ML18036A398

control

system.

This consisted

of

placing the feedwater control

system in single

element

and in three

element

control

method.

The

showed instability in that

the desired

level

and the actual

level

would diverge.

This in turn

caused

instability and resulted

in several

transients

on the system.

The operators

and the test personnel

were eventually able to get the

desired

and actual

level to converge

thereby creating

stabi::ity in

the

system.

The final physical

testing

was

completed

on July

28,

1991

with the

reactor

at

approximately

100'o

power.

One

TD was

identified

involving

information

going

to

the

computer.

The

inspector

concluded

from the observations

and

review that the test

was

conducted

in

accordance

with

an

approved

test

procedure,

activities

were

performed

in

a

step

by step controlled

manner,

and

the test personnel

performed

the required

adjustment

as

needed.

No

deficiencies

were identified.

2-TI-132, Recirculation

Flow Control

The inspectors

observed

the performance

of Section 7.5 of'his TI on

July 29,

1991, ior the conditions

of high

power with all reactor

pumps operating.

This phase of the test

was to demonstrate

proper performance of the reactor recirculation flow control

system

following the insertion of

a large

and rapid neoative

ramp

on the

Master Yianual

Flow Controller to ensure

that recirculation

pump

speed

reduction

and reactor

recirculation

flow reduction

would respond

as

anticipated.

This

was

accomplished

by the

operator

reducing

the

controller setpoint

to approximately

55;o in one

continuous

manual

step,

which

corresponded

to

a

recirculation

HG

set

speed

of

approximately

65:o'.

The plant

power level at the beginning of the

test

was

approximately

93;o',

and

decreased

to

approximately

78;o

following the flow reduction.

Thorough briefing of Operations

and

test

personnel

by the test director were observed

by the inspectors.

The test results

met the

acceptance

criteria,

and

no adjustments

to

plant

process

controllers

were

required.

No deficiencies

in the

conduct of the testing

were identified.

2-TI-149 Reactor Mater Level Yieasurements

This test collected

data

to verify that reactor

vessel

wax,er level

inszrumentation

was operating correctly between

0 and

960 psig.

The

test

included collection of temperature

data

on the reference

leg

condensing

chambers

and

on the reference

leg three

inches

below the

condensing

chamber.

The test results

contained

two TDs.

( 1)

Two of the temperatures

measured

from the top of one condensing

chamber

were

below the specified

350 to

425 degree

F range

of

the procedure.

(2)

One

of the

temperatures

measured

on

the

reference

leg three

inches

below the condensing

chamber

was

more

than

20 degrees

F

above

drywell

temperature,

.he permissible

range

specified

in

the

procedure

(reference

leg

was

226

degrees

F,

drywell

approximately

135 degrees

F).

The

licensee

attributed

the

TDs to

the fact that

the

hand-held

pyrometer failed during the test

due to the high ambient temperature

conditions

that

existed

during

the test.

Since

the reactor

water

level

system

has

performed

satisfactorily

(good

level

agreement

between all instruments)

during the

PATP, the licensee

continued with

the

PATP.

The inspectors

concluded

that the

TDs did not adversely

affect continuation with the

PATP,

based

on the

system

response

and

routine observations

of the systems'erformance.

No deficiencies

were identified

2-TI-188,

RCIC Injection

The inspectors

observed

the performance

of Section 7.3 of this TI on

July 30,

1991.

The testing

was

performed at approximately

91~ full

power.

The

purpose

of the test

was to perform

a cold start of the

RCIC

system

and

in,iect water

from the

CST to the

reactor

vessel

following the injection of a simulated

low water level signal to the

ECCS logic.

The

system

flow controller

response

and stability was

evaluated

to determine if tuning of the controllers

was required.

Thorough briefing of Operations

and

test

personnel

by

the

tes

director

was

observed.

The

system

responded

as

anticipated

with

minor

adjustment

of

the

flow controller

required.

No

testino

deficiencies

were observed

by the inspectors.

2-TI-189,

HPCI Injection

The inspectors

observed

the performance

of Section

7.3 of 2-TI-189 on

July 31.

1991.

The testing

was performed at approximately

75:o power.

The control

rods

were adjusted

to

an approximately

75<< rod line in

order to avoid potential instability problems in case

a recirculaxion

system

runback

occurred.

The purpose

of the test

was to perform

a

cold quick start of the

HPCI system

by simulating

a

low water level

(-45") signal

and demonstrating

that injection of 5000

gpm flow to

the

vessel

was

achieved within

30

seconds.

Final

tuning of

control

systems

was also to be performed if required.

Following initiation of HPCI for the test,

a momentary

low suc;ion

pressure

condition

resulted

in

a trip of the turbine;

the

auto-restarted

when the low suction pressure

condition cleared.

The

test

was

aborted

several

minutes later in accordance

with the test

abort

requirements

when it was

determined

that

the

Level

I test

criteria of less

than

30 second starting time was not achieved.

was tripped

and declared

inoperable,

and

a four hour

ENS report was

made.

During the

pump start transient,

the

upper

head gasket

on the

gland

seal

steam

condenser

ruptured

and

requi red

replacement

following shutdown.

