ML17342A192

(AFW)

pumps

were

not

secured

in

accordance

with

procedures

(paragraph ll); maintenance

was

performed

on

AFW flow control

valve

(FCV)

3-2833 without the

use of

a plant work order

(PWO) (paragraph

8); mainte-

nance activities

were not properly documented

during the

replacement

of

a

reactor

protection

system

test

switch

(paragraph

8);

and

maintenance

procedures

were

" not adequately

implemented

during

work

on

the

A and

B

feedwater flow controllers, resulting in the controllers being wired to the

wrong power supplies

(paragraph

8), (250/85-26-01).

Failure to meet the requirements

of TS 6.8.3,

in that unauthorized

temporary

changes

were

made

to

the

surveillance

procedures

for the

system

(paragraph

7), (250/85-26-02).

Failure to meet the Criterion XVI of 10 CFR 50, Appendix B, in that water in

the

instrument

air

system

adversely

affected

the

operability

of

FCV-3-2833

and the adverse quality condition was not promptly identified and

corrected

(paragraph 8), (250, 251/85-26-03).

Three unresolved

items

(UNR) were identified:

Evaluate

the failure of the

licensee

to adjust

the

B

AFW pump electronic

setpoint after

the

pump

was

observed

to trip repeatedly

on

electronic

without exceeding

the

normal

setpoint value.

Evaluate

the

licensee's

failure to test

the

mechanical

and

electronic

trip setpoints

on

a periodic

basis

(paragraph

7),

(UNR 250,

251/85-26-04).

Evaluate

whether

the

nitrogen

backup to instrument air for the

AFW FCVs

shoul'd

be tested

by actually operating

the

AFW pumps with the instrument air

system isolated

(paragraph

7),

(UNR 250, 251/85-26-05).

Evaluate

the advisability

of calculating

and rescaling

the interim power

range

nuclear

instrument

currents

so that installed annunciators will not

indicate flux imbalances prior to obtaining post refueling

100 percent

power

physics data

(paragraph

12),

(UNR 250, 251/85-26-06).

An

inspector

followup .item IFI (paragraph

13),

(250,

251/85-26-07)

was

identified concerning

whether

Normal Operating

Procedure

15608. 1,

Loss of

Instrument

Air,

requires

improved

instructions

on mitigation of the

consequences

of a loss of instrument air.

The licensee

did not identify as proprietary

any of the materials

provided

to

or

reviewed

by the

inspectors

during this

inspection.

The

licensee

acknowledged

the findings without dissenting

comments.

Licensee Action on Previous Inspection

Findings (92702)

a.

Monthly update of Performance

Enhancement

Program

The

PEP

was

reviewed

to determine if commitments

were

being

met.

Status

was discussed

with the

PEP

Manager

and with other

members

of

management.

The facility upgrade

project

is

on

schedule.

The contractor

has

continued

pouring concrete

support

columns for the

new administrative

building, with the third floor beginning

to

be

poured.

The

paving

around the Health Physics building has

been finished and the fencing to

change

the radiation control area

has

been

moved.

The Health Physics

staff has

moved into the

new building.

The

schedule

for the

PEP continues to be met within acceptable

limits

and all modifications

have

been cleared

by the Region.

q I'

0

b.

Previously Identified Items

(Closed)

UNR 250/83-40-01,

Reactor

Decay

Heat

Inadequate

Procedure.

The

Off

Normal

Operating

Procedure,

(ONOP)

3208. 1,

Malfunction of

Residual

Heat

Removal

(RHR) System,

was adequately

revised

on June

21,

1985.

Another

procedure

to cover complete

loss of RHR, 3/4-0NOP-050,

Loss of RHR, dated

June

12,

1985,

was issued.

These

two ONOPs coupled

with the

procedure

for operation

of the

system,

3/4-0P-050,

Residual

Heat

Removal

System,

dated

May

29,

1985,

are

adequate

for

operator

guidance

to minimize the

impact of malfunctions of the

system

and to properly

lineup the

system.

The

UNR was

opened

by the

Resident

Inspector

in November

1983

due to inadequate

RHR procedures

that contributed

to

the

system

inoperability

and

temperature

excursion

event of October

1983.

The licensee

had agreed at that time

to

promulgate

a

normal

operating

procedure

governing

system

operations.

(Closed)

IFI 250/84-14-06,

Inverter Transfer

Switch

Maintenance

and

Responsibility.

The

licensee

has

assigned

responsibility

to

the

turbine operator

to assure

that inverter transfer switch maintenance

is

properly performed.

(Open) Violation 250,

251/85-02-02,

Failure

to Test the

AFW Nitrogen

System.

The

licensee,

in

response

to

the

notice

of violation,

initially developed

a

Temporary

Operating

Procedure

(TOP 158)

and

subsequently,

a

permanent

Operations

Surveillance

Procedure

(OSP) 075.3,

AFW Nitrogen

Backup

System Operability Verification, to

test

the

AFW nitrogen

system.

The

procedures

were

developed

and

implemented to measure

the bleed-down rate of the nitrogen bottles

and

verify that the

low pressure

alarms

functioned;

however,

the licensee

has

not

performed

any testing

that

demonstrates

that

the

nitrogen

system will act as

an adequate

backup supply to the

AFW FCVs upon loss

of instrument air.

A more detailed

discussion

of the discrepancy

is

found in paragraph

7 and relates

to

UNR 250, 251/85-26-05.

4.

Unresolved

Items

Three

unresolved

items were identified during this inspection

(paragraphs

7

and 12).

An unresolved

item is

a matter

about which more information is

required to determine

whether it is acceptable

or may involve a violation or

deviation.

5.

Licensee

Event Report

(LER) Followup (92700)

The following LERs were

reviewed

and closed.

The inspector verified that:

reporting

requirements

had

been

met,

causes

had been identified, corrective

actions

appeared

appropriate,

generic applicability had been considered,

and

the

LER forms were

complete.

A more detailed

review was then performed to

verify that:

the licensee

had

reviewed

the event,

corrective

action

had

been

taken,

no unreviewed

safety

questions

were involved,

and

no violation

of regulations

or TS conditions

had

been identified.

4

C

il

(Closed)

LER 250/84-01.

On January

8,

1984,

Unit 3 experienced

a reactor

trip from 30 percent

power.

The root cause

was determined

to be

a spurious

signal

which resulted

in closure of the

A steam

generator

(SG)

FCV.

This occurred while the Maintenance

Department

was troubleshooting

the

control circuit.

The spurious closure of this valve or similar valves

has

not recurred.

