ML18033B516

and

replacement

of the

two Squib

valves.

Delays

resulted

from equipment

problems

and

a

needed

revision to clarify several

steps

and correct several

administrative

errors within the procedure.

A thorough pre-evolution briefing was

conducted

by the

SOS with all associated

personnel

prior to the

actual

performance

of the SI.

The licensee's

procurement

require-

ments

prevented

the

use of a

new replacement

Squib valve that was

more than

2 years old.

This is

a conservative

requirement

since

TS

only require that replacement

valves

be less

than

5 years old.

The

inspector determined that adequate

controls existed in this area.

One minor deficiency noted

was that during the system

pipe flushing

activities

performed in accordance

with step 7.10.10,

two gallons of

borated

water overflowed from the collection barrel

onto the floor.

The inspector

noted that the plastic barrels

being

used for this

purpose

were different from the older metal barrels

used previously

during flushing.

The plastic barrels

did not have the full diameter

lids which could be removed allowing unobstructed

view of the barrel

contents.

Although

step

7. 10. 10

states

that

30

gallons

of

demineralized

water are to be flushed into the barrel

to remove the

borated

water present

in the piping, the operator

had to view the

barrel level through

a small opening in the barrel.

This contributed

to the water spill.

The inspector

noted that the floor was not

contaminated

by the

minor spill,

and that the

excess

water

was

immediately

mopped

up by the

ASOS at the scene.

The inspector

noted

that the floor drain located only a few feet from the barrel station

had

been

taped

over immediately prior to the event

as

a precaution

against

borated water entry into the. radwaste floor drain system.

An inspector

observed

the

performance

of 2-SI-4.4.A.2

conducted

on

August 6,

1990 to resolve

a test deficiency from the performance

on

August 3.

During the previous

performance,

the

SLC flow "red" light

failed to illuminate

and

the

"SLC injection flow to reactor"

annunciator

(2-XA-55-5B, window 14) failed to alarm.

The licensee

determined

that flow switch

2-FIS-63-11

was

out of calibration,

causing

the deficiencies.

The flow switch

was recalibrated

and the

SI

reperformed.

No deficiencies

were identified

and

both flow

indicators operated properly.

One violation was identified in the area of Surveillance Observation.

3.

Maintenance

Observation

(62703)

Plant

maintenance

activities

were

observed

and

reviewed for selected

safety-related

systems

and

components

to ascertain

that

they

were

conducted

in accordance

with requirements.

The following items

were

considered

during

these

reviews:

LCOs

were

met, activities

were

accomplished

using

approved

procedures,

functional

testing

and/or

calibrations

were

performed prior to returning

components

or systems

to

service,

gC

records

were maintained,

activities

were

accomplished

by

qualified personnel,

parts

and materials

used

were properly certified,

proper

tagout

clearance

procedures

were

followed,

and

radiological

controls were implemented

as required.

Work documentation

(MR,

WR and

WO) were reviewed to determine

the status

of outstanding

jobs

and to assure

that priority was assigned

to safety-

maintenance

which might affect plant safety.

The

inspectors

observed

the following maintenance

activities

during this

reporting period:

The inspector

reviewed

and

observed

the licensee's

activities

involved

with

performing

procedure

EPI-O-OOO-BKR001,

Electrical

Preventive

Instruction

Maintenance

of Molded

Case

Breakers,

on electrical

breaker

309, located

on Unit 2 control

room panel 2-9-9.

The specific observation

involved the testing

of the

thermal

overloads

of the

breaker

which

supplies

relay and instrument

power to

SBGT system Train C.

Breaker

309

was

a

GE Circuit Breaker

Model

THED, with a

15 to 50 ampere rating.

The

work was authorized

by

WO 90-00387-00

and was performed in accordance

with

the procedure.

The inspector

noted that the hold order, referred to as

a clearance,

was

initiated

by the

work order .

During the review of this activity the

'icensee

could not readily determine

which clearance

this activity was

performed

under.

The current

system

being

used

can indicate which items

were

worked under

a particular clearance

number.

However, if only the

activity, such

as

a

PM or WO, is known the licensee

does not have

a system

that will indicate in a timely manner which clearance

was given to perform

the activity.

The current system is

a manual

system

which makes it very

difficult to tie the activity'o the clearance if the clearance

number is

not

known.

The

licensee

is

implementing

a

computerized

system

to

alleviate

this

problem.

This

item is identified

as

IFI 259,

260,

296/90-25-03,

Documenting'nd

Controlling

Clearances

for Multiple

Activities and will remain

open

pending

a review of .the licensee's

new

system.

No violations or deviations

were documented

in the Maintenance

Observation

area.

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

of operating

systems,

status

and alignments of emergency

standby

systems,

verification of onsite

and offsite

power supplies,

emergency

power sources

available for automatic operation,

the pur pose of temporary

tags

on

equipment

controls

and

switches,

annunciator

alarm status,

adherence

to

procedures,

adherence

to

LCOs,

nuclear

instruments

operability,

temporary alterations

in effect, daily journals

and logs,

stack monitor recorder traces,

and control

room manning.

This inspection

activity also

included

numerous

informal discussions

with operators

and

supervisors.

General

plant tours

were conducted.

Portions of the turbine buildings,

each reactor building, and general

plant areas

were visited.

Observations

included

valve

position

and

system

alignment,

snubber

and

hanger

conditions,

instrument

readings,

housekeeping,

power supply

and breaker

alignments,

radiation

and

contaminated

area

controls,

tag controls

on

equipment,

work activities

in progress,

and

radiological

protection

controls.

Informal discussions

were held with selected

plant personnel

in

their functional areas

during these tours.

The following items were noted

during the observations:

a.

Equipment Clearance

Equipment

clearance

2-89-987

concerning

the

HPCI suppression

pool,

CST suction

valves,

and

steam

supply valves

was verified

by

an

inspector.

No problems

were identified.

b.

Water in Diesel

Generator Building

During

a routine tour of the

DGs buildings

on July 23,

1990,

the

inspector

found the Unit-1/2

DGs

(B and

C),

1C batteries,

and the

120V logic panels

were wet and receiving

a large

downpour of water

from the roof area.

Water

from

a rain

storm

was

entering

the

building through

holes

bored in the roof that

had not been

sealed.

Immediate action

was taken

by plant operators

to seal

two 6" x 6"

holes

in the roof and stop the leak.

Partially plugged roof drains

contributed

to the leak.

This event resulted

in the

1C

DG being

declared

and "tagged-out" until the batteries

and logic

panels

were dried and the equipment verified to be operable.

Discussions

with the operating

personnel

revealed that this problem

had previously occurred

on July

11,

1990

when similar conditions

existed.

The inspectors

reviewed Modifications work plan WP2396-90 which was

the implementing

document to install conduits through the roof of the

DG building.

During this review, the inspector

noted

hand written

work instructions

in the

work

package

that required

water tight

covers

be

placed

over

open

penetrations

prior to grouting.

This

requirement

was to exist until the conduit was installed

and grouted.

This step

had

been

signed

by the craftsmen

and dated July 12,

1990,

certifying that the

requirement

had

been

complied with.

This is

identified

as

a violation of procedures

(YIO 259,

260/90-25-04,

Failure

To Protect

Emergency

Equipment).

One violation was identified in the Operational

Safety Verification area.

5.

Field Activities (37700,

37828)

The inspectors

maintained

cognizance

of field activities to support the

restart of Unit 2.

This included reviews of scheduling

and work control,

routine meetings,

and observations

of field activities.

a.

Fuse

Program

The licensee identified

a significant problem involving the type and

size of fuses installed throughout the plant.

Three

DCNs were issued

to correct

the deficiencies.

The original

scope

of

DCNs

W1569,

0

W1847,

and W2033, affected over 50 plant systems.

At the end of

this'eporting

period all

three

DCNs

were still

open

and

each

DCN

generated

numerous

FDCNs

as follows:

DCN W1569 generated

25

FDCNs

DCN 1847 generated

16

FDCNs

DCN 2033 generated

30

FDCNs

'Although

the

above

fuse

issues

can

be

adequately

resolved

under

blanket

SPOC deferrals,

a potential

problem exists

in that broad

usage of blanket deferrals

could take place.

During discussions

with

Licensee

Nanagement

personnel,

the inspectors

were told that

Browns

Ferry would not routinely use blanket deferrals and'hat

the fuse

program would be resolved prior to fuel load.

Security

(81052)

The inspector

and the security manager

toured portions of the revised

and

updated security

systems

being

implemented at the

BFN facility.

These

included

a

new access

portal

which consisted

of an

improved

detection

system

and

a "Sally Port" for controlled vehicle search,

and

new security fence that

had

been installed to decrease

the size

of protected

area at the

Browns Ferry Facility.

Portions of the

new

fence

are to

be relocated

in the future

because

stored

equipment

prevented

the fence

from being positioned at its permanent location.

Compensatory

measures,

which included security personnel

monitoring

portions of the

fence that

were not monitored

by other

detection

devices,

had been

implemented.

Restart Test Program

(37701)

The inspector

reviewed the licensee activities associated

with TE-ll

to

the

test

results

of procedure

2-BFN-RTP-065,

Standby

Gas

Treatment.