The

licensee

reviewed

the results

of the test

and

developed

and

installed

a

temporary

alteration

consisting

of

a

time delay of

approximately

5

seconds

in the

suction

pressure

trip circuitry to

prevent

HPCI trip during transient

starting conditions.

The test

procedure

was

revised

to incorporate

additional

requirements

from

2-SI-4.5.E.1.d

such that

a rerun of the test

would also satisfy

TS

requirements

for demonstrating operability.

A repetition

of the test

was

performed

successfully

on August

1,

1991.

Minor adjustments

were required

during the test

on the

gain

and drift settings

on the control

board

flow controller.

The torus

temperature

exceeded

95 degrees

F, which required entry into EOI-2.

The maximum temperature

reached

was

98 degrees

F,

and

was moni-ored

closely by the

ASOS in command of the evolution

and the

SOS.

During

the test

run

a leak developed

on the lower head gasket for the gland

seal

steam

condenser.

It was

noted

by the inspectors

that

the

low

suction pressure

setpoint

was not reached

during this test run.

The

inspectors

attended

both test briefings

and

observed

that the

briefings

were thorough

and that anticipated

problems

were discussed

and compensatory

actions

planned.

The

command

and control

function

by the control

room operators

of the test

evolution

and

the

EOI

requirements

was excellent.

No testing deficiencies

other than thos

discussed

above

were observed

by the inspectors.

2-TI-191,

Feedwater

Pump Trip

The inspectors

observed

the performance

of this TI on July 29,

1991,

following the completion of 2-TI-132.

The

reac or power level

was

increased

to

approximately 94.5;.'ull

power

for the test.

The

purpose

of the test

was to acquaint

Operations

personnel

with the

integrated

plant

response

to

a trip of one reactor

pump.

The

response

of the reactor recirculation

system

was

monitored

to

demonstrate

the capability to prevent

a

low water level

scram in the

event water level decreased

to

a point where the automatic rec'.rcula-

tion

runback circuit

was

activated

to

decrease

reactor

power to

within the capability of the remaining

two feedwater

pumps.

Thorough

briefing of Operations

and

test

personnel

by the test

director

were

observed

by the inspectors.

The testing

was performed

smoothly,

but the automatic recirculation

runback circuit was

no.

activated

due

to

the

response

of the

running

feedwaier

pumps

to

maintain

water

level

above

the

27" actuation

setpoint

during

the

transient.

A test deficiency was declared

and the test results

were

investigated.

Review of transient

data

indicated that water level

decreased

to only 27.5",

but observation

of the

SPDS indicated that

water level

was

reduced

below 25".

The

licensee

planned

to perform

additional

testing

of

the

runback circuitry to

ensure

that

the

setpoints

were correct

and that the

system

would have

responded

as

designed.

The difference

between

the water level

observed

on the

SPDS

and the water level

based

on the transmitter output feeding the

runback circuit was

also

being investigated.

Reperformance

of the

test

was

not

anticipated.

No

other

testing

deficiencies

were

observed.

Q

2-TI-193, Turbine Trip and 2-TI-180,

Backup Control

Panel

Testing

The inspectors

observed

the performance

of these

TIs August 2,

1991.

The tests

were initiated

from

a

power level of approximately

45:o.

The purpose of the tests

was achieved

by initiating a plant

shutdown

by operator

performance

of

a turbine trip, resulting

in

a reactor

scram.

Following stabilization of plant conditions,

a test

crew of

operators

proceeded

to the

shutdown control

panel

and to local plant

control panels

and

shutdown

boards

and demonstrated

the capability io

control

reactor

pressure

and

water

level

via

the

shutdown

board

control of safety relief valves

and

the

RCIC system.

Cooldown

and

depressurization

was continued until

a cooldown of 45 degrees

F was

achieved

over

a

30

minute

or greater

time period

to demonstrate

adequate

operator

control

from the backup control panel.

Control of

other plant systems

was maintained

from the main control

room.

Water

level

and

pressure

control

was

returned

to

the

main control

room

following completion of activities from the remote stations.

The

test

crew

and

the

onshift operating

crew attended t aining

sessions

consisting of inplant walkdowns

and simulator demonstrations

in preparation

for the tests.

The inspectors

attended

one of the

training sessions

and

observed

their value in identifying potential

problem areas.

A test brie,ing

was

conducted

by the test director

and

was

observed

to

be

thorough

and

comprehensive.

Additional

discussions

on

equipment

alignments

and operator

personnel

assign-

ments were held immediately following the briefing.

No deficiencies

were observed

in the conduct of the testing.

Set Electrical/Mechanical

Reci rc Control Stops,

SIi-2-SE-96-3

Surveillance

Instrument instruction, SII-2-SE-96-3,

was performed to

adjust

and limit the

speed

on the reactor recirculating water

pumps.

The limit was set at recirculation flows equal

to an approximate

1025

power level. It was

accomplished

by limiting the variable

speed

on

the

generator

sets

which

supply

power

to the

pumps.

This

was

successfully

completed

on the

second effort after

a procedural

er ro,

was

found

and

corrected

after

the first attempt.

The

inspectors

reviewed this effort while in

progress

and

determined

that

the

, activity was accomplished within the guidelines of the procedure.

4.

Power Ascension

Test

Program

Review (72301,

72532)

The inspectors

reviewed testing

performed in accordance

with 2-SOI-100-1,

Master

Startup Operations/Testing

Instruction.

