ML18033B647

and

DCRDR

Audit,, LLRT, essential

design

calculations,

operational

readiness

review,

reportable

occurrences,

Part

21

Reports,

actions

on

findings,

and bulletins.

Results:

'

violation was identified for failure to implement design control measures,

paragraph

5.

This violation was

not

a programmatic

problem with the design

r

910305045k

9 i0220

PER

ADMEN 05000259

Q

PDR

process.

Several

instances

of incorrect design

implementation

occurred.

One

example

involved the installation of unqualified cables 'in three applications

after the cable

usage

was restricted.

A second

example

involved one instance

where

the

drawings, used

in the

design

had

not

been

updated

following an

Appendix

R modification,

and

two instances

where the correct drawings were not

used in modification workplans.

A

NCV was identified

by the

NRC for improper rigging from a safety related

structure,

paragraph

3.

A chain hoist

was

suspended

from a support

and the

loading

had not

been

analyzed.

The licensee

promptly removed

the hoist

and

initiated a detailed review of the problem.

A NCV was identified, by the

NRC for failure to maintain configuration control

of the

DG air starting

system,

paragraph

4.

The licensee

promptly corrected

the problems

and initiated

a review of the configuration control status

sheets.

'A

NCV was identified for the failure to follow workplan instructions

during

modi.fications

on

the

2C1

RPS circuit protector,

paragraph

5.

The licensee

promptly corrected

the deficiencies

and initiated an incident investigation to

identify and correct the root cause.

A URI

was identified for deficiencies

which occurred

during integrated

ESF

testing,

paragraph

2.

The deficiencies

were identified during the Units I/2 A

and

D train

DG load acceptance

tests.

During two tests

the

ECCS

pumps would

not start.

The

problem

was attributed

to

a

load cell switch inside the

output

breaker

compartment

not making contact.

The licensee

reported this

problem to the

NRC and is conducting

an incident investigation.

A

URI

was identified for .resolution of

SPDS reliability and

human factors

concerns,

paragraph

10.

These

items were identified during the

and

DCRDR

audit.

The

licensee

is

continuing

to

have

problems

with the

implementation

of

equipment

clearances,

paragraph

5.

There

appears

to

have

been

inadequate

corrective

action with respect

to

YIO 90-29-01.

Additional

examples

were

identified in

IR 90-33.,

The root cause

of this

problem

may not

have

been

addressed

and the continuing problem represents

a concern with the licensee's

ability to protect personnel

and equipment during ongoing work activities.

Additional examples

of VIO 90-33-01,

Failure to

Make

10 CFR 50.72

and

50.73

Reports,

were identified, paragraph

2.

The licensee

has

denied

one

examp'le of

this violation which

was

identical

to

these

isolations.

The

denial

is

currently being reviewed

by the

NRC.

The closeout

inspection of the Unit

2 torus identified several

material

and

cleanliness

problems,

paragraph

4.

There

was

a lack of licensee

management

involvement in the closeout.

Another walkdown is planned prior to closeout.

REPORT

DETAILS

Persons

Contacted

Licensee

Employees:

0.

L

M

J.

R.

B.

R.

A.

G.

p.

p

J

R.

Zeringue, Site Director

Myers, Plant Manager

Herrell, Operations

Manager

Rupert, Project Engineer

Johnson,

Modifications Manager

McKinney, Technical

Support

Manager

Jones,

Operations

Superintendent

Sorrell, Maintenance

Manager

Turner, Site guality Assurance

Manager

Carier, Site Licensing Manager

Salas,

Compliance Supervisor

Corey, Site Radiological

Control Manager

Tuttle, Site Security Manager

Other

licensee

employees

or contractors

contacted

included

licensed

reactor operators,

auxiliary operators,

craftsmen,

technicians,

and public

safety officers;

and quality assurance,

design,

and engineering

personnel.

NRC Personnel:

C. Patterson,

Senior Resident

Inspector

E. Christnot, Resident

Inspector

W. Bearden,

Resident

Inspector

K. Ivey, Resident

Inspector

G.'umphrey,

Resident

Inspector

+Attended exit interview

Acronyms used throughout this report are listed in the last paragraph.

Surveillance

Observation

(61726)

The inspectors

observed

and reviewed the performance of required SIs.

The

inspections

included

reviews

of the

SIs for technical

adequacy

and

conformance

to

TS,

verification of: test

instrument

calibration,

observations

of the conduct of testing,

confirmation of proper

removal

from service

and return to service of systems,

and reviews of test data.

The inspectors

also verified that

LCOs were met, testing

was accomplished

by qualified personnel,

and

the SIs

were

completed within the required

'frequency.

The following SIs were reviewed during this reporting period:

a.

O-SI-4.9.A. l.a(c),

Diesel

Generator

"C" Monthly Operability Test.

The inspector

observed

several

portions of this SI being conducted

in

the Unit I/2 Control

Room and

DG Building on December

18,

1990.

This

procedure

had

been

validated

during

a previous

performance.

No

deficienci'es

were identified during the observation of this SI.

b.

2-SI-4.2.B-45A(II), Loop II

RHR Logic System

Functional

Test.

The

inspector

observed

several

portions of the SI being conducted

in the

Unit I/2 Control

Room

on December

22,

1990.

The procedure

was being

Validated

during this

performance.

The inspector

noted that the

licensee

issued

a non-intent

change

to step 7.10.13 to clarify the

requirement

to reclose

valve 2-FCV-74-59.

Also licensee

operations

personnel

stopped

the SI performance

during one step

when they became

unsure of the correct contacts

where test leads

were to be connected.

Assistance

in clarifying the correct contact information was obtained

from the

RHR and electrical

system engineers

prior to proceeding with,

the remainder of-the SI.

- No deficiencies

were identified during the

observation of this SI.

I

c.

2-SI-4.2.K.2,

Reactor Building Exhaust

Vent Radiation Monitor Source

Calibration

and Functional

Test 2-RM-90-250.

An inspector

observed

this SI being performed

as

a

PMT.

The SI

had not been validated at

the time of the inspection.

,No deficiencies

were identified.

d.

Integrated

ESF Testing

During this reporting

period,

the

licensee

performed

a series

of

seven

ESF tests.

The inspectors

reviewed the SIs, observed

the tests

being

performed

and

reviewed

the

preliminary test

data.

The

following observations

were noted:

(1)

I/2-SI-4.9.A.3.a,

Common

Accident

Signal

Logic.

This

infrequently performed

SI tests

the

RHRSW initiation logic and

verifies that both divisions of the

common accident signal logic

will function on actuation of the

CS system of each reactor to

provide

an

automatic start

signal

to all four Unit 1/2

DGs.

Additionally this SI served

as

a portion of the

PMT associated

with

DCN

W14030

which is

described

in the modifications

paragraph.

The

inspector

observed

several

portions

of this

being

conducted

in the Unit I/2 Control

Room and shutdown

board

rooms

on December

23,

1990.

This procedure

was being validated during

this

performance.

Although

no

hardware

were

identified

during

the

testing,

and

the

testing

was

eventually

completed with no test exceptions,

the testing

was

halted during performance

when

a portion of the test could not

be performed

due to

a recently installed modification, referred

to as

the slow bus transfer.

The SI

was revised

and the test

was completed.

(2)

3-SI-4.9.A.3.a,

Common Accident Signal Logic.

This infrequently

performed

SI tests

the

RHRSW initiation logic and verifies that

both divisions of the

common accident signal logic will function

on actuation

of the

system of each

reactor

to provide

an

automatic start signal

to all'our Unit 3

DGs.

The inspector

observed

several

portions of this SI being conducted

in the Unit

3 Control

Room

on

December

22,

1990.

This procedure

had

been

validated

during

a

and

no significant

changes

to the Unit 3 equipment

had occurred since the previous

performance.

No deficiencies

were

identified during

the

observation of this SI.

'

1/2-SI-4.9.A.3.b,

480 Volt Load Shedding

Logic System Functional

Test.

This SI

was

performed" to verify that the

480V load shed

logic functioned

in conformance

with the

requirements

of TS 4.9.A.3.b.

The inspector

observed

several

portions of this.SI

being conducted

in the Unit 1/2 Control

Room and shutdown board

rooms

on December

26,

1990.

This procedure

was being validated

during this performance.

During the observation of this SI the

inspector

noted that the

ASOS assigned

lead responsibility for

performance

of the testing

authorized

disabling of the

load

shedding

function associated

with the

lA

FPC 'Pump,

1A

RBCCW

Pump,

and

2B

RWCU Pump.

Step 7.1(8) of the SI allows functional

testing of local logic relays with disabled

load shed contacts

when the

ASOS determines

that the shedding of any load needs

to

be

prevented.

If disabled

the

relay contacts

are

to

be

documented

on Attachment

3 of the SI.

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

2,

3,

and

4,

Diesel

Generators

A.thru

D

Emergency

Load Acceptance

Test.

I

DG A Testing

During the initial performance

of the emergency

load acceptance

test for

DG ~,

the Al

Pump failed to start

due to

an

erroneous

initial system line

up specified in the procedure.

The procedure

was corrected,

the

system realigned,

and

a second

attempt

was initiated.

