ML17223A857

ends;

the

rust

appeared

to

be

superficial.

The Unit

2

room

had

three

high pressure

3/8 inch instrument

tubes

damaged/bent

(pressurizer

steam

space

sample,

steam

blow

down

sample,

and pressurizer

surge

sample lines).

The tubing

and

associated.

lagging

appeared

to

have

been

damaged

while

working abov'e

the tubing.

The

damaged

lines, were not part of

the unisolable

RCS boundary.

Scaffolding in the Unit 2 room could hinder handwheel

operation

of several

manual

valves.

Once

the problems

were identified, the licensee

took prompt correc-

tive actions.

Upon re-inspection

of the Unit

1 pipe penetration

room

on June

2,

after

some

refurbishment,

the

space

was

found to

be

improved

and

reduced

Health Physics controls could be applied.

Two blowdown valve

steam

leaks

had

appeared

since

the cleanup effort.

One of them was

wetting about

one third of the

space.

This was identified to plant

management

and the leaks

were repaired.

The licensee

recognized

that they

had not been conducting sufficient

walkdown

inspections

of the

pipe penetration

rooms

and

took

two

additional

steps

to enhance

control of them:

)

The

pipe penetration

rooms

were

added

to the weekly walkdown

tour schedule.

The training programs for operators

and other selected

personnel

were

being

reviewed

for

enhancements

concerning

material

condition observation

and reporting.

During

a tour of Unit

1

ICW areas

on Nay 30,

a number of areas

of improved material

conditions

were noted.

Some

exceptions

identified to the plant staff were

promptly addressed.

Two

notable

exceptions

were safety-related

valves

FCV 21-3B and

FCV

21-3A, which isolate the lubrication water to the main ci rculat-

ing pumps

upon

ESF actuation.

Though the valves would function,

the

air-pressure-to-open,

spring-pressure-to-close

tubular

operators

were significantly deteriorated

such

that future

operation

could

be affected.

Both valves

were

placed

out of

service

and closed

pending repair.

4

b.

Plant Operations

Review

The

inspectors

periodically

reviewed shift

logs

and

operations

records,

including data

sheets,

instrument traces,

and

records

of

equipment malfunctions..

This review included control

room logs

and

auxiliary logs,

operating

orders,

standing

orders,

jumper logs

and

equipment tagout records.

The inspectors

routinely observed

operator

alertness

and

demeanor

during

plant

tours.

During routine

operations,

control

room staffing,'ontrol

room access

and operator

performance

and

response

actions

were

observed

and evaluated.

The

inspectors

conducted

random

off-hours

inspections

to assure

that

operations

and security

remained

at

an acceptable

level.

Shift

turnovers

were

observed

to verify that

they

were

conducted

in

accordance

with

approved

licensee

procedures.

Control

room

annunciator

status

was Verified.

The inspectors

reviewed

the following safety-related

tagouts

(clearances):

1-4-2,

tags

1

and

2 for V6461 and V6363,

sample line isolation

'alves for the equipment drain tank

and the chemical drain tank,

respectively;

1-6-42,

Replace

FCV-21-3B Actuator;

1-6-56, Repair

FCV-21-3B Flanges;

and

2-5-112,

Repair

2B

ICW Pump.

On May 24, Unit

1 operators

manually tripped the reactor

due to

a

DEH fluid (hydraulic oil) leak from the number three governor

valve's

servo valve.

The servo valve, which had

begun leaking

in the early morning,

was isolated for repair after

a

10 percent

power reduction.

The valve cover, which also served

as

a spray

shield,

was

removed

to facilitate replacing

the five o-rings

between

the servo valve body and mounting plate

and

was left off

following repair

to

enable

the

observation

of

any

minor

post-repair

leakage.

Valving-in the

servo

valve initiated

a substantial

new leak

'hat,

with the valve cover/spray

shield

removed,

could not

be

isolated.

At that point, with turbine

DEH control

pressure

decreasing,

the operations

staff manually tripped

the plant

before the turbine low oil pressure trip setpoint

was reached.

Close examination'f

the o-ring set initially removed

from the

servo

valve

and

the

second

set installed

during

the repair

revealed

that

both sets

of o-rings

were oversized.

Improper

o-ring retention in the retaining grooves

caused

both leaks.

The

o-rings,. which

were

non-safety-related,

were

improperly

identified in the

FPL stock system.

The licensee

replaced all Unit

1

turbine

valve o-rings

and

issued

a

SNOW

NPWO to replace

those

located

on

the

Unit

2 turbine

valves.

There

were

no

known

safety-related

applications for these

specialized

o-rings.

