 2,

9.2. 14,

9.2. 23,

9.3. 3,

9.3.8,

9.3.9, all reference

form 3918,

this

form

was

not in

the

completed

work package.

The

inspector

was

informed that

although

the

procedure

required

the

form to

be

completed

the

information

was

actually

recorded

in

the

journeyman

work

report.

The

procedures

of thi s

type

are

under

going

an

upgrade

process

to eliminate this

form.

This inspector

was

informed that this

procedure

had

not

been

updated,

but

was

on the procedure

upgrade

schedule.

The

inspector

attempted

to

review

operations

procedure,

2-0910053,

performed

under

work

request

XA890323110900,

'"Annual

Auto

Load

SEQ

Relay

Test

2B

Diesel",

dated

March

23,

1989,

and

operation

procedure,

2-2200062,

"2A

Emergency

Diesel Generator

Periodic Maintenance

and Inspection",

Revision

10,

performed

under

WR

XA890621094221,

semi-annual

PM of

2A,

dated

July 4,

1989.

The documentation

in the

micro film storage

system

was

not sufficiently

complete

to

evaluate

this

item

or

to

determine

which portions

of

the

procedure

should

have

been

completed.

The

inspector

was

provided

with

a

reasonable

explanation

of the

documentation

available

after additional

engineering

review.

However,

the

documentation

in

the

vault

would

not

have

provided

useful

records wit) out this supplemental

engineering

review.

The

inspector

reviewed

Operations

Procedure

no.

2-0700050,

"Auxiliary

Feedwater

Periodic

Test",

Revision

16.

The

documentation

for observed

parameters

for this

procedure

was

.inconsistent

between

performance

under

similar circumstances

and similar plant- conditions.

19

Portions

of the

data

recorded

was

not physically possible

such

as

a

steam

ring pressure

of 1660 psi

which is developed

from steam

generator

pressure

(Code

safety

set

point

are

set

at

1000

psi)

or

a

steam

driven

auxiliary

pump

turbine

inlet

pressure

of

0

psi

which

could

not

have

produced

a

measurable

pump

discharge

pressure

(a

discharge

pressure

of

1340

psi

was

recorded).

Five

examples

of this

were reviewed

and are

enumerated

below:

Date

Steam Inlet

Discharge

Pressure

Ring

Delta

Pressure

e

. ~Pft

a) 2/13/90

b) 4/10/90

c) 2/13/90

d) 1/16/90

e) 2/15/90

180

50

860

0

180

1350

780

3075

1350

790

3073

1350

790

3074

1340

1660

3054

1340

780

3051

The

licensee

reviewed

,the

test

results

for

the

AFh'umps

listed

above.

The

licensee

acknowledged

that

steam

inlet

pressures

of 0,

50,

or

180 psig

should

have

been identified

during

the

control

room

review.

Additionally, it

appears

that

the

steam

inlet pressure

of

0

and

the ring pressure

of

1660

psig

may

have

been

read

from gauges

that

were

reading

incorrectly and were not included in existing

PWOs.

e

The

inappropriate

values

that

were

recorded

in

the

surveillance

procedures

do

not

appear

to

have

affected

the

operability of the

pumps,

in that existing

data

from other

sources

was

available

to

indicate

that

the

information

recorded

in

the

surveillance

procedures

was

incorrect.

The

licensee

did not appear

to establish

an

appropriate

level

of

attention

to detail

in the

performance

and

technical

review

for this procedure.

c.

Non technical

specification surveillance

program

Safety Injection Tank

The

inspector

reviewed

the

last

6

performances

of

Operating

Procedure

1-0410025

and

2-0410025,

"Periodic

Stroke

Test

of

SIT

Discharge

Check Valve", Revision

2

and

requested

an explanation

of

the flow rates

listed

on sheet

7 of 7.

The flow rates

are listed

below:

Date

1) 7/24/88

2) 12/8/85

3) 2/23/87

4) 4/28/86,

5) 10/4/87

6) 2/11/89

Aj

A2

2216

1662

2286.3

N/A

. 1778

3325

1772

1908

1596.25

4469

1839

2043

Bl

B2

1662

N/A

1760

1813

1653.9

1516

4469

3192

2299

2043

20

This test is

now conducted

in the

ASME section

XI test

procedure.

Stroke times

and flow rates

were not measured

during the last Uni,t

1

outage.

The

check

valve test

has

been

replaced

by check

valve

disassembly.

The

explanation

of

the

widely varying

flow rates

was that

the

conditions

such

as

refueling cavity level

and

SIT pressure

would

cause

the

changes

in the flow rates'he

inspector

observed

that

for identical conditions, the flow rates

varied

by as

much

as

2873

gpm

( 1596

gpm

vs.

4496

gpm).

The

inspector

questioned

the

technical

adequacy

of

the

licensee's

explanation

which did

not

appear

to

satisfactorily

explain

the

differences

in

the

flow

rates.

The

inspector

discussed

the rational

for the differences

and the

licensee

agreed

that there

were

no reasonable

explanations

for

the

data

recorded.

Additionally,

the

records

for

this

procedure

were difficult to retrieve

from

document

control,

in

that it required

the

test

engineer

to

provide

the

test

dates

before

document

control

could

retrieve

the

records.

The

information

stored

in

document

control

was

not

sufficient

to

provide

qualitative

or

a

quantitative

explanation

for the

flow

rates

recorded.

d.

Instrument calibrations

1)

The following instruments

were identified during

the

control

room

walkdown

as

having

erratic

reading

when

'compared

to

other

channels

of

similar

instrumentation

or

as

having

indicated operation

outside

the normal operating

band:

Unit 2,

FW/AFW to

SG

2B1

Pl - The indication

appeared

to

be

erratic

when

compared

to the

other

channels.

Additionally,

the

instrument

was

operating

primarily in the

red

zone.

The

instrument

was within the

required 'calibration

frequency

and

was

found

to

be within tolerances

and

no

adjustments

were

initiated.

A

PWO

was

issued

to repair

the

instrument.

See

note

1.