The inspectors

performed

a

review of TDs recorded

during performance of the TIs comprising the

PATP,

and noted several

TDs that required further evaluation

by the licensee

as

follows.

0

a.

2-TI-131 Feedwater

Level Control

System

This TI adjusted

the feedwater control

system for satisfactory water

level

con rol,

and ultimately will verify that

components

of the

control

system

can

control

reactor

water

level

satis-

factorily.

After initial controller adjustments

were

made

per the

TI, the procedure

was

completed with no difficulties encountered

in

maintaining

adequate

level control at low power levels.

However, the

time response

to insertion of

a

manual

step

(5

and

10 'hange)

in

feed flow still failed to meet

Level

2 response

criteria.

Notwith-

standing,

a decision

was

made to proceed with the test

program.

and

perform additional

feed

pump tuning at

a higher

power (about

58>)

l evel

.

Additional feed

pump tuning was accomplished

a

a higher power level,

but the time response

of individual feed

pumps to insertion oi manual

steps

(5 and

10'o) did not meet acceptance

criteria.

Technical

support

engineers

acknowledged

.hat the

response ti >es oi

individual feedpump turbines is slower than

Level II test

acceptance

criteria

and

FSAR commitments,

however tney also concluded that the

overall

response

of the ieedwater control

system in single

and three

element

control

was

adequate

to safely

suppor. continued operation;

further evaluation

and review is ongoing.

Based

upon

the

overall

system

response

and

observation

of daily

operations,

the inspectors

concluded

that this

TD did not adversely

affect continued

power operations.

b.

2-TI-174 Recirculation

System

Flow Calibration

The

purpose

of this

test

was

to

perform

a calibration

of the

installed

recirculation

system

ilow instrumentation

at

near-rated

conditions.

The test

was

performed

iour times

at iour difierent

flows.

Test

results

ai led

to

meet

acceptance

criteria

in

two

category

of deficiencies

was

caused

by inconsistent

results (i.e., lack of repeatabi lity).

For example:

(1)

The

GAF calculated for the

APRN/RBM loop proportional amplifiers

and the

GAFs calculated

for the single

tap

loop proportional

amplifiers were

not consistently

between

0.99

and

1.01,

which

was the

acceptance

criteria for these

calculations.

The

GAFs

were acceptable

during the first test,

but

some were outside

the

acceptance

criteria limits on the

second

test

and others

were

outside

the

acceptance

criteria limits during the third tes

.

In

some

cases

the amplifier had

not

even

been

adjusted

between

tests.

Test results

were satisfactory

in

one test,

but not in

the

subseauent

test,

i.e.

inconsistent

results.

The

licersee

noted that the

probable

cause

of the inconsistent

GAFs for the

proportional amplifiers was due to noise in the measured

signal

circuits.

This deficiency requires further resolution.

(2)

The calculated

nozzle

plugging criteria

was at the

acceptance

criteria limit for

one

se

of jet

pumps

and

exceeded

the

acceptance

criteria limit for another

set of jet

pumps during

the last test.

The nozzle plugging criteria

had been

me. durino

previous tests,

i.e.

inconsistent

resul

s.

The licensee

noted

that

the probable

cause

of the

unacceptable

calculated

nozzle

plugging criteria

was

noise

in

the

measured

signal,

which

resulted

in incorrect values

being recorded.

Since satisfactory

results

had

been

obtained

during previous

performances

o. this

test,

the

licensee

concluded

the test results

were

a

one

time

occurrence

and

no further action

was necessary.

None of the deficiencies

noted during the test violated or exceeded

any

TS limits,

and all .the deficiencies

involved Level

2 Criteria.

The

inspector

concluded

that

the deficiencies

did not

adversely

affect continued

plant operation.

However,

the

core

flow and

GAF

calculation deficiencies

need to be resolved.

There

may be equipment

problems

causing

the circuit noise or procedure

changes

necessary

to

eliminate

these

type of deficiencies

and accurately

monitor these

parameters.

2-TI-189,

High Pressure

Coolant Injection System

This test verified proper

system

operation,

including

a manual

start to verify system

parameters

and

absence

of leaks,

a hot "quick"

start,

and

a

cold "quick" start

(the latter is

a

simulation

of

conditions for an

emergency

injection).

Two TDs requi ring further

evaluation

were documented

during this test.

10

(1)

During initial startup of the

HPCI turbine from cold conditions

(at

150 psig),

the

HPCI turbine

stop

valve exhibited

a rapid

opening,

closing

and

re-opening.

This

valve action

was

not

inconsistent

with expected

system

response

during cold, "jack-

rabbit" starts

addressed

in the

system operating instruction

and

GE advisory

information

SIL

No.

352),

indicating

too

low

a

balance

chamber

adjustment.

The

turbine

stop

valve

performed satisfactorily during tests

at rated reactor pressure.

(2)

During HPCI flow tests

to the reactor

vessel

at normal operating

pressure,

step

changes

in flow demand

(3,000

to

2,500

gpm)

exhibited

a

decay

ratio

of

0.60

(test

criteria

<0.25).

Acceptable

decay ratios were exhibited for step

changes

at full

flow (5,000 to 4,500).