During the plant trip, all equipment

responded

appropriately except

a

6.9

KY breaker

that did not

make

a 'rapid transfer

from the unit's

main to auxiliary transformer;

this tripped

two

RCPs

and

one

MFP.

During the recovery after the trip, the tripped

RCPs

and

MFP were

restarted.

Subsequent

testing

by the licensee

could not duplicate

the problem.

On

May 17, Unit

2 experienced

indications of

a

2A main feed water

regulating

valve

control

problem.

Recording

chart

indication

displayed

about

a

ten

percent

variation in

2A

SG level without

corresponding

fluctuations of power or other parameters.

Operations

personnel

took manual

control of the

2A main feed regulating valve

and established

that the controller was working properly.

The technical

support staff instrumented

the feed regulating

system

control features

and,

SG level indication to determine

the cause for

the erratic indications.

Initially, it was found that the recorder

had

worn parts.

Its mechanical

wear

was causing

a

4 to

6 percent

indication swing.

Further investigation

was continuing at the

end of

the inspection

period.

A containment

entry was

planned

to evaluate

the process

signals

from SG level transmitters.

On May 29, the Unit 2 "A" train containment

vacuum relief valve,

FCV

25-7,

accumulator

low pressure

alarm

was actuated

by pressure

switch

PIS25-12A.

The accumulator air pressure

provides

stored

energy to

open

the

valve

on

a

low differential

pressure

between

the

containment

and

the

annulus

(less

than

-0.07 psig).

The

low

accumulator

pressure

alarm could

have

meant that stored

energy

was

not available to open the valve if called upon.

Based

on the annunciator indication, the site properly entered

the

TS 3.6.5 four-hour action

statement

for an

inoperable relief valve.

Inspection

and test

by

18C

personnel

indicated

that

accumulator

pressure

was about

70 psig

and the action statement

was exited.

Further review revealed:

That

PIS25-12A

was

non-safety-related,

had

no calibration

schedule,

and

had not been calibrated

since

1982.

As

a previous

coranitment

to the

NRC,

the

licensee

was

in the

process

of

finding

such

instruments

and

placing

them

on

a calibration

schedule.

That the

PIS25-12A alarm setting

had drifted several

psig high

and caused

the annunciator

alarm.

11

The

PIS25-12A

70 psig

set point agreed

with the set point

document supplied

by engineering.

This set point disagreed

with

the

50 psig

CWD set point; engineering

was looking into why the

CWD had not been

updated.

That the actual

operation of

FCV 25-7 was controlled

by another

detector that would have performed the actual

safety function if

required

and

had

been calibrated

on its required schedule.

The inspectors

reviewed quality control activities

and findings

to determine if the objectives

were being met.

The documented

final results

of the following types

of activities

were

sampled:

Field welds in safety-related

pipe (corrective actions only);

gC hold points in electrical

procedures;

Inspection of stuffing boxes for charging

pumps;

and

Post maintenance

cleanliness

inspections.

The activities were in order

and appropriate corrective actions

were

completed.

c.

, Technical Specification

Compliance

Licensee

compliance with selected

TS

LCOs was verified. This included

the

review

of

selected

surveillance

test

results.

These

verifications

were accomplished

by direct observation

of monitoring

instrumentation,

valve positions,

and switch positions,

and by review

of completed

logs

and records.

The licensee's

compliance with

LCO

action

statements

was

reviewed

on

selected

occurrences

as

they

happened.

The inspectors

verified that plant procedures

involved

were

adequate,

complete,

and the correct revision.

Instrumentation

and recorder traces

were observed for abnormalities.

d.

Physical

Protection

The inspectors verified by observation

during routine activities that

security program plans

were being implemented

as evidenced

by: proper

display of picture badges;

searching

of packages

and personnel

at the

'lant entrance;

and vital area portals

being locked

and alarmed.

The inspectors,

as

a result of routine plant tours

and various operational

observations,

determined

that

the

general

plant

and

system

material

conditions

were

being satisfactorily

maintained,

the

plant security

program

was

being effective,

and that the overall

performance

of plant

operations

was

good.

Areas of weak

housekeeping

controls

were quickly

corrected.

No violations or deviations. were identified.

3.

Survei 1 lance Observations

(61726)

Various

plant

operations

were verified to

comply with selected

TS

requirements.

Typical of these

were confirmation of TS compliance for

reactor

coolant chemistry,

RMT conditions,

containment

pressure,

control

room ventilation

and

AC

and

DC electrical

sources.

