ML18033B591

system.

In addition,

the licensee

indicated that more than

300 feet of

the

system

has

been

replaced.

The carbon steel

piping in the

two

safety-related

systems,

RHRSW and

EECW, with

a diameter of less

than

4

inches

has

been replaced.

The status

of the

MIC program will be routinely monitored

in future

inspections.

Operational

Safety Verification (71707)

The

NRC inspectors

followed the overall plant status

and any significant

safety matters

related to plant operations.

Daily discussions

were held

with plant management

and various

members of the plant operating staff.

The

inspectors

made

routine visits to the control

rooms.

Inspection

observations

included

instrument

readings,

setpoints

and

recordings,

status

and alignments

systems,

ver ification of onsite

and offsite power

supplies,

emergency

power sources

available for automatic operation,

the

purpose of temporary

tags

were

not in place.

The

CS system

was previously

returned

to service

with the

completion

of the

system

.SPOC

on

October

14,

1990.

This system

was under status

control or configura-

tion management

control.

The inspector discussed

this item with the

system engineer

and

no work was in progress

on the valve.

The reason

for the disconnected

leads

was not known.

cwork had been

performed

on

the valve but was

completed

on October 30,

1990.

This item will be

identified

as

URI 260/90-33-02,

Failure to Maintain Configuration

Control

on

Core

Spray

System After System

SPOC.

The

licensee

initiated an incident investigation for the item.

One violation was identified in the,Operational

Safety Verification Area.

6.

Modifications (37700,

37828)

The inspectors

maintained

cognizance of modification activities to support

the restart

of Unit 2.

This included

reviews of scheduling

and work

control, routine meetings,

and observations

of field activities.

a ~

Breaker Installation

The inspector monitored the licensee's

activities in the installation

of

DCN 7161A, Instrumentation

and Control

Power

Buses for all three

units.

The specific activities observed

involved the termination of

the

new power cables

and installation of the

power feed breakers

on

'he

480V shutdown

boards.

The activities also involved the removal

of the temporary

power feeds to the buses.

The safety assessment

for

this modification indicated that

GE type

AK 6A 15/25 series circuit

breakers

were to be used for the

IRC bus feeder breakers

on the 480V

shutdown

boards.

The licensee

installed type

AK 6A 15/25 series for

the Unit 2 IEC buses

and type AK 2A 15/25 series for the

ISC buses

on

the Units

1 and 3.

Additional review by

NE indicated that the type

AK 2A breakers

were

an acceptable

substitute for the type

AK 6A.

The

inspector

also

observed

circuit breaker

testing

and

adjustments

required

by this

modification.

All observed

activities

were

Cl

10

controlled

by approved

procedures.

QC inspectors

were

observed

performing verifications.

Modifications,

NE,

and

system

engineers

were observed actively providing expertise

as

needed.

b.

Cable Installation

The licensee

informed

the

inspector

that during

a cable splicing

activity under

DCN

W14589

the field personnel

questioned

the.

suitability of installing

an

unjacketed

type

PX cable

in

an

EQ

modification.

An initial review by the licensee

indicated that the

cable

was

the wrong type.

The correct cable should

have

been

type

PXJ.

This item was also identified as impacting

DCN W11053;

Additional

reviews

indicated

that

in

June

1990,

a

problem with

electrical

cable

procurement

was identified.

Recurrence

control for

these

problems

was

the

issuance

of QDCN

Q 13819A which contained

a

list of cable qualified for Class

1 structures.

The

QDCN was sent to

the Maintenance,

Modifications,

and

Power Stores

group.

The type

PX

was

issued

by power stores

personnel

after distribution of the

QDCN

and the type

PX was not on the approved list.

The description

on the

bill of material identified type

PXJ cable, but the cable identified

as type

PX was issued for the installation instead.

Other

cable mark

letters manufactured

under the

same contract

number were

shown

on the

approved list.

The issue cler k did not have the list available

and

because

of the

urgency

for the cable,

issued

the cable

because

the

clerk could remember

the contract

number being

on the list.

These additional

reviews involving the

QDCN and power stores activity

also indicated

problems with the use of Anaconda supplied cable in 10 CFR 50.49 application.

NE

by memorandum restricted this type of

cable

from Class

1 structures

and

ordered its

removal

from the

nuclear

inventory.

Two DCNs,

H6910

and

W1073,

were

issued

by

NE

which specified

Anaconda cable.

The following installations resulted

from all the above:

implementation activities for DCN/ECN 10017A installed

700 feet

of PX cable

implementation activities for DCN/ECN W14589 installed

1100 feet

of PX cable

implementation activities for DCN/ECN W11053 installed

2200 feet

of PX cable

implementation

activities

for

DCN/ECN

P5136,

a

Unit

3

modification, installed

470 feet of PX cable,

and

implementation activities for DCN/ECN H6910 install

500 feet of

Anaconda cable.

J

11

An additional

item identified

by the

licensee

was that

advanced

authorized

FDCNs

F15025

and

F15101

changed

the

type of cable

to be

used for

DCN/ECNs

M10017A and

W14589.

These

AAFDCNs specified

PX cable

instead

of

PXJ cable.

The licensee

at the

end of this

reporting

period

was

removing

the

type

PX cable

and replacing it

with

type

PXJ.

The

item

is

identified

as

URI 259,

260,

296/90-33-03,

Failure

to Control

Design

in Allowing Unqualified

Cable Installation.

Cable Pulling Calculation

\\

The

inspector

reviewed

cable

pulling calculation

ED-N2057-88114.

This calculation

was for system

75.

Some existing cables

had to

be'eplaced

due

to fire damage

in the drywell.

The purpose

of the

calculation

was to provide

an evaluation

and analysis of conduit and

cable configuration to ensure

the installation requirements

of both

cable

and conduit related

to the

cable installation

were

met or

exceeded.

The inspector

reviewed the calculation

performed for each

cable

and conduit.

The pull tension

was calculated for each section

of the

conduit installation

accounting

for bends,

inclines,

and

angles.

The inspector

sampled

the mathematics

and found

no errors.

Calculations

of the pull tension,

side wall pressure,

bend radius,

and training radius

were performed

and

compared to allowable values.

All of the

requirements

were met.

The calculation

was

signed

as

being checked

by another engineer.

No discrepancies

were noted.

RPS Circuit Protector Modifications

In the

Browns Ferry design,

the

power supplies

are not Class

lE

electrical

systems.

Therefore,

redundant

Class

1E circuit protectors

were required for isolatiol between

each of the

power supplies

and

the

associated

RPS distribution

buses.

The circuit protectors

monitor

the

power

supply.

If abnormal

voltage

or

an

underfrequency

condition is detected,

the circuit protectors

actuate

to isolate

the Class

1E

RPS equipment

from the power source.

Since the installation of circuit protectors

in 1984, there

have

been

numerous

incidences

of

bus de-energization

and resulting

LERs.

The licensee

created

a task force in March

1989 to evaluate

the

numerous cir cuit protector de-energization

events.

Concerns with the

circuit protector

relaying

setpoints

were

identified

by that

evaluation.

The setpoints of the circuit protector relays were found

to

have insufficient margin with respect

to the

normal

operating

voltage of the system.

This allowed little room for drift of either

the relay setpoints

or the output voltage of the associated

MG sets.

Also, time delay relays

should

have allowed the circuit protectors

to

reset for short duration voltage

spikes without

ESF actuation.

In

addition,

the

large

deadband

on the reset

action of the circuit

protectors

prevented

resetting

when

the

MG set

output

voltage

returned to normal.

'

12

From system

design

reviews

and engineering

analysis,

TVA determined

that

the circuit protector

setpoints

should

be

changed

and other

system

changes

should

be

made.

TVA approved

design

changes

to

implement the following:

( I)

Add or lengthen

the circuit protector relays

time delay to trip.

A three

second

time delay

was established

for both

normal

and

'lternate

supplies

in all three Units.

(2)

Replace

the

5 percent

deadband

relays in Units I/3 with newer

one percent

deadband

models.

Unit 2 already

had the

one percent

deadband

models.

(3)

Revise

the circuit protector relay setpoints for undervoltage,

overvoltage,

and underfrequency.

The modifications

removed

excess

conservatism

from the circuit

protector

setpoints

and

should

allow the circuit protectors

to

withstand

a greater

range of voltage

and frequency excursions without

exposing

RPS components

to damage or malfunction.

The changes

should

reduce

the

number of

RPS trips

due to spurious circuit protector

actuation.

An inspector

discussed

the status

of the

and circuit protector

changes

with the

cognizant

system

engineer.

The system

engineer

stated all the modifications

had

been

completed

in Units I/3.

In

Unit 2,

the

addition of the

underfrequency

time delay

and

the

resetting

of the circuit protector

setpoints

have yet to

be

completed.

The licensee

was awaiting approval of TS change

8286 for

revision of the

Unit 2 setpoints.

The

inspector

reviewed

the

completed

modifications

in the plant during the

SPOC preliminary

system

walkdown

which

was

conducted

on

September

20,

1990.

No

deficiencies

were identified.

The completion of the

RPS circuit

protector modifications

and

TS

changes

are

being

followed by IFI

90-20-03

(see

paragraph

11.d).

No violations or deviations

were identified in the Modifications area.

7.

Post Modification Testing

(37828)

The inspector

observed

and reviewed

the licensee's

activities in the

PMT

area.

This included discussions

with system engineers,

Test Directors,

and

supervisors.

The specific

areas

observed

and

reviewed

were

as

follows:

PMT-196D,

EECW Flow Verification.

This test was performed to verify

that

the

EECW to

RCW systems

crossconnect

will supply at least

900

gpm of water flow from the

EECW to the

RBCCW heat exchanger

2A in

case of a loss of RCW.

Part of the acceptance

criteria

was to set

the travel

stops

on the crossconnect

valve 2-FCV-67-50 such that at

least

900

gpm flows through the valve with only the north header of

the

EECW operating

and just two pumps

on the header.

The licensee

S

!'

13

experienced difficulty with adjusting

the valve travel

stops

due to

fluctuating pressures

when the crossconnect

valve opened.

The system

engineer

informed the inspector that the

BFNP design engineers

would

be informed of the

TD and would be requested

to change

the pressure

setting at which the valve opens

and closes.

PMT-BF-268.006, Test of RHR Valve 2-MOV-74-53A,

RHR Inboard Injection

Valve.

This test

involved testing for proper operation of the

RHR

inboard injection valve from the Control

Room, local station

and from

RMOV Board

2D.

The test

was adequately 'performed

using

an approved

procedure

and

by

a qualified Test Director.

When control of the

valve

was shifted to the

RMOV Board

and tested

in the Appendix

R

configuration,

the valve indicated

both

open

and closed at the local

station

and at the

RMOV Board

2A.

This valve

had

been previously

tested

after

the Appendix

R modification

and

had tested

satisfac-

torily.

However,

a

new modification W10017A,

known

as

the black

snake

issue,

changed

out

an

unqualified

control

cable.

This

modification

used

an

"As Constructed

Drawing"

and

consequently

a

wiring error

was inserted

into the control wiring.

This item was

corrected

and the valve tested satisfactory.