Unit

2,

Intake

cooling

water

header

A 'ressure

-

This

instrument

is operating

in the alert

range

~

The

operators

on shift indicated

that this

was

the

normal

operating

zone

for this instrument.

See

note 2.

Unit

2,

Intake

cooling

water

header

B

pressure

-

This

instrument

is

operating

in the alert

range.

The

operators

on shift indicated

that this

was

the

normal

operating

zone

for this instrument.

See

note 2.

Unit

2,

SG

Level

2A

LIC

9013D -

The

level

indication

appear

to

be erratic

when

compared

to

the

other

channels.

Adjustments

were

made to bring the gauge into tolerance.

Unit 2,

INSTR Air

8

STA AIR Pressure

-

These

instruments'aximum

operating

band

was

above

the

indicated

normal

operating

band.

21

The air compressors

that

are

in these

systems

were replaced

and

the

operating

bands

on

these

did not

appear

to

have

been

updated

to reflect the

new operating

range

and the

higher system operating pressure.

See note 2.

Unit

2,

2B1

Cold

leg

temp

TI1125

This

instrument

was

operating

in the

red

zone.

This

instrument

was

found to

be

reading

3

degrees

above

the

TS

limit,

but

with

the

calibration

tolerance

of plus

or

minus

6.7

degrees.

The

needle

was found to be bent slightly.

See

note 2.

Unit

2,

SG

Delta

P/Total

core

flow -

PDI-1101B -

This

instrument

was

operating

in the

red

zone.

Additionally, the

indication

appeared

to

be erratic

when

compared

to the

other

channels.

PWO 43467

was issued.

See

notes

1 and 2.

Unit 2,

CCW from

HX flow - FIS-14-150 - This instrument

was operating outside

the green

zone.

See

note 2.

Unit 2,

CCW from

HX flow - FIS-14-15A - This instrument

was

operating

outside

the

green

zone

and

was

pegged

off

scale

high.

The" inspector

was

informed

that this 'eading

was

correct

based

on

actual

operating

parameters.

See

note

2.

Unit 2,

CCW from

HX flow - FIS-14-15C

Thi s instrument

was

operating

outside

the

green

zone

and

was

pegged

off

scale

high.

The

inspector

was

informed that this

reading

was

correct

based

on

actual

operating

parameters.

See

note

2.

Unit

1,

containment

pressure

upper

alarm

set

point - all

channels

-The

upper

set

point

appears

to

be

the

alarm

set

point

for

the

ILRT

(approximately

40

psi)

and

not

the

operational

alarm

set

point.

The

lower

set

point

was

at

approximately

2 psi.

The set points

on unit

1 were at

0

and

2 psi.

An operator

from Unit

2 indicated

that

he

was

not

sure if safety

set

points

were

affected

by the position of

the

alarms,

however,

he

confirmed that

some

set

points did

come

from the

SIGMA indicator.

The

inspector

was

informed

that

there

were

differences

in

the

controls

for

these

on

each

unit.

On

the

Unit

1

the

alarm

setpoint

came

off of

both

indicators

and

that

the

lower

alarm

setpoint

was

set

to

the

correct

set- point

and

the

upper

alarm,

although

active,

was

set

at

a point

where it

would not perform

any function.

On Unit

2 the

lower alarm

setpoint

performed

no

function

and

the

upper

setpoint

was

set at the appropriate

setting.

Note

1:

The feedback resistor

was worn, which caused

the

erratic

reading.

The

required

part

was

not

in

stock,

but has

been

ordered.

22

This instrument will be replaced with a

different type of indicator that is not

susceptible

to this, failure mode.

Note 2:

This instrument

was operating outside of the

normal

operating

band

as

indicated

by

operation

outside

of

the

green

area

as

evidenced

by

the

control

board

gauge.

The

inspector

was

informed

that

the color

coded

scales

were

not

intended

to

alert

the

operator

for

specific

actions.

Additionally,

the

scaling

will

be

examined

and

adjusted

as

part

of

the

changeover

to digital

meters.

2)

The

inspector

reviewed

the calculation

IC.0004,

Revision

1,

"Safety

Injection

Tank

Level

Instrumentation"

to

determine

the

licensee's

methodology

for

adjusting

calculated

setpoints

for

process

measurement

bias,

and

discussed

the

calculation with plant engineering

and

the

AE that

generated

the

calculation.

The

calculation

was

based

upon

a

containment

minimum calibration

temperature

of

85

degrees

and

was

only val"id at that point (reference

assumption

5.5

and

step

7. 10).

The

setpoint

calculation

applied

the

temperature

bias

as

an

independent

variable,

in that it was

included

in

the

borated

water

density

correction.

The

calculation

reached

an

appropriate

conclusion

that

the error

was plus or minus

3. 1 inches.

The

85 degree

was arbitrarily

chosen

to provide

a

range for the error contribution for the

Rosemont transmitter,

and although

a value of

75

degrees

may

have

been

more

appropriate,

the operational

alarm

setpoints

appeared

suitable for the application.

Maintenance

testing

t

1)

Main feedwater

regulating valve "A"

The

inspector

witnessed

1400096,

which involved

the testing

of

the

Unit

1

"A"

regulator

valve,

which

was

cycling improperly.

The

tagging

process

appeared

to

be

performed

by

an

operations

person

that

was

not

familiar with

the

valve

locations

in this portion of the

main

system

and

.

the

tagging

process

was

interrupted

by

the

prestaging

of

operations

equipment

that

was

not

needed

for

several

hour

after the testing

began.

The

maintenance

personnel

were

knowledgeable

of the testing

methodology

and

the

expected

test

results.

The

equipment

for the

maintenance

activity was

properly

prestaged

and

the

work was performed in an orderly professional

manner.

I

23

Main feedwater isolation valve "A" manual manipulation.

The

inspector

noted

the

local position

indication of M7-09-

05

was

at

20 percent

open

with the

valve fully opened

and

the

local

indication

did

not

change

when

the

valv'e

was

closed

from the

control

room.

The operations

personnel

used

a

"cheater

bar"

to apply additional

torque

to the

valve

in

an

attempt

to correct

the

errant

local

indication.

There

was

no

procedure

for closing this limitorque valve

in this

manner

using

this

method.