The

inspectors

verified

that

.testing

was

performed

in

accordance

with

adequate

procedures,

test instrumentation

was calibrated,

LCOs were met,

removal

and restoration

of the affected

components

were accomplished

properly,

test results

met requirements

and

were reviewed

by personnel

other than

the individual directing the test,

and that

any deficiencies

identified

during the testing

were properly

reviewed

and

resolved

by appropriate

management

personnel.

The following surveillance tests

were observed:

OP 2-0110050,

Rev 9, Control

Element Assembly Periodic Exercise;

OP

3200051,

Rev 6, At Power Determination of Moderator Temperature

Coefficient and

Power Coefficient (performed

on Unit 2);

18C

2-1400052,

Rev

16,

Engineered

Safeguards

Actuation System-

Channel

Functional Test;

Procedure

1&C 2-0700051,

Rev

13, Auxiliary Feedwater

System Monthly

Functional Test;

Procedure

AP 1-0010125A,

Rev 15, Surveillance

Data Sheets,

Data Sheet

number 26, Accident Monitoring Instruments;

and

OP

1-0120051,

Rev

10,

Flow Determination

by Calorimetric

Procedure.

During the Unit 2 performance of OP 3200051,

CEA 56 froze in position

while the active control

group

was being returned to its full power

position.

The rest of the control

group

moved

several

more steps

before

the

operator's

action

stopped

group

movement

prior to

receiving

a group deviation alarm.

Operations

took the proper steps

to remedy the situation

by contacting

I8C personnel.

Control logic

was reset

by driving the

CEA back into the core in manual

individual

mode.

The clearing of the logic did not identify the cause for the

freeze.

The test itself was not invalidated

by the delay to realign

CEA 56 and its results

were satisfactory.

The history of this unit's

CEA control circuits indicated that the

associated

ACTH cards

occasionally

froze

CEAs for unexplained

reasons.

ACTH cards function to monitor

CEA position

and to prevent:

CEA

rod

drops

and slips;

CEDM coil

burnouts;

and

CEA group

deviations.

In its attempt to perform the above functions,

the

ACTM card complex

logic sometimes

froze the

CEA at inappropriate

times but would not

prevent

the

CEA from dropping into the core

on

a reactor trip.

One

of the

problems with the cards

was that the card did not store

the

information regarding

the

cause for'ts decisions;

storage of such

information would enhance

CEDM troubleshooting. '&C plans to have

card

memory additions

available for card modification during the

September,

1990, refueling outage.

Procedure

I&C 2-1400052

was performed during prototype testing of new

circuit boards for the upcoming Unit 2

ESF system

ATWS modification.

Design

engineers

from Consolidated

Control,

Inc,

the

equipment

vendor,

provided the prototype circuit boards

and participated

in the

test.

The licensee

generated

safety evaluation

FLO 128-35.5007,

Rev

.

0, for the test

and

issued

detailed

instructions

in

NPWO 1244/70.

Although several

minor problems

were identified during testing,

the

overall result of the real

time prototype

assessment

was

an enhanced

modification

process.

The

I&C surveillance

procedure

was later

utilized

as

a functional

check of the existing

system

when it was

returned

to service.

Procedure

I&C 2-0700051,

Rev 13, Auxiliary Feedwater

System Monthly

Functional

Test,

tested

the bistables,

the automatic initiation, and

the control

system that integrated

the actions of the

combined

AFW

output.

The testing

was well controlled

and observed

results

were

satisfactory.

Procedure

AP 1-0010125A,

Rev 15, Surveillance

Data Sheets,

Data Sheet

26,

Accident

Monitoring

Instruments,

checked

the

status

and

operability of the various

instruments

used during an accident.

The

surveillance

was performed to satisfy

TS 3.3.3.6

requirements.

The "A" train liquid plasma display, normally used for indication and

for. data gathering

during performance

of the

CET and

HJTC procedure

segments,

had

been

shut

down since

March

11

due to partial readout

failure.

The data fields would become

garbled

soon after the screen

was either energized

or reset.

The cause

was thought to be

a strong

field adjacent

to the display.

With the

"A" display shut

down, operations

could not complete

the

surveillance

using the

RVLMS back panel for data collection because:

No

I&C personnel

were

on shift on Saturday,

June

2, to supply

expertise

or calibrated

equipment;

The existing test did not address

use of the

RVLMS back panel

for data collection;

and

No operations

personnel

knew

how to

make

the

necessary

math

conversions

from an auxiliary read out on

a back panel.

The test

was deferred until the June

4,

when

I&C energized

the

"A"

train display

and operations satisfactorily collected

the data prior

to the display becoming garbled.

The "A" train display

was then left

in operation

and available for operator

use

on

a reset-to-read

basis.