The licensee

issued

DCN-W 11053A which superseded

ECN

E-0-P7217

to address

this TE.

The

DCN which is considered

a major

modification, issued

numerous

DCAs such

as

W11053-070 thru 073.

The

DCAs in turn resulted. in the writing of approximately

20

WPs which

implemented

the

OCAs.

The

WPs

included

such activities

as

WPs

0465-90,

0466-90, Install conduit and junction boxes in the Control

Bay,

DG Building and Reactor Building; WPs 0471-90,

0472-90, Install

and

delete

duct

supports

in the off-gas stack;

and

WP 0473-90,

Install

dampers

and blank off plates in the off-gas stack duct work.

The inspector

observed

the licensee

work activities involved in the

DCAs mentioned

above.

All activities were controlled

and performed

according to procedures

and were adequately

monitored.

Cable Separation

(37701)

The inspector

reviewed the licensee activities associated

with cable

separation.

CARR

BFP

870860 identified

a

number of non-safety

related cables

which had

been

routed

such that they mixed with both

I

redundant

class

1E divisions.

DCN W5236A was issued

to address

this

item.

Exception to the separation

requirements

was permitted if non-safety

related circuits

were

provided with

a

double

means

of class

lE

isolation.

The double isolation may be provided by the addition of a

class

lE qualified protective

device

in series

with the existing

class

1E device located in a class

1E qualified enclosure.

This

DCN

provides for double isolation

by the addition of fuses in series with

their existing breakers.

The specific work activities

observed

involved the installation of

fuses for breakers

205 and

220 in control

room panel 9-9.

WP 1041-19

implemented

the

DCAs associated

with the

DCN.

The work was being

performed

in accordance

with procedures

MAI-3.3, Cable Terminating

and Splicing for Cables

Rated

up to 15,000 Volts,

and MAI-3.8,

Installation

of Electrical

Components.

The

work

included

terminations,

inspecting for minimum bend radius,

and

use of proper

tools.

A gC inspector

was present

throughout these activities.

No

deficiencies

were identified.

Within the areas

reviewed,

no violations or deviations

were identified.

System Status

Control

During this reporting period

an inspector

reviewed the licensee's

process

for maintaining

the

configuration

of systems

after turnover

to the

Operations

group following SPOC completion.

Procedure

PMI-12. 15,

System

Status

Control,

prescribes

the

methods

to

achieve

and

maintain

configuration status

control.

The inspector

reviewed

PMI 12. 15 and held

discussions

with licensee

personnel

responsible

for system

status

and

configuration control.

The process

includes the following controls:

'

System

Status

File which is maintained

in the control

room

and

contains

the current status

checklist for completed

systems

and

any

deviation forms issued for components

in off normal configurations.

A Configuration

Log maintained

in the control

room which indicates

deviations

from, or

changes

to,

a system's

status

contained

the

System Status File.

A Daily Configuration

Log Working Notebook which contains

the changes

to

a systems'tatus

within the last

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

This notebook is

reviewed

by

each

oncoming

operations

shift and its contents

are

transferred

to the Configuration

Log by the midnight shift each day.

Items that are not in their normal alignment but will not impact the

system operability at the

time of checklist

completion,

or the

performance

of other instructions

may be deviated.

Deviation forms

are filed with the completed checklist.

Checklists

having

components

that cannot

be aligned to the

normal

position

because

their configuration affects

the intent of the

instruction

or

system

operability

cannot

be

deviated.

These

checklists

must

be held

open until the

component

can

be aligned in

its normal configuration.

Each status file is required to be reviewed weekly by Operations

and

the review documented

on

a Weekly Review Form.

System

63,

SLC, is the only system

covered

by PNI-12. 15 to complete

the

SPOC process.

The inspector

reviewed the System Status File for System

63

and

noted

no discrepancies.

The inspector

noted that there

were

no

deviations

included in the file.

No violations or deviations

were identified in this area.

7.

System Preoperability Checklist (71707)

The inspector monitored the licensee's

review of 81 systems

per

SDSP 12.7,

System

Pre-Operability

Checklist

(SPOC)

for Unit

2

system

return to

'ervice.

Of the

81

systems

reviewed,

the

licensee

determined

that

55

systems

required

a

SPOC.

SPOC is

a systematic

method for verifying that

all activities that affect

system operability for restart

have

been

evaluated

and dispositioned

in accordance

with approved

plant procedures

to support

a recommendation

for declaring

a system

operable for restart.

The criteria for performing

a

was that the systems

were essential

to

meet

the criteria specified

in Chapter

14 of the

FSAR for plant safe

shutdown

and accident mitigation and to meet

TS requirements.

The licensee

determined that the remaining

26 systems

were to be evaluated

by a System Checklist (SCL).

SCL is

a systematic

method for ensuring that

outstanding

work against

minor plant systems

has

been

reviewed

and that

work required for operation

of those

systems

has

been

evaluated

and

dispositioned to support

system status

and configuration control.

Per the

licensee's

requirements,

the

SCL can only be utilized for systems

that do

not have

TS operability requirements.

As of August 16,

1990,

17 of the 81 systems

had

been returned to service.

The results of the system reviews monitored

by the inspectors

were

documented

as follows:

a ~

Condensate,

Makeup,

and Demin Water Transfer

(System 02)

The inspector

accompanied

licensee

personnel

during selected

portions

of the system

walkdown associated

with System 2.

During the walkdown

the following material deficiencies

were noted:

The heat tracing

and insulation designed

to prevent freezing of

tank level instrumentation

lines associated

with the

and

Demin Water Tanks were in poor condition.

Insulation was either

temporary or damaged,

and the heat tracing cables

were damaged.

The

"B"

Demin

Transfer

Pump

had

excessive

seal

leakoff.

Although both

pump

discharge

lines

are

connected

there

was

significant difference

in the

readings

between

the

two

pump

discharge

pressure

gauges without either

pump operating.

Over half of the flexible electrical

conduit connections

were

not tight.

Rigid conduit at base of the

was missing clamps

and/or appeared

to have improper clamps.

Each of the

has

an approximate

3/8 inch

gap

between

the

tank

bottom

and

the

concrete

pad

supporting

the

tank with

evidence

of large

amounts of rust and/or

moss that completely

encircles

the lower base of the tanks.

Although the outer sides

of the tanks

appear in good condition, moisture is allowed to go

under the tank base.

This problem appears

worse

on

number

4

& 5.

During

the

walkdown

the

inspector

noted

that

the fire

extinguisher

located

in the

480 Volt Water

II Oil Storage

Board

Building had not been

checked

since

February

1990.

Many fire

extinguishers

located

in the turbine building had three sets of

initials since

May 1990 which probably corresponded

to the June,

July and August required

checks.

However, there

were

no dates

in the column

on the tag provided for that purpose.

Several

sections

of heat tracing

were energized

and building

heat in the 480 Volt Water 5 Oil Storage

Board Building appeared

to

be

on with the building outside

door

open

although

the

outside

temperature

was above

80 degrees

during walkdown.

The inspector

was in the process of reviewing the

SPOC package at the

end of this reporting period.

b.

Extraction Steam

(System 05)

The System Checklist

was

completed

on June

29,

1990.

The inspector

reviewed

the

completed

checklist,

and

no

deficiencies

were

identified.

c.

Heater Vents

and Drains

(System 06)

The System Checklist

was

completed

on July 18,

1990.

The inspector

reviewed

the completed checklist with the cognizant

system

engineer

on July 31,

1990,

and

no deficiencies

were identified.

d.

Turbine Ext. Traps

and Drains

(System 07)

The System Checklist

was completed

on June

23,

1990.

The inspector

reviewed

the completed checklist with the cognizant

system engineer

on July 27,

1990,

and

no deficiencies

were identified.

10

Turbine Drains

and Misc Piping (System 08)

The System Checklist

was

completed

on June

23,

1990.

The inspector

reviewed

the completed checklist with the cognizant

system

engineer

on July 27,

1990 and

no deficiencies

were identified.

Auxiliary Boilers (System

12)

The System Checklist

was

completed

on August 5, 1990.

The inspector

will review the completed checklist during

a future reporting period.

Raw Cooling Water (System

24)

The inspector

attended

a meeting

on July 24,

1990,

concerning

modification of the

RCW piping system to the control

and service air

compressors.

The compressors

are often taken out of ser vice because

of high temperature

caused

by MIC buildup in the

RCW system.

The

results of the meeting were that the licensee

is modifying the piping

to the

compressors

and initiating

a

long term study to evaluate

controls for MIC.

This system is forecast for a

SPOC date of September

7,

1990.

The

system will receive further review as part of the system return to

service.

Raw Service

Water (System

25)

The inspector

reviewed the licensee activities involved with the

process for System

25 which was accepted

on August 5,

1990.

System

25

was

given

a full

in the

summer of 1989 for the

Integrated

Cold Functional

RTP.

This

system

was

updated

and

received

a limited

SPAE.

The inspector

accompanied

the

system

engineer,

an operations

representative

and

a

gM inspector

on the

final

walkdown of the

system.

No significant deficiencies

were

identified.

System

25 is shared

by all three units

and is designated'a

Unit 0

system.