(Closed)

LER 250/84-02.

On January

8,

1984,

the Unit 3 reactor tripped from

one percent

power and

a safety injection signal

was received.

The operators

were

opening

the

main

steam

isolation

valves

and

were

decreasing

the

differential pressure

across

the valves

by rapidly opening

the associated

steam

atmospheric

dump valve.

This caused

a " high steam line flow" in the

line,

and the associated

cooldown caused

the "low primary average

tempera-

ture

" to complete

the initiation.

The licensee

agrees

that this is not

good operating

practice

and

has

instructed

the operators

to

heat

up

the

secondary

plant before trying to

open

the valves.

No water

was injected

since

the

primary pressure

was

higher

than

the

safety

injection

pump

discharge

pressure.

(Closed)

LER 250/84-04.

On January

4,

1984, while performing

a surveillance

on the

AFW system,

the

A and

C

AFW pumps

were started

but did not produce

the required flow.

A unit shutdown per the

TS should

have

been started

due

to their inoperability but

was

not.

This

was

the

subject

of escalated

enforcement

action

and was addressed

in report 250/84-04.

C

(Closed)

LER 250/84-06.

On

February

12,

1984,

at

6:38 a.m.,

a

Unit

3

reactor trip occurred

from 100

percent

power.

A reduced

flow

transient

resulted

from the

loss of the

3C

4160 volt bus.

The root cause

was

the

malfunction

of

a differential fault protection

relay

in

the

switchyard which tripped Unit 4.

This event

was

the subject of escalated

enforcement

action

and

was addressed

in report 250/84-09.

(Closed)

LER 250/84-07.

On

February

16,

1984,

the Unit 3

and

Unit 4

reactors

tripped from 100 percent

power.

A reduced

flow transient

resulted

from the loss of the

4C 4160 volt bus.

The root cause

was

a jarred

relay

caused

by

a bolt interfering with the

opening of a switchgear

door.

This event

was the subject of escalated

enforcement

action

and was addressed

in report 250/84-09.

(Closed)

LER 250/84-08.

On February

23,

1984, while performing

a surveil-

lance

on

the

AFW system,

the

B

pump

was

started

but experienced

flow

osci llations

and

was declared

out-of-ser vice.

Unit 3 was

heating

up the

primary system

and Unit 4's reactor

was critical.

A Unit 4 shutdown per the

TS should

have

been started

due to the inoperability but was not.

This was

the subject of escalated

enforcement

action

and

was

addressed

in report

250/84-09.

liI 'I

Qj

1

(Closed)

LER 250/84-11.

On March 23,

1984,

Unit

3 experienced

a turbine

runback from 100 percent to 83 percent

power caused

by nuclear

power range

channel

42B detector

reading

low.

Water

was

found in the cabling.

The

source of water was sealed

and the instrument returned to service.

,This was

discussed

in report 250/84-11.

(Closed)

LER 250/84-14.

On April 24,

1984,

a Unit 3 reactor trip occurred

from 100 percent

power.

An operator

was switching

a vital bus inverter

and

de-energized

the

wrong inverter

which

caused

a "rod drop

runback" which

resulted

in a reactor trip on high reactor pressure.

This was discussed

in

report 250/84-14.

(Closed)

LER 250/84-15.

On

May 14,

1984,

a Unit

3 reactor trip occurred

from 100 percent

power.

Nuclear

power range

channel

35 power supply failed.

This caused

the vital bus breaker for nuclear instrument rack one to trip,

de-energizing

nuclear

power

range.

channel

41

and

causing

a

"rod

drop

runback".

The source of the failed power

supply was

a ground which has

been

repaired.

(Closed)

LER 251/84-01.

On

February

12,

1984,

at

9:45

a.m.,

a Unit

4

reactor trip occurred

from

100 percent

power.

A reduced

flow

transient resulted

from the loss of the'C

4160 volt bus.

The root cause

was the malfunction of an electrical

synchronism

relay which allowed the

erroneous

closure

of

a

de-energized

bus

feeder

breaker

during

the

restoration

of power to Unit 3 following the Unit 3 reactor trip.

This

event

was the subject of escalated

enforcement

action

and

was

addressed

in

report 251/84-09.

Additional information was to be sent in

LER 251/84-03.

(Closed)

LER 251/84-04.

On

March

7,

1984,

a

spurious

signal

from the

containment

radiation

monitor

caused

the

containment

and

control

room

ventilation systems

to switch to the recirculation

mode.

(Closed)

LER 251/84-05.

VOLUNTARY REPORT,

The April 1984, ISI of the

4A SG

nozzle disclosed

a crack 270 degrees

around the nozzle.

A similar

crack

was

found

on

the

4C

SG,

but it extended

only

180 degrees.

Both

nozzles

were

replaced

per plant change/modification

(PC/M)

84-80.

The

nozzle-to-reducer

areas

were

examined

on the

4B

SG

and the 3A, 3B, and

3C

SGs with no evidence of cracking found.

(Closed)

LER 251/84-18.

On August 29,

1984, while Unit 4 was at

100 percent

power,

the

4B Intake Cooling Water

header

was

removed

from service for

a

period in'xcess

of that allowed per the TS.

This event

was the subject of

escalated

enforcement

action

and was addressed

in report 251/84-30.

IE Bulletin Fol lowup (92703)

The inspector discussed

the requirements

of pending

IEBs with the licensee.

Based

on

an analysis of licensee

supplied information and documentation,

the

inspector

closed all action items relating to the following bulletin:

(Closed - Units

3 and 4),

IEB 80-12,

Decay Heat

Removal

System Operability.

The licensee

responded

to the

IEB on June

11,

1980,

indicating that their

only open

item to close out the

IEB was to revise

ONOP 3208. 1, Malfunction

of Residual

Heat

Removal

(RHR)

System,

by June

30,

1980.

The

licensee

improved

ONOP

3208. 1 adequately

on June

21,

1985,

and

has written another

procedure

to cover

complete

loss of

RHR,

3/4-0NOP-050,

Loss of

RHR, dated

June

12,

1985.

These

two off-normal procedures,

coupled with the procedure

for normal

operation

of the

RHR system,

3/4-0P-050,

Residual

Heat

Removal

System,

dated

May 29,

1985,

are adequate

for operator

guidance to minimize

the

impact of malfunctions of the

RHR system

and to properly line

up the

system.

An

UNR (250/83-40-01)

was

opened

by the

resident

inspector

in

November

1983 for the inadequate

RHR procedures

that contributed to the

system inoperability

and the temperature

excursion

event of October

1983.