This deferral

was acceptable

from a regulatory standpoint.

I&C persons

indicated that the display would require modification to

operate

properly

and

that

a modification

would

require

Juno

engineering

support.

ISC had not submitted

a request for engineering

support at the time of the test.

Operations

was discussing

potential

modifications with IKC to support display modification/repair during

the September,

1990, refueling outage.

The

"A" and "8" train plasma display information was. utilized in the

site's off normal

procedures.

Similar information utilizing the

same

inputs,

but processed

by

a different computer

program with slightly

different results,

was available

from the

fRDADS which, though not TS

controlled,

was also displayed

in the control

room on another

CRT.

At the time of the test,

the operations

personnel

were not fami liar

with the

computer

program

involved with the

ERDADS computation.

Althou'gh operator efficiency may

be

reduced

by having to reset

the

display prior to each

use,

regulatory requirements

are being met.

-The performance

of

OP

1-0120051,

Rev 10,

Flow Determination

by

Calorimet'ric Procedure,

was observed

on

May 14.

This

was

a precise

test

based

on highly accurate

measurements

of loop temperatures.

It

is normally performed

once per operating

cycle following refueling to

confirm adequate

loop flow.

The measurements

were

made

by disconnect-

ing (by switches)

certain

panel

meters

to reduce

measurement

channel

'loading

and

then

measuring

appropriate

channel

voltages

with

a

high-impedance

digital volt meter.

The procedure

required taking at

least ten data sets while plant parameters

remained

near constant.

During the test,

the licensee's

staff did not follow instruction

steps

8.3 through 8.6.

These

steps

directed certai.n action sequences

involving coordination with the

RCO at

the control

board,

control

board

loop temperature

meter switch position selection,

and confirm-

ation that measurements

were being

made only on channels

that had the

meter disconnected

by switches.

The test

persons

instead utilized an

unapproved

method to isolate the loop temperature

meters

and complete

the

data

without coordination.

During the test,

the inspector

questioned

the approval of the technique

in use.

No temporary

change

was

sought.

The licensee,

subsequent

to test completion,

confirmed

the resulting

data validity.

Subsequent

to the test,

a procedure

change

was initiated to upgrade

the procedure

and corrective actions

were taken to sensitize

the test staff to strict, procedure

adherence.

Procedure

gl 5-PR/PSL-1,

Rev 37, Preparation,

Revision,

Review/Approval

of Procedures,

section

5.5,

implemented

10 CFR 50 Appendix

8,

Criterion 5,

through

the

approved

FPL topical

gA report,

and also

implemented

TS 6.8. 1,

which required

that certain

procedures

be

established,

implemented

(followed),

and maintained.

Procedure

gI

5-PR/PSL-1

required that procedures

be strictly adhered

to. It also

provi.ded

the

method to obtain

approved

temporary

procedure

changes

10

and, if appropriate,

subsequent

permanent

changes.

Failure to adhere

to the

OP was identified as violation 335/90-14-01.

The

inspectors

determined

that

the

above

testing activities

were

performed in a satisfactory

manner

and met

TS requirements

except for

the

one violation discussed

above.

4.

Maintenance

Observation

Station

maintenance

activities involving selected

safety-related

systems

and

components

were

observed/reviewed

to

ascertain

that

they

were

conducted

in accordance

with requirements.

The following items

were

considered

during this review:

LCOs were met; activities were accomplished

using

approved

procedures

functional

tests

and/or calibrations

were

performed prior to returning

components

or systems

to service; quality

control records

were maintained; activities were accomplished

by qualified

personnel;

parts

and

materials

used

were

properly certified;

and

radiological

controls

were

implemented

as

required.

Work requests

were

reviewed to determine

the status

of outstanding

jobs

and to assure

that

priority was

assigned

to safety-related

equipment.

Portions

of the

following .maintenance activities were observed:

NPWO 2077/62

performed

PHs

on the "A" train Zurn strainer,

SS-21-3A1,

for the safety-related

ICW

pump lubricating water

system.

The

strainers

had

been rebuilt in September

1989,

as part of an upgrade

program based

on

NRC inspection findings at that time.

PN activities

were

being appropriately

conducted

and

the

disassembled

strainers

appeared

to be in good physical

shape.

NPWO 5138/62

was written to replace

the burned out lights in the Unit

2 SFP.

The job grew from minimal health physics preparation with the

lights

being

replaced

in their standards

at pool

side to maximum

ALARA considerations

including

use of air-fed hoods,

hot particle

controls,'nd

the

SFP

submerged

light standards

being entirely

replaced.