One

minor item

was

discussed

with the

licensee

which

involved 3A and

3B Raw Service Water Pumps.

These

pumps are operable

but are not needed

to support Unit 2:operations;

therefore,

they

will be tagged out.

Vacuum Priming (System

34)

This

system

was

turned

over

to Operations

control

and the

System

Checklist was completed

on June

28,

1990.

The inspector

reviewed the

completed checklist with the cognizant

system engineer

on August 7,

1990,

and identified no deficiencies.

Building Heating

(System 44)

The

System Checklist

was

completed

on July 9,

1990.

The inspector

reviewed

the

completed

checklist

with

system

engineers

on

July 10,

1990,

and identified no deficiencies.

Temperature

Monitoring (System

56)

A full SPOC

was

completed for this

system

on August 2,

1990.

The

inspector

reviewed

the completed

package

with the

system engineer.

The

scope

of this

review included

the

temperature

detectors

and

recorders

which comprise

the

Reactor

Pressure

Vessel

Temperature

Monitoring Subsystem.

This system is primarily designed

to monitor

temperature

at various points of the reactor

vessel

in order to map

its temperature

gradient during startup

and shutdown operations.

The

data

is

recorded

to provide

the

basis

to establish

the rate of

heating

or cooling the

vessel

to

keep

the stress

set

up between

sections

of the reactor

vessel

within the allowable limit.

The

locations monitored are the feedwater

nozzles,

the shell at or near

the waterline

and the flange studs.

This

system

had

two primary/critical

drawings.

One

drawing

discrepancy

was evaluated

and dispositioned for a primary/cr iticaI

drawing

and six secondary

drawing discrepancies

were determined

not

to affect plant operability.

The inspector

reviewed the two drawings

in the control

room.

They were found to be legible and were the

same

drawings identified in the

SPOC package.

No CA('s were

issued

against

equipment,

components

or procedures

associated

with the

Temperature

Monitoring system.

The

system

engineer

reviewed

a listing of generic

CAgRs to determine if any were

applicable to this system.

Two SPOC deferrals,

56-01

and 56-02, were taken against

DCN-M0079 and

DCN-B0060.

These

DCNs

were

to replace

cables

damaged

during

a

drywell fire.

The work was completed for .system

56 but several

other

systems

were covered

by the

DCNs.

By procedure,

the

DCN must

be

closed or

a deferral is required.

The deferral was,tied to drywell

closure.

Switchyard

and 24V/48V DC Distributions

(System 57-6)

The System Checklist is scheduled

to be completed

by August 29,

1990.

The inspector

reviewed the

SMPL with the cognizant

system

engineers

and identified no concerns.

The inspector

noted that paper closure

for ECNs made

up the bulk of the open items for these

systems.

Standby Liquid Control

(System

63)

This

system

underwent

a full

review which

was

completed

on

August ll, 1990.

The inspector

accompanied

the systems

engineer

and

12

operations

personnel

on

a

preliminary

system

walkdown

on

July 17,

1990.

Several

minor deficiencies

were identified which

required

work to correct.

The inspector

also participated

on the

final

system

walkdown

on

August

1,

1990.

Some

minor work

was

required

and

was completed.

The inspector

reviewed

a portion of the

system

functional test,

2-SI-4.4.A.2,

conducted

on August 6, 1990,

(see

paragraph

two).

The inspector

reviewed the system status file

and configuration log for this system

and identified no deficiencies.

The inspector

was

in the

process

of reviewing the

completed

package at the end of this reporting period.

Reactor Building Closed Cooling Water

(System

70)

The inspector

was

informed by the system engineer of a problem with

the

RBCCW HXs.

Recent

eddy current examination of the

2A HX revealed

numerous

indications.

Of 740 admiralty brass

(70% copper

and

30K

zinc) tubes,

195 indicated greater

than

40% through wall defects.

Of

these,

19 tubes

had indications greater

than

90K through wall.

The

tubes

are

40 feet long with carbon steal

tube sheets.

This

system

contains

demineralized

water

on the

RBCCW side (shell

side) with

RCW on the tube side.

Examination of the defects

revealed

numerous

transgranular

cracks

perpendicular

to

the

tubes

and

originating

on the

tube outside

diameter.

The failure

mode

was

reported

to

be

transgranular

stress

corrosion

cracking.

An

evaluation

of the

RBCCW demineralized

water

system

revealed

the

presence

of 1/2

ppm

ammonia

in each

of the three units.

This

environment is considered

to be the cause of the tube cracking.

The

source of ammonia is most likely the reduction of nitrite used in the

system

as

a carbon steel inhibitor.

Bacteria were not controlled in

the system

and

may have provided the mechanism

by which the nitrite

was

reduced

to ammonia.

The source of ammonia

was considered

to be

an unknown.

The licensee

is planning

a number of options to resolve

the problem

prior to restart.

Inspection is planned of the "2B" HX to determine

the extent of the problems.

Some of the options

are

as follows:

1)

Tube plugging with calculation of heat load,

removal capability

during winter months of operation.

2)

Replacement

of tubes

with like tubes

and

adding

a multiple

inhibitor scheme.

3)

Replacement

of tubes with stainless

steel

tubes.

Other areas

of the plant are being examined to determine

the extent

of the

problem site wide.

The licensee initiated

CARR BF900249 to

document the problem.

13

This problem will be further reviewed

as part of the system return to

service for RBCCW.

o.

Primary Containment

Temperature

Monitoring (System 80)

The

inspector

accompanied

the

system

engineer

and

an operations

representative

on

a preliminary walkdown of System 80.

Several

minor

deficiencies

were identified and

documented

by the system engineer.

No significant deficiencies

were identified.

p.

Neutron Monitoring (System

92)

The inspector

ac'companied

licensee

personnel

during selected

portions

of the

system

walkdown associated

with System

92.

During the

walkdown material deficiencies

were noted

as follows:

Various

uncompleted

work activities

were still outstanding.

These

included replacement

of 11

LPRM strings

and completion of

repairs

associated

with LPRM cables.

Within Control

Room Panel

2-P-5, the rear covers for several

NI

recorders

were removed to allow the temporary placement of leads

.

associated

with the Transient Analysis System which will be used

during the unit startup

and power ascension

testing.

Two of the

covers

were lying on the top of the respective

recorders within

the panel.

The covers

were of substantial

metal construction

and

would

have

invalidated

the seismic qualification of the

panel.

The problem was noted

by the system engineer

who removed

the covers

and

gave

them to the instrumentation

personnel

for

safekeeping.

Loose

cable

connectors

were

noted

on the

SRM Detector Drive

Motors.

A clearance

tag

associated

with hold order

2-89-871

was

installed

on

panel

2-25-14,

located

in the reactor building.

Although the tag specified that leads

were lifted in the panel,

no lifted leads

could

be found.

This appeared

to be

a violation

of the licensee's

clearance

procedure.

The problem was jointly

discovered

by the

AUO and guality Organization

representative

during the walkdown and the problem was immediately reported to

the

SOS.

The inspectors will followup on the licensee's

actions

in this area during the next reporting period.

The

inspector

observed

several

different portions of the

system

walkdown including activities within the drywell, under vessel

area,

reactor building and the control

room.

The inspector

noted that

a

member of the Site guality Organization

was continuously involved in

the

walkdown

and that the

system

engineer

displayed

an excellent

overall

knowledge of the status

of outstanding

work items associated

0

14

with this system.

The inspector

was in the process

of reviewing the

package at the close of this reporting period.

q.

Microwave Transmission

(System 315)

System

315

was plant accepted

on July 9,

1990.

This system

was

a

SPOC checklist system.

Within the areas

reviewed

no violations or deviations

were identified.

8.

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.

a.

(CLOSED)

LER 259/87-25,

Technical Specification Violation for Failure

to

Perform

Required

Surveillance

on

Diesel

Generator

due

to

Procedural

Inadequacy.

This

item

was identified in September

1987,

when

a surveillance

requirement

for the

DG

had

not

been

incorporated

into plant

instructions.

The surveillance

required that the diesel start

from

ambient

conditions

and

energized

the

emergency

buses

with the

permanently

connected

loads.

Contrary

to this,

the

normally

connected

480V shutdown

boards

which supply loads required for safe

shutdowns

were not tested.

The failure to test

the

480V shutdown

board

loads

was attributed to

a programmatic

problem with procedures

which has

been corrected

through

a procedures

upgrade

process.

The inspector

reviewed Surveillance

Instructions,

O-SI-4.9.A.1.b-l,

O-SI-4.9.A. l.b-2, O-SI-4.9.A.l.b-3, O-SI-4.9.A.l.b-4 associated

with

emergency

load acceptance

testing of the Unit 1/2 diesel

generators.

It was noted that acceptance

criteria, Section 6.1, subsections

6.1.3

thru 6.1.7

now clearly indicated that all loads

required

to start

were addressed

including 480V shutdown boards.

b.

(CLOSED)

LER 296/88-07,

Overheating of DG 3C Due to Loss of EECW.

The

apparent

cause

of this

event

was

valve misalignment

during

alignment of the

EECW per the SI for hydrostatic testing.