The licensee

evaluated

these

TDs as not adversely affecting the

system

performance

because

the deficiencies

were

observed

during

conditions other than

normal

expected

conditions (i.e.,

low pressure,

low flow).

Nevertheless,

the licensee

continued its

e 'aluation of

the test data.

Based

upon

observation

of

nominal

system

performance

at

design

conditions,

the inspectors

concluded

that

these

system

TDs did

not

adversely

affect

continued

power

operations.

However,

the

inspectors

also

noted that

HPCI operation

may

be required

at other

than

normal operating

pressure

and/or full flow, thus the

TDs must

be

evaluated

further.

The licensee will submit

a final report to the

NRC within 60 days after

completion of the

PATP.

This report will contain the final disposition of

TDs.

The inspectors will review this report

when received.

5.

Operational

Safety Verification (71707)

General

plant :ours

were

conducted.

Portions of the turbine buildings,

each reactor building,

and general

plant areas

were visited.

Observations

included valve position

and

system

alignment,

snubber

and

hanger

condi-

tions,

containment

isolation

alignments,

instrument

readings,

house-

keeping,

power supply

and breaker

alignments,

radiation

and contaminated

area controls,

tag controls

on equipmen.,

work activities in progress,

and

radiological

protection

controls.

Informal discussions

were

held with

selected

plant personnel

in their functional areas

during these tours.

During

a routine tour

on July 28,

1991,

the inspector

iden ified several

problem

areas

around

the

outside

of the

reactor

building

and

intake

structure.

These

items

were

immediately

discussed

with the

SOS

on

July 28,

1991,

and other plant management

on July 29,

1991.

0-

11

Fallen Unit Separation

Signs

Several

Unit 2 Operating

Space

signs

had fallen

down.

These

signs

were placed at various locations in .he plant as part of the Unit 2/

Unit

3 separation

program.

Examples

were

one of the outside

doors

for the

Unit 1/2

DG doors,

Unit

1 reactor

building ventilation

intake,

and mechanical

equipment

room A (door 830).

This indicated

a

need

for periodic

inspection

and

maintenance

for the

separation

program.

The signs

have orange lettering

on

a black background.

Due

to rain the

orange

lettering

had

been

washed

out of several

signs

leaving white lettering

on

a black background.

Smoking In No Smoking Areas

The inspector

observed that

a temporary

machine

shop

had

been erec.ed

on top of the Unit 3

DG building.

At each entrance

to the roof were

No Smoking Signs specifically stating to not

smoke

on the

DG building

roof.

There

was

evidence

of

an estimated

50 to 100 cigc retie butts

on the roof indicating

a blatant disregard

of the

No

Smo! ing Signs.

Fire Wrap Removal

From Operating

Equipment

In the intake structure

the inspector identified that fire wrapping

around

power

cable

junctions

boxes

for the

RHRSW

pumps

had

been

removed.

All of the

pumps

were operable

at the time.

The fire wrap

is used to provide

a one hour fire resistance

barrier rating between

redundant

safe

shutdown

equipment.

The

two electrical divisions of

RHRSW power cables

do not meet the minimum separation

distance of 20

feet,

and the fire wrap is required.

One division is routed

in

a

cable tray tunnel

and the other division routed in a conduit tunnel.

The

RHRSW

pumps

provide cooling

as

the ultimate hea.

sink at

BFNP.

If for

some valid reason

the fire wrap is

removed,

a fire watch is

required

to

be posted within one

hour.

The

inspector

knew of

no

reason this should

be

removed

because

of the operable

equipment.

The

inspector

reviewed the listing of fire protection 'active

impairment

permits

called

Attachment

F to

FPP-2.

No permits or compensatory

actions

were in effect for the fire wrap.

Upon notification

the

SOS

took

immediate

action

to correct

the

problem.

An Attachment

F

was

completed

and

a fire watch

posted.

Licensee

senior

management

was contacted

and

a detailed

action

plan

initiated to identify and correct

the

problems.

It was determined

that the fire wrap was

removed

under

WO 91-35664-00

to support Unit 3

walkdown

inspections.

The

WO

was

approved

by the Operations

Work

Control

Group

on July

17,

1991.

The

licensee

stopped

all

Unit,

3

wal kdown

inspections

until

the

problems

were fully identi fied and

corrected.

The

inspector

concluded

that

a violation of

TS

3. 11.G. l.a

had

occurred.

This requires

that all fire rated

assemblies

such

as

conduit wraps separating

systems

important to safe

shutdown within

a

12

fire area

shall

be operable

at all times.

If the assembly

device is

inoperable

a fire watch

must

be established

within one

hour.

This

was identified as

VIO 259,260,296/91-26-02,

Fire Wrap Inappropriately

Removed.

Later

the

licensee

determined

that

the contractor

preparing

the

walkdown inspection

plan did not

use

the Unit 2/Unit

3 separation

drawings.

This would

have

prevented

walkdowns

in this

area.

The

licensee

at the

end of this report period

had

not resumed

work and

still was developing their corrective action plan.

These

issues will

be followed during the rou.ine resident

inspec.ions prior to resuming

work activities,

and violation closure.

Unit 3 Fuel Sipping

and Inspections

During this reporting period,

the licensee

conducted

fuel sipping

and

inspection

of fuel

assemblies

located

in the

Unit

3

SFSP.