It

was

impossible

to

determine

the actual

torque that

was applied to the valves

seat

or the

consequences

of this action.

Without inspection, it may

be

impos'sible

to determine

the effect

on

the valve's

seat.

The

licensee

responded

to the

inspectors

question,

by issuing

a-

standing

night

order

which

stated

that

"the

use

of valve

wrenches

or cheater

bars

on

MOVs

handwheels

should

only

be

used

in emergencies."

The night order further

stressed

the

importance

of

not

using

cheater

bars

or valve

wrenches

by

stating "Significant torque

can

be

applied

to the

stem

when

the

handwheel

is

engaged.

Valve

stem

or

seat

damage

can

easily

result.

~

MOV operability

must

be verified following

any

handwheel

engagement,

prior to declaring

the

valve

or

associated

system

back

in service."

The

inspector

reviewed

several

documents

that forbid the

use

of valve

wrenches

or

cheater

bars

on MOVs.

Theses

included:

Operating

procedure

no.

0010122,

Revision

41.

Student

handout

no.

0110004,

Revision l.

Good practice

OP-216,

December

1988.

St.

Lucie lesson

plan

DN ¹4502895,

Revision 0.

The

valve

operation

was verified

by manipulating

the

valve

operator

from

the

main

control.

room.

No

operational

problems

were

noted,

however,

a

quantitative

determination

of

the

torque

applied

and

the

subsequent

effect

on

the

valve's

stem

and

seat

were

not

determined.

No

specific

tests

were

run to declare

this valve operable

other

than

the

cycling

of

the

valve.

The

inappropriate

torquing

of

the

Main

isolation

valve

"A"

was

considered

an

additional

example of lack of attention to detail.

At the

end

of the first week of the

inspection

the

valve

still

had

an

errant

local

indication

and

no

PWO

had

been

written to correct this

deficiency.

Due

to

the

fact that

the

operators

local

action

may

have

caused

damage

to

the

valves

seat,

not

taking

prompt

corrective

actions

was

considered

an

additional

example

of lack

of attention

to

detail.

The

inspector

reviewed

the

"Completed

-

Ready

to

work

package"

for

General

Maintenance

Procedure

No.

M-0017,

"Pressurizer

Safety

Valve

Maintenance",

Revision

21,

completed

February

6,

1990.

ll

~

This

package

contained

information that

the

journeyman

noted

in

the

field

at

the

time

the

work

was

completed,

the

documentation

was

generally

comprehensive

with

sufficient

information

for the

journeyman

to

accomplish

the

required

objective.

The

inspector

observed

that

steps

9.3.2,

9.3.2. 1,

and

9.2.4

reference

the

wrong

figures;

however,

these discrepancies

did not affect the procedural

results.

4

f.

Emergency

Diesel Generator

Periodic Testing

The inspector

reviewed

a select

sample

of the

1990

performance

of

operating

procedure

No.

2-2200050,

"Emergency

Diesel" Generator

Periodic Test and General

Operating Instructions",

Revision 21.

The inspector

reviewed the,

performance

of this procedure

with the

following comments:

March 21,

1990:

Page

17 of 33, the value for the lube oil filter

outlet pressure

( less

than

4 psi)

was

below the

minimum guideline

value

(5 psi).

There

were

no

plant

work orders written to investigate

this

problem

when

the

reading

was

noted.

After the

April 4,

1990,

reading of less

than

1

psi

and

the

May 2,

1990,

reading

of 0 psi,

a

PWO was

written.'arch

21,

1990:

Page

18 of 33, the value for generator exciter

(4300)

was not physically possible.

The correct

number should

have

been

less

than

125 volts.

The

number recorded

appears

to

be the

value for Bus

voltage.

March 21,

1990:

Page

32 of 33, this procedure

appears

to have

recorded

a governor rack position for both the

12 cylinder

and the

16 cylinder diesels,

these

positions

are approximately

100 times

the

normal

value, it appears

to be

a misplaced decimal.

March 21,

1990:

Page

33 of 33, this procedure

step

appears

to

have recorded

VARS instead of MVARS, the recording

of

this

reading

is

not

consistent

between

procedural

runs.

The diesel

generator

average

cylinder

temperature

decreased

(4.3

degrees)

during the run.

The inspector

was informed by the

system engineer that this

change

was

due to the

inaccuracies

of the diesel

generator

pyrometers

and

was

not

caused

by

reduction

of

diesel

generator

load.

The

50 degree

drop in cylinder

temperature

in cylinder

number

12,

the inspector

was

informed that

the

temperature

decrease

was

caused

by the inaccuracies

in the gauge

readings.

I

l ~

~

25

There

was

a differential temperature

in the thirty

minute

readings

of

170 degrees

between

cylinder

12

and

9,

the inspector

was

informed that this

was

an

acceptable

band

for the differential

cylinder

temperature

although

the

systems

engineer

identified

the

specific

requirements

for differential

cylinder

temperature

as

200

degrees

as

the

temperature

difference

to begin

actions or investigations.

This information

was

included

in

a letter from Electro-motive

Force,

dated

December

12,

1986.

April 18,

1990:

Page

33 of 33 this procedure

step

appears

to

have

recorded

VARS instead

of

MVARS.

Based

on

the rise of average

cylinder temperatures

(6.65

'egrees)

of the

12 cylinder diesel it appears

that

the

turbo

exhaust

temperature

should

have

been

higher

(reference

the

March 21,

1990,

performance

under similar circumstances

in which

a

5 degree

rise in average

cylinder temperature

produced

a

5 degree rise in exhaust

temperature).

The

inspector

was

informed that this

was with

the accuracies

of the available instrumentation.

March 7,

1990:

April 4,

1990:

Page

17 of 33 the value for lube oil filter

outlet pressure

was

below the

minimum guideline

value.

There

was

no plant work order written to

investigate this problem.

Page

18 of 33 the value for generator exciter

volts

(4300)

was

not physically possible.

The

correct

number

should

have

been

less

than

125

volts.

A general

observation

of

the

average

operating

temperature

for

the

2B diesel

(946.6

degrees)

was

28.5

degrees

higher

than

the

2A diesel

(918. 1

degrees).