An error

on the drawing

was

discovered

when the hydrostatic test

was

being

written and

a drawing discrepancy

was issued.

In the eight months

that followed, the error on the configuration control drawing was not

15

resolved

and

the drawing discrepancy

remained

open.

The untimely

implementation

of the

drawing correction

was

considered

the root

cause

of the event.

The

immediate

corrective

action

included

a

pre-performance

walkdown of the remaining hydrostatic testing SIs

and

correction of the flow diagrams.

Recurrence

control for this problem

was

a revision to the procedure for processing

drawing discrepancies.

This

procedure

now provides

a specified

overall

closure

time of

various categories

for drawing discrepancies.

The

inspector

reviewed

the

licensee's

corrective

action

which

included

revisions

to

procedures

O-OI-82, Unit

0 Standby

Diesel

Generator

System Operability Instructions

and 3-0I-82, Unit 3 Standby

Diesel

Generator

System Operability.

These revisions

cautioned

the

operators

to check for cooling water through the

DG coolers prior to

and during the operation of the

DGs.

The inspector also noted that

untimely resolution

of drawing discrepancies

was

a contributing

factor to this event.

The resident

inspectors

have

documented

the

DD

item as Deviation 90-18-02.

Based

on the revision of the procedures

and resolution of the deviation, the

LER was adequately

addressed.

(CLOSED)

LER 259/88-23,

Inadequate

Water

Seal

of Piping

Floor

Penetration

and Piping Floor Penetrations

and Possible

Flooding of

Residual

Heat

Removal

Service

Water

Pump

Rooms

During Design Basis

Flooding.

During an inspection of the

RHRSW pump rooms

on June

17,

1988,

ground

water was observed

entering the

pump room through

a subterranean

pipe

penetration.

A review of the penetration

drawings

revealed

that

a

water seal at the pipe penetration

had not been provided

and the seal

at the floor penetration

was

inadequate.

The inspector

reviewed the

licensee's

closure

package for this

LER.

Design

Change

H1888A was

implemented

which installed floor piping penetration

seals

in all

RHRSW pump rooms.

The reactor buildings, intake structure,

DG rooms,

and radwaste buildings were inspected

and repaired

as necessary.

The

inspector

reviewed

the

inspection

records

performed

in

1988.

Procedure

MMI-19, Inspection

and

Maintenance

of Flood Protection

Devices, lists

the

penetrations

to

be

inspected

in the various

locations.

The inspector

inspected

the

RHRSW pump rooms

on August 3,

1990

and

no penetration

seal

problems

were noted.

The inspector

concluded that these actions

were adequate

to correct the problem.

(CLOSED for Unit

2 Only)

LER 259/88-32,

Electrical

Separation

Requirements

Violated Due to Inadequate

Design Control.

This

item

was originally identified in October,

1986,

during the

implementation of a design

change

which upgraded

the Unit 2 primary

containment

electrical

penetrations

to

meet

Eg

requirements.

Discrepancies

were discovered

in electrical

cable classifications

and

cable

routings

indicating

possible

violation of the electrical

divisional

separation

requirements.

Subsequent

reviews

and

16

evaluations

identified

approximately

950

division

separation

discrepancies

in either

labeling or actual

physical

separation.

Of

these

discrepancies,,

approximately

230 require physical modifications

or further evaluation prior to Unit 2 startup.

The licensee

indicated that

the root cause

of this condition

was

inadequate

design control.

The licensee

documented

the corrective

action

on the following CAgRs:

BFP 870860

documented

violation of installation criteria where

non-safety

related circuits

were

routed with both

redundant

safety divisions.

BFP

881105

documented

the violation of installation criteria

where safety related

cables

were routed

in non-safety related

raceways.

BFP

881106

documented

the violation of installation criteria

where safety related

cables

were associated

.with both redundant

safety divisions.

BFP

881107

documented

the violation of installation criteria

where

safety

non-safety

were

improperly tagged with an incorrect suffix.

All four

CAgRs resulted

in extensive

work

on

the part of the

licensee.

The

LER is part of the cable separation electrical

issue

which is being monitored

and reviewed

by the

NRC.

Because of these

reviews

and the CA(Rs, the

LER was adequately

addressed.

This item

is closed for Unit 2 only.

e.

(CLOSED)

LER 259/89-04,

Unmonitored

Release

of Condensate

Water

Because of Failure of Instrumentation

Heat Trace.

This event is the

same

event described

in VIO 259, 260, 296/89-35-04

closed in this report.

Therefore, this

LER is also closed.

f.

(CLOSED)

LER 260/89-08,

Electrical

Fault

on

Transformer

Causes

Engineered

Safety Feature Actuation.

An

ESF actuation

occurred

due to an electrical fault on the unit

station service transformer,

USST 2B.

The transformer fault occurred

because

of inadequate

insulation

above the

bus joint.

The design of

the

bus

duct

allowed

collection of condensation,

and

vendor

recommended

preventive maintenance

was not performed.

The original

LER was

issued

on April 7,

1989

and

was revised three

times with revision

3 being

issued

on

September

29,

1989.

Each

revision indicated

a change

in the corrective action.

10

The inspector

reviewed

DCN H5249A, Modify the

2B

USST

Y Secondary

'160V

Winding Bus, which required that the bus

be extended

14 inches

and that

15000 volt Raychem insulation

be used for taping.

This

DCN

was

implemented

by

WP 2235-89.

A review of records

indicated that

this

DCN was

implemented

and tested.

The inspector

reviewed

PM

procedures

EMSIL 103.1

and

EMSIL 103.2.

Procedure

103.2

was required

to be performed

each refueling outage,

not to exceed

24 months,

and

procedure

103.2

was required to

be

performed every other refueling

outage,

not to

exceed

4 years.

The inspector

noted that

both

procedures

require visual inspections

as well as

megger testing.

The

difference

between

procedure

103. 1 and

103.2 is that 103.2 required

high potential testing

as well.

The inspector

reviewed

MRs 911567,

1006083,

and

863275 which indicated that Units 1, 2,

and

3 main and

unit service transformers

were inspected

and electrically tested.

The

inspector

reviewed

records

which indicated

approximately

90

personnel

received live time training

on

LER 260/89-08,

the

USST

2B

event.

Additional discussions

with operations

personnel

indicated

that this training

was

adequate.

The inspector

also

noted that

an

operator

aid,

number 0-89-100,

dated

5/17/89,

on

a Unit 2 control

panel,

was

a single line diagram of the

BFN 500

KV system,

161

KV

system,

switchyard transformer s,

and

4KV plant electrical

boards.

Based

on these

reviews,

the licensee

has

adequately

addressed

this

LER.

(CLOSED)

LER 260/89-09,

Unplanned

Scram

and Main Steam Line Isolation

Due to Spurious

Spikes

on Main Steam Line Radiation Monitors.

This item was identified when

on April ll, 1989,

Browns Ferry Unit 2

received

spurious

spikes

on the

independent

main

steam

line

MSL

radiation

monitors

which resulted

in completion of the initiation

logic for a full scram

and

a main steam line isolation valve MSIV

isolation.

The specific

cause

of the spurious

spikes

was not determined.

The

spurious

spikes

may

have

been

caused

by vibrations

generated

by

personnel

working in the

area

however,

attempts

to recreate

the

spikes

were unsuccessful.

The subsequent

investigations

included

a

response

check of the monitors,

visual

and signal

checks

of the

cables

and

connections

and

generation

of potential

sources

of

electromagnetic

interference.

The inspector

reviewed the licensee activities in trying to determine

the

cause of the spikes.

During the review the inspector

noted that

the

MSL high radiation monitor system did not have

adequate

signal

conditioning.

This made it difficult for the system to differentiate

between

spurious signals

and legitimate high radiation signal.

Since

this occurrence

the

MSL high radiation monitors

have

been

replaced

with updated digital monitors through

DCN H1263B.

18

(CLOSED)

LER 260/89-13,

Failure

to Meet Technical

Specifications

Because of Inadequate

Control of Flood Protection Barriers.

This item was discovered

by a TVA system engineer

when manway covers

in

RHRSW

pump

room

A and

D were found not bolted down.

The manways

provide

a flood barrier for the rooms.

The inspector

reviewed the

licensee's

closure

package for this item.

Inspection of the

manway

covers

was

added

to plant procedure,

GOI-300-1,

Operations

Routine

Sheets.

The inspector

inspected

the

RHRSW

pump

rooms

on August 3,

1990,

and

found all

manways

bolted in place.

An

URI (259,

260,

296/89-19-01)

was

opened

on this

same

issue

and closed in IR 90-18.

Based

on these actions, this

LER is resolved.

(CLOSED)

LER 260/89-23,

Loss of Secondary

Containment

Due to Loss of

Two Trains of Standby

Gas Treatment.

On July 23,

1989,

both

SBGT trains

A and

C were

in

violation of TS.

SBGT train

C

was

declared

when its

emergency

power supply, 'the

3D

DG,

became

due to failed

pinion failure relay.

SBGT train

A

was

previously

declared

due to problems with the relative humidity heater

breaker.

According to the

TS in effect at the time, secondary

containment

was

required

and in order to have

secondary

containment,

two trains of

SBGT were required to be operable.