The old standards

were to

be

reworked in

a controlled

space

separate

from the

SFP.

The electricians

involved were taking

more

than

adequate

interest

in revising

,the

scope

and

making

preparations

for the work.

NPWOs 0904/62

and 0905/62

replaced

the monel shaft sleeves

on the

2A

and

28

ICW pumps

because

of accelerated

corrosion.

The shaft sleeves

were pitted

such

that maintaining

proper

packing

leak off was

difficult.

NCR 2-331

was written to obtain resolution for apparent

galvanic cell

corrosion

between

the

per-plan

carbon

impregnated

packing

material

and

the

adjacent

monel

shaft

sleeves.

The

engineering

resolution,

which will occur after this

inspection

period,

may require

a change of packing material.

For those

maintenance

activities observed,

the inspectors

determined that

they

were

conducted

in

a satisfactory

manner

and that

the

work was

properly performed

in accordance

with approved

maintenance

work orders.

No violations or deviations

were identified in the

performance

of the

above

NPWOs.

Pe

5.

Onsite

Followup of Written Nonroutine

Event

Reports

(Units

1

and

2)

(92700)

LERs were reviewed for potential

generic

impact, to detect trends,

and to

determine

whether corrective

actions

appeared

appropriate.

Events that

were reported

immediately were reviewed

as they occurred

to determine if

the

TS were satisfied.

LERs were reviewed in accordance

with the current

NRC Enforcement Policy.

(Closed)

LER 50-335/89-03,

Automatic Reactor Trip

on

Low Steam

Generator

Water Level

During Startup

Due to Procedural

Deficiency

(Refer to

NRC IR 50-335/89-20).

On July 17,

1989, during.a turbine startup,

the reactor tripped

as

a

result of inadequate

feedwater

flow to the

steam

generators.

Main

feedwater

flow to the

steam

generators

was

prevented

because

main

feedwater

block valves

MV-09-5 and

MV-09-6 were not opened.

This

event

can

be attributed to

a deficiency in procedure

OP 1-0030124,

Turbine

Startup

Zero

to Full

Load,

which did not require

the

operators

to verify the position of the feedwater

block valves.

The

inspector

reviewed

procedure

OP 1-003124,

Rev 48,

and

OP 2-0030124,

Rev 34,

and verified that these

procedures

now require valves

MV-09-5

and

MV-09-6 to

be

open

when transferring

feedwater control from the

15'4 feed regulating valves to the main feed regulating valves.

The

inspector

found the licensee's

corrective actions

to be acceptable.

This item is closed.

(Closed)

LER 50-335/90-04,

Inadvertent Partial Actuation of "A" Train

Containment Isolation

and Containment

Spray

Systems

Due to Equipment

Malfunction (Refer to

NRC IR 50-335/90-08).

On

February

28,

1990,

Unit

1

was

in

Mode

6

when

an inadvertent

partial

actuation

of the

ESFAS

occurred.

Train

"A" of the

containment

spray

and the containment isolation system

were partially

actuated.

The root cause

of the event

was

equipment malfunction.

The licensee

found several.

loose

screws

on

a terminal

board that was

being worked.

Attaching

a jumper wire to that terminal

board

(TB519)

during the work activity caused

the connections

to be jarred loose,

breaking

the circuit,

and partially initiating the

ESFAS.

The

licensee's

investigation determined that the majority of the terminal

screws

were tight and that the most likely cause of the loose

screws

was

not being fully tightened

during initial installation.

The

inspector

verified that

the

licensee

initiated

and

completed

PWO

61-6254

and

61-6219 to verify and check tightness

of the

ESFAS panel

terminal connections.

This Item is closed.

(Closed)

LER 50-389/89-03,

Inadvertent

Actuation of Containment

Isolation Actuation Signal

Due

To Personnel

Error (Refer to

NRC IR

50-389/89-10).

12

On March 21,

1989 with Unit 2 in Mode 6,

a CIAS was received.

This

inadvertent

actuation

was

a result of a personnel

error.

Licensee

personnel

(licensed

operator)

depressed

the check

source

on the

"D"

channel

CIAS monitor while the

"A" channel

was

in the tripped

condition.

This completed

the

2 out of 4 logic resulting in the

inadvertent

actuation.

As

a result of the actuation

the

2B Diesel

Generator

started

and

was

running when,

upon resetting

the CIAS, the

Diesel tripped

on high crankcase

pressure.

This trip was bypassed

by

design while the

ESFAS was active.

The diesel trip resulted

from the

lubricating oil relief valve,

which is in close proximity'o the

crankcase

pressure

detector,

relieving oil

under

fast start

conditions.