The

inspector

was

informed that

these

temperatures

were

not

indicative

of

engine

performance,

but

were

the

result

of

unrelated

physical

parameters

such

as

heat

exchanger

fouling

and

wind direction.

The poor quality of recorded

data

in this procedure

demonstrated.

that the

licensee

had

an ineffective review process

and that there

was evidence of

inattention to detail

on the part of the persons

performing the test.

No violations

or, deviations

were noted within the areas

inspected.

26

4.

Administrative Controls

and Engineering

Support

The

Independent -Safety

Engineering

Group at the St.

Lucie Nuclear

Power

Plant

was

established

in accordance

with the

requirements

specified

in

TS 6.2.3.

Their function

as

specified

by TS 6.2.3. 1

is

to

examine

plant

operating

characteristics,

NRC

issuances,

industry advisories,

Licensee

Event

Reports

and

other

sources

of

plant

design

and

operating

experience

information,

including

plants of similar

design,

which

may indicate

areas

for improving

plant

safety.

The

ISEG organization

consists

of

a

chairman

and

four

ISEG engineers,

which is the

minimum

complement

of personnel

requi'red

by

technical

specifications.

In

order

to

accomplish

their assigned

mission

the

group reviews various

forms of industry

operating

experience

to determine

what problem areas

may exist at

ST.

Lucie.

From this

review,

the

chairman

assigns

projects

to

each

of

the

ISEG

engineers

for

investigation.

These

'nvestigations

take

the

form of

one

of three

types:

1)

ISEG

Evaluations,

which

are

large

scope

investigations

similar to

a

SSFI,

2)

ISEG Surveillances,

which

are

smaller

in

scope

and

may

consist

for

example

of

a walk down of

a safety

system,

or 3)

ISEG

Independent

Verifications,

which

are

even

smaller

in

scope

requiring

approximately

a

day

or

two to accomplish.

Note:

The

ISEG

chairman

has

recently

discontinued

the

Independent

Verification

type

of project

arid

plans

to

issue

this

type

of

project in the future as

ISEG Surveillances.

During this inspection

an overall

assessment

of the

performance

of

the

ISEG

was

conducted

by the

inspection

teams

This

assessment

concluded

that

the

group

has

a limited

impactg on

improvements

in

plant

safety.

This

conclusion

is

based

on

the

following

observations:

The

ISEG is staffed with only the, minimum compliment of personnel

required

by technical

specifications.

Productivity within

the

group

needs

improvement.

The

average

project takes

approximately

three

months

to accomplish

and

issue.

One project

reviewed

( ISEG Evaluation

ISE-87-005)

on the

Emergency

Diesel

Air Starting

System

took

approximately

eight

months

to

accomplish,

and

another

eight

months

to

issue

the

report.

This

evaluation

was

similar

to

an

SSFI

of

the

EDGASS,

and

was

accomplished

by

one

individual.

The length of time to accomplish

this project indicates

that the project

scope

was too large to

be

adequately

accomplished

by

one

individual.

Historically,

the

group

has

accomplished

about five to

seven

projects

per year

per

ISEG engineer.

27

Additionally, the last

ISEG Evaluation

was

issued

October 31,

1989,

the last

ISEG Surveillance

was issued

January

12,

1990,

and the last

ISEG Independent Verification was issued April 12,

1989.

At the

time

of this

inspection,

the

ISEG

had

a total

of

48

recommendations

outstanding.

Of these,

18 were

over

one year old.

The

age of these

items

was attributed primarily to the lack of an

aggressive

ISEG

program

in

obtaining

corrective

actions

from

various

plant- organizations.

Memoranda

forwarding

the results

of

ISEG

evaluations/survei llances

and

independent

verifications

do

not

require

a

written

response

from

the

responsible

plant

organization,

which firmly establishes

a corrective

action

plan,

and

a

time table for accomplishments

Additionally,

ISEG does

not

have

a

program or policy implemented,

which formally documents

and

follows corrective

actions

through completion.

As

a result,

there

is

a

lack of organized,

detailed

documentation

concerning

the

current

status

and

closeout

of deficiencies.

The

only practical

way to determine

the

status

of an outstanding

item is to discuss

the

item with the

responsible

ISEG engineer.

The development

and

implementation

of the

ISEG

Follow-up Status

System

was

the

only

positive

aspect

to

a

very

weak corrective

action

program within

ISEG.

The

IFUSS is

a computerized

tracking

system

for outstanding

ISEG

recommendations,

which

provides

a

quick

reference

to

the

status

of items.

Monthly

IFUSS

reports

have

been

issued

to

the

plant

manager

and site

vice president

for the last year.

These

status

reports

do

provide

some

added visibility to'utstanding

ISEG items.

The

new

ISEG chairman

had

recognized

a

number of these

weaknesses

prior

to

this

inspection.

Several

corrective

actions

were

completed,

during

the

inspection,

to

improve

performance.

These

included

revision

to

the

appropriate

ISEG

administrative

procedures .to require written

responses

from the plant for

ISEG

category

1

and

2

items

(NRC

concerns

and

safety

significant

deficiencies).

The

corrective

action

plans

and

commitment

dates

for category

3,

and

below,

items continue

to

be the responsibility

of the

ISEG engineer.

The

chairman

committed

to establishing

a

corrective

action

section

in all. future report files,

and

he also,

committed

to the

update

of all files with

open

items,

with the

corrective

<<action

documentation

that

is

available.

The

implementation

of

these

actions

and

improvement

in overall

ISEG

performance

is identified

as

inspector

follow-up

item (IFI

50-

335,389/90-09-7).

The

Facility

Review

Group

at

ST.

LUCIE

was

established

in

accordance

with TS 6.5.

The function of the

FRG is to advise

the

plant

manager

on all matters

which relate to nuclear

safety.

The

chairman

of the

FRG is the plant

manager

and

members

are

from the

various

disciplines

within the

plant staff.

To

accomplish

its

mission

the

FRG

reviews

the

various

documentation

concerning

the

activities which are important to safety at the site.