The cause of this event

was the

failure of the diode installed across

the operating coil of the start

failure auxiliary relay.

This failure caused

the relay contacts

in

the pinion failure relay to fuse

in the

closed

position.

This

prevented

the diesel

from being

shutdown

by normal means.

The diode

and relays

were replaced.

The diesel

and

SBGT train

C were returned

to service July 24,

1989.

Each of the eight diesel

generators

has

19 relays of the

same

type

and configuration.

No pattern of failure could be determined

by the

investigation.

No other

diodes

were identified

as failed.

The

licensee is attributing this failure to random

end of life failure.

The inspector

has

reviewed the

LER, the Incident Failure Report, the

incident investigation,

and the

MRs used to troubleshoot

and repair

and they were acceptable.

All three units at

BFN have

been

shutdown

for an extended

outage

and thus there

was little safety significance

to this event.

(CLOSED)

LER 260/90-02,

Unplanned Reactor Protection

System Actuation

Due

to

Undetermined

Reason

During Functional

Testing of

Scram

Discharge

Instrument

Volume Level Switches.

This

LER

was

about

an

unplanned

RPS actuation

during functional

testing of the SDIV level switches.

The cause of the event could not

be

determined.

The

immediate corrective

action

was to stop

the

functional test

and determine

the

cause.

The valve alignment

was

f

verified correct

and the functional test completed.

The sequence

of

events

recorder

was out of service at the time making it impossible

to pinpoint the exact

cause

of the actuation.

The recorder

was

restored

to service

and the

channel

was retested

successfully

six

times.

No further

problems

were identified

and

the exact

cause

could not

be

determined.

The inspector

reviewed

the licensee's

closure

package

for this

item.

The licensee's

troubleshooting

actions

were

appropriate

to resolve the actuation.

(CLOSED)

LER 296/90-02,

Unplanned

ESF Actuation'uring Electrical

Board Power Transfer

Due to Personnel

Error.

The

ESF actuations

which occurred

on March I, 1990,

were caused

by

failures

to follow procedures

while transferring

shutdown

board

3A

from its alternate electrical

source to its normal

source.

The

ESF

actuations

were reset

following the return of shutdown

board

3A to

its normal lineup.

The inspector

reviewed

the

LER, dated April 2,

1990,

and verified

that it met

the reporting

requirements

of

10 CFR 50.73.

The

inspector

noted that the

LER was submitted

beyond the

30 day limit

allowed

by

10 CFR 50.73 (a)(1).

Violation 90-05-03

was issued for

the failure to follow procedures

which resulted

in the

reported

event.

The violation is closed

in this report.

The corrective

actions

included in the

LER were verified during followup of the

Violation.

(CLOSED)

LER 259/90-03,

Failure to Maintain Secondary

Containment

Requirements

Following Inoperability of Second

Standby

Gas Treatment

(SBGT) Train due to Damper Closure

by Unknown Cause.

On February

1,

1990, during performance

of O-SI-4.7.B.3.C,

licensee

personnel

discovered

the "B" train inlet damper,

O-FC0-65-39,

closed.

This normally

open

fan inlet

damper

had

become

closed

after

a

mechanical

stop in the associated

motor actuator

became mispositioned

when screws holding it in place loosened.

This caused

SBGT train "B"

to be inoperative.

Since

SBGT train "C" was already out of service

for other maintenance,

secondary

containment integrity could not

be

maintained.

The licensee's

investigation did not identify any history of similar

damper failures.

The inspector

reviewed

MR 893139,

which documented

repositioning of damper

and retightening of screws for the failed

damper.

The inspector

noted that the respective

screws

on the "A"

train inlet damper

were also

checked

under this

MR and found not to

require tightening.

Since

the

"C" train inlet damper

is of a

different design without an external

mechanical

stop,

there

was

no

need

to include it in the

licensee's

corrective

actions.

The

inspector

also

reviewed

Final

Event

Report,

II-B-90-017,

which

documented

the licensee

s investigation of the failure.

Based

on the

20

n.

above

reviews,

the

'inspector

concurs

with

the

licensee's

determination that the failure was

an isolated

case.

(CLOSED)

LER 259/90-05,

Failure

to

Take All

Raw Cooling

Water

Compensatory

Samples

Due to Personnel

Error Results

in Operation

Prohibited

by Technical Specifications.

This event occurred

on April 4, 1990.

The inspector

reviewed the

LER

and

determined

that it met the reporting

requirements

of

10 CFR 50.73.

Violation 90-08-01

was issued for this event

and is closed in

this report.

The corrective

actions

included

in the

LER were

verified during followup of the violation.

(CLOSED)

LER 259/90-07,

Isolation of Plant

High

Pressure

Fire

Protection

Systems

Resulting in Technical Specification Violation.

This

LER resulted

from valve manipulations

on the

HPFP system in an

attempt to isolate

a broken water pipe thought to be in the

HPFP.

Non-licensed fire protection

personnel,

not cognizant of the

HPFP

system configuration, isolated

the north header

supply from the west

supply while the

north

header

supply

from the

east

supply

was

isolated

for maintenance,

without contacting

the

SOS.

This

combination resulted

in the isolation of the

HPFP system that placed

the plant outside

TSs.

A contributing factor in this event

was that

fire protection personnel

at the scene of the event perceived that an

emergency situation

was forming.

The corrective action for the event

was to return the

HPFP system to service,

repair the leak which was

actually on

a potable water line, and return the potable water system

to service.

0 ~

To prevent reoccurrence

of this event, fire protection personnel

were

trained

on independent

work limitations, the requirements for control

room oversight,

and control of all plant evolutions.

They were

counseled

on proper communications

and protocol techniques.

The inspector

reviewed the licensee's

closure

package for this

LER.

The licensee

conducted

an incident investigation of this event which

was

complete

and thorough.

Copies of the training

and counseling

sessions

and

attendance

sheets

were

reviewed.

The actions

taken

addressed

the problems

which resulted in the

LER.

(CLOSED)

PART-21 259,

260,

296/P21-86-01,

Mangetrol

Model

402 Level

Controls Shipped Without Torque Check.

An identical

IFI( 259,

260,

296/86-11-02)

was

opened

for this

problem.

The IFI is closed in IR 86-40.

P

(CLOSED)

PART-21 259,

260, 296/P21-90-07,

Brown Boveri Inc-ABB 27/59

211L Relay has Deteriorated

Leads

Due to Thermal Stress.

The

inspector

reviewed

the

licensee's

closure

package

for this

Part 21.

The licensee

conducted

a survey of the locations

in which

Brown Boveri voltage relays installed

on February 28,

1990.

No 211L

relays were found installed.

Power Stores

stock records

wer e checked

and

no 211L relays

were found in stocks.

The inspector

reviewed the

survey tabulation results

and

concluded

the licensee

actions

were

appropriate

to address

the Part 21.

9.

Action on Previous

Inspection

Findings

(92701,

92702)

a ~

b.

(CLOSED)

IFI

259,

260,

296/88-04-04,

Single

Failure

Criteria

Involving Emergency

Core Cooling Systems

Identified

as Part of the

Restart Test Program.

This

IFI involved

a

licensee

identified condition

where

single

failure design criteria

was

not applied to the design of subsystem

.

280,

Battery

Boards,

and

subsystem

231,

480 Volt AC

SDBD.

The

finding was

documented

on

CARR

BFP 880067,

Revision

1.

This IFI

involves

only equipment

modifications

associated

with

CARR

BFP

880067.

The resolution of this problem

was the reassignment

of the

250V

DC control logic power supplies of the

480V

AC shutdown

boards

1A, 2A, 1B, and

2B from the unit batteries

to the 4160V

AC SDBDs

250V

DC SDBD batteries

(SB-A, SB-B, SB-C,

and SB-D).

Now with the failure

of

a single

DC control

power

source,

such

as

SB-D,

only the

associated

4160V

AC board, its associated

DG, and the 480V AC boards

fed from them would

be affected,

thereby preserving

single failure

design criteria.

(CLOSED)

IFI 259,

260,

296/88-10-02,

Lack of Stack

Effect for

Anticipated Air Circulation Using Smoke Medium.

The item was originally identified during the

RTP. It was initiated

to document

a possible

discrepancy

in the

RTP

and to identify and

track

a significant hardware

The licensee

issued

CARR

BFP 880304

and

LER 259/88-39 to document

the effect of th'is problem

on plant operations.

A review of the

CARR indicated that the description of condition

stated

2-BFN-RTP-065,

Revision

1

was

performed

to determine if a

natural draft existed within the stack,

to prevent

a ground level

release

with only

SBGT operating.

Credit could not be taken for the

stack dilution fans or the cubicle exhaust

fans

and their associated

ductwork since they were not previously identified as safety related.

Testing

indicated

a

convective

flow did not exist.

TE-11 to

2-BFN-RTP-065 also addressed

this problem.

22

As

a result of this testing,

the licensee initiated

DCN W11053A which

required the installation of twelve bubble tight isolation dampers

to

specifically identified lines,

such

as

the Unit 2

and

3 dilution

ducts,

the filter cubicles

and offgas building ventilation exhaust

duct,

the

steam

packing exhaust

duct,

and Unit 2 and

3 dilution of

SBGT crossties.