The inspector will continue

to monitor the licensee's

activities in the

Post Modification Testing area.

No violations

or deviations

were identified in the

Post Modification

Testing area.

8.

System Pre-Operability Checklist

(71707)

a 4

Systems

Returned

to Service

The

inspectors

continued

to monitor the licensee's

activities to

evaluate

and

upgrade

both plant

equipment

and

documentation

as

necessary

to

insure

that

plant

systems

are

in compliance

with

applicable

standards

and

commitments

to support their

required

functions.

As of November

15,

1990,

20 of the

35 systems

required to

support

fuel re-load

had

been

completed

and

35 of the

80 systems

required to support plant operation

were completed.

Those

systems

reviewed

by the inspectors

during this reporting period

are listed as follows:

(1)

Raw Cooling Water

(System

24)

The inspector

reviewed

the completed

SCL

and

SPAE package for

this system.

The checklist

was completed

October 5, 1990.

Six

deferrals

were

taken for this

system.

The inspector

reviewed

the completed

package

and

each of the defer rais.

There

was

a

logical basis for each of the deferrals.

Most of the items were

deferrals

because

the

ECN was not being closed

as work was not

complete for other systems.

14

(2)

(3)

(4)

(5)

(6)

(7)

Normal Ventilation System

(System

30)

The inspector

performed

a walkdown on portions of this system

on

November

5,

1990.

Plant

areas

included

the

DG

rooms

and

radwaste

building.

One

item

was identified to the

system

"engineer.

The

DG 3A exhaust

fan local controller contained

no

identification label to identify the junction box.

Other labels

were in place for 3B, 3C,

and

3D.

No other items were noted.

Station Drainage

(System

40)

The

SCL was completed

on August 8,

1990.

The inspector

reviewed

the completed checklist with the system engineer

on August 13,

1990,

and identified no deficiencies.

Breathing Air (System

49)

The

SCL was

completed

on July 3,

1990.

The inspector

reviewed

the

completed

checklist with the

system

engineer

on July 6,

1990,

and identified no deficiencies.

Sodium Hypochlorite (System

50)

The

SCL

was

completed

on

November

8,

1990.

An inspector

accompanied

the

system

engineer

on the final walkdown for this

system

on

November

6,

1990.

No major work activities

were

identified.

The

inspector

reviewed

the

completed

SCL

on

November

13,

1990,

and

identified

no deficiencies.

The

inspector

noted that

no exceptions

or deferrals

were taken for

this system.

DG 120V

DC Distribution (System 57-1)

The inspector

reviewed

the

package for the

system.

The

was

completed

on October,7,

1990.

The inspector

observed

the following:

ECN/DCNs were identified; primary and critical

drawings

were verified;

PMs identified

by the

system

engineer

were in periodicity; and system hold orders

cleared

except for

the

DG logic power.

These

breakers

were open

and tagged

due to

continuing

System

82, Diesel

Generators,

work activities.

The

inspector

noted

one

minor deficiency

in that

primary

and

critical

drawing

3-C196C11017,

Revision

2 carried

the

wrong

title in the

package.

This item was discussed

with system

engineering.

250V

DC Distribution (System 57-3)

The inspector

observed

the following:

Battery Board

1 battery

was recently replaced with a new upgraded battery; Battery Board

2 battery

was replaced

during this outage

and

was not upgraded;

Battery

Board

3 battery

is

near

the

end of life and

is

0

15

(s)

(9)

(IO)

scheduled

to

be

replaced

during the Unit

2 cycle

6 outage;

Battery, Board

4 battery is

a balance of plant battery

and is not

scheduled for replacement;

and the Control

Power Battery for the

4KV Shutdown

Board

B is scheduled

to be replaced prior to Unit 2

restart

and will not be upgraded.

Additional information supplied

by the licensee, indicated

the

total

amount of

DC power available for station blackout will be

raised

from three to four hours.

This increased

duration is

based

on the present

configuration of the system,

a change

to

the load shed procedures,

and

an ongoing calculation revision.

Secondary

Containment

(System

64 C)

An inspector

accompanied

the

systems

engineer

on

a portion of a

preliminary

walkdown

on

November

16,

1990.

Members

of

operations

and maintenance

groups

were also present.

Only minor

work items

and

housekeeping

were identified.

This system is

currently scheduled for SPOC completion

on December 5, 1990.

Primary/Secondary

Containment Isolation

(System

64 D)

The

inspector

accompanied

the

system

engineer,

Plant Manager,

Technical

Support

Manager,

and others

on the final walkdown of

this

system.

Plant

areas

toured

included

the auxiliary

instrument

room, control

room,

and reactor building.

No major

deficiencies

were identified and all items

were

documented

on

the final walkdown

check

sheet.

The inspector

reviewed

the

system

boundaries

with the system engineer.

The boundaries

were

stated

in

a

memorandum

from the

Project

Engineer

to

the

Technical

Support

Manager.

The boundaries

were

the drywell

pressures

transmitter,

panel

PCIS

annunication,

and

panel

internal

components.

Further review of this system will occur

when the system

SPOC scheduled

for November

16,

1990.

Emergency

Equipment Cooling Water (System

67)

On

November

1,

1990,

the

inspector

accompanied

the

system

engineer

on

a portion of the final walkdown of this system.

The

inspector

went into the shutdown

board

room chiller room located

above

the Unit

3

DG

rooms

and four of the

RHRSW discharge

tunnels.

The

walkdown

was effective in identifying material

problems.

The inspector

noted that

housekeeping

items

were

previously identified

on the preliminary walkdown but were not

corrected

prior to the final walkdown.

This was discussed

with

plant

management.

Also,

the

inspector

questioned

the

consistency

of support installation

on the piping in the

RHRSW

discharge

tunnels.

Design engineering

reviewed the supports

on

the piping

and

determined

that

the

inconsistency

was

due to

Units

1

and

3 piping not presently

being part of the support

program.

Some

sections

of the piping for Units

1 and'

have

been

cut

and

a blank flange installed until those units are

prepared for operation.

This resolved

the inspector's

question

and no other items were identified.

Reactor

Water Cleanup

System

(System

69)

The

SPOC for this system

was completed

on October 23,

1990.

The

inspector

reviewed

the completed

package.

There

was

one

exception

and

two deferrals

against this system.

The exception

was for

a

TS

change

scheduled

for January 5,

1991.

The change

involved installation of

a

10 CFR 50.49 qualified

break

detection

system.

One deferral

involved installation of thermal

overload heaters.

The work for System 69'as

complete but the

DCN was

not closed

due to outstanding

work on other'ystems.

The second deferral

was

a

PMT which required the system to be at

operating

temperature

and pressure.

The inspector

concluded

the

exception

and deferral

could

be justified.

Control

Rod Drive (System

85)

The

was

completed for this

system

and

reviewed

by the

inspector.

The inspector

accompanied

the systems

engineer

and

those

representing

the plant staff

on

a final. walkdown of the

system

and found the equipment

in good condition.

Eight items

deferred

in the

package

were reviewed

and determined to be

acceptable

for system completion.

Ho'Id orders,

temporary alterations,

and configuration control

documentation

were also reviewed.

It was determined that at the

time of system

completion,

each

had

been

evaluated .and

accepted.

In addition,

drawings

were

reviewed

and

were found to have

been

incorporated.

There were

no deficiencies

noted after

SPOC completion.. The completed

for this system

was evaluated

to be acceptable.

b.

Options for System Return to Service

Over the last four reporting periods,

the inspector

has

made

numerous

observations

of the

SPOC activities.

Based

on these

observations,

the

inspector

has

concluded

that

the

licensee

has

two options

available for returning system to service,

as follows:

Option A

This option involves completing

the work prior to turning the

system

over to operations.

This

means

correcting

hardware

deficiencies

and performing

adequate

testing.

A system to be

turned

over to operations

should

have

hardware

deficiencies

C

4

t

0

17

corrected

either

by modification activities

or maintenance

activities

and post modification/maintenance

testing performed.

2.

Option

B

Deferral/Exception.

If a deficiency cannot

be corrected

then

a

deferral

or

an exception

is written.

As of this reporting

period

the

20

systems

which

have

completed

the

process

contain

60 deferrals,

and

10 exceptions.

Break the tie, work arounds,

and punchlist items are also being

generated

during the

SPOC process.

These options should produce

deferrals or,exceptions if not corrected

by the completion of

the

SPOC process.

The inspector

has

observed

that all of the

above

methods

can

be

applied in stages

of the

SPOC process.

The licensee's

SPOC process

requires

that all

Deferr als/Exceptions

be

approved

by the Plant

Manager.

It was

noted

by the inspector that the break the tie, the

work around,

or the punchlist

methods

do not require

individual

approval

by Senior

Management.

This item is identified as IFI 259,

260,

296/90-33-04,

Hardware Activities Delayed

but not approved

by

Senior Management.

One example of senior management

involvement occurred

when System 32,

Control Air, was

being divided into two systems.

System

32 would be

SPOCed

and

a

new system

32A, Drywell Control Air would

be

SPOCed

later.

This is the

break

the tie method.

Site Management

became

aware of this

and directed

middle

management

to

the entire

system

as originally planned.

Another example

noted involved System

9, Control

Bay Panels.

Thils system

was originally established

to

check

the control

panels

to ensure

adequacy

of configuration

and

verify the

HEDs

from

CRDR.

The inspector

was

informed that this

system

would

no longer

be

a

SPOC system,

and consequently

there will

be one less

system to

SPOC before fuel load.

No violations or deviations

were identified in the

SPOC area.

9.

Restart Test Program

(70400)

The inspector

reviewed

the licensee's

PRD

BFP 890772P in which

RTP Test

Exceptions

were

reviewed.

The

TEs

reviewed

were

those

which

were

classified for equipment

performance

or hardware

issues.

The results of

this review indicated that

11 corrective actions

were necessary

such as:

provide

the required

documentation

to ensure

that the appropriate

design

output documentation

has

been

issued;

evaluate

each listed

TE against the

issued

design output document;

and document all discrepancies

which relate

to any failure to satisfactorily

complete

the required testing or which

affect the acceptability of test results.

18

The inspector

noted that this review consisted

of TEs from 39

RTP test

'rocedures.

A total of

16

TEs

from

9

RTP test

procedures

required

additional

review due to inadequate

documentation.

The documentation

was

required for two reasons:

The

TEs did not provide clear and complete exception descriptions

or

failed

to

provide

adequate

disposition

documentation

within the

package.

The

TEs did not provide adequate

documen'tation

that all disposition

was coordinated

through other organizations.

The

licensee

discussed

these

16 TEs'n

depth

and

provided

necessary

documentation for adequate

disposition of each

item.

Based

on this

review

and

the

inspector

has

concluded

that

the

licensee

conducted

the

RTP test

procedures

in

an

approved,

controlled

and

adequate

manner

and that

TEs were adequately

addressed.

Additional

RTP reviews

and observations

will be

documented

under the licensee's

Power Ascension

Program.

10.

Reportable

Occurrences

(92700)

The

LERs listed

below

were

reviewed

to determine if the information

provided

met

NRC

requirements.

The

determinations

included

the

verification 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.