The

licensee

had

agreed

at that

time to

promulgate

a

normal

operating

procedure

governing

RHR.

That

UNR is discussed

in paragraph

3b of this

report.

Monthly and Annual Su'rvei llance Observation

(61726/61700)

The inspectors

observed

TS required surveillance

testing

and verified: that

the test

procedures

conformed to the requirements

of the

TS, that testing

was performed in accordance

with adequate

procedures,

that test instrumenta-

tion was calibrated,

that limiting conditions for operation

( LCO) were met,

that test results

met acceptance

criteria

and

were

reviewed

by personnel

other

than

the

individual

directing

the

test,

that

deficiencies

were

identified,

as

appropriate,

and

were

properly

reviewed

and

resolved

by

management

personnel

and

that

system

restoration

was

adequate.

For

completed tests,

the inspectors

verified that testing

frequencies

were

met

and that tests

were performed

by qualified individuals.

The inspectors

witnessed/reviewed

portions of the following test activities:

Units 3 and

4 AFW Train

1 Operability Verification

Units 3 and

4 AFW Train

2 Operability Verification

Instrument Air System

Dew point Sampling

AFW Pumps

A,

B and

C Electronic Overspeed

Testing

Unit 4 Reactor

Protection

System

Logic Testing

On July 22,

1985, at 12:40 a.m.,

the

AFW system received

an automatic start

signal

due to

a low level in the

3B SG.

The

A and

C

AFW pumps tripped

on

mechanical

and, thus,

were not immediately available

to supply the

SG.

The

B

pump trip-and-throttle

valve

cycled

closed

because

its

electronic

setpoint

was

exceeded.

The resultant

loss of steam

supply

reduced

the

pump's

rate of rotation allowing the trip-and-throttle

valve to reopen

as the electronic

reset setpoint

was reached.

The

B AFW pump trip-and-throttle valve cycled repeatedly

in this manner.

Between

1:30

a.m.

and 2:30 a.m.

on July 22, the licensee

performed testing

on all three

AFW pumps to establish operability subsequent

to the overspeed

trips.

gA records

of the testing,

~etained

as

requi~ed

by

Operations

Surveillance

Procedure

(OSP)

3-OSP-075. 1,

Auxiliary Feedwater

Train

1

~

Operabi

1 ity

Verificati on,

and

3-OSP-075. 2,

Auxi 1 iary

Feedwater

Train

2

Operability Verification, were reviewed

by the inspectors.

Numerous

steps

in

each

procedure

were

found to

have

been

omitted.

The

omissions constituted

changes

to the intent of the procedures

in that the

acceptance

criteria

for

pump

operability

were

modified

to

be

less

restrictive than

was previously acceptable.

Pump discharge

pressure

was not

monitored or recorded.

Checks for noise

and vibration were not made.

The

pumps were run for less

than the required

15 minute interval,

and they were

not verified to

be capable of delivering feedwater at the required rate of

375 gallons

per minute

(gpm) within three

minutes

of initial operation.

Additionally, the procedural

changes

were not approved

by two members of the

plant management

staff,

they were not documented

or reviewed

by the Plant

Nuclear

Safety

Committee

(PNSC),

nor

were

they

approved

by the

Plant

Manager-Nuclear within 14 days,

as required.

TS 6.8.3 requires that temporary

changes

to procedures

only be

made provided

that:

a.

the intent of the o'riginal procedure

is not altered;

b.

the change is approved

by .two members of the plant management

staff, at

least

one

of

whom holds

a

Senior

Operator's

License

on

the

unit

affected;

and

c.

the

change

is

documented,

reviewed

by the

PNSC

and

approved

by the

Plant Manager-Nuclear

within 14 days of implementation.

Failure to comply with the requirements

of

TS 6.8.3 is

a violation.

This

violation applies to Unit 3 only (250/85-26-02).

The licensee

management

was not aware that only modified versions

of the

surveillance

procedures

had

been

performed following the

AFW pump trips of

July 22,

1985.

When

informed of the

discrepancy

they directed that the

tests

be performed

in their entirety.

Since Unit

3

had

been

cooled

down

during that afternoon

the additional testing

was

performed with the

pumps

aligned to Unit 4.

The surveillance

testing

was

observed

by the

Resident

Inspector

and was completed satisfactorily.

The July 22,

1985, electronic overspeed

cycling of the

B AFW pump trip-and-

throttle valve prompted reviews of previous surveillance

tests to determine

the

hi story of the

problem.

During

a previous

surveillance

on June

23,

1985,

the

B AFW pump failed its operability test

because it twice tripped

on

electronic

overspeed.

Consequently,

PWO

8116

was

issued

to resolve

the

problem.

The

pump

was determined

to

be

running

at

5980

revolutions

per

minute

(rpm)

instead

of the

desired

5900

rpm.

The electronic

setpoint

should

have

been

6200

rpm.

The

B

AFW pump governor

was adjusted

such that the turbine rotated

at

5900

rpm.

The

pump

was tested

and it no

longer tripped

on electronic overspeed.

'II

Ap

Discussions

with technical

support personnel

indicated that the

pump was not

demonstrating

large oscillations

in speed.

The

maximum anticipated

speed

change,

during

normal

operation,

is

about

100 rpm.

Consequently,

on

June

23,

1985,

the electronic

for the

B AFM pump could have

been

estimated

to have occurred at

no more than

6080 rpm.

The licensee

did not

perform

this

extrapolation

and

after

the

symptom

had

been

corrected,

a verification of the actual

setpoint

was not performed.

Following the malfunction of the

B AFM pump on July 22,

1985,

the electronic

setpoint

was tested.

The setpoint

was found to be 6066

rpm which

was

134

rpm too low.

Apparently, the electronic

tri.ps

on June

23

and July 22 were

due to an incorrectly adjusted

setpoint.

Discussions

with the licensee

revealed

that their surveillance

program did

not require

the

routine

periodic testing

of either

the

electronic

or

mechanical

setpoints.

The electronic

and

mechanical

setpoints

had last been

checked

in December

1983, following installation of

new governors.

While not

on

a periodic schedule,

the mechanical

setpoints

were subsequently

tested

in 1984 following governor maintenance.

On March

1,

1985,

the

Power Plant

Engineering

Department

recommended

that

both the electronic

and

mechanical

setpoints

be tested

annually

(JPE-PTPO-231).

On March 26,

1985, the Technical

Department

requested

that

the

Procedure

Upgrade

Project

(PUP)

develop the procedures

by December

31,

1985.

As of August

12,

work on the

procedures

had not begun.