This

caused

the detector

to

sense

a high pressure

condition

and trip the diesel.

To prevent high crankcase

pressure

trips,

the

licensee

installed lubricating oil relief valve splash

guards

on both diesels.

The inspector

reviewed

PWO 62-2798

and

62-3276 which installed the oil deflectors

'and verified that the work

had

been

completed.

-

The inspector

found the licensee's

corrective

actions to be satisfactory.

This item is closed.

(Closed)

LER 50-389/89-04,

Containment

Local

Leak

Rate

Exceeds

Technical Specifications

Due to Valve Closure Stop Out of Adjustment

Due to Personnel

Error.

On June

5, 1989, with Unit 2 at

100% power,

a routine local leak rate

surveillance

test.

was

performed

on

the

containment

containing

the

containment

purge

system

exhaust

line.

The

leakage rate

was found'o exceed

the

TS limits.

The root

cause of the leakage

was determined

to be personnel

error in that the

valve adjustment

stop

was not properly locked

down by the personnel

who previously

tested

the

valve.

To prevent

this

event

from

recurring,

the

licensee

revised

the

technical

manual

to provide

guidance

on how to tighten the valve travel adjustment

screw locknut.

The

inspector

reviewed

the

change

to Technical

Manual

8770-5625,

Butterfly Valves Safety Class,

and found it acceptable.

This item is

closed.

Preparation for refueling (60705)

Refueling Activities

( 60710)

These activities were reviewed for Unit 1 during the period from November,

1989,

through March,

1990,

and were reported,

in part, in IRs 335/89-26,

335/90-08,

and 335/90-11.

The inspection attributes

included

management

supervision,

fuel receipt

and storage,

fuel

movement,

CEA installation,

core

reassembly,

operational

and

health

physics

controls,

and quality

verification.

The activities

were generally

well controlled

and well

monitored.

No violations or deviations

were identified in this area.

Followup of, Headquarters

and Regional

Requests

(Units

1 and

2) (92701)

Generic Letter

NO. 88-17,

Loss of Decay Heat Removal,

(TI 2515/101)

13

History:

IN 88-36,

Possible

Loss

of

Inventory

During

Low Coolant

Level

Operation,

dated

June

8,

1988,

was issued just prior to the Unit

1 outage

commencing

August,

1988.

Since

the training cycle

was over,

the site

issued

the

IN as

required, reading,and

the

operations

group

conducted

meetings

on

the

subject

each shift.

had

installed the

Information Notice NO. 88-36,

dams in an incorrect order;

the work instructions

were

changed

to correct this.

PCMs (listed

below)

were

issued

to install

remote

RCS level indication in the control

room.

GL 88-17,

Loss of Decay

Heat Removal,

was issued

on October

17,

1988.

The site

has

taken steps

in

responding

to

the

GL

as

addressed

in several

letters

'to the

NRC.

Additionally,

INPO issued Case'tudy

88-018,

Loss of Decay

Heat Removal,

September

1988,

which

has

a

few more

suggestions

for the licensee

to

consider.

The

CE owners

group

had also supplied information to the site.

Unit 2 shut

down in early February,

1989, for a refueling outage.

Mid-loop

operation

went smoothly during that Unit 2 refueling.

On April 7, 1989,

the. resident

inspectors .observed

implementation of the

GL response.

The

current

(February,

March,

and April, 1990)

Unit

1 refueling

involved

mid-loop operations

which were also observed

by the inspectors.

Material Reviewed:

During the course of the review by the inspectors,

the following material

was considered:

Temporary Instruction

2515/101,

Loss of Decay Heat

Removal

(Generic

Letter

NO. 88-17)

10 CFR 50.54(f), of February

16,

1989

FPL letter L-89-38, Loss of, Decay Heat Removal, of February

1,

1989

FPL letter

L-88-552,

Loss of Decay

Heat

Removal

(Generic Letter 88-17), of January

1,

1989

NRC Generic letter 88-17,

Loss of Decay Heat Removal, of October

17,

1988

INPO case

Study 99-018,

Loss of Decay Heat Removal, of September

1988

NRC

Possible

Sudden

Loss of

Inventory During Low Coolant Level Operation, of June 8,

1988

OP-0010129,

Rev

14,

Equipment

Out of Service

(the actual

out of

service

logs for periods

when mid nozzle operation

was occurring,

February

6 to 19 and April 15 to 19,

1989)