0

a

~

(CLOSED)

LER 259/88-53,

Main Steam Relief Valves Actuating Outside of

Technical Specification Setpoint

Because of Pilot Disc Sticking.

Wyle Laboratories

notified Browns Ferry

on

December

14,

1988, that

two of three

Unit

1 Target

Rock

MSRV tested

did not meet

the

acceptance

criteria specified

in

TS.

The

two valves failed to

actuate

within one

percent

(11 psig) of their setpoints.

Wyle

Laboratories

investigated

the

problems

and

determined

that

the

setpoint drift was

due to sticking of the pilot disc in combination

with inadequate

clearance

between

the pilot rod

and liner in the

labyrinth seal.

Wyle refurbished

these

valves

as necessary

to assure

that each would actuate within TS requirements.

The inspector

reviewed

the closure

package for this

LER, reviewed

plant procedures,

Plant SIs,

PMs

and interviewed plant personnel.

SI

O-SI-4.6.D.1

is

the controlling

document

used for verifying the

setpoint

of the

MSRVs.

Completion

of this

SI satisfies

the

requirements

of TS 4.6.G. 1.

Documentation

indicates that all Unit 2

valves

have

been

tested

by Wyle Laboratories.

The licensee

has

19

written

PN R08672 to have the setpoints

verified for all Unit I and

Unit 3

NSRVs

as required

by O-SI-4.6.D. 1.

Continued

implementation

of 'present

plant

procedures

should

ensure

that

the

TS's

NSRV

setpoint requirements

are met.

(CLOSED)

LER 259/89-28,

ESF Actuation

Caused

by Fault

on "8" Phase

Shunt Reactor of 500

KV Union Transmission

Line.

On

December

28,

1989,

a Unit 2 half scram occurred

when the Unit 2

2A bus

tripped,

resulting

in

an

ESF actuation.

The event

occurred

during

an attempt

by plant personnel

to flush debris

from

the

HPFP system automatic

deluge valve, which resulted in a full flow

fire protection

discharge

onto

the

500

KV shunt

reactors

while

energized.

The licensee

issued

LER 50-259/89-28

to document

the

events

leading to the

ESF actuation,

the results/consequences

of the

actuation,

and corrective action provided.

The inspector

reviewed

the licensee

closure

package

and associated

documentation.

The licensee

identified the root cause of the event

as

personnel

error

in the

LER.

The

licensee

also

identified

unreliable

equipment,

in the final event report,

as the

second

root

cause

that

contributed

to

the

event.

The

licensee

performed

appropriate

corrective actions

to properly re-align the

ESF systems

which actuated.

The license

provided counseling

to the personnel

responsible for the

error,

and provided reinforcement

in initial training for all fire

protection

personnel.

DCNs were

issued

to modify the

RPS circuit

protector underfrequency trip circuitry to make't less vulnerable to

transients,

and

to replace

the deluge

system

valves

as

necessary.

The

licensee

performed

appropriate

evaluations

to determine

the

effect of the

system

spray

on the shunt reactor,

and performed

sufficient tests

to assure

that the shunt reactor functions properly.

(CLOSED)

LER 260/90-04,

ESF Actuation

Caused

by Design Oversight-

Water Intrusion in

ECCS

ATU Panels.

On June I, 1990, during

an air test

on the

HPFP system,

an unplanned

ESF actuation occurred.

The actuation

was

a result of water from the

HPFP system in cable

spreading

room

A dripping onto the

ECCS analog

trip units in the Unit 2 auxiliary instrument

room in the elevation

below the

spreading

room.

The water dripping

on the

ATU panels

caused circuit cards

in the

ATUs to generate

spurious

signals

which

resulted

in unnecessary

start of EECW pump Al and emergency

DGs A, C,

and

D.

Additional review by the licensee

indicated that an'ATWS/ARI

trip also

occurred

and if the plant were not in its present

system

lineup, additional

equipment actuation

would have occurred.

The

cause

of the event

was

a design oversight.

The design of the

seismic

gap is such that water from the cable spreading

room in the

elevation

above

the Unit 2 auxiliary instrument

room leaked directly

20

d.

onto the

ATU cabinets.

This effect has

the potential

to cause

the

ATU cards

to short and,initiate

erroneous,

signals

to various

ECCS

equipment.

The inspector

reviewed the licensee's

corrective

actions

which stated

that

a technical

assessment

of the safety aspects'f

intrusion of

water into the

ATU panels

and the design of the seismic

gap slip

joint to insure water tightness will be performed.

The inspector

also

noted that IFI 259,

260,

296/90-'18-01,

Interaction of ATU and

Seismic

Gap,

was initiated to review the results of the licensee

activities

in this

area.

This

LER is closed

based

on reviews

generated

by the IFI.

(CLOSED)

LER 259/90-11,

De-energization

of

Bus

Caused

by

Inadequate

Design of Circuit Protector

Setpoint.

(CLOSED)

LER 296/90-01,

De-energization

of

Bus

by Alternate

Supply Circuit Protector

Operations

Caused

by Inadequate

Design of

Protector Setpoints.

On January

26,

1990, in Unit 3, and

on July 20, 1990, in Unit 1, the

de-energization

of

buses

occurred

due

to the tripping of

associated

circuit protectors.

In

each

case,

unplanned

ESF

actuations

occurred.

These

two events

are further examples

of the

licensee's

continuing

problems

with the

RPS circuit protector

setpoints.

As

a result of previous trips

and

LERs,

the licensee

developed

a detailed

plan to resolve

these, problems.

These

two

events

occurred

before

the licensee's

corrective

actions

could

be

completed.

The

inspector

reviewed

the

LERs

and verified that they met the

requirements

of

This issue

has

been followed on

an

ongoing

basis

by the resident

inspectors.

All modifications

have

been

completed for Units

1

5 3.

The majority of the physical

work

has

been

completed

and the license

is awaiting the

issuance

of TS

amendments

for completions

of the modifications

in Unit 2.

A

detailed

status of this issue

is given in paragraph

6.d.

No further

deficiencies

or concerns

were identified for these

LERs.

11.

Action on Previous

Inspection

Findings

(92701,

92702)

a

~

(OPEN)

IFI

50-259,260,296/86-05-07,

Reactor

Building Isolation

Radiation Monitor

This

item dealt

with the

question

of

how long

the radiation

monitoring channels for the reactor

zone

and the refueling zone could

remain inoperable

during

a surveillance

before the channel

had to be

tripped or declared

inoperable.

Note

11 to

TS Table 3.2.a states

that

a

channel

may

be

inoperable

for

up to four

hours

for

surveillance

without placing

the trip

system

in

the

tripped

condition.

Note

22 to

TS

Table 4.2.a

states

that

one

channel

Cl

~,

21

may

be administratively

bypassed

for a period not to exceed

24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />

for functional testing

and calibration.

A followup of this IFI was conducted

and documented

in IR 89-19.

As

a result of additional

discrepancies

that arose during that followup

coupled with the original issue

had not been resolved,

IFI 86-05-07

was left open.

As indicated

in

IR 89-19, for the

purpose

of

eliminating

concerns

over

time

periods,

the

licensee

revised

procedures

2-SI-4.2.A-10FT,

"Reactor Building Ventilation Radiation

Monitors

RM-90-140,141,142,143

Instrument

Functional

Test"

and

2-SI-4.2.a. 10,

"Reactor

Building

and

Refuel

Floor Ventilation

Radiation

Monitor Calibration

and

Functional

Test"

to place trip

systems

in the tripped condition at the beginning of the tests.

This

approach

however

was later judged

inadequate

in that it introduced

other

TS associated

with the unavailability of the drywell and torus

hydrogen

analyzers

due to the

Group VI isolation signal that results

from the SI's

systems

being tripped.

As stated

in IR 89-19 followup,

the inspector considered

the changes

to the SIs

as incomplete in that

they still did not clarify how long

a Reactor

Building radiation

monitor is allowed

by TS to remain inoperable for surveillances.

Based

on

a current

review of the

issue,

a clear

and

unambiguous

position

on the original question

raised

by IFI 86-05-07 regarding

how long

a Reactor

Building radiation monitor is allowed

by TS to

remain

inoperable for sur'veillances,

has

not

been developed.

Step

3.4 in Section

3.0,

"Precautions

and Limitations" in addition to

a

CAUTION note preceding

Step 7.4.5 in each of the following procedures

alerts

the

user to the notion that

a

TS

LCO "may result" if the

particular monitor being tested is out of service for more than four

hours,

and requires

the individual to notify the

SOS if it becomes

apparent that the four hour time limit will be exceeded:

2-SI-4.2.A-9(A)

2-SI-4.2.A-9(B)

2-SI-4.2.A-10(A)

2-SI-4.2.A-10(B)

Rev.3

Rev.4

The

ambiguity "of the

"may result"

wording utilized in these-

procedures,

permits

the inference that allowable outage

times other

than

the four hour provision of Note

11 to TS Table 3.2.a

(such

as

may

be afforded

by Note

22 to

TS Table 4.2.a)

are available to the

SOS in making an operability determination.

The inspector

was unable

to find

any

programmatic

documentation

defining

usage

and/or

restrictions

on the

usage of "administrative

bypass" in the context

of Note

22 to

TS Table 4.2.a.

Consequently,

the original

TS

inconsistency

between

Note

11 to

TS Table 3.2.a

and Note 22 to TS

Table 4.2.a,

covered

by IFI 86-05-07,

has not been resolved.

Additional deficiencies

identified in IR 89-19 followup and their

current status

are:

i

22

Deficiency:

TS Table 3.2.a -- Unit

2

Notes

(2), (5),

and

(13)

are not

attached

to any item in the table.

Resolution:

TS Amendment

Request

8288 submitted

by TVA on 10/30/90,

revises

Table 3.2.a to add

Note (13) next to "Instrument Channel

- High

Radiation

Main Steam

Line Tunnel". Additionally, Notes

(2) and

(5) have

been deleted.

Deficiency:

Paragraph

6.2 of SI

4.2.A-10FT,

which describes

acceptance

criteria, is not accurate.

Resolution:

This paragraph

has

been modified to replace

"and" by "and/or"

thereby correcting the inaccuracy.

Deficiency:

SI 4.2.A Data Tables

7-1408,

1418,

142B,

143B should denote

the

value of the downscale trip as

an acceptance

criteria since the

downscale trip is

a

TS function.

Resolution:

The following procedures

containing

the

above referenced

tables

were reviewed

by the inspector

during the current follow-up to

IFI 86-05-07:

2-SI-4.2.A-9(A)

Rev.3

2-SI-4.2.A-9(B)

Rev.3

2-SI-4.2.A-10(A)

Rev.4

2-SI-4.2.A-10(B)

Rev.4

Each

of- the

referenced

tables

provides

the. information for downscale

trips.

Based

on this review and recognizing that the

TS do not establish

a downscale trip setpoint

as they do for the upscale trip, the inspector

considers

that the additional

concerns

contained

in the deficiency

have

been adequately

addressed

by the referenced

procedures.

b.

(CLOSED) IFI 89-16-12,

Followup

on Compensatory

Actions

Due to the

Inability to Perform

10 CFR Part 50 Appendix J Testing

on Containment

Check

Valves74-705,

706,

829,

830,

and

75-580A,

580B,

581A,

and

5818.