Since

the

testing

process

is

not

complicated

and

since

the

Technical

Department did not request

the procedures

in the near future,

a low'priority

was assigned

to the task.

The failure of the licensee

to have

a program requiring periodic testing of

the electronic

and mechanical

setpoints

and the failure of the

licensee,

on

June

23,

1985,

to

address

the

improper

setting

of the

electronic

setpoint

on the

B AFW pump is an

UNR (250,251/85-26-04)

pending additional

review and analysis

by the resident

inspectors.

Early

on July

24,

1985,

the

licensee

returned

Unit,

3 to critical

and

performed

AFM pump testing,

including electronic

testing,

on the

A

and

C

pumps.

Testing

was

observed

by the

Resident

Inspector

and

was

satisfactory

on the

A pump;

the electronic

testing portion

was

satisfactory

on the

C pump.

During this testing,

when the

FCV controllers

were left in the automatic

mode,

the

pump

speed

remained essentially

constant at approximately

5900

rpm

but the

FCVs continuously cycled plus or minus

~~

inch around the

20 percent

open position.

The control board flow indications were rapidly cycling from

0 to

300 gpm,

and

each controller output

was cycling from 0 to 60 percent

demand.

From the control

room it appeared

that the

system

was unstable.

However,

pump speed,

which

has

only local indication',

was stable.

These

unusual

indications

have existed for quite

some time

'E

I

10

The control

room operators

do not feel comfortable with the

system operating

in the automatic

mode.

As

a

standard

practice,

the control

room operators

place the system in manual control

as

soon

as

possible

following automatic

system

initiation.

At the

Resident

Inspector's

request

the

licensee

demonstrated

pump operability in the automatic

mode by running each

pump for

five minutes.

Although the

pumps

did not trip,

the control

room flow

indications

remained erratic

and the licensee

declined

a request

to perform

the full surveillance

procedure

in the automatic

mode.

The

licensee

maintains

that

there

is

no

requirement

that

the

system

be

capable of sustained

automatic operation.

In Inspection

Report

250,251/85-02,

covering

the period of January

1 to

February 2,

1985, Violation 250,251/85-02-02

was issued

because

the licensee

did not demonstrate,

through periodic testing, that the

AFW nitrogen

system

was

capable

of controlling the

AFW FCVs.

As an interim corrective action,

the licensee

developed

TOP 158, Auxiliary Feedwater

System Periodic Nitrogen

Backup Test.

The

TOP is designed

to measure

the bleed-down

rate of the

nitrogen bottles

and to verify that the

low nitrogen

pressure

alarms

are

functional.,

Acceptance criteria require that the bleed-down rate

be

no more

than

50 pounds

per minute and that the low pressure

alarm be received at 500

pounds

per square

inch.

A review of the

TOP

revealed

that it does

not verify that the bottled

nitrogen

system

could actually

operate

the

FCVs during

a

simulated

automatic

system

actuation.

The

TOP

was only performed with the

AFW pumps

secured.

The

AFW FCVs were positioned

20 percent

open

in manual

control.

Cycling of the valves

through their full range of motion,

as

would occur

during

an automatic

system actuation,

was not required.

The bleed-down rate

obtained

was not representative

of the rates

which would exist if the valves

were operating in the automatic

mode or if the

manual

valve positions

were

frequently adjusted

by the control

room operator.

Measuring the bleed-down

rate

and verifying that it was sufficiently slow to

allow the

timely

replacement

of depleted

bottles

provided only circumstantial

evidence

of

system operability.

Discussions

with licensee

personnel

revealed

that the

AFW system

has at

no

time

been physically operated

with the instrument air system

isolated

and

only nitrogen available to position the

FCVs.

This discrepancy

constitutes

an

UNR (250,251/85-26-05)

pending

an evaluation of the licensee's

AFW system

.

test program.

Maintenance

Observations

(62703

8 62700)

Station maintenance activities of safety-related

systems

and components

were

observed/reviewed

to ascertain

that they were

conducted

in accordance

with

approved

procedures,

regulatory guides,

industry codes

and standards

and in

conformance with TS.

I

Il

)

The following items

were

considered

during this

review,

as appropriate:

that

LCOs were

met while components

or systems

were

removed

from service;

that approvals

were obtained prior to initiating the work; that activities

were

accomplished

using

approved

procedures

and

were

inspected

as

applicable; that procedures

used were adequate

to control the activity; that

troubleshooting

activities

were controlled

and

repair

record

accurately

reflected

what took place; that functional testing and/or calibrations

were

performed

prior to returning

components

or

systems

to service;

that

records

were

maintained;

that activities

were

accomplished

by qualified

personnel;

that

parts

and materials

used

were

properly certified; that

radiological

controls were implemented;

that

QC holdpoints were established

and observed

where required; that fire prevention controls were implemented;

that outside contractor force activities were controlled in accordance

with

the approved

QA program;

and that housekeeping

was actively pur sued.

The following maintenance activities were observed

and/or revie'wed:

Unit 3 AFW FCV-3-2833 repair

Unit 3 and Unit 4 instrument air system repair

Unit 3 reactor

protection

system test switch S-5 replacement

3A and

3B

SG feedwater controller rewiring

Instrument inverter replacement

Reactor protection

system logic contact cleaning

(PWO 7534)

B AFW pump electronic overspeed

setpoint adjustment

AFW FCV air system cleaning

AFW FCV-3-2817 positioner calibration

During this inspection

period,

the

licensee

failed to

comply with the

requirements

of

TS 6.8. 1, in the

area of maintenance

activities,

on three

occasions.

On July

14,

1985,, during Unit

3

AFW surveillance

testing,

FCV-3-2833

failed

in the

open

position.

The

valve

was

repaired

without the

issuance

of a

PWO.

Administrative Procedure

(AP) 0190. 19,

dated

May

21,

1985, entitled Control of Maintenance

on Nuclear Safety Related

and

Fire Protection

Equipment,

requires that

a

PWO

be i ssued

for mainte-

nance

activities.

Section

8 of the

procedure

requires

that

and

supervisory

reviews

be performed prior to beginning the maintenance

and

that the activities be thoroughly documented

on the

PWO.

Contrary to the

above,

on July 14,

1985,

maintenance

was performed

on

Unit 3

AFW FCV-3-2833

and

a

PWO was

not issued for the activity.

and supervisory

reviews of the maintenance

were not performed'nd

the

maintenance

was not documented.

b.

On July

30,

1985,

test

switch

S-5

was

replaced

in Unit

3 reactor

protection

rack

41.