During the

second

attempt of the

A test,

the

sequence

of

events that should

have occurred

was

as follows:

t= 0 sec

Trip breaker

1614,

4160V

Shutdown

Board

A Normal

Feeder

Breaker,

A starts

and accelerates

to full

speed.

t=O

sec

Breaker

1818 closes,

reenergizing

4160V Shutdown

Board

A from

DG A,

RHR

pump

2A starts,

and

480V load shed

logic is initiated.

t=7

sec

pump

2A starts.

t=l4 sec

RHRSW pump Al starts

8

0

I.

t=40 sec

Load shed logic timer times out, sequencing

on various

loads

During this test

perfo'rmance,

only the events

through t=0 sec

actually occurred.

A review of the strip'ecorder

monitoring

the load

shed logic indicated that it was only energized for

approximately

0.5 seconds.

The

2A

pump

and the Al RHRSW

pump did not start.

A followup review of the

event

indicated

that

a

possible

defective

breaker cell switch contact,

which closes

when the

DG,

breaker

closes,

caused

the failure of the logic.

The breaker

was exercised

on

a dead

bus

and the test proceeded.

During

the third attempt

of the

A test

the

equipment

performed

as required.

No deficiencies

were identified.

DGs

8 and

C Testing

During the initial performance of the load acceptance

tests for

DGs

B and

C; no deficiencies

were identified.

However, the

B

test strip recorders

indicated

a momentary

loss of generator

field voltage.

D, Testing

During the initial performance

of the

D test,

the

DG came

up

to speed

and voltage

and the

DG breaker closed onto the shutdown

board.

However,

the

RHR pump,

the

pump,

and the

RHRSW pump

failed to start.

The

480V load

shed logic did not function

properly.

As

a result of this failure, the licensee

obtained

technical

assistance

from the

vendor

and

determined

that

a

contact

on the cell switch did not close.

Consequently,

the

equipment

did not

perform

as

expected.

The

breaker

was

exercised

on

a dead

bus

and the test proceeded.

During the

second

attempt

of the

D test, all

equipment

performed

as required.

No deficiencies

were identified.

The

licensee

completed

the

series

of 'integrated

ESF testing

by

performing

a total of

10 tests,

seven of which were successfully

completed

and three

which were not.

The licensee

issued

a

CARR and

initiated

an incident investigation

to determine

the

cause

of the

test failures.

In addition,

the licensee

plans to initiate a design

change

to parallel

the cell switch contacts

with other contacts

on

the actual

breakers.

The inspectors will monitor the progress

on

a

routine

basis.

This

item is identified

as

URI 259,

260,

296/

90-40-01, Deficiencies Identified During Integrated

ESF Testing.

On January

7,

1991, during the performance of O-SI-4.2.A-17,

Refuel

Floor Ventilation Logic

System

Functional

Test,

two refuel

zone

ventilation trips were received.

When the fans

were shifted from

slow to fast, speed

as part of the SI, the low static pressure

relays

dropped,out,

tripping the Refuel

Floor fans

and isolating the refuel

zone ventilation system

on Unit 2.

The trip signal cleared

when the

fans

stopped.

Performance

of the SI

was

stopped while the licensee

determined if,the test

could

be

conducted

with t'e fans

in slow

speed.

During this time

PMT 65-211

was star ted

on the

SBGT system

requiring

SBGT trains

B 'and

C to

be placed

in service.

The

PMT

caused

the Refuel Floor pressure

to drop below the actuation

pressure

of the

low static

pressure

switches

so that the ventilation trip

signal

was sealed

in when the SI was started'gain.

Both tests

were

stopped until the conflict could be resolved.

'0

CFR 50.72 requires

that licensee's

notify the

NRC within four

hours of any event'r condition that results

in manual

or automatic

ESF actuation.

The refuel

zone ventilation

system is designed

to

isolate

upon receipt of a

PCIS group

6 actuation

signal

which is an

ESF.

These

events

were not reported

to the

NRC within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months

as

unanticipated

ESF actuations.

The failure to report these

events

are

,examples

of VIO 90-33-01,

Failure to Make

10 CFR 50.72

and

50.73

Reports,

-which was

issued

on

December

17,

1990.

The licensee

has

denied

one

example

of

VIO 90-33-01

which is identical

to these

isolations.

This denial is currently under review by the

NRC.

On

December

20,

1990,

during the performance

of 2-SI-4.2.B-45A(I),

Loop I

RHR Logic System

Functional

Test,

the

2D

RHR

pump started

unexpectedly.

The

pump

was

secured

iomediately

and the test

was

stopped.

No injection to the vessel

occurred

because

the system

was

out of service

and could not perform its intended function.

The licensee

initiated

an incident investigation

( II-B-90-152) to

determine

the

cause

of this event.

Preliminary reviews

indicated

that

a volt-ohm meter

being

used

to verify continuity completed

a

pump start circuit because it was

connected

between

two terminals

instead of between

a lifted wire and

a terminal.

This issue will be

followed by the resident

inspectors until

a review of the completed

incident investigation report can

be performed.

On

December

30,

1990,

during

the

performance

of 3-SI-4.2.K.2.a,

Reactor

Building Ventilation Exhaust Monitor Source Calibration

and

Functional

Test,

radiation monitor 3-RM-90-250

was

valved out of

service

several

times

during

the test.

At the

time of the

performance

a

temporary

continuous

monitor

was

installed

on

3-RM-90-250 to satisfy

the

compensatory

requirements

of TS 3.2.K.

This

TS requires

a

4 hour4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months flow rate estimate,

'an

8 hour9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months grab sample

for noble gases,

and continuous

sampling for iodine and particulates.

During the SI, the compensatory

monitor was valved out each time the

permanent

monitor was.

The

was

begun

on

December

30,

1990, at

2:05 p.m.

and completed

on January

1,

1991 at 4:00 a.m.

At various

times

during

the

test,

the

Chemistry

Laboratory

placed

the

compensatory

monitor

back into service

to per'form the

sample

flow

estimates

and collect grab

samples.

The compensatory

monitor was

placed into and

removed from service several

times during the next

14

hours.

The licensee 'determined that the continuous

function of the

compensatory

monitor was never out of service for greater

than three

hours at

a time (per Chemistry Laboratory records of flow estimates);

however,

the aggregate

time that the monitor was out of service

was

estimated at up to

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .,

The licensee

initiated

an incident investigation

( II-B-91-002) to

determine

the

cause

and establish

corrective actions for this event.

The

inspector

discussed

this

event

wi'th

licensee

personnel

responsible

for the investigation.

Licensee

personnel

stated that

a

configuration

problem in which the sampling

taps

were

downstream of

the process

flow from the isolation valves contributed to this event.

Licensee

personnel

further

stated

that

the ventilation

exhaust

radiation monitors for the refuel

and reactor

zones,

radwaste,

and

turbine buildings

had

been modified with sampling

taps

upstream of-

the isolation

valves.

The

use of these

taps will ensure

that

sampling continues

even if the monitor is

isolated.'he

inspector

and

a

compliance

engineer

walked

down the affected

radiation monitors

in the plant.

The inspector

noted that

each

monitor had been'odified

to include the

new sampling taps;

however,

the

inspector

noted

that

a temporary

sampling unit connected

to

2-RM-90-252,

Radwaste

Ventilation Exhaust Air Particulate

Monitor,

was

connected

to the

downstream

taps.

This would make the temporary

sampling unit susceptible

to the failure discussed

above.

This

problem

was brought to the licensee's

attention for review.

This issue will be followed by the resident

inspectors until a review

of the completed investigation report can

be performed.

2-SI-4.2-3(A),

Revision

6,

Instrumentation

That Initiates

Rod

Blocks/Scrams,'ntermediate

Range

Channel

A Calibration.

The inspector

observed

this calibration while in progress

from the

control

room

on January

9,

1991.

The inspector

noted that

the

procedure

had

been validated,

prerequisites

had

been

performed,

and

procedural

steps

were

performed

in

the

proper

sequence.

No

deficiencies

were noted during the performance.

No violations

or

deviations

were

identified 'in

the

Surveillance

Observation

area.

3.

Maintenance

Observation

(62702,

62703)

Plant maintenance

activities

were

observed

and/or

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 maintai'ned,

use of approved

procedures,

functional testing and/or calibrations

were performed prior to

returning

components

or

systems

to service,

gC records'aintained,

activities accomplished

by qualified personnel,

use of properly certified

parts

and materials,

proper

use of clearance

proce'dures,

and

implementa-

tion of radiological controls

as required.

Work documentation

(MR, -WR,

and

WO) was reviewed'o

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:

a.

WOg 90-24128-00,

Troubleshoot

Breaker

1818

and

Switch

52STA per

EMI-106 "Troubleshooting

and Configuration

Control of Electrical

Equipment."

This work was

performed

on the Units 1/2

D

DG output breaker

and

switch following failure of the switch to actuate

relays

as required

during load acceptance

testing.

No deficiencies

were identified.

b.

WOO 90-21017-00,

Replace

Damaged

Stainless

Steel

Braided Flexible

Conduit.

co

This work was

performed

January

9-10,

1991 to replace

a section of

. special

Eg flexible conduit that

had

been

damaged

due to an unknown

cause.