, OP-1-0120021,

Rev 23, Draining of Reactor Coolant System

14

OP-2-0120021,

Rev 13, Draining the Reactor Coolant System

ONOP 1-0440030,

Rev 10,

Shutdown Cooling Off-Normal

ONOP 2-0440030,

Rev 11,

Shutdown Cooling Off-Normal

I&C Procedure

1400097,

Rev 0, Core Exit Temperature

Monitoring During

Reduced

RCS Inventory

I&C Procedure

1400023,

Rev 0, Incore instrumentation

Outage

Tasks

Work Process

Sheet

8435-848,

Rev 0,

Install/Remove

Nozzle

Dams, of

November 7,- 1988 [Unit 2j

Work Process

Sheet

6659-1297,

Rev 1, Install/Remove

Nozzle

Dams,

Hot

and Cold Legs, of September

12,

1988 [Unit 1j

Memorandum of Instruction, Instruction for Closing Penetration

P-50,

approved

by Facility Review Group

on February 8,

1989

QA Audit JQQ-89-131,

February Monthly Performance

Monitoring, of

March 31,

1989

OP 1-1600023,

Rev 33, Refueling Sequence

Guidelines

OP 2-1600023,

Rev 18, Refueling Sequence

Guidelines

Plant

Change/Modification

(PCH)

N0.89-287,

Remote

Reactor

Vessel

Level Indicator, of June

30,

1988 [Unit 2]

PCM

NO.88-187,

Remote

Reactor

Vessel

Level Indicator, of July 30,

1988 [Unit 1]

FPL Letter FRN-89-088, of January

29,

1989

Memorandum

JQQ-89-048,

Independent

Verification of PSL Response

to Generic Letter 88-17,

Loss of Decay Heat Removal, of January

31,

1989

Memorandum

SGOM-90-1-001,

Proper

Sequence

of S/G Primary Side

Manways

and Nozzle

Dams Installation (PSL-l), of January

26,

1990

Mechanical

Maintenance

Procedure

M-0029A, Rev 5,

Steam Generator

(SG)

Primary Side Maintenance

QA Audits:

QSL-88-316,

September

15,

1988

QSL-OPS-89-687,

August 24,

1989

QSL-OPS-89-656,

March 31,

1989

QSL-OPS-90-707,

February 6,

1990

15

Areas

Inspected

a

~

b.

T~rainin

The inspectors

examined training records,

training material,

and the

class

training

plan for the

special

GL training.

The licensed

operators,

unlicensed

SNPOs,

STAs,

and

selected

technical

staff

received this training.

No maintenance

or trades

persons

received

the training.

Maintenance

and trades

persons

were often observed

to

be directed

by the operations

staff to not perform certain

work

during mid-loop operation

or to ensure

that precautions

were taken

during work performance while th'e plant was in a mid-loop condition.

The training

covered

the industry experience

in the events,

the

.pertinent

aspects

of the

GL, and the operational

impact of mid-loop

operation.

The bulk of the training was given

as special

training

immediately after

issuance

of the

GL.

Hot leg

and cold leg

dam

installation

sequence

training

was given during operator requalifi-

cation training in January,

1989.

Training materials

and

time

allotted to training appeared

to have

been

adequate.

Additional training did occur in the plant.

Operations

personnel

were

given instructions

as to actions

to take

and stations

to

be

manned;

a special

operator

was placed at the shut

down cooling board

in the control

room,

a nuclear operator

manned

a position in contain-

ment at

a tygon tube

RCS standpipe,

and the indicated

RCS level

was

logged every

15 minutes.

Containment

Closure

Containment

closure

would have

been

carried

out by two letters

of

instruction

during

the

Spring,

1989,

Unit

2 outage.

Mechanical

maintenance/backfit jointly issued

a letter providing instructions to

cl,ose

the

main containment

hatch

during

a loss

of

OHR while in

,mid-loop

operation.

One

other

containment

was

administratively allowed during mid-loop operation.

Penetration

P-50

was

used

for

steam

generator

eddy current

testing;

the backfit

organization

issued

the

closure

instruction for that penetration.

Backfit personnel

were continuously stationed

in the containment

to

close

the containment at the order from the operations shift super-

visor.

The inspectors

did observe

the personnel

on shift and sighted

containment

closure

tools

and material.

Pre-shift briefings

were

held to discuss

containment

closure details.

Back-shift dry runs of

contacting

personnel

for containment

closure

were implemented.

The method for determining

the required

containment

closure time was

a graphical

method

found in the

RCS drain procedure.

Based

on the

RCS conditions

at the time of a postulated

DHR loss,

the time till

RCS boil off occurred

could

be determined.

The licensee

indicated

that the curves

in this procedure

were derived

from

EBASCO calcula-

tions indica'ted in FPL letter FRN-89-088

(see

above).