The inability of the licensee

to perform Appendix J testing

on the

above

valves

was identified in IR 89-16.

Because

these

valves

can

not

be Appendix

J tested, it is necessary

to close valves75-582

A

and

B when primary'ontainment

is required.

The inspectors

noted in

the report that the

licensee

was

aware of this

problems

and

an

evaluation of the corrective actions

was in process.

23

The inspector

reviewed

the licensee's

corrective action,

both short

ter'm and

long term.

The short term res'olution

included

a change to

the

"Core

Spray

System

Operating

Instructions".

The

procedure

presently

requires

that

be charged

using the

PSC

head

tank

when

primary

containment

is

required.

The

inspector

reviewed

the

associated

plant drawings

and verified that this alignment

would

provide the necessary

water to charge

the

CS system

and assure

that

the necessary

valves are closed

when primary containment is required.

The licensee

has issued'a

OCR to provide long term corrective action.

The inspector

reviewed

the

DCR and discussed

its details with the

responsible

system

engineer.

The

requested

changes

adequately

addressed

the

concerns

identified in

IR 89-16.

The licensee

has

established

90-0407

as

a tracking

number for this item.

The design

is scheduled

for completion in 1992

and implementation in 1993.

Any

further inspection

in this area will be conducted

under the routine

inspection

program.

(CLOSED) IFI 259,

260, 296/89-17-05,

Followup on

ATWS Modifications.

This

item

was

closed

during

the

ATWS inspection

discussed

in

paragraph

14 of this IR.

(CLOSED)

IFI 259,

260,

296/89-27-03,

Verification That

DG Output

Breakers

Recharge

in 2.5 Seconds

or Less.

The ihspector

reviewed

the yearly surveillance

instruction for all

eight

BFNP

DGs

and noted that step 7.12 of the SIs required that the

DG output

breakers

be tested

to verify that they recharge

in 2.5

seconds

or less.

(OPEN)

IFI 259,

260,

296/90I 20-03,

RPS Circuit Protector

Trip Level

Setpoints

and Surveillance.

This item concerns

the inconsistency of surveillance

requirements for

RPS circuit protector

setpoints

between

the

TS for all three units at

BFNP.

Because

of these

inconsistencies

and

numerous

RPS circuit

protector trips, the licensee

revised

the setpoints

and submitted

a

TS revision

to establish

consistent

setpoints

and

surveillance

requirements

for all three

BFNP units.

Change

request

8286

was

submitted

to the

NRC

on June 4,

1990.

Issuance

of the

TS change

request

and implementation 'of the

new setpoints will resolve the

circuit protector

issues

for

BFN Unit 2.

The

TS change also included

new requirements

for Unit

1

and Unit 3.

The

new setpoints

are

already in place in those units.

All other

aspects

of the

RPS circuit protector

concerns

have

been

resolved

(see

paragraph

6.d).

The inspector

reviewed the licensee's

upgraded

SI for Unit 2,

2-SI-4. 1.B-16

"RPS Circuit Protector

Calibration/FT",

and verified that it included the setpoints

which

were

submitted

in the

TS

change.

The

SI will remain

under

administrative

hold until the

TS change

has

been

issued

by the

NRC.

This item will remain

open pending the issuance

of the

TS revision by

the

NRC

and

the

change

of the setpoints

for the Unit

2 circuit

protectors.

f.

(CLOSED)

IFI 259,

260,

296/90-25-03,

Documenting

and Controlling

. Clearances.

This item relates

to the difficulties encountered

by the licensee

in

determining

which equipment

clearance

numbers

were associated

with

work activities being reviewed

by the inspector.

The licensee

believes

that the current hold order tracking

system

provides

the necessary

information for operations

to manage

the hold

order

process.

The licensee

indicated that several

sorting fields

are currently available including the following:

system

people

on the hold order

expected

date of the hold order release

working group requesting

the hold order

The licensee

has further stated'hat

to create

another field to sort

by the

WO or

PN would not be especially beneficial

and there

are

no

plans

now to implement

a computerized

tracking system that would tie

the activity to the clearance

number.

During the followup of this

open item, the inspector

reviewed Site

Director

Standard

Practices

7.6.2,

"Maintenance

Management

System-Planning

Work Orders"

(Rev.

10)

and

SDSP

14.9,

"Equipment

Clearance

Procedure".

The following aspects

were noted:

Appendix

B,

"Work Order

Form" to

SDSP 7.6.2 presently

provides

for the documentation

of the hold order

number

on space

18 of

the form.

Section

6. 1 of

SDSP

14.9 currently states

that

no work shall

begin

on equipment

to

be

included

in

a clearance

until the

clearance

has

been

issued

to the

person

responsible

for the

work..

Based

on

the

above

the

inspector

considers

that

an

adequate

programmatic correlation exists

between

hold order

numbers

and the

activities covered

by work orders.

g.

(CLOSED)

URI

259,

260,

296/89-06-05,

Inadequate

Calibration

of

Instrumentation

Required for TS Surveillance Testing.

Previously

an inspector identified that

some calibration instructions

used

to calibrate

instruments

necessary

to meet

system operability

requirements.

wi 11

not

be

upgraded prior to Unit 2 restart.

During

the inspection,

several

calibration instructions

were

found to

be

0

25

inadequate

and

the

inspector

was

concerned

that

the

inadequate

instructions

could affect

system

operability

following Unit

2

restart.

The inspector

held discussions

with licensee

personnel

concerning

the

'completion of calibration instruction upgrades.

In the

NPP Volume 3,

TYA committed to prioritize the

procedures

to be upgraded prior to

restart

using

information similar to that

used for

a

PRA.

The

licensee

established

a list of maintenance

procedures

to be completed

prior to restart

based

on this priorit'ization.

The

inspector

reviewed

the list and

noted

there

were only a few remaining which

were not upgraded.

The licensee

stated that the few remaining

ones

would be upgraded prior to Unit 2 restart.

The inspector identified

no further concerns.

(CLOSED)

URI 260/89-16-06,

Evaluation of Unsupported

Piping Spans

For

Pump Suction Pressure

Instrument

During inspection

89-16,

the

team identified that the approximately

15 foot and

17 foot span of unsupported

1/2 inch schedule

80 piping

for the

2C and

2A

pump suction instrumentation

appeared

to exceed

the piping code in place during Brown's Ferry construction.

The licensee's

review of this issue

involved determining what program

would

have

corrected

or evaluated

this condition.

The licensee

determined

that

the piping in question

was qualified

under

the

attribute

walkdown portion of the

small

bore piping program.

To

resolve

the question

about

whether

the

span

was acceptable

per the

piping code,

the licensee

provided the following information:

The piping

was

designed

and installed to the requirements

of

USAS B31. 1.0-1967,

"Code for Pressure

Piping-Power Piping".

Section

121. 1.4,

"Hanger

Spacing"

of B31.1.0

requires

that

supports

for piping

be

spaced

to prevent

excessive

sag

or

bending

and shear stresses

in the piping.

Mhere calculation are

not made,

suggested

maximum spacing of supports for standard

and

heavier pipe are provided in included tables.

Table

121. 1.4,

which

addressed

1-inch to

24

inch piping,

suggested

that support spacing for 1-inch piping be

a maximum of

7 feet for water service.

The

licensee

indicated

that

the

suggested

table

values

were not

utilized during construction,

and that is why the small

bore program

was

implemented

to

evaluate

the

actual

configuration

through

walkdowns utilizing acceptance

criteria that

had

been

established

through bounding calculations.

To ensure

the adequacy of the small

bore

program evaluation,

which had

been previously completed for the

piping sections

in question,

and to ensure that the above piping code

requirements

were

implemented,

the licensee

rigorously analyzed

the

26

piping in question.

This analysis

was to ensure

that the actual

stresses

were within those

allowed, by the piping code.

The analysis

was

documented

by calculation

CD-Q2075-900468

which

evaluated

the

instrument

piping for all four of the

pump suction

lines in

question.

The licensee

performed

a worse case analysis for the

2D

pump suction line

which they determined

to involve the

longest

unsupported

span.

The inspector

reviewed

the results of the previous

walkdown

as well

as

the

results

of

the

rigorous

analysis

performed

by

the

calculation

noted

above.

The

review of the

walkdown

package

indicated

that

the

small

bore

program did not evaluate

sag

as

an

attribute

,in the walkdown.

The licensee

indicated that sag for the

small

instrument

lines

was evaluated

during the resolution of the

instrument

slope

issue.

Additionally, the inspector

discussed

the

lack of a piping sag verification for small

bore piping with NRR, who

had accepted

the

program in

NUREG 1232,

Volume 3, Supplement

1.

Sag

is not

a mandatory

code requirement for piping supports

design

and is

in most cases

bounded

by the piping stress

analysis.

Regarding

the

rigorous

analysis,

the

licensee's

calculation

CD-Q2075-900468

(a

QA document)

that

was

presented

to the inspector

in the closure

package

contained

information that was different from

an identical calculation that

was latter presented

to the inspector.

Specifically,

identical

revisions

with the

same

RIM

number

contained different information on page

5 as to what instrument line

was analyzed.

The original calculation in the closure

package

tied

the four analysis

problems

numbers

to the respective

pump.

The

latter

calculation

aligned

the

calculation

problem

numbers

to

different

pumps.

Statements

from the

two calculations

are provided

for clarification.

Closure

package calculation stated,

"Four similar

problems

2-75-814-1-17,21,22,24

are

branched

out from 16" suction

header

of

pumps

2A,28,2C,

and

2D, respectively.

Only the worst

case,

i.e.,

problem

17 is analyzed

to confirm that the piping is

properly

supported ...."

However,

the calculation

presented

on

November 8,

1990 stated,

"Four similar problems 2-75-814-1-22,21,24,

17 are

branched

out from 16" suction

header of CS

pumps

2A, 2B, 2C,

and

2D, respectively.

Only the worst case, i.e.,

problem

17 is

Analyzed to confirm that the piping is properly supported'...."

It is

be apparent

from, the two versions

that the worst case

problem

analyzed (i.e.,

17) could

have

been either

the suction

instrument

piping for the

2A or the

2D pump,

depending of the version of the

calculation reviewed.

The inspector

reviewed the actual installation

and determined that the suction line for the

2D pump appeared

to be

worst case

based

on the unsupported

length..

The inspector.

requ'ested

that the licensee

determine

the cause for the different versions of a

QA record.

The licensee

determined that the official record

was the

one that

was provided to the inspector during the inspection

and not

the

one that

was

provided

in the closure

package.

The licensee

27

provided

the following explanation

based

on their investigation of

the calculation discrepancies:

'uring the calculation review and approval

process

the reviewer

noted that the problem to pump correlation

was incorrect and it

was

changed

on the official copy.

'he calculation

was sent to RIMs for distribution

(The process

takes

approximately

4 weeks).

'he licensing organization

requested

an expedited

copy for the

closure

package.

'he engineering

organization

got a copy of the cover sheet

from

the

RIMs group and attached it to an in-house

copy of the

'alculation

that

had not been

changed

to correct the error that

was discovered

during the review and approval

process.