Oocumentation

includes for example

procedure

changes,

TS changes

and any violations

to TS, modification packages

and

LERs.

28

In order to have

a voting quorum to accomplish its assigned

mission,

at least five

FRG members

must

be present,

and

no more than

two of

these

members

can

be designated

alternates.

Minutes of all meetings

.

are

recorded

and distributed

to document

the activities of the

FRG'n

accordance

with TS 6.5. 1.8.

During this inspection

the

performance

of the

FRG was

reviewed

by

the inspection

team.

The activities

of the

FRG

were

reviewed

by

attendance

at

two

FRG meetings,

and

by review of meeting

minutes

for

approximately thirty meetings.

Overall,

the

performance

of

the

FRG was

considered

to

be excellent.

The

FRG is very active at

the site,

and

an

average

of approximately

two meetings

per, week

are

conducted

to

review plant activities.

A meeting

agenda

is

prepared

by the

FRG secretary,

and

items

which require

some

time

to review are distributed to

members

in advance

of the meeting

to

allow for detailed

review.

The

meetings

are

very

informal

and

discussion

of

safety

issues

are

very

open

and

relevant

Participation

by all

members

was very active.

The

FRG also

has

a

policy of not

reviewing

new activities

unless

the

sponsor

of the

activity is

present

to

answer

al,l

FRG questions

on 'the

subject.

The

informality of

the

meetings,

and

lack of attention

to the

meeting

minutes

did

,

however,

to

several

concerns

by the

inspection

team

which, if corrected,

would

improve

overall

performance:

During

the

meeting

on

May

8,

1990,

LER 335-90-05

concerning

a

problem

with

the

electrical

breakers

on

the

Emergency

Diesel

Generators

was

presented

to

the

FRG

for

approval.

Several

comments

on

the

technical

content

of

the

LER

were

provided

separately

to

the

LER

sponsor

by

several,FRG

members

before,

during

and after the

FRG meeting.

No vote

on approval

of the

LER

was

taken

during the meeting

by the alternate

FRG chairman.

After

the

meeting

the

inspection

team

question

whether

or not

the

LER

had

been

approved

by the

FRG.

The

team

was

informed that the

LER

had

been

"approved with comments",

which meant that the

LER would

not receive

any additional

review by the

FRG.

It was

noted

by the

inspection

team that

no listing of the

problems with the

LER was

compiled

by the

FRG

and

no

FRG

member

was

assigned

to ensure

that

all

FRG issues

were resolved.

Therefore,

the only person

who

new

the

extent

of all of the

comments

was

the

LER sponsor,

and

no

follow-, up

by the

FRG

was initiated

to

ensure

resolution

of all

issues.

This is considered

to be extremely poor practice.

A distinct difference

in

the

area

of

item

approval

was

noted

between

the. meeting

conducted

by the

chairman

on April 26,

1990,

and

the alternate

chairman

on

May 8,

1990.

The

chairman

asked,

for

each

item,

whether

the

FRG

members

had

any

problem

with

approval

of th'e

item.

The alternate

chairman

took

no

such

vote

on

the

items

in the

May 8,

1990.,

meeting.

Failure to take

some

sort

of vote

on

each

issue

is

considered

to

be

a

week

practice,

especially for items

where

there is

an extensive

discussion

of the

item.

Review of meeting minutes

noted several

weaknesses:

c<

e

29

'1)

Meeting

minutes

for the

most part consisted

of

a listing of

'he

items

approved

by the

FRG.

Minutes

do

not include

any

of

the

FRG

discussion

that

accompanies

'many

items.

Also,

the

minutes

do

not reflect

items

rejected

by the

FRG, with

the reason

for rejection.

2)

3)

Meeting

minutes

are

always

signed

out

by the plant manager.

This

is

the

case

even

concerning

meetings

which

are

not

attended

by

the

plant

manager.

Meeting

. minutes

should

be

reviewed

and

approved

by

at

least

one

FRG

member,

who

understands

the

technical

issues

discussed

at

the

meeting

and

who attended

the meeting.

This is necessary

in order to

verify that

the

minutes

reflect

what actually

occurred

at

the meeting.

Meeting

minutes

are

not distributed

in

a

timely fashion.

Review of this

area

noted that

minutes

for

32 site

meetings

remain

undistributed

over

one

month after

the

meetings

were

conducted.

I

The weakness

in the

FRG area

are identified as

inspector

follow-up item

(IFI 50-335,389/90-'09-8).

C.

Industry

Operating

Experience

Program

was.

reviewed

by

the

inspection

team

to evaluate

the

implementation

of the

licensee's

program.

This

was

accomplished

by

review

of

the

licensee's

evaluation

and corrective

actions

for

a

sample

of several

IEBs,

LERs,

and

Generic

Letter s.

This

review

concluded

that

the

licensee

has

an

adequate

program

to

address

these

issues.

No

weaknesses

were identified.

The

items

reviewed

and

the details of

the reviews are

as follows:

1)

LER

89-007,

Unit

2:

This

LER discusses

a

manual reactor trip which

was

initiated

on

September

23,

1989,

due

to

a

dropped

CEA in

one

group,

followed

by four dropped

CEAs in

another

group.

Recovery

from this trip was

complicated

by

inadequate

performance

of

a

steam

bypass

control

valve,

failure

of 'one

of

the

Auxiliary

Feedwater

flow control

valves,

and

failure

of

the

limit switch

on

another

control

valve.

The

team

reviewed

the

results

of

the

in-

house

investigation

of

the

problems

encountered,

which

caused

the trip, 'and

the

problems

experienced

in recovery

from the trip ~

The investigation

of all of these

problems

was

thorough

and

in

all

cases,

except

the

steam

bypass

valve

problem,

identified the root cause

of each

problem.

The unsatisfactory

performance

of the

bypass

valve -could not

be duplicated after

the trip recovery

was completed.

Corrective actions

to correct

the

immediate

problem

and

to .prevent

similar

problems

were,

adequate.

The

inspection

team

focussed

on

the

retesting

of

components

after completion of maintenance

work.

Adequate

post

maintenance

testing to verify operability was accomplished.