The inspector

observed

portions of the

ongoing

work and

reviewed

the uncompleted

work package.

The inspector

noted that the

work instructions

included in the package

were adequate

and contained

sufficient detail to allow satisfactory

completion of the work.

Improper Rigging from Snubber Support

During a tour of the Unit 2 Reactor Building on January

10,

1991, the

inspector

observed

an electric

1000 pound rated chain hoist suspended

from a snubber

support,

2-478450H0036.

The snubber

was attached

to

the

RHRSW piping

and

the

support

was

anchored

to the

con'crete

building structure wall at one

end

and the opposite

end

was supported

from the building ceiling by 4 anchor bolts,

1/2 inch in diameter.

A

review of the situation

revealed

that the

snubber

support

had not

been

analyzed

to support

a

load

as

required

by SDSP-14. 14,

Safe

Practices

For Operation

Of Overhead

Handling Equipment,

Attachment 9,

Safe

Operating

Practices

For Rigging

Personnel,

Step

1.21

which

states

that "Limitations assigned

to the

use of temporary

support

structures for rigging purposes

shall

be based

upon the determination

of

a

designated

person

who is

competent

in this field.

Such

determinations

shall

be documented

and recorded appropriately."

The situation

was

immediately

brought

to the attention

of the

maintenance

manager

who took prompt action to have the hoist removed.

The licensee initiated

an incident report, II-B-91-015, to determine

any

adverse

effects

and

to

determine

" corrective

actions, if

applicable.

Criteria specified in Section

V.A of the

NRC enforcement

Policy were

satisfied

and therefore this

NRC identified violation is not being

cited.'his

NCV is identified as 260/90-40-02,

Improper Rigging From

Safety Related Structures.

d.

Preventive

Maintenance

on

DG Stationary Auxiliary Sw'itches

During

the

reviews

and

observations

of

System

57,

Auxiliary

Electrical, activities the inspector

noted that the

PN for the 4160V

shutdown

boards

did not specifically address

the stationary auxiliary

switches.

Information received

by the inspector

indicated that the

switch contacts

had never

been cleaned,

the switches

are

changed

only

when they fail, and

the manufacturers

recommendations

for cleaning

the switches

are not followed.

The inspector

was

informed that the

switches

are inaccessible

and consequently

have never

been

cleaned.

The inspector'atched

a vendor representative

observing

the contacts

of a stationary auxiliary switch

by using

a mirror.

The inspector

was also

informed that these

switches

were not removed

and

checked

for proper operation

and cleanliness

when

the

4160V breakers

were

sent off site for the five year overhaul.

This item will be further

reviewed

as

part

of IFI

259,

260,

296/90-40-01,

Deficiencies

Identified During Integrated

ESF Testing.

One

NCV was identified in the Maintenance

Observation

area.

4.

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 purpose of temporary

tags

on valves

2-FCV-20-530

and

2-FCV-20-554 which resulted

in

those

valves

being

operated

and

a piece of equipment

being

returned

to service.

Both valves were'under

HO¹ 2-90-529 which-

had 'not been

released

by the authorized

clearance

holder.

This

event

was discovered

by the licensee

and

an incident investiga-

tion

was initiated.

The licensee

determined

that the valves

were properly tagged.

In addition, the individual involved was

not an operator

and would not normally be authorized to operate

- equipment.

Disciplinary action

was taken against

the individual

involved.

(2)

On

January

10,

1991,

Operations

personnel

implemented

a

"standing

hold order" for the

performance

of wiring modifica-

tions

on the

2C1

RPS circuit protector.

This "standing 'hold

order"

involved

removing

power

to the

2C1 circuit protector

cabinet

by opening

the

"110

Backup

Supply to

Disconnect

Switch" in the Unit 2 Battery Board

room and opening breaker

SCI

Unit Preferred

AC Regulating Transformer

TUP 2,

on

RMOV Board

28

in Shutdown

Board

Room 28.

Procedure

SDSP-14.9

allows the performance of work not under the

controls of the clearance

procedure

provided it is authorized

on

a case-by-case

basis

by the responsible

supervisor

and

SOS/ASOS.

An example

of this given in SDSP-14.9

is

"work of a limited

scope

where full control

can

be provided

and maintained

in the

immediate proximity to the involved equipment."

The operator

remained

in the Battery

Board

room during the work activities

and

was

in the

immediate

proximity of the

backup

supply

disconnect

switch;

however,

the

operator

was

not

in the

immediate proximity of breaker

SCI during the performance of the

work activities.

The failure to provide and maintain control of

breaker

SCI is

a violation of equipment clearance

requirements.

The above instances

of clearance

deficiencies

are additional

examples

of VIO 90-29-01 which was

issued

on November 8,

1990; for clearance

Two additional

examples

were

subsequently

0

L

11

identified in

IR 90-33 which was

issued

on

December

17,

1990.

A

supplemental

response

to address

these

new examples

is pending.

LCO Tracking

The inspectors

reviewed

the

LCO tracking

items identified below to

verify compliance with PMI 15.10, Tracking of Limiting Conditions for

Operations.

This system

provides current status of each

LCO to the

on-shift Operations

personnel

and provides

the restrictions

on the

plant

and

compensatory

actions

to

be

taken for each

LCO.

The

inspectors

reviewed

the tracking

system

information for the

LCOs

listed below'.

LCOP

Title

19900492

19910022

TS 3.1.A and

TS 4.1.A.

RPS inoperable until SIs are

performed.

TS 3.2.K.

Monitor 3-RM-90-250

inoperable

due

to

modifications.

Continuously collect

samples

with

auxiliary sample

system

and analyze

every

7 days

when

ventilation is in service.

No deficiencies

were noted.

Torus

Walkdown

The inspectors

were notified by the licensee

that

a Unit

2 Torus

walkdown

would

be

performed for final inspection

and

closure

on

December

21,

1990.

The licensee

stated that persons

representing

an

upper level of management

would participate in the walkdown and that

security would perform their final check

and lock the entrance

to the

hatch

upon completion

and final acceptance

of the equipment.

However,

the

walkdown consisted

of

NRC inspectors,

a plant operator,

a

gC

inspector,

a security officer,

and

radwaste

personnel.

No utility

senior management

was present.

During the walkdown, the inspectors

identified various

problems

that

included

some debris

found floating in the water (ball point pen,

tape,

and what appeared

as pieces of paint), debris

on the walkway,

a

pipe

extended

into the torus that

was not coated

and

was heavily

oxidized,

coating that

was

badly scratched

on the

vacuum breakers,

position

indicator

switches

on

two of the

vacuum

breakers

that

appeared

to be corroded

to the extent that they may not operate,

and

visibility was limited to approximately

18 inches in the water.

After management

personnel

were

informed of the above condition it

was

determined

that this area

would again

be reviewed

and another

walkdown for acceptability

would

be

performed.

The

inspectors

notified the licensee that they plan to participate in that walkdown.

12

One

NCV was identified in the Operational

Safety Verification area.

5.

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.

Throughout

the observation of modifications being performed in the field

gC inspectors"

were

observed

monitoring

and

documenting verification at

work activities.

a

~

Design Control

In previous inspection reports

the inspectors

documented

observations

'and

reviews

involving the installation of electrical

cables

for

modifications,

the modification of systems

for Appendix

R purposes,

and

the

change

of unqualified electrical

cables for 10 CFR 50.49.

The specific actions

observed

and reviewed were the following:

(I)

In IR 90-33,

an inspector

opened

a

URI involving the instal-

lation of unjacketed

electrical

cable.

These

activities

involved four

DCN/ECNs.

Additional review

by the

inspector

indicated that

a

PRD BFP900189P,

initiated on June 6,

1990,

and

signed off on September

6,

1990, identified the fact that Site

Procurement

Service

failed to specify

appropriate

quality

assurance

and

technical

requirements

as

required

to

meet

qualification of Class

1E cable

and failure to procure cable to

meet

the requirements

of

GDC BFN-50-758.

This

PRD listed

as

recurrence

control six items.

One item required

NE to issue

a

gDCN which listed acceptable

cable

contracts,

including TIIC

cable,,for

use at

BFN.

This item was completed

on August 28,

1990, with the

issuance

of gDCN-gl3819A.

An additional

item

required

that modifications,

maintenance

and

any other plant

organization with cable

intended for installation in a Class

I

structure

must obtain

concurrence

from engineering

that

the

cable

has

been

drawn

from

an

approved

contract, if not

on

DCN-f13819.

This item was completed

on October 5, 1990.

As

a result of the installation of unjacketed electrical

cable

the licensee

issued

additional

CARR/PRDs;:

BFP900376,

Okonite

Un-jacketed,

Type

PX Cable,

Mark

Number

WOV-2;

BFP900378,

Anaconda

Cable

Installation

in

System

90;

and

BFP900386,

Installation of Type

THHN Cable for Drywell Lighting.

These

three

CA(R/PRDs

indicated that

the root

cause

for the cable

installation

was that the corrective action for

PRD

BFP900189P

did not establish

necessary

controls to ensure notification of

employees

of the qualified cable list issued

by gDCN g13819A.

Due to this modification, Maintenance

Management

did not have

adequate

direction to train employees

in the use of the

ODCN.