16

c.

RCS Temperature

Indication

The licensee

developed

a procedure for temporary

hookup of the

CETs

for control

room display while in an

outage

with the vessel

head

removed.

The procedure

connects

two CETs from one train of a safety

power supply

and

one

CET from another.

The procedure

was adequate

to

establish

the

hookup.

The installed cabling

was

observed

in the

containment

and control

room.

Additionally, normally available

SDC

system temperature

indication was available in the control

room.

d.

RCS Level Indication

Level indications

were in accordance

with FPL commitments in response

to the

GL.

The noted exception

to this

was the audible alarm to be

installed in Unit 2 by August,

1990.

Level indication

was provided

by two means

as follows:

The referenced

PCMs installed level indication in the form of

instrument loops;

two separate

transmitters

attached

to one

loop tap provided wide and narrow range signals.

Level read out

was provided by double indicating Sigma meters.

The meters

were

powered

from two separate

nonsafety

power

panels

which also

supply the transmitters

in containment.

Unit

1

had additional

monitoring capacity in that level could be viewed

on the

ERDADS.

This capacity

was

scheduled

for installation in Unit 2 during

the

September,

1990,

outage.

A licensed

operator

was assigned

to monitor level indication during mid-loop operation.

A tygon tube

was installed

on

a separate

RCS tap for additional

indication.

A non-licensed

operator

was

assigned

in the

containment

to monitor

RCS level indication

on this tube during

critical evolutions.

This operator

was in radio communication

with the control

room.

There

was

good correlation

between

the

tygon tube

and the level transmitter

loop indications.

e.

Controls while in Mid Loop Operation

Overall operations

control of RCS perturbations

was good.

Heightened

awareness

was evident during mid-loop evolutions.

All unnecessary

work was prevented

on the

RCS boundary during these

periods.

When the loop level sensing

lines were filled and vented for use in

February,

1989,

the site

gA group

documented

procedure

adherence

problems

as minor audit findings.

Use of the

CETs for temperature

indication

was satisfactory.

Available additional

support instru-

ments,

such

as those

reading

SDC flow parameters,

were functional.

f.

Water Addition with the Loss of DHR

Prior to entering

mid-loop,

the

RCS draining

procedure

required

operability of the charging

system

and the off normal

procedure for

'Qe

17

e

SDC required that at least

one

HPSI

pump

be available.

Observation

and selected

operational

log reviews

indicated

that the

pumps

were

available for mid-loop operation.

g.

Nozzle

Dam Installation

Prior to draining to mid loop, the pressurizer

was vented to atmos-

pheric

pressure

and

then

nozzle

dams

were installed

by the

above

referenced

work process

sheets.

These

sheets

contained

specific

sequence

steps

to ensure

that simultaneous

nozzle

blockage did not

occur.

Operations

maintained overall control via their work permits.

As with

any

set

of

new

procedures

and

their

attendant

new

inter-relationships, it has

taken

time to make

adjustments

to the

procedures

and work flow paths.

Importantly, the licensee

has

been

attentive

to the details of the inter-relationships

and accomplish-

ment of this complex evolution.

Overall, the licensee's

effort has

been

comprehensive.

Exit Interview (30703)

The inspection

scope

and findings were

summarized

on June

8,

1990, with

those

persons

indicated in paragraph

1 above.

The inspector described

the

areas

inspected

and discussed

in detail

the inspection

findings listed

below.

Proprietary

material

is not contained in this report. Dissenting

comments

were not received

from the licensee.

Item Number

Status

Description

and Reference

335/90-14-01

open

VIO - Failure to follow a test procedure,

paragraph

3.

9.

Abbreviations,

Acronyms,

and Initialisms

A

ADV

A/E

AFAS

AFM

ALARA

ANPO

ANPS

ANSI

AP

ASME Code

Ampere(s)

Auxiliary Building

ASEA Brown Boveri

(company)

Alternating Current

Automatic

CEA Timing Module

Atmospheric

Dump Valve

Architect/Engineer

Auxiliary Feedwater Actuation System

Auxiliary Feedwater

(system)

As Low as Reasonably

Achievable (radiation exposure)

Auxiliary Nuclear Plant [unlicensed] Operator

Assistant Nuclear Plant Supervisor

American National

Standards

Institute

Administrative Procedure

American Society of Mechanical

Engineers

Boiler and Pressure

Vessel

Code

0

18

ATI

ATWS

'BCS

BQAP

CFR

CIAS

CIS

CRAC

CWD

CWO

DC

DCN

DDPS

DEV

F

FI

FIS