The

purpose of these activities was to assess

the condition of fuel for

possible

use

in Unit 3 cycle

6 by identifying failed fuel

a semblies.

The

sippinq

and

inspection

were

conducted

by

GE personnel.

The

inspectors

reviewed

and observed

tnese activities

on

an ongoing basis

during the reporting period.

No deficiencies

were identified wi

h

the fuel inspection activities;

however,

fuel handling errors

were

made during fuel sipping operations.

Fuel

sipping

was

performed

in accordance

with special

test

3-ST-

90-03,

Unit 3 Fuel Sipping.

Two fuel sipping cans

were utilized and

were

addressed

as

the

"north"

and

"south"

sipping

cans.

Fuel

assembly

transfer

forms

were

prepared

and

approved

for each

fuel

movement in ihe

SFSP.

Procedure

SDSP

26. 1, Special

Nuclear Material

Management,

establishes

the

admin',strative

requirements

for

the

handling of

SNM and the transfer of SNM from one item control area to

another.

Because

the Unit 3

SFSP

is considered

as

a single "Item

Control Area," the requirements

for second party verificacion of fuel

assemblies

were no. in place.

Fuel

assembly identification was being

performed

bv

SFSP

row-rack-column location only.

Procedure

3-ST-90-03

required

that

fuel

handling

be

performed

in

accordance

with 3-GOI-100-3,

Refueling Operations,

and

the

approved

FATFs for moving fuel assemblies

between

the

sipping

cans

and their

SFSP locations.

Procedure

3-GOI-100-3 required

thar, all steps

on the

FATFs

be

performed line by line.

The fuel handling errors

were

a-

follows:

( 1)

On June

29,

1991,

the fuel

handlers

grappled

a fuei

assembly

from

a different

SFSP

location

than

that identified

on

the

approved

FATF.

The fuel assembly

was

moved to the south sipping

can.

After the assembly

was sipped

the fuel handlers

attempted

to place it in the position called for

on

the

FATF.

Upon

finding that

SFSP

location

occupied,

all fuel

nandling

was

stopped

and

the

refueling

SRO

was

notified.

The

licensee

13

conducted

an

incident

investigation

(II-B-91-130)

which

concluded

that

the

event

was

caused

by personnel

error

and

failure to follow procedures.

Immediate

corrective

actions

included

verifying that

surrounding

fuel

assemblies

were

in

heir proper locations; initiating

a field change

to place

the

errant

fuel

assembly

in its proper location;

and

conducting

a

briefing on the importance of verifying correct

SFSP

locations.

In addition

to

these

corrective

actions,

the

licensee

also

implemented first and

second party verification of both the fuel

assembly

serial

number

and

SFSP

location during the

remaining

fuel moves.

(2)

On July 6,

1991,

the licensee

identified that

a fuel

assembly

was

placed

in

SFSP

location

05-10-G

instead

of 05-10-F

as

designated

on the

FATF.

The licensee

determined

tha

the error

occurred

when

the

assembly

was

being

moved

from the

soutr

sipping

can to its

SFSP location.

A second error then

occurred

when thefuel

assembly

serial

number

was incorrectly identifed

and

the incorrect

assembly

was

returned

to the

south

sipping

can.

A third error occurred

when the fuel assembly

in the north

sipping

can

was

placed

in

SFSP

location

05-10-F

instead

of

05-10-G.

All fuel

handling

was

stopped

and

the

licensee

initiated

an

incident

investigation

(I'I-B-91-132).

The

investigation

concluded that the mistake

was caused

by personnel

error

and

ailure to follow procedures.

The

licensee

took

immediate corrective

actions

in response

to these errors which

included

comparing

the

SFSP

storage

racks

to the

FATFs; field

changes

to

place

the

fuel

assemblies

in

the

correct

SFSP

locations; counselling fuel handlers

on the importance of second

party verification; placing

a supervisor

on the fuel handling

bridge to monitor operations;

and establishing

an operator

aid

to formalize

communications

between

the

bridge

and

the

fuel

handling

SRO.

In addition,

personnel

disciplinary actions

were

taken against

the individuals involved.

The failure to follow steps

on the

FATFs line by line is

a violation

of

TS section 6.8. 1. 1 for the failure to implement

procedures

(VIO

296/91-26-03,

Fuel Handling Errors).

The inspectors

are concerned

by

these

fuel handling errors

and

the apparent

ineffectiveness

of the

corrective actions for the first event.

6.

Procurement

(38702)

The

inspector

reviewed

information

,from

Connex

Pipe

Systems

Inc.,

forwarded

by Region III, that

BFN had received

12

one

and

one half inch

socket

weld unions

and three

150 lbs. pipe flanges,

which were processed

as

B31. 1 non-nuclear

instead

of under

Connex's

ANSI N45.2

program.

The

unions

were

shipped

on

BFN order

90NJS-82557C

and

the pipe flanges

on

91NJA-82667C.

The

licensee

initiated

CAQR

BFP

910110,

dated April 4,

1991,

which indicated

that

the

ma-erial

was

received

without adeaua~e

documentation.

The

CAQR also indicated that

Connex

was contacted

about

the deficiency.