The inspector discussed

the following concerns

with the licensee:

(1)

With the long delay in issuing the

RIMs copy of calculations it

appears

that any revisions

during that time frame would be made

to uncontrolled copies of the calculation.

(2)

The

process

that allow attaching

a cover sheet to an in-house

document

is

a weakness

in the record distribution process

and

should

be evaluated.

(3)

Information being provided to the

NRC needs

to be factual

and

complete

Review of the licensee

gA control

process

in the

above

areas

is

identified as IFI 50-260/90-33-05.

(OPEN)

URI

50-260/89-16-07,

Need

to

Perform

ASME Section

XI

Inspections

On Valve Operator Supports

During inspection

89-16 the

team questioned

ISI SI-4.6.G regarding

the failure to include

valve operator

supports

in the

American

Society of Mechanical

Engineers

Boiler and Pressure

Vessel

Code

(ASME

Code) Section

XI program.

The ISI group advised

the team -that valve

operators

were not included in the ISI program because

they were not

pressure

boundary

component

supports.

Contrary

to this,

the

licensee's

Engineering

Department

advised

the

team

that

valve

operator

supports

are

designed

either

to maintain

pipe

pressure

boundary

integrity

(pipe

stress)

or to

assure

valve

operation

(seismic

oualification).

The

team

noted

that

the

RHR

system

contained

valve operator

supports

that were not in the ISI program.

On December

15,

1989, the ISI group proposed

a corrective action plan

to review all drawings, identify all required

valve supports,

and

I

0

28

perform

a baseline

examination of the identified supports

to

ASME

Code Section

XI requirements

prior to restart.

The

inspector's

review of

the

licensee's

corrective

actions

associated

with resolving this

URI indicated that the licensee

had

changed

their

proposed

corrective

action.

Specifically,

the

licensee's

gA ISI group reevaluated

the requirements

of Section

XI of

the

ASME Boiler

and

Pressure

Vessel

Code,

1974

summer of 1975

Addendum edition,

which is

the current

code of record for

BFNP

Unit 2.

This reevaluation

indicated

that

the

licensee

no longer

believed

that

the

code

required

inspection

of supports

which

connected

to valve operators.

The licensee's

did indicate

in the

issue

closure

package

that they were planning to implement the

1986

revision of the

code during the next

10 year interval

and that the

newer code specifically requires

inspection of intervening elements.

The inspector's

review of the

1974 edition of Section

XI determined

that sections

IWB for Class

1 and

IWC for Class

2, requires

in Tables

IWB-2500

and

IWC-2520 that the support

components

be inspected..The

tables specifically require that the area to be inspected

include the

support

components

that

extend

from the piping, valve,

and

pump

attachment

to

and

including

the

attachment

to the

supporting

structure.

-The licensee

had interpreted

that this requirement

did

not apply to valve

operator

supports

even if the

operator

is

supporting

the valve

and 'piping system.

The inspector

has discussed

the licensee's

interpretation with NRR and Regional

NRC staff and the

NRC does

not concur with the licensee's

position.

The requirements

to inspect

supports

are

to

ensure

pressure

boundary

integrity

and to eliminate

supports

that serve this

purpose

does

not comply

with code requirements.

The inspector

met with licensee site senior management

on November 8,

1990 to discuss

the licensee's

position.

The licensee

agreed that

the supports

logically should

be inspected.

However, the licensee

pointed

out that their

program that

was

submitted

to the

NRC in

July 1977

and for concurrence

in November

1981

never

intended

to

inspect the type of supports

in question.

Nevertheless,

the licensee

proposed

to include the supports

in their program

and

perform the

baseline

inspection

before plant restart.

Follow up inspections

of

the licensee

resolution of this issue will be tracked

by this item

remaining open.

(CLOSED) Violation 259,260,296/88-28-01,

Failure

to Control

and

Correct

Known Drawing Discrepancies

(CLOSED)

Violation

259,260,296/90-14-04,

Failure

to

Implement

Drawings

and Procedures.

The program description for handling drawing discrepancies

at

BFNP is

found in SDSP 9. 1, "Processing

Drawing Discrepancies".

The detailed

handling

of drawing

discrepancies

within Nuclear

Engineering

is

.

'I

0

29

described

in

BFEP

Process

Instruction

87-,70,

"Processing

Drawin'g

Discrepancies"

which is

a subtier

document of SDSP 9.1.

The following discussion

centers

around

VIO 90-14-04

since

the

corrective action originally implemented

as

a result of VIO 88-28-01

when coupled with the corrective action taken for 90-14-04 satisfies

the original concerns

associated

with VIO 88-28-01.

During the

NRC inspection

conducted

from April 16 - May 18,

1990,

and

documented

in IR 90-14,

two examples of failure to implement drawings

and procedures

were. identified by the inspector

.

In their July

13,,

1990

response

to the Violation the

licensee

attributed

the

cause

of

example

one

to

inadequate

procedural

controls.

IR 90-14 previously documented

the inspector's

review of

the

licensee's

completed

incident

investigation

( II-B-90-504)

associated

with this

example

and determined

that inadequacies

had

existed in the implementation of SRN G-38-69.

The

SRN was

signed

out April 6,

1990,

as "effective immediately" yet

it did not arrive at

BFNP Document Control until April 26,

1990, at

which time it was

given

a

due

date

of

May 27,

1990 for site

implementation.

The licensee

acknowledged

in their response

that the source

document

implementation

program

had failed to process

the change

covered

by

SRN G-38-69 in the timeframe necessary

to support the ongoing field

activities.

As corrective

action,

NEP-5.1,

"Design Output",

was

revised

to

provide

an

administrative

control

program for the

processing

of "effective immediately" changes.

Under this revision to

NEP-5. 1, the inspector

confjirmed that the Chief Discipline Engineer/

Project

Engineer

is

now required

to provide to the affected site

directors

approved

copies of any specification, revision, or

SRN when

implementation

date is "effective immediately" or is not supported

through the normal controlled copy distribution.

In the case of example

82, the licensee

attributed the Violation to

personnel

error.

As

a result of the system engineer's

review of the

PDD that

was written to address

the difference

between

the field

wiring and the plant drawing, the decision

was

made to reconnect

the

wiring in

accordance

with

the

plant

drawing.

However,

this

dispositioning

of the

PDD failed

to consider

the effect

the

reconnection

would have

on the control logic for the

4160V shutdown

board.

Details

associated

with the inadvertent

diesel

generator start were

documented

in

LER 259/90-06

which

was

subsequently

reviewed

and

closed out in IR 90-27.

30

As corrective aetio'n,

the

system engineering

personnel

involved with

the event

have

been

counseled

and instructed

on the

importance of

performing

thorough

technical

evaluations

of

PDDs. Additionally,

Revision

10

to site

procedure

SDSP

9.1,

"Processing

Drawing

Discrepancies",

has

been

issued

to require

independent

verification

on

PDD resolutions.

Section

7.0 of SDSP 9.1 assigns

an "Independent

Verifier" to review and concur with

PDD disposition

and categoriza-

tion.

A block requiring independent verification of PDD disposition

and categorization

has

been

added to Attachment A, "Potential

Drawing

Discrepancy

Flow Process"

of

SDSP 9.1,

downstream

of the

system

engineer's

det'ermination of the

method for dispositioning

the

PDD.

Finally, Form SDSP-17,

"Potential

Drawing Discrepancy

Form", has

been

modified to require

a signature

by the independent verifier, the date

signed,

and the individual's extension

number.

Based

on

the

above,

the

inspector

determined

that

the

concerns

associated

with the

referenced

violations

have

been

adequately

addressed.

(CLOSED) YIO 50-260/89-16-04,

Inadequate

Procedure.

The

issue

that

was identified by the

NRC

as

the first example,

involved inadequate

instructions

in procedure

2-0I-75 which directed

valve manipulation that allowed post accident

water to

be directed

outside

the

containment

boundary.

The

licensee

response

dated

April 9,

1990,

indicated that the

OI in question

was revised to note

that the resetting of PCIS

and that restoration of keep-fill water

would be controlled by procedure

2-AOI-100-1.

The inspector

reviewed revision

16 of 2-OI-75 which added

caution

about contacting chemistry for special

caution

on opening containment

isolation valves.

This

same

revision indicated in step

7.1 that

resetting

of

PCIS

and

restoration

of keep-fill water

would

be

controlled

per

procedure

2-AOI-100-1,

"Reactor

Scram

Abnormal'perating

Instruction."

The

inspector

reviewed

2-AOI-100-1

and

verified that instruction

on operating

the valves

and resetting

the

PCIS signal

were included.

However, the licensee failed to insert

a

caution

about

hazards

associated

with diverting post accident water

outside

the containment

boundary.

The licensee

subsequently

revised

2-AOI-lOO-I to include the caution note.

Regarding

example

2 of VIO 260/89-15-04,

the licensee's

calculation

(MD-f2075-890109)

determined

that

the

flow valve specified

in

procedure "2-SI-4.5.A. 1.D (1)

was incorrect.

Revision

19 of the SI

corrected

the values

and referenced

the calculation.

The inspector

also

reviewed

the

CCRIS

system

to ensure

that there

was

a cross

reference

from the calculation

to the

SI to ensure

that if the

calculation*changed

the procedure

would be reviewed.

(OPEN) Violation 259,

260, 296/89-17-01,

Failure to Comply With the

Requirements 'of 10 CFR 50.59

31

This violation involved the processing

of DCN H3858A,

ECN P7113,

and

DCN

HO166A, which modified the facility as

described

in the

FSAR

without

a written safety

evaluation

to provide

the

basis

for

determining that an unreviewed safety question

was not being created.

The licensee

responded

to the Violation by letter dated

September ll,

,

1989.

The

NRC accepted

the licensee's

response.

by letter

dated

October

2,

1989.

The

licensee

committed

to

provide

safety

evaluations for the three

DCN/ECNs identified in the violation and to

review change

packages

closed

between

January

1988 and April 1989 in

support of the next

FSAR annual

update.

The inspector

reviewed the safety evaluation

provided for the three

change

packages

identified in the violation.

They appeared

to

be

adequate.

However,

the

licensee

committed

to review all

ECN/DCN

packages

completed

between

January

1988

and April 1989.

The

inspector

questioned

the basis for the review beginning in January

1988 versus

,the date

on which screening

reviews

were permitted.

The inspector

reviewed the

SWEC procedure

for

FSAR verification and determined that

although all

DCN/ECNs closed during this time period were reviewed,

they were first screened

for

FSAR impact.

If none was'ound,

the

packages

were not further reviewed.

The purpose of this commitment to review all

ECN/DCNs closed

during

that

time period (or the period during which inadequate

screening

reviews

may

have

been

performed)

was

to find any

packages

which

should

have contained

a safety evaluation

but did not.

However, the

inspection

determined that if ECN/DCNs did not affect the

FSAR, they

were

not reviewed for adequate

50.59 evaluations.

The inspector

expressed

this concern to the licensee,

and it was confirmed (I) that

the January

1988 date

was

based

on the

FSAR update

schedule

and (2)

that

the first screening

criteria

used

by their

FSAR

update

contractor

was

impact

on the

FSAR, therefore,

packages

which would

not impact the

UFSAR were

not reviewed for 50.59

adequacy.