Additional blank-off were to

be installed

in the

Unit

1 dilution duct

and

the off-gas line to the dilution duct.

Based

on this review,

the

inspector

determined

that the

RTP did

identify a significant hardware related

TE.

A CARR was initiated to

document

the

item

and

the

licensee

issued

a

DCN to correct

the

deficiency.

This indicated that the

RTP was effective in this area.

(CLOSED)

IFI

259,

260,

296/89-47-03,

Failure of

TS

Change

to

Implement SI Task Force Recommendation.

During

a

NRC

TS Team Inspection

a problem

was identified with a

TS

submittal

concerning

containment

venting.

To fulfill a commitment

.

made in

LER 260/89-01,

Fuel

Load Without Adequate

Neutron Monitoring

Due to Inadequate

Safety

Review of TS Amendments,

a licensee

task

force

conducted

an

assessment

of Unit

2

TS.

The task

force

recommended

as

a restart

item that

TS 3.7.F.1

concerning

the vent

path for primary containment

be changed.

The inspector

reviewed the

TS submittal

dated

August 4, 1989,

and concluded that the submittal

did not address

the task force concern.

No statement

was

added to

allow the preferred

vent path.

Part of the

LCO statement

was

moved

to the bases.

The

TS

was

resubmitted

to the

NRC on June 4,

1990.

This proposed

amendment

revised

TS 3.7.F14.7.F

and the associated

bases

to more

accurately reflect the intended operations

of purging and venting of

the primary containment.

The inspector

reviewed

the licensee's

TS submittal for this item.

The

TS change is being tracked

as

a restart

TS change.

(CLOSED)

URI 260/89-06-06,

Configuration Control of Instrument Line

Slopes.

This item concerned

the system

used to maintain configuration control

of instrument line slopes

and

an earlier

commitment from Sequoyah

Nuclear Plant to issue

the walkdown isometrics

from their instrument

project to maintain configuration control.

The inspector

reviewed

the licensee's

closure

package for this item.

Configuration control

is maintained

through

implementation

of Engineering

Requirement

Specification

ER-BFN-EEB-001,

Instrument

and

Instrument

Line

Installation

and Inspection.

This procedure

was effective October 2,

1987.

Sequoyah

had agreed

to maintain their walkdown isometrics

as

controlled

drawings

but this

requirement

was

deleted

once

they

implemented their

ER specification.

The

ER specification

contains

all the requirements

necessary

to ensure that all field work conforms

23

to the appropriate

standards.

All routing

changes

are

performed

under

a

DCN or

ECN package

and must meet all the requirements

of the

ER specification,

including slope.

Normal maintenance activities are

controlled

by IMSI-3014, Instrument Maintenance

Special

Instruction,

which implements

the

ER specification.

The inspector

reviewed the

ER

specification

and

IMSI-3014 and concluded that

a system

was in place

to maintain configuration control.

The approach

used at Sequoyah

and

Browns Ferry is consistent.

Based

on these conclusions,

a violation

did not occur.

Instrument

sensing

lines are

an item to be checked

when the plant systems

walkdowns occur

as part of the system return

to service

program.

This will provide

an additional

check that

sensing

lines are acceptable.

(CLOSED)

DEV

259,

260,

296/89-49-02,

Failure

to

Make

Timely

Notification to the

NRC of Senior

Management

Changes.

In Revision

6 of TVA's CNPP,

Volume I, TVA committed to keep the

NRC

advised

of changes

in senior

management

at the earliest

possible

time.

In that

same

book were listed,

by name, senior

TVA managers.

In the fall of 1989,

both the chairman of the

NSRB and the Director,

Division of Nuclear Training,

who were listed

as senior

managers,

were replaced

by TYA.

The

NRC was not notified, either formally or

informally till some

time after the

new individuals

assumed

their

positions.

This

was

a deviation

from

a

commitment in the

CNPP,

Volume I.

Subsequent

to the deviation,

TVA submitted to the

NRC

notification of the management

changes

and an updated list of Nuclear

Power Senior Managers.

TVA has

submitted

the Nuclear

Power Organization Description Topical

Report for

NRC approval.

When approved, this topical report will be

revised

as necessary

to reflect major organizational

changes

at least

annually in accordance

with the requirements

of 10 CFR 50.71.

TVA

has

requested

and received

NRC permission

to discontinue -the formal

notification required

by CNPP,, Volume I.

The inspector

has

reviewed

the documentation

provided relevant to this issue

and

has

determined

it is acceptable.

(CLOSED)

DEV 259,

260,

296/89-53-03,

Failure to Submit

a Special

Report in Accordance

With a Licensee

Commitment.

This deviation concerns

the failure of TVA to submit

a special

report

to the

NRC

as

committed to in

a letter dated April 1,

1988.

In

February

1988, TVA's PORS group determined that three events

recorded

on

a

CARR were reportable.

A four hour non-emergency

ENS telephone

report was

made to the

NRC and preparations

began

on

a 30 day written

LER 259/88-04.

In March

1988,

TVA's

PORC

group rejected

LER 259/

88-04

as

not reportable.

In April 1988,

TVA sent

a letter to

NRC

stating that

LER 259/88-04 would not be submitted,

but that the three

concerns

would

be addressed

and submitted to the

NRC in a special

0

24

report.

The special

report

was never submitted.

Subsequent

to this

deviation,

the licensee

reevaluated

the three

conditions

and did

submit

LER 89-25.

TVA has

combined

the reportability of LERs

and commitment tracking

into

the

Site

Licensing

group

instead

of

separate

group

responsibility 'o eliminate the recurrence

of this kind of missed

commitment.

TVA has

also

committed to advise

the

NRC by letter

within 30 days

in cases

where

an event is initially determined

to

require

an

LER and it is determined

through

subsequent

evaluation

than

an

LER is not required to be submitted

under .10 CFR 50.73.

This

commitment

was

made in a letter to the

NRC dated

September

21,

1989

dealing with NRC IR 89-27.

The inspector

has

reviewed

the

program

and selected

examples

where

TYA has submitted the 30 day letters.

No discrepancies

were noted in

the sample selected.

g.

(CLOSED)

VIO 259,

260,

296/88-36-01,

Failure to Properly Establish

and Implement

a Procedure for Configuration Control.

During

a previous inspection, it was identified that OSIL 43,

System

Status

Control,

was

issued

by the Operations

Manager without review

and approval of the

PORC

as required

by TS 6.8. 1.2. This instruction

was the document

governing the configuration control process

and the

completion of OI checklists for component

alignment.

In addition,

the previous

inspection identified the following deficiencies

in the

OSIL 43 program:

System alignment checklists

were being initialed even though the

components

were not positioned in accordance

with the checklist.

No indication was

made

on the checklist to identify that

a 'TACF,

clearance

sheet,

or

an

abnormal

status

sheet

existed

that

documented

the actual

position of the

components;

or that the

components

were not in the checklist position because

the system

was

running.

This

was

contrary

to

PMI 12.12,

Conduct of

Operations,

which stated that initialling a procedure

step

means

that the step

was completed

"as stated."

Deviations

from OI checklist

steps

during initial checklist

performance

did not receive the level of approval

required

by TS

for a temporary

change to a procedure.

Abnormal Status

Sheets controlling deviations

from the specified

positions

during

OI checklist

performance

were

not

being

controlled

as quality assurance

records

and were discarded

when

the deviations

were cleared.

0

25

These deficiencies

were acknowledged

by plant management

and included

as part of the violation for future

NRC inspection.

This item was

reviewed further in

IR 89-03

and

the

inspector

identified more

administrative

problems in the system status files.

During this report

period,

an

inspector

reviewed

the licensee's

response

dated

Nay 5,

1989,

and the licensee's

closure

package for

this violation.

The licensee

issued

new procedure

PNI 12. 15, System

Status

Control,

on

December

30,

1988,

to prescribe

the methods

to

achieve

and maintain cognizance

of operational

status

and configura-

tion status

control.

The inspector

reviewed

PMI-12.15

and

held

discussions

with licensee

personnel

responsible

for system status

and

configuration control.

The

new procedure

and

programs

include

controls

to

preclude

the

problems

identified

during

In the response

to the violation the licensee

identified four other

OSILs which

needed

to

be

upgr aded to include

PORC review.

These

OSILs

were

OSIL

11

"Environmental

Data

System - Trouble Reporting

Procedure",

OSIL

33

"Records

Control - Handling

QA Records

in

Operations",

OSIL 63 "Electrical Circuit Breaker

Rack -In/Rack-Out",

and

OSIL 66 "Checklists,

Logs, Inspections,

and Routine Sheets."

The

inspector

reviewed

the

licensee's

procedures

and

noted that the

contents of OSIL

11 and OSIL 33 had

been incorporated into PMI 12.12,

Conduction of Operations;

OSIL 63

had

been

upgraded

to GOI-300-2,

Electrical

General

Operating

Instructions;

and

OSIL

66

had

been

upgraded

to GOI-300-1,

Operations

Routine

Sheets.

All PMI's

and

GOI's require

PORC approval.

(CLOSED)

VIO 260/89-06-02,

Failure to Have

a Procedure

to Control

QA

Records of Instrument Calibrations.