These

items are considered

examples

of a failure to prevent the

installation of electrical

cables

not meeting design criteria..

0

13

This failure is

considered

a violation,

VIO 259,

260,

296/

90-40-04, Failure to Implement Design Control Measures.

1

(2)

In

IR 90-33,

the inspector

documented

the observation

of the

performance

of PMT-BF-268-006,

Test of RHR Valve '2-MOV-74-53A,

RHR Inboard Injection Valve.

The

PMT identified a problem with

a modification,

DCN

W10017A,

which

negated

a

previously'nstalled

Appendix

R modification.

The inspector

observed

a

recent-PMT involving DCN W14030,

which modified the Unit 1/2

4

KV Shutdown

Boards

and the Shutdown

Buses.

This portion of the

modification

required

that

the

four alternate

power

feed

breakers

to the four shutdown

boards

be tripped during

the'resence

of an accident signal.

This would prevent overloading

one of the

shutdown

buses.

During the performance of procedure

1/2-ETV-SMI-I-C-4, Functional

Test of

C shutdown

board,

the

alternate

breaker tripped free

and would not close.

The problem

was

traced

to

an

Appendix

R modification which modified the

breaker

to obtain electrical

isolation from the control

room.

DCN W14030 did not use the latest modification

DCA when it was

approved for installation.

These

items are considered

examples

of a failure to use

the latest

design

change when'installing

additional

modifications.

This failure is

a

second

example

of

VIO 259,

260,

296/90-40-04,

Failure to

Implement

Design

Control Measures.

b.

RPS Circuit Protector Modifications

On January 3, 1991, the

NRC issued

TS amendments

178,

184,

and

149 to

change

the

RPS circuit protector setpoints

for Units 1,

2,

and

3

respectively.

The licensee

had previously revised 2-SI-4. 1.B.16,

Circuit Protector Calibration/FT, to include the

new setpoints

and

placed the SI

on administrative hold until the

TS change

was issued.

During this reporting period,

the licensee

implemented modifications

WP 2460-90,

WP 2461-90,

and

WP 2462-90

to wire the underfrequency

relay contact in series with the time delay coil for each of the Unit

2 circuit protectors.

Modifications for Units

1 and

3 were completed

during previous

reporting periods.

The inspector

observed

portions

of the

performance

of

WP

2462-90

on

the

2Cl

and

2C2 circuit

protectors

and

WP 2461-90

on the 281 and

282 circuit protectors.

The

inspector

also

observed

the performance

of PMTP-BF-99.003

conducted

on the

2C1 circuit protector.

The

PMT corisisted of performing the

revised

SI to verify correct time delay operation,and

set the relays

to the

new setpoints.

No deficiencies

were identified during these

observations.

Prior to conducting

the

PMT on the

2C1

and

2C2 circuit protectors,

the

system

engineer

noted that the

2C1 circuit protector

had

been

wired incorrectly.

The licensee initiated an incident investigation

(II-B-91-008) to determine

the

cause

of the wiring error.

The

investigation

concluded

that

a wire was incorrectly removed during

the work, contrary to the written steps

in the workplan.

14

The licensee

took immediate action'o revise the workplan to correct

the wiring errors.

The modification was reperformed

and the

PMT was

conducted satisfactorily.

The inspector

observed

the performance of

the revised workplan.

No deficiencies

were observed.

This licensee

identified violation is

not

being

cited

because

the criteria

specified

in Sec'tion

V.G. 1 of the

NRC Enforcement

Policy were

satisfied.

This violation is identified

as

NCV 260/90-40-05,

Modifications Wiring Error.

.,c.

ECN

P0901.

This

design

change

provided

a

longterm

(72

hours)

alternate

source of nitrogen to the drywell control air header to be

used

in the event that the drywell control air compressors

are not

available

due to

a fire.

The modification installed

a

new one inch

sup'ply line

and

two manual

isolation

valves

to provide crosstie

capability between

the

B

CAD Tank and the compressor

discharge line.

Existing drywell penetration,

X-22, will still be used for drywell

control air.

The inspector

reviewed

the

ECN closure

package

and

observed

selected

portions of the installed

hardware

located in the

Unit 2 Reactor Building. The inspector

determined that the

ECN was

field complete

and in the closure

process

pending

NRC approval of TS

Change

251.

The

closure

package

included

identification

of

modification training

requirements.

Additionally the

inspector

verified that

2-0I-32A,

Drywell

Control

Air

System

Operating

Instruction,

2-AOI-32A-1, Loss of Drywell Control Air, and 2-0I-84,

Containment

Atmosphere

Dilution System

Operating Instruction,

have

been revised to reflect

TS 3.7.A.5 and 3.7.G.3 requirements

that the

B

CAD train

be considered

inoperable

(placing the plant in a 30 day

LCO) or when plant control air is

used

(placing the plant in a

24

hour

LCO) whenever

the crosstie

valves

are

open.

The inspector did

not identify any discrepancies

with this modification activity.

d.

.ECN P3176.

This design

change

replaced-existing limit switches

on

various

primary containment

isolation

with environmentally

qualified switches.

These

are required to isolate

primary

containment

on

a

LOCA.

The

ECN required

the replacement

of the

existing limit switches with Eg Snap-Lock type switches,

installation

of CONAN seals,

and installation of stainless

steel

braided flexible

conduit

and

seismic

conduit supports.

The design

change

was field

complete

and in the process

of being closed

by the licensee.

The inspector also reviewed portions of work plans 2182-87,

2326-89,

2079-89,

2080-89,

and

2351-89.

These

work plans

implemented

ECN

P3176.

With the exception of the problem with

WP 2182-87 described

in paragraph

3.b,

the inspector

did not identify any discrepancies

with this modification activity.

One violation and

one

NCV was identified in the modifications area;

C

15

6.

Post Modification Testing

(37700,

37828)

a ~

SBGT Decay Heat

Dampers

The inspector

reviewed

and

observed

the

PMT activities associated

with

DCN

W 10416A.

This

DCN installed

manual

decay

heat

removal

cross-tie

dampers for the standby

gas treatment

system.

Procedure

PMT-BF-65.2ll aligned

the

SBGT

and

manipulated

system

in order to achieve 'a throttled

decay

heat

bypass

damper

position.

When

the

decay

heat

removal

were

properly

throttled,

the design

flow required, to remove

decay

heat

from the

charcoal, absorber .would

be

achieved;

The

PMT

was

to provide

information that

damper

manipulation

would have

no effect

on the

required containment differential pressure.

Two TDs were identified during this

PMT.

TD-03 documented that

SBGT

Train A inlet damper leaked excessively

during the decay heat

removal

lineup for Train A.

TD-04 documented

that

SBGT Train

B inlet damper

also

leaked

excessively

during the

decay

heat

removal

lineup for

Train B.

The licensee initiated

CARR BFN 900015

and

NE dispositioned

this item as Use-As-Is.

The inspector also reviewed information that

during

a single failure event where

one of the three trains of SBGT

fails to start,

an excessive

amount of back flow'will go through the

idle train

due to excessive

leak-by through the back flow dampers.

No additional testing

was

performed

by the licensee

to determine if

the

two remaining operating trains

would achieve

the required flow

rate.

An additional

problem identified during

the

PMT,

was

that

the

licensee

could not verify that the following TS was met: 4.7.B.1.c.

"Air distribution is

uniform within 205 across

HEPA filters and

charcoal

absorbers."

The

inspector will followup on

these

test

deficiencies.

b.

DG Stationary Auxiliary Switch

The inspector

reviewed

and

observed

the

PMT associated

with

DCN

15894A.

This

DCN installed additional contacts

in parallel with the

stationary auxiliary switch for the shutdown

board A, B, C,

and

D,

normal supply breakers

and the

DG breakers.

The modification was originally for the Unit 3

DGs.

However, after

additional

review the licensee

determined

that the modification to

the Unit 3

DGs

was

not necessary

to support Unit 2 operations.

A

modification specifically for Unit 3

DGs will be installed prior to

Unit 3 restart.

The

PMTs were

BF 57.038

and

BF 57.039.

The first PMT was

performed

while the individual shutdown

boards

were deenergized

and the actions

of the

DG breaker

and the normal

feed breakers

could

be exercised.

During the performance of PMT 57.038,

the inspector

noted that when

16

the

DG breakers

were manipulated,

only two of the four logic relays

for initiating the start of the

RHR pump, the start of the

CS pump,

the start of 480V load

shed logic and the start of the

pump

actuated.

This

was

later

traced

to

an incorrectly installed

modification

performed

by plant

maintenance

personnel.

-.After

additional

review,

the

inspector

determined

that this

item

was

caused

by having inadequate

drawings

associated

with this modifica-

tion.

This item is identified as part of example

two of Violation

259,

260$ 296/90-40-04.

On violation was identified in the Post Modification Testing area.

7.

Electrical

Issues

- Cable Ampacity and Separation

(37700)

The

inspector

was

informed that

due to reviews

by

NE of System

31,

additional

cable rerouting/replacement

was

needed.

The review identified

at least

3 cables

buried in flammastic that must

be replaced

because

of

the

ampacity

issue.

The

cables

are

the

normal

feeder

to Ventilation

Board A, Shutdown

Board

Room

3B Supply

Fan,

and Battery Board

Room

C

Exhaust

Fan.