The inspector

reviewed

the following items:

DCN W457A, which added

iwo

pieces of one-and-one-half-inch

diameter pipe,

each

two feet long, to the

demineralized

water

supply for the

RHR heat exchanoers.

and was done for

stress

reduction

in order to enhance

the ability of the

RHRSW piping to

maintain

a Seismic Class

I boundary;

MR 891015103,

which replaced

flanged

fittings on drywell cooler

A5 inlet and outlet which is part of the

RBCCW

system;

QDCN Q16640A, which indicated that the

use of a B31. 1 union in tne

nonsafety-related

DI water system

was acceptable;

and

QDCN Q1667A,

which

indicated that

an

ASTM B-61 was

an acceptable

material

in accordance

with

ANSI

B 16.24,

Bronze

Pipe

Flanges

and

Flanged Fitting, for the flanges

installed

on drywell cooler

A5 inlet and outlet.

The inspector

concluded

from these

reviews that the material

was shipped

from

Connex

without the

proper

vendor

QA reviews

and

approvals,

BFN

receipt inspection initially identified the problem,

the material

was

used

in the

RBCCW and

DI systems,

and the

use of ;ne material

was acceptable.

7.

Reportable

Occurrences

(92700)

The

LERs listed

below

were

reviewed

to determine if the

information

provided

met

NRC requirements.

The determinations

included

the verifi-

cation of compliance with

TS

and regulatory

requirements,

and

addressed

the

adequacy

of the

event description,

the corrective actions

taken,

the

existence

of

potential

generic

problems,

compliance

with

reporting

requirements,

and

the

relative

safety

significance

of

each

event.

Additional in-plant

reviews

and

discussions

with plant

personnel,

as

appropriate,

were conducted.

(CLOSFD)

LER 296/91-02,

Unplanned

ESF

Actuation

Following

Deenergization

of

Bus

By Unknown Cause.

On April 5,

1991,

an

unplanned

ESF actuation

occurred

upon the loss

of

Bus

3B.

The

bus deenergized

when the

3B1 circuit protector

tripped.

All equipment

responded

as designed io the

ESF signal.

The

cause of the event could not be determined.

An inspector

reviewed the

LER, dated

May 5,

1991,

and determined that

it met the requirements

of 10 CFR 50.73.

The inspector also reviewed

the

incident

investigation

which

was

conducted

on this

event

( II-B-91-078).

The

investigation

did

not

discover

any

failed

components

or plant conditions

which could

have

caused

the circuit

protector to trip.

However,

during troubleshooting

on the circuit

protector internal

components,

the overvoltage relay setpoint

jumped

from 129.7 volts to 131.4 volts and then continued- to repeat

in the

range

of the higher value.

Even

though this test did not indicate

fai lure of the overvoltage

relay, it was

replaced

for conserva.ism.

No discrepancies

or

concerns

were identified during the

review of

this

LER.

0

15

(CLOSED)

LER 259/91-03,

Gaseous

and Liquid Effluent Samples

That Were

Missed

Due

To Improper

Work Activities Caused

TS Requirements

To Be

Exceeded.

On

March

1,

1991,

the

licensee

discovered

that security

data

could

not support

the

performance

of effluent

samples

for two inoperable

radiation monitors.

Based

on this finding, the

licensee

determined

that

TS required compensatory

measures

were not implemented.

An inspector

reviewed

he

LER, dated April 1,

1991,

and

determined

that it met the requirements

of 10 CFR 50.73.

A violation was issued

for this

event

(VIO 91-10-02)

in

a

report.

The

follow-up of the violation

and

associated

corrective

actions

are

discussed

in paragraph

8 of this report.

No further concerns

were

identified during the review of the

LER.

(CLOSED)

LER 296/91-03,

Unplanned

ESF Actuation Unit 3

DGs Started

On April 12.

1991,

an unplanned

ESF actuat'on

occurred

when the four

Unit 3 emergency

DGs unexpectedly

auto-started

during the performance

of the

common accident

signal logic SI.

The cause

of this event

was

personnel

error resulting

from

a lack of attention to detail during

installation

of

an inhibiting boot

between

two

contacts

on

the

Division II core spray logic

B relay.

Corrective

actions

performed

included Operations

personnel

ensured

that electrical

maintenance

personnel

stopped

the performance

of the

SI;

an incident investigation

was conducted

to determine

the cause of

the

event;

and

the

SI

was

resumed

and

successfully

completed.

Maintenance

personnel

who install

boots

received

training

on

the

proper installa .ion

o

boots.

The

inspector

reviewed

the

LER and

supporting

documentation

which

included

electricai

maintenance

training

records

and

incioenv.

investigation

No. B-91-091 dated

June

13,

1991.

Based

on this review

the inspector

concluded that adequate

corrective action

was taken.

(CLOSED)

LER 259/91-05,

Potential

Failure of

RHRSW and

EECW Systems

Following A Seismic

Event

On

April

12,

1991,

the

licensee

determined

that

a

previously

recognized

condition

had

not

been

reported

in accordance

with the

requirements

of 10 CFR 50.73.

This condition involved the potential

for failure of the

RHRSW and

EECW Systems

during

a seismic event.

In

July 1987, during performance

of hydrostatic testing of

RHRSW piping,

a flexible joint,

Dresser

coupling failed

due

to excessive

axial

load.