~

30

LER

89-007,

Unit

1:

This

LER reported

a violation of the

one

hour time limit for bypassing

a failed 4160V channel,

in

accordance

with

TS 3.3.2

~ 1

action

12,

when it failed its

monthly

surveillance.

The

problem

was

caused

by

inadequate

procedures

for

bypassing

the

affected

channel.

The

inspection

team

reviewed

the

revised

procedure,

and verified

that

the

other unit

had

been

reviewed

for similar existing

conditions.

LER

89-009,

Unit

2:

This

LER

reported

that

containment

purge

isolation

valve

FCV-25-5

had

failed its

local

leak

rate

test

on

November

28,

1989'he

inspection

team

reviewed

the

licensee's

corrective

action.

Emphasis

was

placed

on

ensuring

that

th'e

testing

frequency

(which

has

been

increased

to

every

six weeks),

and

interim corrective

actions

as

specified

in the

LER were

being maintained.

This

action

was being

performed

in accordance

with the

licensee's

commitment.

Permanent

corrective

action for this'eficiency

is

scheduled

to

be

completed

during

the

upcoming

Unit

2

outage.

LER

88-008,

Unit

1:

This

LER

reported

a reactor trip

on

September

20,

1988.

This trip was

caused

by

a

power

being

inadvertently

lifted by

IEC,

when troubleshooting, the

Steam

Generator

Feed

Regulating

System

for

the

cause

of

minor

Steam

Generator

level

swings.

The

troubleshooting

called

for

removal

of

one

wire

from

a

terminal

connection.

A second

wire (the

power

supply wire)

was

also

connected

to

this

terminal;

but

was

not

independently

secured

from the wire being'removed.

As

a result,

the

power

wire eventually

came off of the

terminal

resulting

in loss

of feed,

and,

ultimately,

the

reactor trip.

The

licensee's

corrective

action

was

to

place

all

multi

wire

terminal

connections

in

the

SGFRS

into

common

lugs

to

prevent

inadvertent lifting of leads.

The

inspection

team

verified

that

this

action

had

been

accomplished

on

both

units

by

inspection of the hardware

in the plants.

IEB 89-01,

Failure

of

Westinghouse

Steam

Generator

Tube

Mechanical

Plugs:

This

IEB

required

licensees

to

investigate

and

evaluate

certain

lots

of

defective

Westinghouse

Steam Generator

Tube Plugs.

The- licensee

had

investigated

the

use

of

these

plugs

at

St.

Lucie,

had determined

which plugs required

removal,

and

had

remove

the

plugs during

two separate

outages.

The inspection

team verified plug

removal

and

replacement,

by review of the

completed

work packages

for this work.

31

6)

Generic Letter 89-08,

Erosion/Corrosion-Induced

Pipe

Wall

Thinning:

This

Generic

Letter

required

licensees

to

establish

and

implement

a

formalized

long

term

program

to

prevent

catastrophic

failure

of

piping

components

due

to

pipe

wall

thinning

caused

by

erosion/corrosion.

The

inspection

team

reviewed

the

administrative

controls

establishing

the

FP&L program,

and verified implementation,

by

review of the 'last

Unit

2

outage

plan,

and

completed

inspection results.,

No violations or deviations

were noted within the areas

inspected.

5.

Closeout of ins ector follow-u

items

P

'(Closed)

IFI 50-335,389/88-03-01

Natural circulation

cooldown

procedure

omits 20 hour2.314815e-4 days 0.00556 hours 3.306878e-5 weeks 7.61e-6 months soak time from instruction section.

The

licensee

has

issued

Revision

9 to procedure

1-0120039,

"Natural

Circulation

Cooldown".

This revision contains

a

step

to perform

a 20.4

hour

soak

of

the

RCS

upon

reaching

325

degrees

F.

A

procedure

change/review

request 'has

been

generated

to include

the

same

step

in

procedure

2-0120039 during the next revision.

6.

Exit Interview

The inspection

scope

and findings were

summarized

on

May 11,

1990, with

those

persons

indicated

in paragraph

1.

The

inspectors

described

the

areas

inspected

and discussed

in detail

the

inspections

findings.

The

licensee

did not identify as proprietary

any of the material

provided to

or

reviewed

by .the

inspectors

during

this

inspection.

Dissenting

comments

were not received

from the licensee.

Item

Status

Descri tion/Reference

Para

ra

h

335,389/90-09-01

Open

335,389/90-09-02

Open

335,389/90-09-03

Open

335,389/90-09-04

Open

VIO Failure to follow PWO tagging

procedure,

paragraph

2.c.

UNR The licensee

needs

to

administratively define

NWE position

to substantiate

that the

NWE meets

the

requirements

of the

TS defined watch,

paragraph

2.a.

UNR Review of historical

documents

is required to substantiate

licensee's

exception to 24 month procedure

review,

paragraph 2.f.2)

IFI - Further review is necessary

to

verify licensee's

calibration practices

concerning

SDAWF pump surveillance

testing,

paragraph

2.d.2)

'I

~

32

335,389/90-09-05

Open

335,389/90-09-06

Open

IFI - Review-licensee's

corrective

actions

taken to correct control of

TCs,

paragraph 2.f.l)

IFI Review licensee's

actions

concerning

exemption of licensed

operators

from taking requalification

exams,

paragraph

2.n.

,

335,389/90-09-07

Open

335",389/90-09-08

Open

List of Acronyms and Initialisms

IFI - The

ISEG was being reorganized,

review the implementation of functional

requirement

changes,

paragraph

4.a.

IFI Review licensee's.actions

concerning

the noted distinct difference

in

FRG approval

process

between

the

meeting

conducted

by the chairman

and

the meeting held by the acting chairman,

paragraph

4.b.