The inspector

was also

informed that

two additional

cables

'may require

rerouting/replacement.

One

cable is

a

System

31

and

the other is

a

System '57 cable."

These

cables

appear to be in the cable separation

issue,

with the control

power

and

the

power feed

cables

being supplied

from

different safety divisions.

The inspector will continue

to follow the

licensee's

activities

in this

area.

These:problems

are

apparently

centered

around 'application of the 9-list for these

programs.

No violations or deviations

were identified in the Electrical

Issues

area.

8.

System Pre-Operability Checklist

(71707)

The

inspectors

continued

to review the

licensee's

progress

in their

efforts to upgrade

the plant equipment

and documentation

to insure that

systems

are acceptable.to

support restart of Unit 2.

At the end of this

reporting period,

35 of the

38 systems

required to support fuel load have

been

completed

and

49 of the

78 required for Unit

2 restart

have

been

completed.

The

number of systems

required for each

phase is based

on the

licensee's

most

current

evaluation

as

listed

in the

Master

Star tup

Operations/Test

Instruction, 2-SOI-100-1,

Rev. 0.

The systems

reviewed

by the inspectors

during this reporting period are

listed

as follows:

a.

Control Air (System

32)

The

inspector

reviewed

the

package

for the

CA System

and

performed

a

walkdown of

a major portion of the

system

equipment.

This system

includes

both the

CA and the

DCA systems.

Four deferrals

were issued for items that could not be finalized due to restraining

plant conditions.

Each of the

4 were reviewed

and

none were found to

e

17

b.

c ~

impair system operability.

In addition, the engineering

summary was

reviewed

which concluded

that the configuration of this

system is

satisfactory to support restart of BFN Unit 2.

Based

on

a review of

the

system

by the inspectors',

no areas,

were identified to prohibit

system operability.

Annunciator and Sequence

of Events

Recorder

(System

55)

The inspector

walked

down this system which consisted of the control

room annunciators

and recorders

and reviewed the licensee

completed

SPOC documentation.

Part of the package'onsisted

of an update of

the work efforts

performed

during the latter part of 1989 for the

fuel load at that time. It was noted that only one deferral

remained

open

and

was

deemed

not to affect system operability.

Within the

areas

reviewed,

no deficiencies

were noted.

Auxiliary Electrical

(System

57)

The inspector

observed

and reviewed the licensee's

activities in the

SPOC processes

for the following auxiliary electrical

systems:

57-2 120/208 volt AC Distribution

57-3 250 volt DC Distribution

57-4 480 volt AC Distribution

57-5 4160 volt AC Distribution

The inspector

observed

walkdowns

performed

by licensee

personnel.

During these

walkdowns,

the inspector

noted that breaker maintenance

involving overload settings, modifications to insure cable separation

and breaker modifications involving the change

out of overloads

were

in progress.

Most of the breaker modifications involved Micro Verse

Trip installations.

Although these

activities

were

performed

on

numerous

switch gear,

the majority of activities were associated

with

the

systems

served

such

as

RHRSW,

RBCCW,

and

HVAC.

The switchgear

themselves

were viewed for SPOC

purposes

separately

from the systems

serviced.

The inspector

reviewed

the

PMs for the

systems

and

noted that of

eleven electrical

systems

involving 477

PM items.

These electrical

systems

included both safety related

and non-safety related

equipment

PMs.

Of the

477 items reviewed,

27 items

were considered

late

and

each late item had engineering

approval.

The inspector also reviewed

the status

of SIs

performed

such

as

the

DG operability,

common

accident signal,

480V load

shed,

and

DG load acceptance.

All SIs

were performed with minor changes.

The

inspector

reviewed

the

packages

which

included

the

exceptions

and deferrals.

The inspector

noted that

no unverified

assumptions

were

documented

as

being outstanding.

The inspector

reviewed

RTP Test Exception

No. I System 57-2, which documented that

TI-73B was not performed.

This TI verifies that the electrical

loads

on

panel 25-32,

Backup Control Panel, will transfer to the

120V

AC

18

Unit Preferred

Power. Source

when the transfer switches

are placed in

the emergency position.

Due to this panel

not being considered

as

a

part of System

57-2, the system

can

be returned

to service prior to

completion of TI-73B.

The inspector

noted that at the

end of this

reporting period, site

QA personnel

were reviewing several

CAQRs that

impacted

these

systems.

Reactor Building Closed Cooling Water (System

70)

The inspector

reviewed the completed

package for this system

on

December

20,

1990.

There

were

two ..exceptions

and four deferrals.

One exception

was taken

because

the drywe11

head must

be installed to

balance

the drywell ventilation systems

and associated

RBCCW supply

to the drywell coolers.

The

second

exception

was

because

of a

TS

change

to. add

the

RBCCW containment

isolation valves

to

TS Table

3.7.A.

For three of the deferrals all of the work was complete for

System

70,

but the

ECNs were not closed

due to remaining

work on:

other

systems..

The fourth deferral

was

a

RTP-70 test

exception

requiring

a

heat

load in the drywell to perform.

The inspector

concluded there

was

a logical basis for each exception

and deferral.

The inspector

noted that in the

SPAE Evaluation Checklist,

Attachment

E of

BFEP

PI 88-07,

numerous

signature

steps

were

marked

as

"not

applicable".

The steps

were denoted with a footnote that the step

was only required for SPAE packages

identified in Attachment I.

This

attachment

provided

the

system

mode descriptions

by system.

For

Revision

6 of PI 88-07,

dated

July 7,

1990,

RBCCW was listed in

Attachment I.

For

Revision 7, dated July 27,

1990,

RBCCW was not

listed

as

a separate

system.

This was

done apparently

because

the

only item to

be

reviewed

was

primary containment

isolation which

listed

System

70

under

primary containment,

System

64.

This

was

considered

a weakness

of the

SPAE review of System

70.

Several

open

issues

remained

with the

NRC concerning

RBCCW such

as

seismic

qualification outside the drywell and containment isolation valves at

the time of the system

SPOC.

Radiation Monitoring System

(System 90)

The radiation monitoring system consists

of various

CAMs, ventilation

and liquid effluent monitoring equipment,

and

ARMs.

This system

has

undergone

a series of major modifications during this extended

outage

which are further described

below:

W1073,

this

DCN replaced

many of the

chart

recorders

and

existing

CAMs associated

with the ten building effluent monitors

with newer

Eberline

equipment.

This

DCN is associated

with

equipment

that

is

necessary

to

support

fuel

load

and

is

substantially field complete.

H6910, this

DCN replaced

many of the chart 'recorders

and

existing

CAMs

not part of

DCN

W6910 with

newer

Eberline

equipment.

Various work still remains to complete for this

DCN

which is associated

with equipment that the licensee

does

not

consider

required

to support fuel load.

However the primary

19

containment

leak

detection

monitor,

2-RM-90-256,

which is

included in this modification has

been replaced

and tested.

P0354, this

ECN added

the

new Stack'ide

Range Monitor required

by

NUREG 0737.

This modification consisted of,,installation

a

substantial

amount of new equipment

and construction of a

new

building directly'djacent

to the plant stack

to house that

equipment.

Hl263,'his

DCN

was

associated

with the

main

steam

line

radiation monitors.

It replaced

the existing

GEMAC drawers

in

the control

room with newer

NUMAC components.

The

MSL radiation

detectors

and other

remote

equipment

located

outside of the

control

room was unchanged.

The

was delayed

due to numerous

problems associated

with the ten

building effluent monitors.

Many internal

wiring problems

were

discovered

during

system

setup/testing

which resulted

in

many

troubleshooting

work requests

and over 40

FDCNs.

The inspector

accompanied

licensee

personnel

during the final system

walkdown conducted

on January

7,

1991.

During the

walkdown the

following minor material deficiencies

were identified:

Although the

CAMs located

in the Reactor Building were mounted

to satisfy

seismic

requirements,

each

CAM is

equipped

with

wheels

to allow portability and

those

CAMs located

in the

Turbine Building are free to move.

The

new design

includes

an

apparent

permanent

installation with stainless

braided flexible

hoses

which does

not allow much

freedom for movement

and the

hoses

are therefore

subject to potential

damage

due to movement

during operation.

CAM 3-RM-90-249 already

had

a flex hose that

appeared

to

be

damaged

possibly

due to addition of

a quick

disconnect fitting.

During the control

room portion of the walkdown the inspector

noted that the 9-2 and 9-10 panels still include recorders

which

are associated

with online liquid effluent monitors which are

no

longer used.

Although offline monitors

are

now available

and

provide for monitoring of liquid effluents

and

the

online

monitors are

no longer in service

nor maintained with no plans

to ever

use

the online monitors, the control

room recorders

are

tagged

as temporarily removed

from service.

The inspector

was

informed

by licensee

personnel

during the walkdown that TYA's

policy was to abandon

equipment of this nature

in place rather

than

expend

the

money to

remove it.

The licensee

plans

to

'mplement

numerous

human factors

upgrades

to the control

room

during the next refueling outage

and the inspectors will follow

the licensee's

work in this area.

0

20

Based

on

discussions

with licensee

personnel

the

inspector

determined

that adequate

training

on the

new equipment

may not

have

been provided to operations

personnel.