The

inspector

does not believe that the corrective action

was adequate

to

identify the type of problem cited in this violation.

After the

above

review the inspector

evaluated

several

additional

screening

reviews for other modification

performed

in

1988

time

frame.

The inspector identified similar problems to those described

in the violation.

Although the inspector did not identify any items

that constituted

an

unreviewed

safety

question it could not

be

ascertained

from the

screening

review. that

the

licensee

had

an

adequate

written basis

for their determination.

The

SWEC review

relied

on

a review of the entire design

change

package

and not just

the screening

form.

The inspector

discussed

the findings of this

sample

review with the licensee

and the licensee

indicated in the

exit interview that they

may

sample

some of the screening

review

forms that

were

excluded

from the

SWEC review.

The

inspector

32

informed

the

license

that this

item

wi 11

remain

open

pending

additional

reviews of screening

forms by the

NRC.

(CLOSED)

VIO 259,260,296/89-27-04,

Failure to Report

as

Required

by

During the

NRC inspection

conducted

from June

16 - July 15,

1989,

three

examples of a failure to submit

a

LER within 30 days after the

discovery of an event,

as required

by

10 CFR 50.73,

were identified

by the inspectors.

These

examples

formed

the

bases

for Violation

50-259,

260,

296/89-27-04

transmitted

to the

licensee

on August 8,

1989 in

IR

89-27.

In their

September

21,

1989,

response

to the

VIO, the

licensee

admitted violation

example

83 but expressed

the belief that

the

events

covered

by examples

81 and

b'2 were not reportable

pursuant

to

Based

on the information provided in the licensee's

response,

the

denial of example

81 was accepted

by

NRC Region II in a letter to the

licensee

on

November

16,

1989.

Irrespective

of the original

uncertainty regarding

the reportability of Example

81 pursuant to 10 CFR 50.73

the

licensee

did identify it as

a condition adverse

to

quality

and

issued

CARR

BFP 880702

thereby formalizing root cause

identification and corrective

action plan development.

In reference

to the reportability of example

P2, the

NRC Region II

November

16,

1989 letter advised

the licensee that the

NRR technical

staff would be reviewing the licensee's

position and that the results

of their evaluations

would be communicated

to the licensee

once they

became available.

Notification of these results

was

made

by

NRC Region II in a letter

dated

November

2,

1990.

This letter

provided

the

NRC staff's

conclusions

there

was insufficient basis

available to support

TVA's

engineering

judgement

that

the

postulated

relay failure scenario

would only trip one diesel

generator

and that therefore,

the ability

of some

systems

to fulfill their safety functions

was indeterminate

during certain

plant

accident

conditions

and

should

have

been

reported in accordance

with 10 CFR 50.73.

The letter also noted that TVA's commitment to install

an additional

lockout relay prior to restart of Unit 2 as stated

in the voluntary

LER (89-09) that

was

submitted after the

30 day requirement,

was

adequate

corrective action for the conditions described

in LER 89-09.

The

inspector

confirmed

in the field that installation of the

additional

lockout relay is complete

and is being tracked

by Design

Change

Notice

DCN 8W6909A.

Post modification testing

remains

to be

done prior to final package

closeout.

4

,

33

Regarding

example

b'3,

the licensee's

September

21,

1989

response

stat'ed

that although

TVA initially identified potential

equipment

area

cooler air flow problems

on

May 25,

1989,

no

LER was submitted

within thirty days

of

May

25

because

at that

time

TYA had

not

determined, that

a

strong possibility existed

that the plant

had

previously operated at power with the degraded

flow rates.

As TVA's investigation continued into the possible

causes

of degraded

flow, they discovered

on July

12,

1989, that'he grill/registers

mounted at the

end of each

room, cooler duct =were partially closed,

restricting air flow.

Sine'e

as their condition indicated

a long term

degradation,

TVA then

concluded

that this condition

could

have

existed

during operation

and it was

then that

the

10 CFR 50.73

reportabi lity aspect

was= formally recognized.

LER 50-259/89018

was

later submitted

on August ll, 1989.

In this

LER the root cause

of the

problem

was attributed to the

inexistence of a procedure/program

to periodically measure

flow rates

through

room coolers.

As

a result of the lack of a procedure

and the

attendant

lack of historical

data,

the licensee

had

been

unable to

readily determine if the air flow had deteriorated

over time or if

there

had

been

a step

change

in air flow.

The inspector

confirmed that

Technical

Instruction TI-134,

"Core

Spray

and Residual

Heat

Removal

Room Coolers Air Flow Verification"

was

developed

and

issued for Units

1 and

3 on November

21

1989

and

for Unit 2 on August 24 1989.

Of the three

examples

cited in the original violation, examples

hl

and

b'2 had

been

the subject of an initial 10 CFR 50.72 report

on the

part of the licensee.

The licensee's

subsequent

reviews would result

in their judgement

that the conditions

were

not reportable

under

In their response

to the violation,

TVA made

a commitment to advise

the

NRC by letter within 30 days in cases

where

a four hour report

will not require

a

10 CFR 50.73 report.

Based

on the

above

discussion,

the inspector

determined

that the

concerns

associated

with the referenced violation, as modified by the

NRC

Region II November

16,

1989 letter,

have

been

adequately

addressed.

(CLOSEO) Violation 259,

260, 296/90-14-05,

Failure to Implement. the

Independent Verification Requirements

for a Temporary Alteration.

During

the

review of activities

performed

under

WO 90-02259,

associated

with the determination

and retermination

of cables

in

conduit 3ES-1676-IB,

discrepancies

in the documentation

of the work

activities were identified by the inspector

independent verification

of the wire lifting activities

as required

by STD-10. 1.5s,

"Control

34

of Temporary Alterations"

and

PMI 8.1,

"Temporary Alteration," had

not

been

performed

before

conducting

high potential testing of low

voltage cable in accordance

with special test ST-90-01.

TVA Standard

STD-10.1.53

and PMI-8.1 require independent verification

for both lifting and relanding of electrical wires.

Both of these

documents

include wire lifts as

an example of a temporary alteration.

In their July

13,

1990,

response,

the

licensee

attributed

the

violation to personnel

error for failing 'to follow procedures.

Also,

the format of the data

sheets

being utilized for the -"determinating".

activities is listed in their response

as

a contributing factor in

that the test of the procedure

requires

two signatures,

yet the data

sheets

only provide one block for both signatures.

The inspector

reviewed

the following documents

and records

provided

by the licensee

to support completed corrective actions

in this area:

(1)

MIA-1.3, "General

Requirements

for Modifications" (Rev. 3)

(a)

Definitions

have

been

incorporated

in Section

4 of the

procedure

to address

First Party Verification, Second Party

Verification, and Independent Verification.

(b)

Duties

and responsibilities

in the area of "verification"

have

been

incorporated

in Section

5 of the procedure for

craftsmen,

foremen,

"and responsible

engineers"

(c)

Attachment

B to

the

procedure

has

been

modified

to

encompass

guidance

on independent verification requirements

associated

with the data sheet.

(2)

MIA-3.3, "Cable Terminating

and Splicing for Cables

Rated

up to

15,000 Volts" (Rev. 9)

The "Cable/Mire Life and Reland

Data Sheet"

was revised in Rev.

8 of this procedure

to add

a block for independent verification,

initialing, and dating.

Also,

an asterisk

was

added to the data

sheet

denoting,

"Independent

Verification (IV) required for

SDSP-3. 15".

(3)

Training

on Independent

Verification and the changes

to MAI 1.3

and 3.3 for individuals in the modifications organization

who

are designated

to perform IV.

(a)

A lesson

plan titled, "Verifications

Performed

During

Modifications Activities" was

developed

and

presented

to

personnel

performing

IV activities.

Course

attendance

sheets

were

examined

and

a

review

was

conducted

of a

July 17,

1990, scenario

issued

by the Modifications Manager

and containing

a listing of individuals

who

had received.

I

35

the training and

who meet the site criteria for personnel

performing

I.V.

(4)

ASSP-3. 15, "Independent Verification" (Rev 6)

As

a result of the licensee's

independent verification generic

impact evaluation,

Rev.

6 to SDSP-3.15

was issued

September

27,

1990.

This

version

clarified

the

differences

between

"Independent

Verification" and

Second

Party Verification".

A

statement

was

added

to indicate that

an "independent verifier"

was to authorized to make configuration changes.

Also, Standard

STD-10. 1.15,

"Independent

Verification,"

was

added

to

the

.

references, section of SDSP-3. 15.

The inspector

determined

that the concerns

identified in the

above

inspection report item have

been adequately

addressed.

12.

TMI Action Items

(CLOSED)

260/TMI Action Item II.F.1.2.E,

Suppression

Pool

Water

Level

Monitor.

The

NRC approved

TS Amendment

Number, 125 for Unit 2 on August 19,

1986.

This

amendment

included

TS requirements

for the suppression

pool water

level

wide range monitor.

The instruments

are for the

A and

B channel

respectively,

LI-64-159A and

XR-64-159.

The

inspector

reviewed

the

applicable

SIs for calibration

and functional test of the instruments,

2-SI-4.2.F-20(A)

and 2-SI-4.2.F-20(B).

The

instruments

were installed

under

ECN P0323.

The inspector

reviewed the

ECN and the instruments

were

Eg verified on September

21,

1990.

The inspector toured the control

room

and discussed

operation of the jnstruments with the plant operators.

The

instruments

had

been operable

and operations

were knowledgable

about them.

The inspector

noted that the

B channel

recorder

XR-64-199

had

no units

designation

label.

The

A channel

had units of feet.

This was discussed

with Operations

Management.

The review of the TS,

ECN,

and

instruments

found the item acceptable.

13.

Bulletins and Generic Letters

a ~

(CLOSED for Unit 2 Restart

Only)

NRC Bulletin 88-05,

Nonconforming

Materials Supplied

by Piping Supplies,

Inc. At Folsom,

New Jersey

and

West Jersey

Manufacturing

Company at Williamstown,

New Jersey.

This bulletin

was

issued

May 6,

1988,

to require that

licensees

submit

information

regarding

materials

supplied

by the

subject

companies

and

to request

the

licensee

1)

assure

that materials

comply with

ASME Code

and design specification

requirements

or are

suitable for their intended service,

or 2) replace

such materials.

36

Supplement

1 to the bulletin was

issued

on

. June

15,

1988,

to

1) provide. additional information concerning material

supplied

by the

subject

companies,

2)

reduce

the

scope of the requested

materials

review to only flanges

and fittings, 3) delineate

actions

licensees

are

requested

to take to identify these materials

and to determine

whether

the materials

comply with ASME 'and

ASTM design

and material

specifications,

and

4) clarify what actions

licensees

are

requested

to take

once

they identify material

that

does

not compl'y with the

above material specifications.

Supplement

2 to the bulletin

was

issued

on August 3,

1988,

to

1) modify, the

schedule

for actions

addressees

were

requested

to

perform in the original bulletin and

supplement

1,

and

2), provide

additional

information concerning

materials

supplied

by the subject

companies

and

an

affiliated

company,

Chews

Landing

Metal

Manufacturers

Incorporated

(CLM).