AP

0190. 19 requires,

in section

8,

that

the

conduct of maintenance activities

be thoroughly documented

on

a

PWO.

I

12

Contrary to the

above,

on July 30,

1985,

maintenance

activities

were

not thoroughly

documented

during

the

replacement

of switch

S-5

in

reactor protection

system

rack

41 of Unit 3,

in that

erroneous

and

incomplete information was recorded

on

PWO 7546.

The

PWO documentation

section

did not indicate

that wiring changes

had

been

made

on

the

switch prior to its final installation.

At 11:45 p.m.

a

QC Inspector

was contacted

by telephone

and informed of

the

need to replace

the switch.

The replacement

plan was discussed

and

verbal

approval

was

obtained.

A replacement

switch,

part

number

40302-501,

was obtained

from supply and installed.

Subsequent

reactor

protection

system testing indicated that the problem was not completely

corrected

and

switch

S-5

was

not operating

properly.

Troubleshooting

was

resumed

but the

gC Inspector

was not informed that the replacement

of switch

S-5 failed to correct

the

observed

discrepancies.

The

IKC

technician

removed switch S-5

and determined that it contained

normally

closed

rather

than

the

required

normally

open

contacts.

The

I&C

technician,

without authorization,

reversed

the contacts

on

S-5

and

reinstalled

the switch.

The entry recorded

on the

PWO states,

"the

correct

switch

was

obtained

and installed,"

which is

an inaccurate

statement.

Switch

S-5

was initially installed

without

independent

verification of the wiring installation.

At the request

of the

NRC

Inspectors,

the verification was performed

and the switch, which is not

listed

as

a

safety-related

component,

was

found

to

be

correctly

installed.

This problem occurred

because

the

gC Department

was not appraised

of

all aspects

of the switch contact discrepancy.

Consequently, it could

not institute

programmatic

protections

to assure

the quality of the

maintenance.

The

18C technician's

actions

were contrary to

numerous

requirements

of

AP

0190. 19.

The

Department

has

issued

noncon-

formances

which

require

the

Naintenance

Department

to

address

the

failure to implement

AP 0190.19.

On August 1,

1985, the Unit 3 reactor tripped due to

a loss of 120 volt

vital instrument

panel

3P08.

Several

hours after the unit stabilized

the

Resident

Inspector verified that

the on-shift reactor

operators

felt

the

plant

had

responded

in

a

manner

consistent

with the

description

found in 3-0NOP-003.8,

Loss of

120 Volt Vital Instrument

Panel

3P08

~

While discussing

the

plant

response,

the

operators

indicated that the

A SG feedwater regulating valve hand/auto controller

was operated

in manual following the loss of power.

Since

3-0NOP-003.8

indicates that the

A SG feedwater regulating valve hand/auto controller

is deenergized

on loss of 3P08,

a review of the apparent

problem was

initiated.

It was determined that the hand/auto

control stations for the

A and

B

feedwater regulating valves were each wired to opposite

power supplies.

Consequently,

the as-built controller wiring was connected

contr ary to

approved

drawings.

The

licensee

determined

that the

crossed

wiring

probably occurred during maintenance

activities

on the controllers

on

13

some

The

date

could

not

be

readily

determined.

Consequently,

the problem existed for an

unknown length of time.

Previously,

on June

13,

1985,

the licensee

had performed testing of the

Unit

3

instrument

power

supplies

to

determine

whether electrical

drawings

were

accurate.

The testing

was

documented

on

PWO

7210.

During the testing,

breaker

7 on power supply

3P08 was opened

and the

B

SG feedwater

regulating valve hand/auto controller was observed

to lose

power;

however,

approved

drawings

show that

the

A

SG

regulating valve hand/auto

controller should

have lost

power instead.

The discrepancy

was not detected

by the licensee until after the trip

on August 1,

1985.

Section

5.'1 of ANSI N18.7-1972

and section

9 of Appendix

A of

USNRC

Regulatory

Guide

1.33

require

that

maintenance

that

can affect the

performance

of safety-related

equipment

shall

be properly

planned

and

performed

in accordance

with written procedures,

documented

instruc-

tions or drawings appropriate

to the circumstances.

Contrary to the

above,

maintenance

procedures

for the

3A and

3B feed-

water regulating valve hand/auto

flow controllers

(CV-2900 and CV-2901,

respectively)

were not adequately

implemented

in that the controllers

were wired to power supplies

other

than those specified in the approved

drawings.

The discrepancy

was corrected

on August 2,

1985.

The

events

discussed

in

items

a through

c occurred

because

the licensee

failed to

comply with

TS 6.8. 1

in that

procedures

were

not adequately

implemented.

Items

a

through

c

document

three

of the

four

examples

constituting

Violation 250/85-26-01.

The other

example

is discussed

in

paragraph

11.

The

following paragraphs

address

a

sequence

of events

and

maintenance

activities concerning

the instrument

air-AFW interface:

d.

At ll:43 p.m.,

on July 21,

1985,

following a Unit 3 reactor trip,

a

low-low level in the

B S/G caused

an auto-start of the

AFM system.

The

AFW system

functioned normally,

and at 11:50 p.m. the reactor control

room operator

placed the normal feedwater

system

in service

and

began

to secure

the

AFW system.

He attempted

to close

FCV-3-2833

(AFW train

2 flow control

valve to the

C SG),

but the valve

was failed in the

full-open position.

The

I&C Department

was notified of the problem.

At 12:40 a.m.,

on July 22,

1985,

a low-low level in the

B

SG occurred

because

the

B main feedwater

bypass

valve,

FCV-3-489, failed to respond

to

demand

signals

from the control

room.

The low-low level

signal

caused

the

AFW system to auto-start.

The

A and

C AFW pumps,

both lined

up to train 1, auto-started

and promptly tripped

on mechanical

over-

speed.

The

B AFW pump, lined up to train 2, auto-started

and cycled

on

electronic

overspeed.

Electronic

cycling resulted

in the

trip-and-throttle valve shutting

when the

pump's turbine

reached

the

setpoint

and

then

opening

as

the turbine

slowed

to the

i

I

tl I

14

reset

setpoint.

The cycling

was repetative

and continued

until the

AFW system

was secured.

The circumstances

surrounding

the mechanical

tripping of the

A and

C

AFW pumps are discussed

in paragraph

11.

The cycling of the

B AFW pump

is discussed

in paragraph

7.

At 4:00 a.m.,

a high level in the

C

SG occurred

because

the

C feedwater

bypass

valve,

FCV-3-499, failed to respond

to

a

r emote

manual

close

signal initiated by the reactor control

room operator.