This violation was identified regarding

the use of calibration cards

to record vital instrument

information

and results of calibration

activities.

These

cards

were not controlled by plant administrative

procedures

and their status

as

QA records

was indeterminate.

The inspector

reviewed

the licensee's

response,

dated July 7, 1989,

which

stated

some

generic

calibration

instructions

required

instrument

mechanics

to obtain

instrument setpoint,

accuracy,

and

range information from calibration cards.

IMs were instructed

that uncontrolled

sources

shall not be

used to

obtain calibration information

on technical

specification or other

safety-related

instruments.

The particular instruction in which this

problem

was

found,

SCI 511,

was revised to refer to the applicable

system

instrument

maintenance

indexes,

SIMIs, for calibration

information.

26

The inspector

reviewed

procedure

2-SIMI-3, Feedwater

System

and the

data for instruments

2-FI-3-13,

2-FM-3-13,

2-FS-3-13A,

B,

C,

and

2-FT-3-13.

A review of procedures

2-SIMI-3, SCI-204.4

and SCI-212.1

indicated that controlled

procedures

exist for the calibration of

safety related instrumentation

and calibration data are handled

as

gA

records.

(CLOSED) VIO 259, 260, 296/89-10-02,

Apparent Failure to Establish

an

Effective Program to Promptly Identify and Correct

a

Known Condition

Adverse to guality.

Contrary to

10 CFR 50,

Appendix

B, Criterion

XVI requirements,

licensee

personnel

failed to

document

a

known design

deficiency

associated

with nonseismically qualified vitrified clay pipe.

The

clay pipe present

in three separate

EECW discharge

flow paths

was not

identified

on

a

CARR until February

3,

1989,

even

though

licensee

Nuclear Engineering

personnel

had knowledge of the condition as early

as

January

11,

1989.

Plant operations

was not made

aware of the

condition until issuance of the

CARR.

The inspector

reviewed the

~ licensee's

response

to the violation dated

June

14,

1989.

In that

response

the

licensee

attributed

the

violation to the lack of sensitivity

among

NE personnel

regarding

Browns

Ferry

becoming

operational,

being

covered

by,

TS

and

the

necessity

of timely problems identification and documentation

at an

operating nuclear plant.

The

inspector

reviewed

documentation

provided

by the licensee

to

verify completion of training for

NE and other site

personnel

on

sensitivity to timely identification of problems,

TS significance,

and

importance of escalation

of potential

problems.

Additionally,

the inspector

reviewed Site Director Memorandums

dated

March

13 and

March 14,

1989,

which stated

Browns Ferry site policy on sensitivity

to timely identification and escalation

of potential safety problems.

During the

review the inspector

noted that

NE personnel

are

now

included

as

a non-voting representative

on

PORC

and that there

has

been

a

general

improvement

in communications

between

the various

organizations

on site since

the violation occurred.

The inspector

determined that the licensee

has adequately

addressed

the problem and

corrective actions

should

be adequate

to preclude recurrence.

(CLOSED)

VIO 259, 260, 296/89-35-04,

Failure to Respond

in

a Timely

Manner to Off-Normal Conditions.

The inspectors

had identified that on February

10, 1989, control

room

personnel

failed to respond

to

CST level instrumentation

information

resulting in uncontrolled

and unmonitored

loss of 200,000 gallons of

water from the

CST.

This loss of potentially radioactive water was

not immediately recognized

by licensed

personnel

and not acted

on by

operations

until almost

16 hours1.851852e-4 days 0.00444 hours 2.645503e-5 weeks 6.088e-6 months after first becoming

aware of the

condition.

0

27

The inspector

reviewed the licensee's

response

to the violation dated

August

31,

1989.

In that

response

the

licensee

attributed

the

violation to

the failure of the

Unit Operator

to

adequately

investigate

an

abnormal

indication

resulting

in the

incorrect

conclusion that the

CST level instrumentation

had malfunctioned

and

indicated erroneously

because

of cold weather conditions.

The inspector

reviewed various

IIRs

and

LERs which occurred

during

1989.

Based

on this review the inspector

determined

that

a large

number of personnel

errors

occurred

in this area.

The licensee

experienced

10 separate

events

during this

period that

involved

failure to control fluid systems

resulting in spills, flooding, or

uncontrolled loss of large amounts of potentially contaminated

water.

Two of these

failures resulted

in

NRC violations for failure to

respond

promptly to off normal conditions.

The inspector

held discussions

with management

representatives

from

plant operations

and the Site guality Organization

to determine

the

extent of corrective actions

associated

with this problem.

Based

on

this discussion

and examination of various additional

documentation

provided

by the licensee,

the inspector

determined that the problem

has

been

adequately

resolved

due to the following corrective actions

.

which took place in December

1989:

Reassignment

of an experienced

SRO to the newly created position

of Water and Waste Coordinator.

Assignment of operations

personnel

to newly created

Radwaste

Unit Operator

position which is

now fully manned

around

the

clock.

Each

SOS

was

counseled

with increased

emphasis

placed

on

attention

to detail

and

prompt

response

to off normal

conditions.

Training conducted

with all operations

personnel

on the

above

events.

The inspector

noted that these

actions

appear to have

been effective

by the

absence

of any similar events

during

1990.

This is

made

further evident in the decrease

in the overall average

radwaste

input

rate

(which represents

plant leakage)

from 25

gpm to

10

gpm during

the

same

time period.

Based

on the above

review of the licensee's

corrective

actions

in this

area

the

inspector

determined

that

adequate

measures

have

been

taken to preclude recurrence.

(CLOSED)

VIO 260/89-53-01,

Failure to Respond

in a Timely Manner to

Off-Normal Conditions.

The inspectors

had identified that

on December 2, 1989, control

room

personnel

failed to respond

in

a timely manner

to the fuel

pool

28

skimmer

surge

tank

high level

alarm resulting

in water

from the

Unit 2

Spent

Fuel

Storage

Pool

overflowing into the ventilation

system

and leaked onto areas of the reactor building.

The inspector

reviewed the licensee's

response

to the violation dated

March

5,

1990.

In that

response

the

licensee

attributed

the

violation to the failure of the Unit Operator

to follow the alarm

response

procedure

and the failure of the

AUO to close the condensate

supply valve to the skimmer surge tank.

Since

the

NRC staff considered

this violation similar to

VIO 259,

260,

296/89-35-04

closed

in this report, the inspector considers

the

completed

measures

adequate

to prevent recurrence.

(CLOSED)

VIO 260/89-53-02,

Failure to Initiate CAgRs for Disposition

of Test Exceptions.

The

inspector

reviewed

the

licensee's

closure

package

for this

violation.

The licensee

initiated

CA(R BFP 900186 to address

that

the control

bay chilled water

pumps failed to supply the design flow

rate.

CA(R BFP 900187

was written to document operational

problems

resulting

from the

design

of the

C

and

D shutdown

board

room

emergency

cooling units.

The licensee

committed to make modifica-

tions to resolve the operational

problems.

In IR 89-53,

an extensive

review of TEs by the licensee

is discussed.

The inspector's

review

concluded that the licensee's

review was adequate.

The resolution of

the

CAgRs will receive additional review as part of the

SPOC process.

(CLOSED)

VIO 259,

260,

296/90-05-03,

Failure to Follow Operating

Instruction.

This violation

was

issued

for the failure to follow 0-0I-57B,

480V/240V

AC Electrical

System

Operating

Instruction,

step

8.6.3

prior to transferring

shutdown

board

3A from its alternate

power

source

to its

normal

power source.

Step 8.6.3 required that the

normal

feeder

breaker

AC voltage

indicate

greater

than

450 volts

prior to transferring. the board

power supply.

By failing to verify

the voltage,

the operator did not notice that the

4KV feeder breaker

was

open.

The transfer

resulted

in unplanned

ESF actuations.

A

contributing factor to the event

was that operations

did not follow

procedures

in returning shutdown

board

3EA to service.

This resulted

in the

4

KV feeder breaker for shutdown

board

3A being left open.

The licensee

responded

to the violation by letter

on May 18,

1990,

and admitted the violation.

The

NRC accepted

the licensee's

response

by letter dated. June

12, 1990.

The inspector

reviewed the licensee's

response

to the violation and the closure

package.

The corrective

actions

taken

included

closing

the

4KV feeder

breaker

and

reenergizing

shutdown

board

3A;

the

operator

involved

was

individually counseled

concerning

the

use of plant procedures

and

O~

l

0

29

disciplinary action

was taken;

and operations

personnel

reviewed the

event.

In addition,

procedure

0-OI-57B was revised

to include

a

caution before

step 8.6.3 to make this step

more noticeable

during

future

performances.

The inspector verified that the corrective

actions

had

been completed.

n.

(CLOSED) VIO 259, 260, 296/90-08-01,

Missed

RCW Samples.

This violation

was

issued

for

the failure to take

complete

RCW

compensatory

samples

while the

RCW effluent radiation monitor

was

Condition Adverse to Quality

on April 4,

1990.

Compensatory

sampling

was

completed

following identification of this occurrence.

The licensee

responded

to the violation by letter

on June

4,

1990,

and admitted the violation.