AE

AF

ANPS

ANSI

CFR

FRG

I8(C

IEB

IFI

IFUSS

ILRT

ISEG

IST

JPN

LER

MOV

NI

NJPS

NLO

Architect Engineer

Auxiliary Feed

Auxiliary Feedwater

Assistant Nuclear Plant Supervisor

American Nuclear Standards

Institute

American Society Mechanical

Engineers

Component

Cooling Water

Combustion

Engineering

Control

Element Assembly

Code of Federal

Regulations

Emergency

Core Cooling Systems

Emergency

Diesel Generator

Emergency Operating

Procedure

Florida Power and Light

Facility Review Group

Functional

Recovery

Procedure

Final Safety Analysis Report

Heat Exchanger

Instrumentation

and Control

Inspection

and Inforcement Bulletin

Inspector

Follow-up Item

ISEG Follow-up Status

System

Integrated

Leak Rate Test

Independent

Safety Engineering

Group

Inservice Test

Juneau

Plant Nuclear

Licensee

Event Report

Motor Operated

Valve

Nuclear Instrumentation

Nuclear Job Planning

System

Non-licensed

Operator

33

NPO

NPWO

NRC

NUREG

NWE

OSTI

psig

PWO

REA

RFD

SGFRS

SNPO

TS

TQAR

UNR

-VIO,

WR

Nuclear Plant Operator

Nuclear Plant Supervisor

Nuclear Plant Work Order

Nuclear Regulatory

Commi ssion

Nuclear Regulations

Nuclear Watch Engineer

Operational

Safety

Team Inspection

Pounds

per square

inch gauge

Plant Work Order

Quality Assurance

Quality Control

Radiation Control Area

Reactor Coolant

Pump

Reactor Coolant

System

Request for Engineering Assistance

Request for Design

For Equivalent Engineering

Package

Reactor Operator

Reactor Turbine Generator

Board

Refueling Water

Tank

Syatematic

Assessment

of Licensee

Performance

Steam Driven Auxiliary Feedwater

Steam Generator

Functional

Recovery

System

Senior Nuclear Plant Operator

Senior Reactor Operator

Safety System. Functional

Inspection

Shift Technical

Advisor

Temporary

Change

Technical Specifications

Total Quality Assurance

Report

Unresolved

Item

Violation

Work Request

APPENDIX A

Additional

PWO Concerns

and

Exam les of Potential

0 erator Desensitization

PWO/JO

7843/61

(XA 880914031912);

P-57 is

locked

in

when

the

fan is running:

This

PWO

was written

on

September

14,

1988,

and

parts

were

ordered

November

3,

1988,

t'o rectify the discrepancy.

After

discussions

on

May 8,

1990,

with maintenance

personnel,

the

inspector

determined

that this part

had

been

received

on site,

and

was awaiting

dedication.

P-57

is

the

Containment

Airborne Activity

Removal

Fan

(HUE-1)

flow low/motor

over load

alarm.

This

item is

a

concern,

in that,

for approximately

16

months

operators

did not

have

complete

indication

available

for

low flow nor

a

motor

overload

condition

on HVE-1.

The

commercial

grade dedication

group

was effective

January

1,

1990.

However,,this

part

has

been de-prioritized.

Due to

the length of time this condition has

been

present,

the potential

exists

for de-sensitization

to the discrepant

condition by the operating

crew.

PWO/JO

7841/61

(XA880910143426);

Level

indicator

alarm for. Boric Acid

Make-up

Tank

1B Level: This

PWO identified that

RTGB indicator

LIA-2208

disagrees

with local

indication

LT-2208

by

5 percent.

The

PWO also

identified

that

the

instrumentation

is

TS

instrumentation

and

that

"accuracy

is

very

important".

On

September

16,

1988,

the

licensee

determined

that the

on the local level transmitter

(LT-2208)

was

reading

high

and

could

not

be

adjusted

within the

manufacturer's

specifications.

On October

27,

1988,

an In-plant Requisition/Stores

was

generated

for

a

new

meter kit assembly;

evidently this

meter kit

assembly

was not subsequently

ordered

nor received.

On April 18,

1990,

(approximately

18

months later),

the

assembly

was reordered.

There is

no

documented

evidence

that correct

action/follow-up

was

taken

during

the

18

month

interval.

Additionally,

the

deficiency

tag

(C29547)

associated

with this

PWO was

located

on the

RTGB versus

locally, which

is where

the discrepant

indication

was

located.

When questioned

by. the

inspectors,

the operator

at

the

controls

was

not

aware

that

the

indication

was

accurate

and

was apparently

mislead

by the

improper

tag

location (i.e.

tag was not hung locally).

This

18 month delay with no corrective

action is significant,

in that,

it is

indicative

of

a

lack of .aggressive

PWO

follow-up/statusing.

Additionally,

the

operator

was

not

aware

of

the

details

of

the

discrepancy

and did not

know his

RTGB indication

was

adequate.

He

was

also

unable

to discern this

information

from

NJPS.

The

operators

may

have

become

desensitized

to this condition

due to the approximately

19

months it had been

open.

PWO/JO

6252/62

(XA890514212343);

Window for fuel

pool

HX

CCW

flow

Hi/Lo:

This

PWO

requested

investigation/repair

as

the

was alarming with good flow.

On

May 16,

1989,

attempts

were

made

to correct

this condition.

However,

the

PWO stated

that

an

"REA

needs

to be written to install dampers

in line to eliminate pulsations".

The inspector

questioned

as to the REA's status

and

was informed that

on

May 9,

1990,

an

RFD was initiated as the

REA was never written.

Appendix A

This 'approximate

one year delay in follow-up is indicative of a lack of

aggressive

follow-up and statusing

of

PWOs.

Additionally, the operators

may

have

become

desensitized

to this alarm

as

the

PWO tag

on the

was

a year old.

4 ~

PWO/JO

6631/62

(XA 890804124015);

Window for

RWT level

Hi/Lo:

This

PWO

was written

as

the

alarm

was

apparently

in for

no

reason.

On

August

14,

1989,

relay

71X

was

replaced

which corrected

alarming

condition.

However,,

due

to

operating

constraints,

the

low

level

alarm could not

be tested.

When

an operator

was questioned

as to

the reason

why the annunciator

had

a deficiency tag

on it, the operator

stated

that

the

condition

had evidently cleared.

While attempting

to

verify

PWO status

on

NJPS,

the

status

was listed

as

a

code

45 (i.e.

ready to

be worked).