Subsequently,

on

December

5,

1987.,

a condition

adverse

to

quality report

was written to

document

that protection

'of buried

piping from differentiaI movement of the soil and building structures

was not achieved

because

none of the existing flexible joint designs

could have

accommodated differential movement in the di rection

along

o

~,

~

16

the axis of

a the pipe.

This

was

the result of a rigid connection

called

a

saddle

which

was installed

across

the flexible joint to

prevent pressure

loads

from pulling apart the piping from the joint.

As

a result of this design,

a seismic

event could have

caused

loss of

RHRSW

and

EECW.

This condition existed

since original construction

of the plant.

The

inspector

reviewed

the

LER

and

supporting

documents.

The

corrective action

was consistent with the commitments

in Volume

3 of

the

NPP.

Programs

were

established

to resolve

past

deficiencies

which

led to

inadequately

documented

or analyzed

designs.

At ihe

requirements

for these

programs

were

developed

and

implemented.

Project instructions

were also issued

which augment

the requirements

of the

programs.

TVA added

a

section

to the

Rigorous

Analysis

Handbook

which established

guidelines

for design

and

analysis

of

flexible joints.

A clarifying statement

was also

added

to

a design

criteria

that

established

requirements

for analysis

of flexible

joints.

Based

on this review the inspector

concluded

that

adequate

corrective action

was taken.

(CLOSED)

LER 260/91-07,

ESF Actuation Resulting

from Leaking Packing

on the

DP Transmitter.

This

item

was

identified

on April 9,

1991

when

an

unplanned

ESF

actuation

occurred.

A Group

1

PCIS occurred

during the performance

of a SI when

IMs placed

Channels

A and

B in

an isolated

mode

and

a

leak

from 2-PDT-1-25B valve

caused

the depressurization

of the

low

side of the Channel

B transmitter.

The cause

of this event

was that

one

process

instrument

had

entrapped

air in the

low-side

sensing

line,

and

one process

instrument

had

a water leak from the packing in

the low-side manifold valve.

Both instruments

were part of the

MSL,

high flow logic.

f

The unit operator

contacted

in the

IMs,

and

work

on

the

SI

was

stopped.

The

IMs

returned

the affected

instruments

to service.

Subsequent

corrective

actions

were

the

IMs

vented

trapped

air;

backfilled line for the first process

instrument;

and

-ightened

packing nuts

on the other process

instrument.

In addition,

SIs that

test

excess

flow check

valves

were

revised

to require

constant

communications with control

room Unit Operator

and to install jumpers

to bypass

the initiation of Group

1

PCIS logic on

main

steam line

high flow.

The inspector

reviewed

the licensee

corrective action.

It was also

noted that the SI, Z-SI-4.7.0. l.d-2, Instrument

Line Flow Check Valve

Operability Test,

was

resumed with no additional

problems.

(CLOSED)

LER 260/91-12,

Unplanned

ESF Actuation Following

Bus

Deenergization

Caused

By Random

Equipment Failure.

0

17

On

May 19,

1991,

an unplanned

ESF actuation

occurred

upon the loss of

Bus 2A.

All equipment

responded

as

designed

to the

ESF signal.

The cause

of the event

was the failure of the

Bus

2A normal

power

source,

MG set

2A.

An inspector

reviewed

the

LER, dated

June

17,

1991,

and determined

that it met the requirements

of

10 CFR 50.73.

The inspector

also

reviewed

the

incident

investigation

conducted

for

this

event

(II-B-91-112).

The investigation attributed

the motor failure to

a

breakdown of the winding insulation.

There

was

no history of motor

failures

by this

method at

BFN and this

was

considered

an isolated

event.

The licensee

replaced

the failed motor

and returned

the

MG

set to service.

No discrepancies

or concerns

were identified durin,

the review of this

LER.

8.

Action on Previous

Inspection

Findings (92701,

92702)

(CLOSED)

IFI 259,

260,

296/89-35-01,

Flexibility of Reactor

plater

Level Sensing

Lines.

This

item addressed

the inspector's

concerns

in two areas

associated

with the

replacement

of

a flexible instrument

piping

system

on tne

reactor

water level

sensing

lines

on Unit

2 with

a one-inch rigid

stainless

steel

piping:

The first concern

involves

the

need

for

preventative

maintenance

and

the

second

deals

with setting

the

spring-can

hangers

for operating

temperatures

("hot setting" ).

The

licensee's

corrective

actions

included

an

evaluation

and

determination

tha

the

system

has

been installed properly and that

no

prescheduled

preventative

maintenance

activities

are

required.

However,

the

system

engineers

are

required

to

walkdown their

respective

systems periodically to evaluate

the

need for maintenance.

The

actions

to disposition

the

second

part

of

the

issue

were

completed

when

z,he

spring

cans

were

evaluated

and

adjusted

as

required during the

performance

of TI-190,

Thermal

Expansion,

with

the reactor at operating

temperature

and pressure.

Based

on

the

above

actions

taken

by the

licensee.

this

issue

is

closed for Unit 2.

However,

the item is administratively closed for

Units

1 and

3 since it was

opened

based

on concerns

associated

with

the corrective actions for Unit 2 only.