This issue

was also

raised

by licensee shift management

personnel.

Although the

system

was accepted

by the plant staff with this deficiency,

a

representative

from Eberline

was onsite during this period

and

was

used

for

specialized

training

for

instrumentation

technicians

that perform work on this equipment.

Additionally,

the inspector

was informed that .a lesson

plan

had .been

developed

in this

area

and training for operations

personnel

was in

progress.

The

system

checklist

was

completed

on

January

13,

1991.

The

inspector

reviewed

the 'ompleted

package

with the

system

engineer

on January

15,

1991.

The inspector did not identify any

outstanding

problems

with the

system that affected operability to

support Unit 2 fuel reload.

f.

Cranes

and Hoists

(System

111)

The inspector

reviewed the licensee's

completed

System Checklist for

the efforts associated

with the cranes

and hoists.

This activity was

limited to four overhead

cranes

which were selected

on the basis that

each

could

be

used

to lift nuclear

and safety-related

materials

located

in areas

with materials

and

equipment

important to plant

safety.

The limited checklist

was further influenced

as

a result of

the cranes

and hoists

being maintained throughout the outage.

Only minor discrepancies

were identified during the

walkdown which

consisted

of two missing labels,

one minor repair

and

some cleaning

of the reactor building crane trolley.

Each

has

now been corrected.

NE evaluated

the

system

and

determined:

(1) that all primary and

critical drawings associated

with the system

were being evaluated

as

parts

of other

systems,

(2) the applicable

primary

and critical

drawings

have

been

computer-aided

drafted

restored,

and

(3)

no

drawing discrepancies

or outstanding

DCNs existed against

the system

and that the drawings for the system will support unit 2 operation.

Based

on the review,

no deficiencies

were noted.

No violations or deviations

were identified in the System Pre-Operability

Checklist area.

9.

Restart

Experience

Reviews

(71707)

The

inspectors

reviewed

the

licensee's

program

implemented

to

take

advantage

from the restart

experiences

at Peach

Bottom and Pilgrim Nuclear

Power Plants.

The experiences

consisted

of a list of 26 major problem

areas

to

be considered

during restart of those plants.

Those identified

were:

(1) major equipment failures

and preventative

actions that should

be

21

considered,

(2)

personnel

assignments

to critical specific

areas;

(3)

communication

enhancements

within the licensee's

organization

and with the

NRC, and (4) operational

precautions

to be aware of during power ascension

and testing.

The licensee

has

reviewed

each of the

26 major areas

identified.

A

letter

from the Technical

Support

Manager to the Plant Manager,

dated

December

10,

1990, stated

that

17 of the

26 items

have

been

implemented,

an additional

6 items will be

implemen'ted prior to plant startup,

and

3

of the

items

were not applicable

to

BFN. Within the

6 items identified

that were not completed,

some require specific plant conditions prior to

their performance

and those conditions

had not been

met prior to issuing

the subject letter.

,This effort will be

monitored

during

the

remainder

of the restart

'ctivities by the inspectors.

10.

Safety

Parameter

Display System

and Detailed Control

Room Design

Review

Audit

During November

13-15,

1990,

an

NRC audit team conducted

an onsite audit

of TVA's SPDS

and

DCRDR.

The results of this audit are detailed

below.

a

~

Safety Parameter

Display System

The

purpose of the

SPDS audit was to assess

the

BFN-2 interim SPDS

against

the requirements

in Supplement

1 to NUREG-0737 for an

SPDS.

The audit

team determined

that the licensee's

interim

met the

requirements

concerning

(1) continuous

display of safety

status

information,

(2) location convenient

to control

room operators,

and

(3) concise

display.

The audit

team

found that the

requirement

regarding

minimum information about

the five safety functions

was

satisfactory for the interim SPDS;

however, this requirement

would

not

be

completely satisfied

for the

operational

SPDS until the

licensee fulfills its

commitment

to provide additional critical

safety

function

parameters.

The audit

team

concluded

that

the

licensee

would

meet

the

requirement

and

procedures

when

the

licensee

satisfies

its

commitment

to

have

procedures,

and trains operators

with and without the

before

restart.

The requirement

and

electrical

interference

is currently under review by the Instrumen-

tation and Control

Systems

Branch

(SICB) of NRR.

The audit

team

determined

that the licensee's

interim

SPDS did not

meet

two of the eight

SPDS requirements

as follows:

( 1) rapid

and

reliable (e.g.,

unreliable

touch screens

and function keys,

unclear

how sensor

inputs with different rates

would be handled,

weaknesses

regarding

configuration

management,

and

clarifications

needed

concerning

security

controls

for

data

base);

and

(2)

incorporates

accepted

human factors principles (i.e., glare

on

22

I

cathode

ray tubes'nd

SPDS status

box

on display obscured

by the

anti-glare

hood when operator is standing).

The staff expects

that the noted examples of SPDS

system unreliabil-

ities, the glare

on the

CRTs,

and the .obscured

SPDS status

box,

will be resolved

prior to restart. of BFN-2.

Resolution of these

items will be followed

as

URI 260/90-40-06,

SPDS Reliability and

Human Factors

Concerns.

, b.

Restart

Human Engineering Discrepancies

The audit

team

concluded

that

TVA had satisfactorily

implemented

corrective actions for the nine restart

HEDs.

The results

were

as

follows:

(I)

HED

109

concerned

electrical

shock

that

operators

could

encounter

when

changing control

room annunciator light bulbs.

Two screws that hold annunciator light bulb mounting panels

in

place

are

located

very close to the

48V

DC buses

which supply

power to the bulbs.

The licensee

wrapped

the portions of the

buses

adjacent to the screws with electrical insulating material

to prevent personnel

from receiving shock while manipulating the

screws.

The staff found the corrective

action

adequate

to

resolve this

HED.

(2)

HED 201 indicated that operators

were required

by procedure

-to

determine if drywell pressure

had

reached

55 psig

on

a control

instrument that

had

a range of 0-40 psig.

The licensee

changed

the drywell pressure

instrument

range to 0-60 psig.

The staff

found that the corrective action satisfactorily resolves

this

HED.

(3)

HED 202

and

HED 292 concerned

EOI ambiguities.

The audit team

evaluated

a sample of these ambiguities

and determined that they

had

been

resolved

in subsequent

revisions of the

EOIs.

In

addition,

the licensee

implemented

a formal

process

to ensure

that revisions

to

EOIs

do not have

problems with clarity and

ambiguity.

This process

is

implemented

through

the following

PMIs:

PMI 12.6,

"Implementation

and Maintenance

of Emergency

Operating Instructions";

PMI 12.7, "Writers Guide for Emergency

Operating

Instructions";

PMI 12.8, "Verification of Emergency

Operating Instructions";

and

PMI 12.9, "Validation of Emergency

Operating Instructions".

The staff found that the licensee

had'atisfactorily

resolved

these

HEDs.

(4)

HED 283 concerned different zero references

for reactor

vessel

level

instruments.

The

licensee

changed

the

affected

instruments

to the

same

zero reference.

The staff found that

this

HED was resolved.

V

0

23

(5)

HED 287 noted that,

when

emergency

standby lighting is in use,

some

areas

of the control

room did not meet the design lighting

illumination level of 10 footcandles.

The licensee

modified the

emergency

standby

lighting

and

conducted

light illumination

surveys.

For those

areas

that still did not meet the lighting

illumination design criteria,

the

licensee

performed

a task

analysis -'and evaluation

of requisite

operator

actions.

The

results

of the evaluation

indicated that operator

tasks

would

not be impaired by,the reduced

illumination levels.

The staff

reviewed

the

task

analysis

and evaluation,

and

performed

a

walkdown of those

areas

having reduced

illumination levels

and

observed

what operator

actions

were required

to

be performed.

The staff determined

that operator

tasks

could

be performed in

the

reduced

illumination conditions

and

was satisfied that the

1'icensee

had corrected this

HED.

(6)

HED 290 indicated that-control

room indication regarding

steam

line flow was

inconsistent

with emergency

EOIs.

The licensee

completed

an

EOI

change

that provides

consistency.

The staff

found that this

HED was resolved.

(7)

HED

299

and

HED 300

concerned

an

EOI step

regarding

reactor

building differential

pressure

that

did

not specify

what

operator

action

was

required

and

an associated

control

room

annunciator with multiple inputs that was ambiguous with respect

to this procedure

step.

The

EOI step was~hanged

to indicate

what operator action should

be taken

and dedicated

annunciators

specifically for reactor

building differential

pressure

have

been

provided in the control

room.

The staff found that the

licensee

had satisfactorily resolved this

HED.

During

a Unit 2 Control

Room walkdown, the audit team observed that

two suppression

chamber

water

level

instruments,

2-LI-64-54A and

2-LI-64-66, with

a

range

from negative

25 to positive

2 inches,

lacked indication of negative

values.

The licensee

reported that

this discrepancy

was not identified during the

DCRDR.

In addition,

the

resident

inspectors

identified

in

IR 90-33 that

B

channel

recorder

XR-64-199

had

no units designation

label.

These

problems

will also

be tracked

under

URI 260/90-40-06,

SPDS Reliability and

Human Factor Concerns.