The high level

signal tripped the operating

main feedwater

pump

and auto-started

the

AFW system.

The

AFW system

responded

normally except for FCV-3-2833,

which had remained full-open since failing ear lier.

At 4:40 a.m.,

a cooldown of Unit 3 was begun.

FCV-3-2833 was still out

of service

TS 3.8 provides

no

LCO or action

statement

when

a unit

with an

AFW problem is operating

below two percent

power.

Since Unit 3

was

subcritical

when

FCV.-3-2833 failed,

no

LCO or action

statement

exi sted

and

a cooldown was

begun

under

TS 3.0. 1.

The transients

of July 22,

1985,

revealed

valve operability di screpan-

cies for AFW train

2 FCV-3-2833,

and both main feedwater

bypass

valves,

FCV-3-489 and FCV-3-499.

In each

case

the valves failed to respond

to

remote positioning signals initiated from the control

room.

The Resident

Inspectors

reviewed

gC records

documenting that FCV-3-2833

and

FCV-3-2832 received

maintenance

after malfunctioning during testing

on July 14,

1985.

The Plant Supervisor's

Log documents that FCY-3-2833

did not operate

properly.

Haintenance

personnel

and

members

of the

Technical

Department staff stated

that

FCV-3-2833

was cleaned

because

it stuck

open.

Following cleaning it still did not fully close until

its positioner

was re-zeroed.

Water

was

found in the

instrument air

supply line.

FCV-3-2832 failed to reposition

in response

to

remote

signals until after its orifice plunger

was exercised

to unblock

an

obstructed

instrument air bleed-off line.

On July 22,

1985,

18C technicians

removed,

cleaned

and recalibrated

the

FCV-3-2833 current-to-pneumatic

controller.

Upon controller reinstalla-

tion, the valve was stroked

and immediately stuck in the

open position.

Investigation

revealed

that water

in the valve's

instrument air line

precluded

proper

valve operation.

The water

was

blown

out of the

instrument air line and

then

the valve

was

stroked

successfully

and

returned to service (reference

PWO 7491).

Early

on July 24,

1985,

the licensee

started

the Unit 3 reactor

and

performed

AFW system

surveillance

testing.

FCV-3-2833

and

FCV-3-2832

failed to reclose at the

end of the A AFW pump testing.

The licensee

determined

that train

1 of the

AFW system

was inoperable

due to the

failure of the valves

and Unit 3 was placed in hot standby.

15

Later

on July 24,

the inspectors

informed maintenance

personnel

that

Unit 4 instrument air dessicant

dryer had

a high humidity alarm and was

not operating

properly.

An evaluation

revealed

that the dryer system

was improperly aligned.

Several

components

were found to be inoperable

and

a

PWO was submitted to address

the discrepancies.

Since

the Unit 4 -instrument air system supplies air to Unit 3 train

2

AFW FCVs,

including

FCY-3-2833,

and

since

the Unit 4 instrument air

dryer

was

observed

,to

be

operating

with unattended

high humidity

alarms,

the licensee

checked

the Unit

4

FCVs for water

in the

instrument air lines.

The instrument air line for one Unit 4 train

1

AFW FCV was found to contain water.

The Unit 4 instrument air system

supplies

both Unit 4 train

1 and Unit 3 train

2

AFW FCVs.

On the afternoon

of July 24,

1985,

the licensee

began to correct the

discrepancies

associated

with the Unit 4 instrument air system.

The

decision

was

made

to

take

local

dew point measurements

at the

FCVs.

I

On July 25,

1985,

the filters which had

been

removed

from each

units'nstrument

air system were observed

to have

been

degraded.

The Unit 4

oil/water separator filter was excessively

wet,

and the dryer outlet

filter had white/gray,

light powder

on it.

The filters

had

been

changed

during quarterly replacement

in June

1985.

The Unit

4 instrument air dryer maintenance

effort resulted

in the

replacement

of the selector

switches,

the cycle timer and the three-way

valve limit switch.

The failed limit switch

had apparently

precluded

energizing

the

drying heaters.

The Unit

4 dryer outlet

dew point

reading

was

determined

to

be

+53

degrees

Fahrenheit

(F).

This

constituted

an

excessively

moisture

ladden air output.

The dryer

outlet dew point should

have

been

on the order of -30 degrees

F.

On the afternoon

of July 25,

1985,

the Unit

3

AFW valve current-to-

pneumatic

converter s

and

positioner

air

lines

were

cleaned.

Some

foreign matter

had

been

cleaned

out of each

valve control

mechanism.

The train

2 valves

had

dew points at their instrument air supply

connections

of +14 degrees

F to +20 degrees

F and the train

1 valve dew

points were +60 degrees

F to +51 degrees

F.

Following a fifteen minute

air system

blowdown, the train

2 valves

had

dew points of +52 degrees

F

to +55 degrees

F.

The dew point values

were indicative of moisture in

the instrument air system.

The

licensee

changed

the

dessicant

in Unit

4 instrument air dryer

because it was

brown

and

had

released

the white/gray

powder

found in

the downstream filters.

These

were indications that the desiccant

may

have lost

a substantial

ability to absorb

moisture.

Some

loose

metal

brackets

were discovered

in the bottom of the

Unit

4 dryer

and

an

evaluation

was begun to determine their significance.

16

Discussions

between

NRC Region II management

and the licensee

resulted

in mutually acceptable

criteria for establishing

and verifying satis-

factory instrument air system operability as follows:

Clean

and

flush

the

controls

for

the

AFW valves

on

Unit 4

(clean/flush/calibrate/retest).

Take

dew

points

on all six Unit

4

AFW valves,

compare

with

acceptance

criteria and evaluate

any discrepancies.

Blowdown low points

and valves of the instrument air system

on

a

systematic

basis

(list locations/length

of time of blowdown /when

done).

Blowdown

AFW valve regulators,

including

main

bypass

valves (list valves/length of time of blowdown /when done).

Take periodic dew point readings

at each dryer outlet and maintain

outlet dew points within acceptable

ranges.

Evaluate

and repai r, as necessary,

the Unit 3 instrument air

system.

The licensee's

evaluation

of the valve failures occurring

on July 22,

1985,

concluded

that water in the instrument air system

had prevented

the

valves

from operating.

The

licensee

was

aware

that

water

was

contained

in the instrument air system but was not aware that the water

would adversely

affect the operation

of the safety-related

AFW FCVs.

When water was observed

in the instrument air supply to FCV-3-2833,

on

July 14,

1985,

the discrepancy

was only symptomatically addressed.