The

NRC accepted

the licensee's

response

by letter dated

June

20,

1990.

The inspector

reviewed the licensee's

response

and the closure

package for this violation.

The corrective

actions

taken

included counseling

the responsible

individual

on the

importance of complying with plant procedures.

The inspector 'noted

that the individual

who committed the mistake

was also the

one

who

identified the problem to his management.

In addition, the chemistry

control

group

issued

a

memorandum

concerning

compliance

with

procedur'es

to all affected

personnel

and the chemistry staff held

discussions

on the details of this violation.

The inspector verified

that the corrective actions

had

been completed.

No violations or deviations

were identified during the Followup of Open

Inspection

Items.

10.

Essential

Design Calculations

During the review of the licensee's

closure

documentation

associated

with

IFI 89-06-07,

Reactor

Vessel

Level Setpoint,

the inspector identified

a

concern

associated

with the licensee's

essential

calculation

program.

This

IFI

had

been

identified during

a special

NRC

team

inspection

conducted

at

Browns Ferry to review the licensee's

program for testing,

calibration,

maintenance

and

configuration

control of safety

The

inspector

was

concerned

that

new setpoint

calculations

were required to support

proposed

new setpoints

associated

with

RPV water level

instruments

2-LT-3-203A, 2-LT-3-203B, 2-LT-3-203C,

and 2-LT-3-203D.

These

instruments

provide redundant

channels for Reactor

Building and

PCIS isolations

and

SBGT actuation.

New setpoints

would have

to be selected

that would not be affected

by normal plant operations

and

yet would have sufficient margin for error

so that the "as found" value

would

not

exceed

the

technical

specification

value

during

periodic

functional testing

and calibration.

The value stated

in TS 3.2.A is

greater

than or equal

to 538 inches

above

vessel

zero.

The licensee

had

committed to resolving this issue prior to Unit 2 restart.

O~

II

30

The inspector

reviewed

new scaling

and setpoint calculations

ED-Q2003-

880177,

ED-Q2003-880178,

ED-Q2003-880179,

and

ED-Q2003-880180,

which were

to support

a

new setpoint of 539 inches for each of these

instrument

channels.

The inspector

noted that although

539 inches

complies with the

TS requirement,

the calculations

did not support closure of the open item

since

the calculated

"allowed value" in each

case

was

less

than

538

inches.

All four of the calculations

used the

same setpoint methodology,

and

due to conditions

unique to the individual instruments,

resulted in a

different resulting

value of PV3.

PV3

was

defined

as

the calculated

allowable value

and varied

among

the four calculations

from 537.8

to

537.9.

Since

these

values of PV3 included only those margins

based

on

normal

operating

conditions,

and not accident conditions,

the calculated

allowable value would be that value that the instrument

channel

could

be

expected

to reach prior to periodic functional testing

and calibration.

The inspector

discussed

this issue with site compliance

and engineering

personnel

and

members

of the

TVA engineering

staff from Knoxville.

Compliance

personnel

agreed that the

open

item was not ready for closure

and the closure

package

was withdrawn.

The inspector

was further informed

by members of the licensee's

engineering

organization .that there existed

an ongoing program for verification of scaling

and setpoint calculations

and that these

four calculations

were

now part of the defined

scope of

that program.

The licensee

stated that the

program

scope

was defined

on

an internal

punchlist,

and

had

included approximately

450 calculations

with remaining work down to 88 revised calculations

and

3 new calculations

pending.

Although licensee

engineering

personnel

were unable to show the

inspector conclusive evidence that these four calculations

were tracked

on

that internal punchlist the inspector

was provided with a copy of Project

Engineer

memorandum

dated

June

13,

1990

(B22 90 0613 099) which documented

a proposed

TS change.

The proposed

change

was

based

on

6 parameters

that

had calculated

allowable values that disagreed

with the existing TS.*

The

inspector

was also

informed that the proposed

change

was disapproved

by

licensee

management,

which required

the

licensee

to again

revise

the

calculations.

This item will remain

open

pending further review of the

licensee's

program for calculations to support setpoints

on safety related

instrumentation.

Modifications and Unit 3

On

March 30,

1990,

TVA issued

the

Browns

Ferry Nuclear Plant Unit 3

Integrated

Restart Action Plan.

This plan outlined

a six phase

integrated

approach for the Unit 3 restart.

The six phases

are:

Planning - which was completed

by issuing of the Restart Action Plan

Scope

Development - will complete

the detailed

planning required to

begin the walkdowns

and analysis

of as-installed

conditions.

This

plan

will develop,

validate,

and

implement

the Restart

Equipment

List used to complete Unit 3 discovery activities.

Discovery - will complete

the integrated

walkdowns

and engineering

analysis

required for Unit 3 modifications.

31

Design

Production - will provide bulk design

and

long lead

time

procurement.

Implementation - will install

and perform post-installation testing,

at the component level, of the modification.

Restart

- will include

integrated

system

testing,

surveillance

testing, fuel load, restart,

and power ascension.

In July 1990,

TVA issued

the Browns Ferry Nuclear Plant Unit 3 Development

Phase

Plan.

This plan

included detailed

schedules

for all the major

activities of this

phase.

The overall

six

phase

restart

plan

was

scheduled

to start early

1990

and culminate

on January

1,

1993 with the

closure of the generator

breaker

on the grid.

In mid July 1990,

the

Development

Phase

Plan

was put on hold by TVA due to the slippage of the

Unit 2 schedule.

One of the

key elements

of the Unit 3 plan is the roll

over of certain

key individuals from the Unit 2 restart effort to the Unit

3 plan development

phase.

With the slip in Unit 2 these

lead individuals

cannot

be released

from the current responsibilities.

Some efforts

on the

Development

Phase

Plan continue,

but not

on

any

defined schedule.

The key individuals and approximate staffing needs

have

been

developed.

For example,

the Unit 3

ONE will be comprised of 18 TVA

engineers

in the three

main disciplines,

and about eight support people,

all

from the current

Browns

Ferry Project

Engineering

Group.

These

engineers

will not

perform the

engineering

work, but serve

as

lead

engineers

and liaisons

between

BFN and the

AE.

No

new date

has

been

established

for reinitiating the Unit 3 schedule.

The inspector

has

reviewed

both the Unit 3 Integrated Restart Action Plan

and

the

Development

Phase

Plan,

and

has

attended

several

development

meetings.

Within the Unit 2 Modifications effort, productivity is increasing

but

still not at

normal

industry rates.

Field rejection rates

have

been

reduced to about four percent.

One item still causing

schedule

delays is

the amount of field changes

and discovery.

Partially as

a result of field

changes,

material

availability

has

caused

a

delay

in field work

completion.

Specific examples

are

documented

in earlier sections of this

report.

No violations are deviations

are identified.

Exit Interview (30703)

The inspection

scope

and findings were summarized

on August 17,

1989 with

those

persons

indicated

in paragraph

1 above.

The inspectors

described-

the areas

inspected

and discussed

in detail the inspection findings listed

below.

Although proprietary material

was reviewed during the inspection,

proprietary

information is not contained

in this report.

Dissenting

comments

were not received

from the licensee.

P

32

Item Number

Descri tion and Reference

259,

260, 296/90-25-01

260, 296/90-25-02

260, 296/90-25-03

260, 296/90-25-04

VIO, Inadequate

Fire Protection

Surveillance,

paragraph

two.

IFI, TS Reformatting,

paragraph

two.

IFI, Documenting

and Controlling Clearances

for Multiple Activities, paragraph

three.

VIO, Failure to Protect

Emergency

Equipment,

paragraph

four.

Licensee

management

was

informed that

14 LERs,

2

PART 21s,

3 IFIs,

1 URI,

2 deviations,

and

8 violations were closed.

Acronyms

ASOS

AUO

BFNP

CAQ

CAQR

CFR

CNPP

CRD

CS

CST

DBVP

DCN

DEV

EEB

ER

FDCN

GEMAC

GOI

HPCI

HPFP

IFI

IIR

IM

Assistant'Shift Operations

Supervisor

Auxiliary Unit Operators

Browns Ferry Nuclear Plant

Condition Adverse to Quality Report

Code of Federal

Regulations

Corporate

Nuclear Performance

Plant

Control

Rod Drive system

Core Spray

Condensate

Storage

Tank

Design Baseline Verification Program

Design

Change Notice

Drawing Discrepancy

Deviation

Diesel Generator

Engineering

Change Notice

Electrical Engineering

Branch

Emergency

Equipment Cooling Water

Emergency Notification System

Environmental Qualification

Engineering

Requirement

Engineered

Safety Feature Actuation

Field Design

Change Notice

Fuel

Pool Cooling

General Electric

General

Electric/Manual Automatic Controller

General

Operating Instruction

High Pressure

Coolant Injection

High Pressure

Fire Protection

Inspector

Followup Item

Incident Investigation Report

Instrument Maintenance

33

INSI

IR

KV

LCO

LER

LRED

MIC

NNI

NR

NSIV

NRC

OS IL

PN

PMI

PORS

PS

QM

RCW

SCI

SCL

SDBD

SDIV

SDSP

SI

SINI

SMPL

SLC

SOS

SPAE