(CLOSED) VIO 259,

260, 296/91-10-02,

Missed Compensatory

Samples.

This

violation

was

issued

for

the

failure

to

implement

TS

compensatory

measures.

On March

1,

1991,

the

licensee

discovered

that

security

data

could

not

support

the

performance

of effluent

samples

for

two

inoperable

radiation

monitors.

Based

on

this

finding,

the

licensee

determined

that

TS

required

compensatory

measures

were not implemented.

18

The

licensee

initiated

an

incident investigation

( II-B-91-045) to

determine

the root cause

of the

event

and corrective

actions

to be

taken.

The investigation

determined

that

the

causes

of the

event

included

failure

to

follow sampling

procedures,

the

misuse

of

checklists,

and

inadequate

chemistry

supervision.

The corrective

actions

included

personnel

actions

against

the

chemistry

analysts

involved;

discussions

with all

chemistry

personnel

of strict

procedural

compliance

and

the

meaning

of initials/signatures

in

procedures;

and

revisions

xo

procedures

for

the

oversight

of

compensatory

SIs.

.An inspector

reviewed

the licensee's

response

to this violation the

completed

incident investigation,

and

revised

chemi. try SIs.

Tne

inspector

determined that the corrective actions

had

been

completed.

No discrepancies

or concerns

were identified during

the

review of

this item.

(CLOSED)

VIO 259,

260.

296/91-17-01,

Failure to Follow Hold Order

Procedure.

The

licensee

had failed to follow SDSP-14.9,

Equipment

Clearance

Procedure,

in that

an

independent

verification

o

the

clearance

boundary

was

not performed prior the placing

the

hold tags

on the

applicable

equipment.

The

boundary

was that utilized

to isolate

Units

1 and

3 from Unit

2 for the restart

of Unit 2.

The licensee

stated that the tag-out

was

an extremelv large boundarv that involved

several

systems

and

was being initiated and verified

on

a

system

by

system

basis

rather

than

the entire

tag-out

being identified

and

verified and signed-off prior to the

placement

of any tags

on ihe

equipment

as required

by the procedure.

This issue

was identified by the inspector

and once the licensee

was

confronted,

changes

were

made

to the

tagging

process

to

meet

the

requirements

of the procedure.

Based

on this cor'rective action, this

item is therefore

closed.

(CLOSED)

Open

Item

260/91-202-01,

inadequate

Review

of

Plant

Conditions Prior To Beginning Surveillance

Test.

During the

NRC

ORAT followup inspection,

an inspector identified

a

concern

with

inadequate

Operations

shift

supervision

over

the

performance

of

an

SI.

A

UO

had

to

stop

the

performance

of

O-SI-4.2.B-67,

RHR

Service

Mater Initiation Test,

when it

was

realized that continuing would reduce

the

number

of operable

RHRSM

pumps below that required

by TS.

The procedure

required

a

EECM

pump

to

be

made

inoperable;

however,

the

other

EECM

pump

on the

same

header

was already inoperable

for reasons

not related to the SI.

The

inspector

considered

this

an

example

of inadequate

supervision

in

that off-normal conditions

were

not considered

prior to authorizing

the

performance

of the SI.

The inspector

discussed

this

item with

19

licensee

management

and

the

Operations

Manager

stated

that

the

following corrective actions would be taken:

( 1)

Discuss

with shift

supervision

the

importance

of properly

assessing

plant status prior to authorizing SIs.

(2)

Revise

the

SI to

assure

that

TS

pump requirements

cannot

be

inadvertently violated.

During this reporting period,

an inspector- reviewed

the licensee's

closure

package

for this item

and

the

revised

SI.

The

inspector

concluded

that

the

licensee

had

completed

corrective actions

which

should

preclude

the

recurrence

of this issue.

No discrepancies

or

concerns

were identified during the review of this item.

9.

Exit Interview (30703)

The inspection

scope

and findings were

summarized

on August 16,

1991 with

those

persons

indica;ed

in paragraph

1 above.

The inspectors

described

the areas

inspected

and discussed

in detail

the inspection findings'l:s.ed

below.

The licensee

did not identify as proprietary

any of the material

provided

to

or

reviewed

by

the

inspectors

during this

inspection.

Dissenting

comments

were not received

from the licensee.

Item Number

Description

and Reference

260/91-26-01

NCV,

Failure

to

Update

Control

Room

Procedure,

paragraph

2.

259,260,296/91-26-02

296/91-26-03

VIO, Fire Wrap Inappropriately

Removed,

paragraph

5.

VIO, Fuel Handling Errors,

paragrapn

5.

Licensee

management

was

informed that

6

LERs,

1 IFI,

2 VIOs, and

1

ORAT

Item were closed.

10.

Acronyms and Initialisms

ANSI

APRM

ASOS

BFNP

CAQR

CFR

DCN

DCRM

DG

DP

ECCS

American National

Standards

Institute

Average

Power

Range Monitor

Assistant Shift Operations

Supervisor

Browns Ferry Nuclear Plant

Condition Adverse to Quality Report

Code of Federal

Regulations

Design

Change Notice

Document Control

and Records

Management

Diesel Generator

Differential Pressure

Emergency

Core Cooling Systems

20

ECCW

GAF

GOI

GPM