Supplement

2 temporarily suspended

most of the activities'nd

reporting

requirements

requested

by the

original bulletin and supplement

1.

The remaining actions

requested

from full power licensees

by supplement

2 were:

(1)

Maintain documentation

of the specific actions

taken for the

identified materials.

(2)

Retain nonconforming materials until advised further

by the

NRC.

(3)

Report the results of tests of PSI

and

WJM flanges

and fittings

to the

INPO Nuclear Network for dissemination

to the industry.

The licensee

responded

to the bulletin and both supplements

by letter

on August 26,

1988.

The response

provided the information requested

by supplement

2

and

stated

that

TVA had

suspended

work

on the

bulletin.

The

TYA program

and status

given in the response

was

as

follows:

TYA transmitted letters

to 22 intermediate

suppliers

requesting

information

on

WJM or PSI material

supplied to TVA.

TVA had

received

nine responses

from those supplier stating that

no

WJM

or PSI material

had

been furnished to TVA nuclear plants.

Hub, Inc.,

and

Consolidated

Power

Supply

are

intermediate

suppliers

that

had

provided

WJM or

PSI material

to

BFNP.

Specific information necessary

to locate material at

BFNP was

being obtained.

A plan

was

developed

to systematically locate installed

WJM and

PSI materials,

and test

instructions

were written to test

suspect material

once it is located.

A search

of TVA purchasing

records

revealed

that

no direct

TVA

contracts

existed with either

WJM or PSI.

37

Through the

use of Nuclear Network,

TVA is maintaining contact

with other utilities to locate,

test,

and qualify suspect

material.

TVA participated

in the

NUMARC effort to

bound

the

issue,

develop

a

data

base

from results of industry test data,

and

establish

methods

to qualify in-place material.

Based

on the suspension

of the bulletin's efforts by Supplement

2 and

the licensee's

response,

this bulletin is resolved for Unit 2 restart

only.

Further followup or closure of this bulletin will be addressed

once the

NRC has

determined

the extent of further actions

and issued

further guidance.

(CLOSED) Units

2 and

3 TI 2515/96,

Drywell Vacuum Breaker Modifica-

tions,

MPA Item D-20 (Generic Letter 83-08).

This item was modification of vacuum breakers

on Mark I containments

(Generic Letter 83-08).

In December

1979,

GE issued

SIL No.

321

informing customers

of unanticipated

cycling and

damage

to drywell

vacuum breakers

during

LOCA tests

in a prototype

Mark I containment.

To

assure

that

drywell

vacuum

breakers

would

be

capable

of

withstanding

chugging

and

condensation

oscillation

loads;

Generic Letter 83-08 requested

licensees

of Mark I containments

to perform

plant-unique calculations

to determine

the structural

adequacy of the

drywell vacuum breakers.

The

NRC in

a letter to TVA dated

November

25,

1986 issued

a safety

evaluation

report accepting

TVA's proposed modifications.

In TVA's

letter of January

29,

1987,

the progress

on the modifications

were

given as follows:

Unit

1 - No work started

Unit 2 - Complete

Unit 3 - Complete

The inspector

reviewed

ECN P0684

and workplans

2114-85 (Unit 2)

and

13130 (Unit 3).

It was found that the hinge arm, the hinge pin, and

the

hinge

arm to pallet bolts

could

become

overstressed.

The

licensee

decided to remedy the situation

by using different materials

for these

parts to increase

their allowable stress limits.

By using

316 stainless

steel for the hinge arms,

303 stainless

steel for the

hinge'ins

and

A193

GR

B6 material for hinge

arm to pallet bolts,

proper safety margins were thus restored.

The inspector

reviewed

WP 2114-84 in the

permanent

record

storage

area

and verified the correct material

was

used.

The material

selection

was verified

by

a

gC holdpoint.

This fulfills the

inspection

requirements

of the TI.

C

38

(CLOSED Unit

2 Only) TI 2500/020,

Revision

2, Inspection

to Determine

Compliance with ATWS Rule,

10 CFR 50.62, Unit 2.

This

item

had

been

reviewed

during

an earlier

inspectio'n

IR 259,

260,

296/89-17,

when

the inspector

determined

that the

ongoing modification

work was not yet complete.

The

inspectors

reviewed

engineering

design

documents

and

inspected

the

installed modifications

associated

with Unit 2

ATWS mitigating systems.

The licensee

modified the existing

SLCS and

RPT systems

and

added the ARI

system.

In addition,

the licensees

ATWS programs

were reviewed to assess

the implementation of training, plant procedures,

and the effectiveness

of

quality "controls

used

during design,

installation

and testing of ATWS

systems.'.

Standby Liquid Control

System

The

SLCS

was modified to allow for the

use of Boron-10 enriched

sodium

pentaborate.

This

option meets'0

CFR

50.'62

(C)(4)

requirements

for the

SLCS

and

was

approved

by the

NRC in safety

evaluation report dated

September

2,

1988.

TS amendments

154,

150,

and

125 concerning

these matters

have

been

issued for Units 1, 2, and

3 respectively.

The inspectors verified that surveillance

procedures

have

been

approved

and

issued

to implement the

new

TS surveillance

requirements.,

A review of Unit

2

completed

surveillance,

data

indicated satisfactory

results.

The trending of chemistry analysis

for

Boron-10

enrichment

showed

stable

chemistry

conditions.

Chemistry personnel

handle

boron addition and analysis.

The licensee

has

procedures

which establishes

.guidel,ines

for the

procurement,

receipt

inspection

and

sampling

the

drums

of enriched

sodium

pentaborate.

The

inspectors

noted

that

the

enriched"

sodium

pentaborate

drums

are

kept in segregated

storage

in a warehouse

at

the site.

b.

Alternate

Rod Injection System

The licensee

ATWS design

associated

with the ARI system

and

RPT were

submitted to

NRR in TVA letters

dated

March 1, July 15,

and August 4,

1988.

NRC safety evaluation report dated

January

22,

1989 approved

the plant specific design for Browns Ferry Units 1, 2, and 3.

The

purpose

of the

ARI system

is to initiate

a reactor

scram

independent

of the

RPS.

The protective

action

can

be initiated

manually using switches

from the main control

room, or automatically

when inputs of low reactor

vessel

water level or high reactor vessel

pressure

(two out of

two logic) trip setpoints

are

reached.

Following an

ARI initiation signal,

the control air supply to the

HCUs is blocked

by energizing

a 3-way valve

and depressurizing

the

air lines to the individual

scram

valve

by energizing

two-way ARI

39

vent valves.

Opening

the individual scram valves results in control

rods

being inserted.

Once the ARI system is initiated it can not be

immediately reset

because

of a

30 second

time delay.

This ensures

that protective action

goes

to completion..

The ARI system

redundant

two out of two trip logic combined with placing the bypass

switch in

test'osition

allows for maintenance,

testing,

and calibration during

power operation.

Surveillance

instructions

2-SI-4.2.B-ATU (A), (B),

(C), and (D)'are in place to conduct monthly functional test of each

ARI/RPT channel initiating logic.

Alarm and annunciator

windows are

provided to indicate

when

ATWS system is being tested

or when

an

ATWS

has

been initiated.

The

inspectors

identified that

ARI

system

valves

(8)

are

not

scheduled

to

be functionally tested

following the post modification

testing

(PMT-184).

Following discussion of this matter the licensee

initiated

a

change

to incorporate

a functional test of ARI system

valves

in 2-SI-4. 1.A. 1.

The test

is to

be

conducted

during

refueling outages.

The inspectors

informed licensee

management

that

the testing

should

be initiated

though

the

SRI system

logic with

requirements

to verify that all ARI system

valves

go to their

ATWS

positions.

The

ARI system

is required

to start

rod

inward motion wi'thin 15

seconds

of initiation and

be completed within 25 seconds

from ARI

initiation.

Test

data

taken

during

Post Modification Test

184

indicated

that

approximate

by

14 control

rods

exceeded

the

rod

injection motion start time of 15 seconds

(ie 15.2 to 18.0 seconds).

Rod injection completion

times

met the

acceptance

criteria of 25

seconds.

The

licensee

performed

plant specific

analysis

and

justification review using

GE documents

and

changed

the rod motion

start

time acceptance

criteria to

19 seconds.

Although these

time

extensions

were

not

reviewed

in the

SER,

similar reviews

and

approvals

have

been

made

by

NRR for other

BWRs.

Based

on the review

of

completed

PMT-184

test

results,

licensee's

analysis

and

discussions

with NRR, the inspectors

determined that the

ARI system

function times are acceptable.

To comply with the

ATWS rule, the ARI/RPT system is required to have

components

diverse

from those of the

RPS.

Presently,

the diversity

between

the

ARI/RPT system

and the

RPS is not acceptable

as

both

systems utilize Rosemont

ATUs.

This concern

was identified in the

SER.

The licensee

had taken

the

BWROG

s position

on diversity, ie,

waiting on appeal

of NRC's position.

The staff recently replied to

the owner's

group

and denied

the appeal.

The licensee

informed the

inspectors

that their current

schedule

provides for replacement of

the

ARI/RPT system

ATUs with

GE models

during cycle

6 refueling

outage.

The licensee

stated

that

a letter concerning

the schedule

for GE Model installation would be sent to the

NRC.

The inspectors

discussed

this

issue with

NRR personnel

and determined that it was

not

a restart

issue.

This will be tracked

as

IFI 260/90-33-06,

RPS/ARI Diversity.

Additionally 259, 260, 296/89-17-05 is closed.

40

co

d.

Recirculation

Pump Trip System

The

RPT system

implemented at Browns Ferry is similar to, that used at

the Monticello.

The

RPT initiates from the

same

two out of two logic

as the'RI

system.

A spare trip coil in the "End-of Cycle

RPT

Breakers" is used

and

a trip signal will open

one of the two ATWS/RTP

breakers

in series

for

each

recirculation

pump.

Surveillance

instructions

are

in place

to perform monthly test

on the

ARI/RPT

channel

logic 2-SI-4.2.B-ATU (A), (B), (C),

and

(D) and

a once

per

cycle test of the channel

logic including the tripping of the

RPT end

of cycle breakers

(2-SI-4.2-B-71).

Generic Letter 85-06 provided guidance

concerning

(}A requirements

to

be

used during the implementation of the

ATWS 'rule.

The inspectors

reviewed

gA records

(gA audits,

inspection

reports,

work plan hold

points,

procurement

records,

and

acceptance

test results)

which

indicated that gA/gC was active in all the proces'ses

for implementing

the

ATWS rule.

In addition, the inspectors verified that an on-going

program is in place

(NIZAM, Part I, Section

1.3) which identifies

those

management

controls for maintaining the

ATWS equipment.

The

inspectors

reviewed

changes

to Unit

2 operating,

emergency,

abnormal

operating,

and

annunciator

procedures

and verified that

actions

required

to initiate

and restore

ATWS systems

have

been

incorporated.

The

review of lesson

plans,

written

exams,

and

attendance

records

in the

area of

ATWS modifications

and plant

procedures

indicates

that training for plant operators

has

been

provided.

Simulator training has also

been provided.