No violations or deviations

were identified in the

and

DCRDR area.

ll.

Local Leak Rate

Rate Testing

(61720)

The inspectors

continued

to follow the progress

of the licensee's

LLRT

program.

As of January

10,

1991,

51.4X of the individual

LLRT tests

required

to

be

completed prior to performance

of the

ILRT have

been

completed.

The

ILRT is presently

scheduled

to be performed

on March 16,

1991.

24

The

inspectors

monitored portions of LLRT testing

associated

with four

of the eight

MSIVs.

This testing

was

performed

on January

6,

1991.

This testing

was

performed

in accordance

with 2-SI-4.7.A.2;i-3/la,

A

. Main

Steam

Line

LLRT, associated

with 2-FCV-1-14

8

2-FCV-1-15

and

2-SI-4.7.A.2.i-3/1b,

B Main Steam Line LLRT, associated

with 2-FCV-1-26

8

2-FCV-1-27.

This testing is intended to satisfy

ASME Section

XI testing

for leak tightness

in accordance

with TS 4.6.G

and

TS Definition 1.0.MM

along

with verification of primary

containment

operability

per

TS 4.7.A.2.i.

The stated

acceptance

criteria

shown in the SIs is 11.5

SCFM

while maintaining

a minimum pressure

of 26 psi.

The two SIs observed

by

the inspector failed the above acceptance

criteria with 149.7

SCFM for MSL

A and

81.7

SCFM for

MSL B.

Subsequent

testing

on

MSL" C also

ended

with unsatisfactory

results.

As the result of the unsatisfactory

LLRT

results

the

licensee

performed

various

corrective

measures

such

as

stroking of the valves,

attempts

at flushing of the valve seats,

and

disassembly

and maintenance

of valve internals for the inboard

MSIV on

MSL

C.

Licensee corrective action

was still in progress

in this area at the

close of .this reporting period.

The inspectors will continue to follow

licensee

actions

in this area.

No violations or deviations

were identified in the

LLRT area.

The inspectors

reviewed various

completed

essential

calculations

selected

from the Calculation

Cross

Reference

Information System printout.

The

calculations

were reviewed for a partial

check of mathematical

equations

and to determine

the adequacy

of the licensee's

methodology

and approach.

The inspectors

also verified that inputs

and assumptions

were current

and

valid, and that they reflected

the controlling conditions with reasonable

results

considering

the inputs,

method,

and objectives.

The calculations

reviewed were

as follows:

a

~

b.

ND-(0064-890010,

Revision

1, Secondary

Containment/Zonal

Boundaries.

This calculation

defines

the

secondary

containment

boundaries

and

zonal separations

to provide

a technical

basis for future studies

and

modifications which identify penetrations

that breach

a boundary.

No

deficiencies

were identified.

ND-(2063-890014,

SLC System

Boron-10 Necessary

to Meet

10 CFR 50.62

Requirements.

This calculation

was

performed

to determine

the

minimum amount of boron-10

and the minimum volume of enriched

sodium

pentaborate

necessary

to respond

to an

ATWS event.

No deficiencies

were identified.

co

BFN-BF53-003,

Systems

Required for Fuel

Loading.

This calculation

was performed to identify the systems

required to be evaluated

by the

DBVP prior to fuel loading for Unit 2.

The calculation listed the

Unit 2 systems

necessary

to mitigate accident and/or transient

events

during fuel

movement.

Through discussions

with licensee

personnel,

the inspector

found that the calculation

was performed to support the

0

25

fuel

load conducted

in 1988

and not the cur'rent

SPOC process.

For

this reason,

the licensee

placed this calculation in the archives for

history only.

This calculation

was not used to support

the current

core reload.

No violations or deviations

were identified in the

area of Essential

Design Calculations.

13.

Operational

Readiness

Review (93806)

The

inspector

reviewed

the

status

of the

licensee's

program

for,

implementation

of corrective actions

associated

with concerns

identified-

as

part of the licensee's

ongoing

ORR program.

TVA's

ORR program

was

designed

to be

a comprehensive effort to assess

the material

and personnel

readiness

at Browns Ferry necessary

to support

safe plant operation.

The

ORR

team

has

conducted

two phases

of their review of Browns Ferry's

operational

readiness.

The first phase

was performed during May 1989 with

the results

documented

in

an interim report

dated

June 9,

1989.

The

second

phase

was

performed

during February

1990.

A total of 47 general

concerns

with 501 associated

action items were identified during these

two

-phases

of review.

These

items

are tracked

on the licensee's

TROI system

along

with other

corrective

and

administrative

control

programs.

According to the licensee's

ORR status

report dated

December

21,

1990, the

corrective

actions,

have

been

completed for. 64K of the concerns

and

92K of

the individual action items.

The inspector

selected

several

individual action items from the

TROI that

the licensee

has listed as having corrective action complete.

These

items

were

reviewed

to determine

adequacy

and extent of licensee

corrective

actions

in each

area.

A manager

has

been

assigned

responsibility for

coordination of the corrective actions

in this area

and closure

packages

have

been

prepared for many of the items.

Those individual action items

reviewed along with the inspector's

comments

are listed below.

Phase II Concern

A Item

P2.

During the

ORR team's

review of the

licensee's

self

assessment

program, it was

noted

that

routine

observation

checks

by non-shift operations

managers

were not being

performed

as

required

by the licensee's

program.

The inspector

examined

documentation

that verified the

performance

of routine

observation

checks

performed

during

the

period of November

and

December,

1990.

These

observation

checks

were

performed

by both

operations

shift

management

and

non-shift

management

personnel.

Several

were

performed

by

the

Operations

Superintendent

and

Operations

Manager.

The inspector

believes

that the original

ORR

concern

has

been adequately

addressed.

Phase II Concern

B Item h2.

During the

ORR team's

review of General

Operating

Instructions, it was

noted that the plant procedures

for

shutdown

from powered operation

to cold shutdown,

2-GOI-100-12A and

2-GOI-100-12C,-

placed

the unit in

a condition requiring very careful

operator action to ensure

the reactor

remains

shutdown during plant

.26

cooldown.

The

GOIs

had

been

revised to,eliminate

a reactor

scram

from about

30K power requiring fully inserting all control

rods per

the rod program

as

the normal

means of plant shutdown.

Cooldown was

permitted

to start

as

soon

as

the reactor'as

taken subcritical.

This

concern

for difficulty in

balancing

the effects

of rod

insertion,

heat

removal,

decay

heat

generation,-

and

Xe buildup is

significant considering

the recent event that occurred at another

BWR

where

an inadvertent criticality occurred

while conducting

such

a

cooldown.

The inspector

reviewed the closure

package for this item

and held discussions

with members of licensee

management.

Although

the licensee

has

not reached

a final decision

concerning

the exact

method of control rod insertion to be used during plant shutdowns

and

a revision to the

GOIs

may

be required

in this area,

the

above

licensee

procedures

hav'e

been .revised to include caution to not begin

forced

cooldown until all control

rods

are full in.

The inspector

believes that the original

ORR concern

has

been adequately

addressed.

Phase

II Concern

D

Item ¹1.

During the

ORR team's

review of

resolution

of various

identified technical

issues,

a

concern

was

identified where

an item that

had previously been identified during

'the

Phase

I

ORR

review

had

not

been

aggressively

pursued

to

completion.

This item associated

with Category

I

GE SIL 419 issued

in August

1985,

which recommended

the inspection of certain

one inch

Hancock

gate

valves

in the

HCU.

The planned

inspections

had

been

postponed

due to lack of parts after having

been

delayed for over

four years.

The

inspector

reviewed

the

closure

package

which

contained

documentation

to verify the

completion of this

item.

Specifically the inspection of al,l

185 gate valves

(2-HCV-85-617)

had

been

completed

by July 30,

1990,

under

WO 90-04598-00.

As the result

of the inspections

various cracked,

broken or otherwise

damaged

valve

wedges

were identified.

A total of 63

(34%)

wedges

had

to

be

replaced.

The inspector believes that the original

ORR concern

has

been adequately

addressed.

Phase

II Concern

D

Item ¹5.

During the

ORR team's

review of

resolution

of various identified technical

issues,

a

concern

was

identified during

a partial simulator validation of 2-GOI-100-lA and

2-GOI-100-1C.

The

GOI

and

SI referenced different power levels at

which the

Intermediate

Range

and

Average

Power

Range

Monitors

overlap

is verified.

The inspector

reviewed

the closure

package

which contained

documentation

that verified that both of the

above

GOIs

were

revised

to clarify the

requirement

for verification of

proper overlap prior to exceeding 5l power by a visual

check of IRMs

and

APRMs instead of performing 2-SI-4.1.8.1,

IRM Calibration.

The

SI is

now required to be performed at

10-25'A power.

The inspector

believes that the original

ORR concern

has

been adequately

addressed.

Phase II Concern

E Item ¹6.

During the

ORR team's

review of the

licensee

s line organization/training

interface, it was identified

that

revised

reactor

water

level

curves

were

needed

to support

27

training

on the modified water level instrumentation.

During the

extended

outage

reactor

vessel

level

instrumentation

lines

were

relocated

as part of ECN-7131.

These

curves

had not been

prepared

by

NE although

the training was in progress.