The

lack of management

action at that time was influenced by the informal

and undocumented

nature of the July

14 maintenance

(paragraph S.a.).

10 CFR 50, Appendix B, Criterion XVI, as

implemented

by Florida Power

and Light Topical Quality Assurance

Report (FPL-NQA-100A), Revision 7,

TQR 16.0, Corrective Action, requires,

in part, that measures

shall

be

established

to

assure

that

conditions

adverse

to quality,

such

as

failures,

malfunctions,

deficiencies,

deviations,

defective

material

and

equipment,

and

nonconformances

are

promptly

identified

and

corrected.

Florida

Power

and

Light Quality Assurance

Manual, Quality Procedure

(QP)

16. 1,

Revision

8,

delineates

requirements

for assuring

that

conditions

adverse

to quality are corrected.

AP

0190. 13,

dated

May

21,

1985,

entitled

Corrective

Action for

Conditions

Adverse to Quality, itemizes the mechanisms

by which condi-

tions

adverse

to

quality

are

promptly

identified,

tracked

and

corrected.

~

C

1'

17

Contrary to the

above,

the licensee

failed to establish

measures

to

assure

that conditions

adverse

to quality were promptly identified and

corrected,

in that the licensee's

corrective action program

was imple-

mented in a manner

which allowed

symptom correction without requiring

the identification, evaluation

and correction of the

source

problem.

Consequently,

on July 14,

1985,

and again

on July 22,

1985,

water

was

drained

from the

instrument air

supply line for

AFW FCV-3-2833

to

restore

valve operability while no effort was

made to locate,

evaluate

or eliminate

the

source

of the water.

Failure to prevent- water from

entering

the instrument air system

resulted

in

an additional

malfunc-

tion of FCV-3-2833

on July 24,

1985.

The licensee

did not address

the

degraded

status of the instrument air dryers

and heaters until 10 days

after

the air system

was

known to contain water.

By that time

FCV-3-2833

had failed on three

separate

occasions.

The failure

to

meet

the

requirements

of

10 CFR 50, Appendix B,

Criterion XVI is

a Violation 250,251/85-26-03.

9.

Operational

Safety Verification (71707)

The inspectors

observed

control

room operations,

reviewed applicable

logs,

conducted

discussions

with control

room operators,

observed shift turnovers

and confirmed operability of instrumentation.

The inspectors

verified the

operability

of selected

emergency

systems,

verified that maintenance

work

orders

had been

submitted

as required

and verified that followup and priori-

tization of work was accomplished.

The inspectors

reviewed tagout

records,

verified compliance

with

TS

LCOs

and verified the

return

to service of

affected

components.

By observation

and direct

interviews,

verification

was

made

that

the

physical security plan was being implemented.

Plant housekeeping/cleanliness

conditions

and implementation of radiological

controls were observed.

Tours of the intake structure

and diesel,

auxiliary, control

and turbine

buildings

were

conducted

to

observe

plant equipment

conditions

including

potential fire hazards,

fluid leaks

and excessive

vibrations.

The

inspectors

walked

down

accessible

portions

of the following safety-

on Unit

3

and

Unit

4 to verify operability

and proper

valve/switch alignment:

Emergency diesel

generators

Auxiliary feedwater

Component cooling water

4160 volt and 480 volt switchgear

Radiological

waste processing

and storage

Control

room vertical panels

High head safety injection

18

Containment

spray

system

120 volt ac inverters

Battery power supplies

Spent fuel storage

Charging

pumps

No violations or deviations

were identified.

10.

Engineered

Safety Features

Walkdown (71710)

The inspector verified operability of'he

AFW system,

which is

common to

Units

3

and 4,

by performing

a complete

walkdown of the accessible

portion

of the

system.

The

following items

were

specifically

reviewed

and/or

observed

as appropriate:

a.

that the licensee's

system lineup procedures

matched plant drawings

and

the as-built configuration;

b.

that the

equipment

conditions

were satisfactory

and

items that might

degrade

performance

were identified

and evaluated

(e.g.

hangers

and

supports

were operable,

housekeeping

was adequate);

c.

that instrumentation

was properly valved-in

and functioning

and that

calibration dates

were not exceeded;

d.

that

valves

were

in proper position,

breaker

alignment

was correct,

power was available,

and valves were locked/lockwired

as required;

e.

that local

and remote position indications were in agreement

and remote

instrumentation

was functional;

and

f.

that

breakers

and

instrumentation

cabinets

were

free of

damage

and

interference.

During the

walkdown of the

AFW system,

the following discrepancies

were

identified:

g.

Numerous

AFW FCVs were

found to

have

instrument air

leaks

along the

upper cylinder housing.

PWOs

were written documenting

the discrepan-

cies.

The

li'censee

has

begun

an evaluation

of the

leakage

and its

effects

on valve operability.

Recent testing

revealed

no diminished

valve control capabilities

due to instrument air leakage.

h.

A broken

connector

pin was found on the positioner for Unit 3 train

1

valve 2816.

The pin was promptly .replaced.

The connector

pins

on all

12 Unit 3

and Unit 4

FCV positioners

lacked

grease.

While

no

specific

preventive

maintenance

document

requires

pin greasing,

the valve technical

manual

states

that each pin

should

be greased

upon installation.

The licensee

plans to keep these

pins greased

in the future to help preclude binding.

~'

I,

19

j.

Several

FCV positioner

arms

were

improperly aligned

causing

the

arms to scrape their associated

stem lifting arms.

While binding had

apparently

not

occurred,

visual

evidence

of physical

contact

was

present.

The licensee

has

issued

PWOs to align the positioner

arms in

parallel with the

stem lifting arms.

When informed of these discrepancies

the licensee initiated prompt

corrective action.

No violations or deviations

were identified.

Plant Events

(93702)

An independent

review was conducted of the following events.

On July 16,

1985,

a subcritical trip of the Unit 3 reactor occurred

due to

the loss of the

3C vital instrument

bus inverter.

The loss

de-energ'ized

source

range

nuclear

instrument

N-31 causing

a spurious

source

range

high

flux trip.

Shutdown

control

rod banks

A and

B automatically

entered

the

core.

Control rod banks

A through

D were already fully inserted at the time

of the trip.

Fuse

F-6 was replaced

and the inverter was returned to standby

service.

The licensee

is currently expediting

the

replacement

of all

12

inverters with a newer,

more reliable model.

On July

17,

1985,

the Unit 4 reactor tripped from 100 percent

power due to

the loss of the

4D inverter.

A current limiting circuit was

found to have

failed.

The circuit was replaced

and the inverter was restored

to service.