Based

on the

above

reviews,

the inspectors

determined that the licensee

has

adequately

met the requirements

for the

ATWS rule for Unit 2. except

for the unresolved diversity issue which is not a restart issue.

15.

Restart

Assessments

a ~

b.

Senior Management

Assessment

for Restart

Team Meeting

The

inspector

attended

a

portion

of

a

SMART

meeting

on

November 3,

1990.

The last meeting of SMART was held on August 14,

1990.

The meeting

was attended

by four Vice-Presidents

of TVA and

other

TVA managers.

The meeting

was

conducted

according

to the

agenda

and

using

the

SMART notebooks.

Detailed charts

of

CARR

trends,

WO trends,

etc.,

were

used

during the meeting to gain

an

overall perspective of the plant recovery status.

Licensee

Operational

Readiness

Review Program

(93806)

The

inspector

held

discussions

with licensee

personnel

for the

purpose

of determining

the

status

of the licensee's

Operational

Readiness

Review Program.

r'

C

41

The inspector

was

informed by the licensee

that

Browns Ferry has

an

ongoing

Operational

Readiness

Review

Program

which is intended

to

provide a,review of the state of readiness

by an independent

group of

personnel

with a broad

base of management,

operating,

and technical

experience.

TVA's stated

objective which was provided to the

ORR

team was to review the qualification and motivation of site personnel

and availability of necessary

supporting

resources

for safe

and

reliable testing,

operation

and maintenance

of the unit.

The review

was initially intended

to

be provided

as

a two phase

look with the

first phase

conducted

during May - June,

1989

and the second

phase

in

March 1990.

The

Phase

1 report

was

issued

in June

1989.

Various concerns

were

identified as follows:

Operations

Conduct of operations

not at desired

standards.

Division of responsibilities

in control

room not well defined.

Sensitivity of reactor safety factors not at desired levels.

Actions to

improve supervision

of non-licensed

operators

not

effectively addressed.

Walkdowns

by managers

not effective.

Administrative, operating,

and work procedures

deficient.

Maintenance

Work packages

need

adequate

work instructions for personnel.

Post maintenance

testing

problems.

Management

involvement required to address

PM backlog.

Vendor technical

recommendations

not timely.

Chemistry

PASS procedures,

training,

and lab techniques

need

improvement.

Other

Emergency

preparedness

exercise

lacked

high

standard

of

performance.

Nuclear experience

reviews

and lessons

learned

lack attention.

~ >.

'PA

42

These

concerns

were

reviewed

by

TVA management

personnel

with

a

formal

response

to 0.

D. Kingsley documented

in Vice President,

Nuclear

Power

Production

Memorandum

dated

October

30,

1989.

This

response

outlined the licensee's

corrective action plan in each

area

and

a schedule for improvement.

The Phase

2 review was completed in March 1990.

This second

team was

given similar guidance

to that provided to the first ORR team.

The

purpose

was

to provide

an additional

independent

assessment

of

readiness

and review the status of corrective actions

associated

with

concerns

identified during the

Phase

1 review.

Although the

team

concluded that it was safe to restart

the unit and that various areas

of improvement were noted there

were inconsistencies

in achieving the

standards

of performance

expected

by senior

management

indicating

that corrective actions

associated

with the

Phase

1 review had

been

less

than fully effective.

Additional'concerns identified included:

guality of procedures

lacking.

Maintenance

planning

and

PMs still need attention.

Training effectiveness

affected

by poor communications.

These

new concerns

were reviewed

by TVA management

personnel

with a

formal

response

to the staff documented

in licensee

submittal

dated

October

24,

1990.

This

response

outlined

the

status

of the

licensee's

corrective actions for each of these

concerns

and provided

a schedule for completion.

The licensee

has identified 47 specific

concerns

with

480

items

which

must

be

closed

associated

with in this

area.

The

licensee

has

established

a

tracking

program

and

assigned

a manager

to follow the progress

of

status

of corrective actions for these

issues.

A biweekly status

.

report is issued.

As of October 31,

1990, the licensee

had completed

closure of 70/ of the concerns

and

93K of the action items.

The licensee

plans to conduct

a Phase

3 review of operations

and work

control.

This final licensee

readiness

review will be

a short

limited review

and is scheduled

to be conducted after Unit 2 core

reload.

Additionally this review is not intended to be

a followup on concerns

identified as part of the

Phase

2 review since that followup is being

performed independently

by NMRG.

The

inspectors will review the licensee's

corrective

actions for

adequacy

for selected

items

identified

during

the

licensee's

Operational

Readiness

Review

Program

during

the

next reporting

period.

~ ~ s

l$

43

16.

QA Activities (35701)

a.

Management

Review Committee

'n inspector attended

portions of a scheduled

meeting of the

MRC held

on November 9,

1990.

The

MRC is intended to provide the proper level

of management

review neccessary

to assign

the correct

the

proper

safety

significance

level

to

any

licensee

identified potential

conditions

adverse

to quality.

During the

meeting

several

new

potential,

CAQRs/PRDs

were discussed.

In each

case

the

items

were

properly classified

as

a

CAQR or

PRD, inactivated

(one Unit 3 item

was placed

on an inactive list i.e. deferred),

or held over until the

next scheduled

meeting for further discussion.

The inspector

noted

an

improvement

in the sensitivity to potential significant issues

compared to the last meeting attended.

The inspector

determined that

the proper safety significance

was assigned

to each item reviewed

by

the committee

and did not disagree with any committee decisions that

occurred during the period that the inspector

was present.

b.

Corrective Action Program

The

inspector

reviewed

the

status

of the

licensee's

program

to

identify potential

adverse

trends

in the corrective action program.

The inspector

determined

that

the licensee

has

continued

to make

progress

in the area'f

reducing

the

number of outstanding

items

tracked

on TROI.

Although this effort is receiving positive results

the

inspector

noted

various

potential

concerns

which

may require

additional attention.

Although the

number of outstanding

items

on TROI has

continued

to increase

a recent

trend

has

indicated that the

combined

number of CAQRs,

PRDs,

and

COTS related

items increased.

Although the

inspectors

had previously identified

an

adverse

trend involving an excessive

number of bypassed

or missed

QC

holdpoints

which resulted

in a recent violation as discribed in

IR 259,

260,

296/90-27,

the inspector

noted that

two recent

CAQRs

have

been

issued

which identify further problems'n this

area.

CAQR

BFP900364

was

identifed

by the Site Quality

Organization

where holdpoints

were

bypassed

during Appendix

R

and cable" tray penetration

work.

CAQR BFP900368

was identifed

by the Site Quality Organization

where holdpoints were bypassed

during

welding activities

on safety-related

piping.

These

constitute

additional

examples

of Violation

259,

260,

296/90-27-03.

The

number of delinquent

CAQRs

has

shown

a slow but gradual

increase

since

May

1990,

an indicator

which should

be of

particular

concern.

The Quality Tracking

and

Improvement-

Level II Trend Report dated October 1,

1990, identified that the

number of CAQRs deliniqunt at the end of the month

had increased

from 33 to 51.'f 69 outstanding significant

CAQRs open

17 were

delinquent.

C

~)s

r

44

During

the

recent

gA audit

on correction

of deficiencies

(BFA90021) Site guality Organization

personnel

identified two

examples

where

CA(Rs received

improper closure.

The two CAgRs

were closed

on Sept.

30,

1990,

by Site equality

Management after

being rejected

by the Site guality Monitoring section

on the

preceding'ay.

Field work was

not complete

at the time of

closure

and

the

CAgRs were not redispositioned

to reflect the

revised

basis for closure.

One of the

CAgRs was closed

without'vidence

being in the

CA(R package

that all corrective actions

were

complete.

This

failure

was

identified

in

PRO

BFA900336021P.

Although the inspectors

previously identified a problem with the

control of work activities

which resulted

in

a violation as

documented

in IR 90-29,

two new examples

have

been identified by

the licensee.

The violation dealt with the licensee's

failure

to adequately

control

work activities

by site maintenance

and

modifications

personnel

in that work was not performed

on plant

equipment within properly defined

clearance

boundries.

Since

that time the licensee identified that work was performed

on the

Unit 2 "B" CS

Room Cooler and the Unit 3 Dilution Air Discharge

Damper Actuator without an approved clearance.

The licensee

has

initiated

incident

investigations

for both of these

recent

event's

which the inspector will review with licensee

personnel

when

complete.

Both of these

events will be

included

as

additional

examples of Violation 260/90-29-01.

Although these

conditions

were discovered

by the licensee

and the

prematurely closed

CAgRs were reopened

and properly dispositioned

the

inspectors

consider all of the above

as

an indicator of a potential

problem with the implementation of the licensee's

corrective action

program.

Furthermore

the staff considers

any examples of premature

closure

of conditions

adverse

to quality or missed/bypassed

gC

holdpoints

as unacceptable.

17.

Exit Interview (30703)

The inspection

scope

and findings were

summarized

on

November

16,

1990

with those

persons

indicated

in paragraph

1

above.

The

inspectors

described

the areas'nspected

and

discussed

in detail

the inspection

findings listed 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.

For

URI 260/89-16-07,

Need to Peform

ASME Section

XI Inspection of Valve

Operator

Supports,

TYA committed

to perform

a .review of drawings

to

identify supports

in question

and to do the following:

c

~>)

r

1)

Add the supports

to the Unit 2 Section

XI program

2)

Perform the baseline

inspection prior to Unit 2 restart

3)

Review the other units

and place

the required

supports

into their

respective

programs prior to Unit 1 or. Unit 3 restart.

Item Number

259,

260, 296/90-33-01

260/90-33-02

259,

260, 296/90-33-03

259, 260, 296/90-33-04

260/90-33-05

259,

260, 296/90-33-06

Descri tion and Reference

VIO, Failure to Make

10 CFR 50.72

and 50.73

Reports,

paragraph

5.

URI, Failure to Maintain Configuration

Control

on

Core

Spray

System After System

SPOC,

paragraph

5.

URI, Failure to Control Design in Allowing

Unqualified Cable Installation,

paragraph

6.

IFI, Hardware Activities Delayed But Not

Approved by Senior Management,

paragraph

8.

IFI,

QA Control Process

Related to

Calculation,

paragraph,

11.

IFI, RPS/ARI Diversity, paragraph

14.

Licensee

management

was

informed that

5 LERs,

5 IFIs,

2 URIs,

5 VIOs, and

1 TMI Item were closed.

AOI

ATU

BFEP

BFNP

CAQR

CFR

COTS

DCN

FDCN

Abnormal Operating Instruction

Alternate

Rod Injection

American Society of Mechanical

Engineers

Analog Trip Units

Anticipated Tranisent Without Scram

Browns Ferry Engineering Project,

Browns Ferry Nuclear Power Plant

Condition Adverse to Quality Report

Code of Federal

Regulations

Corrected

on the Spot

Core Spray

Design

Change Notice

Design

Change

Request

Diesel

Generator

Emergency

Core Cooling Systems

Engineering

Change Notice

Emergency

Equipment Cooling Water

Environmental Qualification

Engineered

Safety Feature

Field Design

Change Notice

Final Safety Analysis Report

(tl

'4

GE

GL

GPM

HCU