The operator

was not aware of the maintenance

that

had

been

performed

and

had apparently

not questioned

the status

of the

deficiency

during

any

shift

turnovers

nor

while

on

shift.

This

situation is of concern,

in that,

while other indication

was available,

had

the

come

in during'

RWT

low-level

condition,

the

operator

could

have

been

temporarily mislead

into believing

the

alarm

was in for no reason.

PWO/JO

6079/62

(XA900408174151);

This

PWO was written on April 8,

1990,

to address

the fact that the

number

9 bearing

on the main turbine

was in

alert

due

to vibration.

This condition

was

tagged

on

the

RTGB (back

panel).

An

18C technician

validated

the

alarm

on April 17,

1990,

and

was

awaiting

a

new

setpoint

from

Engineering

when

evidently,

the

condition

cleared;

the

PWO

tag

was

subsequently

removed.

The

alarm

returned

at

a later date,

and the

PWO was

held open to troubleshoot

the

problem.

During

a walkdown on April 24,

1990,

the inspector

noticed

the

alarm

and

inquired

as

to

why there

was

not

a

PWO tag identifying the

alarm

condition.

The

operator

questioned,

did

not

know

a

PWO

was

currently

open

addressing

the condition,

nor did the operator

conduct

a

search

on NJPS.

The inspector

then

accompanied

an

18C technician

to the

local Bentley-Nevada

Monitoring device to validate the alarm.

This item is of concern,

in that,

the operator

at the controls did not

know how long the alarm

had been

in, nor did

he attempt

to utilize

NJPS

for status.

Additionally, the

PWO tag

should

have

been

re-hung

when the

alarm

condition

reappeared

or

when

the

walkdown

(by

the

operators)

was

conducted

during

turnover.

This

is

an

example

of

desensitization

of operators

to plant conditions/alarms

and demonstrates

the

need

for

increased

cognizance

of

PWO

status

during

turnovers.

Subsequent

to the inspector questioning

PWO tag status,

the tag was re-hung.

PWO/JO

6672/61

(XA 90041?180952);

This

PWO tag identified that

there

were

no audible

alarms

on the Unit-1

ECCS

panel

106.

This-PWO was

generated

on April 17,

1990,

and

completed

(including

post-maintenance

testing

on April 20,

1990.

On April 24,

1990,

the inspector

questioned

the operator

as to the status

of alarm availability;

the

operator

was

initially unaware

that

the

problem

had

been

corrected.

This

item

demonstrates

a lack of sensitivity

on part of the

operators,

in that,

this

condition

was

evidently

not

discussed

during turnover,

and

the

operator

was

unaware of whether

he

had

ECCS audible alarms available.

ll

I

l

< J

Appendix A

'3

This

PWO is

an additional

example

of the

need

to discuss

PWO status

during turnover

and to have

a correct

and

updated

PWO status

available

to the operators.

PWO/JO

5274/62

(XA 880915085631)

and

PWO/JO

5640/62

(XA 890226173942);

these

two

PWO's identified deficiencies

associated

with circuit 43 motor

for the

125 volt DC Buses

2A and

2B.

These deficiencies

resulted

in the

inability to operate

the

125

V

OC buses

transfer

breakers

from the

keyswitch operator.

This item is significant, in that,

the

125 volt OC bus

2A key was in the

keyswitch

and

according

to the

ANPs, this keyswitch could

be utilized

even

though

the deficiency

tag

(C 29175)

stated

that it did not work.

The

ANPS

was

concerned

as

the other

keyswitch

had the

key

removed with

no

power indication

(2B bus).

However,

the deficiency

tag

(C

323164)

associated

with this keyswitch contained

the

same

wording

as

the other

tag.

Thus, it was potentially confusing to the operators

whether or not

the

keyswitches

worked,

and

whether

or

not

they

could

believe

the

deficiency tags'nformation

Subsequent

to

the

inspection,

the

inspector

spoke

via

telephone

communication

with the Electrical

Maintenance

Supervisor

and

an

NPS;

Evidently,

at

the

end

of

the

inspection,

neither

keyswitch

worked.

However,

one

key

was in the respective

keyswitch

and the

ANPS believed

it did,

in

fact

work.

Evidently,

the

deficient

condition

was

temporarily corrected

in the past

which misled the

ANPS into believing

one

keyswitch worked.

This is another

example of old

PWOs,

the status

of which

operators

were

unaware

of,

and

as

such,

were

unaware of-

equipment unavailability.

PWO/JO

5606/62

(XA 890907081845);

Reset

switch

rotates

freely

and

breaker will not

close.

This

PWO identified that

the

reactor trip

switchgear

breaker

TCB-5 would not close

locally

and that

the

reset

switch rotated 'freely.

This

PWO was worked

on

September

7,

1989.

The

work performed

included

replacing

the closing coil

and

damaged

latch

r'elease.

The

breaker

was

functionally tested

and

was

released

to

operations.

The

NPS Notification of Completion

was

signed

later

the

same day.

On

May 8,

1990,

the

inspector

noted

that

the

reset

switch

had

a

deficiency

tag

(C41183)

located

next to it stating

that

the

switch

rotates

freely.

However,

on

September

7,

1989,

the

switch

had

been

repaired.

This

PWO has

been

kept

open for tracking

purposes

only.

This

item is

of

concern,

in that,

the

condition

on

the

tag

has

been

corrected,

but the deficiency description

on the tag

was incorrect for

eight

months

since

the

switch

was fixed.

One operator

questioned

did

not

know that

the

switch

had

in fact

been

fixed

and

apparently

took

credence

in

the

tag's

deficiency

description

when that condition

no

longer existed.

While witnessing

packing repairs

to the

1C charging

pump,

the inspector

noted

a

PWO tag

(number

unknown)

hanging

on the

pump's

seal

tank.

This

tag stated

that the annunciator

for the

seal

tank does

not work.

This

item is another

example of inconsistent

tagging practices.

Appendix A

0

The annunciator

identified

on the tag is evidently the

RTGB annunciator;

however, it was

tagged locally at the

seal

tank versus

the

RTGB.

This

tag location is critical, in that, if the

tag

was actually for the