The failure of vital instrument

inverters

is

recognized

as

a repetative

problem.

The inverter s are being replaced

on

an expedited

schedule.

On July 21,

1985, the Unit 3 reactor

tripped from 100 percent

power due to a

spurious

protection

relay actuation.

The

unexpected

relay

actuation

was

attributed to

a lightning strike

near the Unit 3 turbine deck.

During the

resultant transient,

the

AFW system

and the

main feedwater

system did not

respond

properly,

as

discussed

in

paragraphs

6

and

7,

respectively.

Following the first initiation of the

AFW system the

A and

C AFW pumps were

improperly

secured.

The

pumps

were

secured

using

procedure

3-OSP-075. 1,

Auxiliary Feedwater

Train

1 Operability Verification.

Sections

7. 1

and 7.2

of the

procedure

specify that -the trip-and-throttle valve for each

pump be

open prior to exercising

the governor oil knob.

On July 22,

1985,

shortly

after 12:00

am, the

A and

C AFW pump governor oil knobs were exercised prior

to opening

the trip-and-throttle valve for each

pump.

Subsequently,

when

the trip-and-throttle

valves

were

opened,

each

governor

became

misadjusted

due

to additional

pump rotation.

Consequently,

the

A and

C

pumps

tripped

on mechanical

when next called

upon to operate.

Failure to

secure

the

A and

C

AFW pumps in accordance

with procedures

is an example of

Violation 250/85-26-01.

Additional examples

are discussed

in paragraph

8.

On July 24,

1985, the Unit 3 reactor

was

shutdown

due to the failure of AFW

FCV-3-2833

and

FCV-3-2832 to operate

properly.

Water in the instrument air

system

was

found to have contributed to the degraded

status of the valves.

20

The repair of the instrument air

system

and the

AFW FCVs is discussed

in

paragraphs

7 and 8.

On July

26,

1985,

preparations

were

begun

to

again

shut

down Unit

3

following the failure of

AFW FCV-3-2817 to pass

an operability test.

The

valve positioner

was adjusted

and the valve was tested satisfactorily prior

to the reactor being shut

down.

Preparations

to shut

down the reactor

were

terminated.

On July 29,

1985,

the Unit 3 reactor tripped from 100 percent

power due to

dirty relay contacts

in the reactor protection

system cabinets.

The

power

range

nuclear

instrument relay contacts

for high flux were cleaned.

While

no specific dirty relay could be identified, additional

system testing

led

the

PNSC to conclude that

a dirty relay contact existed

and contributed to

the trip.

On August

1,

1985,

the Unit 3 reactor tripped from 32 percent

power due to

the failure of the

B spare

inverter.

Several circuit cards

were

replaced

due

to failed

components.

The inverter

was

returned

to

service.

The

replacement

of the inverters is progressing

on

an expedited

schedule.

12.

Independent

Inspection

During the report

period the inspectors

routinely attended

meetings

with

licensee

management

and monitored shift turnovers

between shift supervisors

(Plant

Supervisor-Nuclear

[PSN]), shift

foremen

(Nuclear

Watch

Engineers

[NWE]) and

l=icensed control

room operators

(CRO).

These

meetings

provided

a

daily status

of plant operating

and testing activities in progress

as well

as

a discussion

of significant

problems

or

incidents.

Based

on

these

discussions,

the

inspectors

reviewed

potential

problem

areas

to indepen-

dently assess

their importance

to safety,

the

proposed

solutions,

improve-

ment

and

progress,

and

adequacy

of corrective

actions.

The

inspector's

reviews

of these

matters

were

not restricted

to the

defined

inspection

program.

Independent

inspection

efforts

were

conducted

in the following

areas:

Axial flux difference off-normal procedures

quadrant

power tilt off-normal procedures

From July

26 through

29,

1985,

Unit

3 control

room annunciators

indicated

that the allowed axial flux band of five percent

was being exceeded.

The

annunciators,

labeled

Axial Flux .> five percent

and Axial Flux

> five

percent

> one

hour,

are controlled

by the digital data

processing

system

(DDPS).

The annunciators

were considered

out of service

by the

CROs because

the

DDPS was

known to not have the correct axial flux limits installed.

The

correct limits were

promulgated

on

June

12,

1985.

Due to

an oversight,

these

limits were not installed in the

DDPS axial flux program until after

the

Unit

3

reactor

was

operated

at

power.

CROs

compensated

for the

erroneously

alarming

annunciators

by recording

indicated

axial flux as

required

by TS 3.2.8

and

comparing

the values

to the correct limits.

The

installation of the correct axial flux limits in the

DDPS takes only a short

l

3,,

g

21

period of time.

Failure to install the limits resulted in the annunciators

being

needlessly

out of service.

The

problem

was corrected

on August 1,

1985.

Between

August

4

and

8,

1985,

the

upper

and

lower quadrant

power tilt

annunciators

were

alarmed

in the

Unit

3 control

room.

The

alarms

were

considered

erroneous

because

the power range nuclear instrument currents

had

not been adjusted

to reflect the results of post refueling physics testing.

The

licensee

delayed

the calculation

of the correct

currents

until

100

percent

power, equilibrium xenon flux maps were obtained.

Consequently,

the

power

range nuclear instruments

were providing incorrect radial flux outputs

between

August

4

and 8,

1985.

The licensee

performed flux maps at 30,

50

and

75 percent

power prior to August 4,

and these

maps indicated that there

was not an actual flux imbalance

in either the axial or radial directions.

t

It may be possible to extrapolate

approximate

power range nuclear

instrument

currents

from the lower power flux maps.

The resultant interim values would

represent

a

more accurate

approximation of the

necessary

currents

than is

obtained

by using

the currents

from the pre-refueling

core.

The

interim

values

could

be accurate

enough

to prevent the unnecessary

alarming of the

axial

and radial

alarm circuitry prior

to

completing

the

100

percent

equi librium xenon flux calculations.

The failure of the licensee

to

use

interim currents

to preclude

unnecessary

flux alarms is

an

UNR (250,251/

85-26-06)

pending

further evaluation

of the licensee's

low power physics

testing

program.

13.

Office of Analysis and Evaluation of Operational

Data

(AEOD) Visit

From August

6 to

9,

1985,

a representative

of the Office of the

AEOD

accompanied

by a Region II inspector

conducted

a special

team site visit to

gather

information

on

the facts

and

circumstances

surrounding

the

malfunction

which occurred

on July 22,

1985.

Details of this event

are

described

elsewhere

in this report.

The

team

focused its efforts

on the