Senior

NE management

was

not aware of the critical need for this information.

The inspector

reviewed

the

closure

package

which contained

NE

memo

to Plant

Operations

(R62

901101

891)

dated

November

1,

1990,

which provided

the required curves.

Training for operations

personnel

to cover this

information is scheduled

to be provided during the licensee's

restart

training during the

r equalification cycle starting

February

11,

1991.

The

inspector

believes

that

the original

ORR

concern

has

been

adequately

addressed.

Phase II Concern

H Item'3.

During the

ORR team's

review of the

license'e's

Preventative

Maintenance

Program, it was identified that

one monthly

PM had not been

performed in an extended

period of time

even

though

the

system

had periodically been

in service

during the

period while fuel

was

in the reactor

vessel

during

1989.

The

inspector

reviewed the licensee's

closure

package

on this item..

The

licensee

had closed this

item based

on the fact that although

the

RHRSW system

had

been

in service several

times during that period it

had

been for only short periods

and the total accumulative

service

time

was actually minimal.

The

PM,

RHRSW Flow Blockage Monitoring

Measurement,

has

no performance criteria

and is performed to record

differential pressure

data

which would~ be

used to identify adverse

trends

during normal operation.

The licensee further stated

in the

closure

package

that the

PM would be performed for baseline prior to

fuel load.

The inspector

determined

from discussions

with licensee

personnel

that

this

PM

was

originally scheduled

for early

January

1991,

but had

been

delayed

and is scheduled

to be performed

prior to=-fuel load.

The inspector will continue to follow the licensee's

progress

in this area

by reviewing more completed

ORR items during the next reporting period.

14.

Reportable

Occurrences

(92700)

The

LERs listed

below were

reviewed

to determine if the

information

provided met

NRC requirements.

The determinations

included the verifica-

tion 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 for Units

1

and

2 only)

LER 296/85-20,

Failure to Install

Core Spray Hanger.

This

LER concerns

the July 21,

1985 discovery that

a pipe support

(No.

H-81)

had

not

been installed

on the Unit 3

CS system

10-inch

0

28

pump test line as

required

by the

system

design

drawings.

The

LER

indicated that

an engineering

evaluation of the condition determined

the line to be seismically qualified'but that it could not be shown

to

be qualified for the

loss of coolant accident

induced

torus

hydrodynamic loads.

The licensee

attributes

the

cause

of the

LER to the

process

then

being utilized,for the revision

and

issuance

of plant drawings. It

appears

that the system in place at the time allowed for the issuance

and revision of drawings without an attendant

revision to the

ECN

data

sheet.

This introduced

the potential for incorrectly closin'g

,

out

an

ECN prior to completion of wor k scope

changes

that might have

arisen

subsequent

to the initial issuance

of the

ECN.

The following procedures

and/or

procedure

changes

have

since

been

implemented to correct the noted process

deficiencies:

Procedure

SDSP-8.4,

"Modification Workplans" has

been revised to

require all

work plans

to contain

marked-up

drawings

to

be

utilized

and

an associated

drawing list which references

all

drawings required to implement and/or inspect

a modification.

The design control

process

is presently

managed

via NEP-6. 1 Rl,

"Change

Control" (Revision

0 issued 7/I/86).

Attachment I to

NEP-6. 1

Rl requires

that

when

adding,

deleting or changing

information about

a drawing, the associated

Data Sheet revision

number

be entered

on

Forms

10575A and

10575E.

On

December

17,

1990

the

NRC inspector

visually inspected

the

counterpart

locations

on the Unit I and Unit 2

CS system test lines

and ascertained

that the required

supports

were in place

in the

comparable

area

where support

H-81 was found missing

on Unit 3.

This

item will remain

open for Unit 3 pending installation of the missing

support

scheduled

to take place prior to Unit 3 startup.

Thi.s item

is closed for Units I and 2.

(CLOSED)

LER 259/87-31,

Procedural

Inadequacy

Results

in Start

of,

Control

Room Emergency Ventilation System.

This event

was

an automatic start of the

CREV system

as

a result of

inadequacies

in a restart test procedure

being utilized on December

4,

1987 to align

4

KV electrical

boards for maintenance.

It appears

that the restart

procedure

did not specify

a desired position for the

4

KV shutdown

boards

A and

B transfer switch.

After the alignment of

the electrical

boards,

4

KV shutdown

boards

A and

B were left

connected

to their alternate

power sources.

In the

absence

of

a

procedurally prescriptive position,

the operator

placed the transfer

switch for 4

KV shutdown

board

A in automatic.

This resulted

in a

transfer of the

board

back to its normal

power supply.

During the

transfer,

the

undervoltage

relay for the

480V shutdown

board

IA

tripped ultimately causing

normally energized

radiation monitoring

0

29

equipment

serving the control

bay ventilation duct to trip, thereby

resulting in'he completion of the

CREV start logic.

A commitment to revise the restart test procedure

to specify transfer

switch position is contained

in the licensee's

LER submittal.

This

revised restart test

procedure

was successfully

run and its results

were

approved'- by the licensee's

Joint Test

Group

as

documented

in

Meeting Minutes88-062.

Considering that after the successful

run of the revised restart test

procedure its

use is

no longer required,

the licensee

expanded their

corrective action to include

a review of all other existing plant

procedures

whose

present

and future

use is contemplated,

and which

are associated

with 4

KV shutdown board alignments to ensure that the

desired

position of the

subject

transfer

switches

is adequately

addressed.

This additional

procedure

review was

conducted

by the licensee

and

resulted

in

no adverse

findings.

A statement

to this effect

was

included

on January

16,

1991

in the licensee's

closure

statement

package for this

LER by cognizant

TVA Licensing

and Transmission

and

Customer Services

engineers.

Based

on

an

examination

of the

above

reviews,

the

inspector

determined

that the

concerns

associated

with this event

have

been

adequately

addressed.

(CLOSED)

LER 259/89-09,

Single

Failure of Electrical

Fire

Pump

Lockout Relay During LOP/LOCA Could Overload

a Diesel Generator.

This

LER details

a condition in which, during

a LOP/LOCA, the single

failure of

a lockout relay intended to prevent the starting of the

.

fire pumps during

a LOP/LOCA, could cause

the overloading of a single

diesel

generator.

Aspects of this

LER were previously reported

in

NRC IR 90-33 during

the

followup

and

closure

of

VIO 89-27-04.

The

circumstances

associated

with this

LER had

been

presented

in the violation as

one

of three

examples of an apparent failure to report.

An NRC Region II

letter

dated

November

2,

1990

expressed

concurrence

with TVA's

commitment

to install

an

additional

lockout relay

as

adequate

corrective

action for the conditions

described

in the

LER.-:;: As

indicated

in

NRC

IR 90-33,

an

inspector

had verified field

installation of the additional lockout relay noting that

PMT remained

to be performed prior to closeout of DCN PW6909A.

Procedure

O-SI-4.11.B. l.f, Simulated

Automatic

and

Manual Actuation

of the High Pressure

Fire

Pump System,

was performed

on December 4,

1990.

A functional test of the lockout relays

was performed via step

7.6 of the surveillance instruction.

Block 23 of the Retest Control

Form

(Form

SDSP-417)

was

signed

on

December

7,

1990

by the

system

30

engineer

and the systems

supervisor attesting

to the completion

and

satisfactory

approval of the results of the surveillance test.

(CLOSED)

LER 260/89-29,

Failure of Residual

Heat

Removal

Service

Water

Sump

Pump

Level Switch Resulted

in a Condition Prohibited

by

Technical Specifications.

On

December

21,

1989,

an

AUO identified that the

number of

pumps

was

less

than

the

number

required

by TS.

The

pump

inoperability was

the result of the loss of'wo redundant

B series

pumps.

The

B series

pumps

are considered

to be

technically inoperable'ithout

the support of their associated

pump.

The

AUO determined

that the automatic start feature of the

redundant

pump

Bl failed

and

caused

the

pump

room to,

overfill..

Sump

pump

B2

was

tagged

out for maintenance.

The

AUO

changed

the control

switch position of the

RHRSW sump

pump Bl from

automatic

to manual.

The

pump started

and the water level in

the

10 CFR 50.73(a)(2)(i)(B).

returned

to

normal.

The control

room operator

was

subsequently

notified of the

event.

It was

determined

that

TS 3.5.C.7

was violated

and the event

was reportable in accordance

with

Based

on the event,

LER 50-260/89-29

was

issued.

The

inspector

reviewed

the

corrective

action

and

associated

documentation

provided

in

the

closure

package.

The

licensee

determined

that

the

event

resulted

from

a failure of the level

switches

associated

with the

pumps.

The licensee

reviewed

trend

data

and

determined

that existing switches

had

a history of

unreliability.

The licensee

issued

DCN H3916 to replace

the

pump level switches.

The inspector verified that all changes

associated

with this

DCN were complete.

(CLOSED)

LER 296/90-04 Rev.l,

Unplanned

Engineered

Safety

Feature

Actuation.

This event occurred in connection with the anticipated

deenergization

of the

3B

bus occurring during the October 20,

1990 transfer of

the

3B 480V

RMOV board to its alternate

supply.

The deenergization

of the

3B

bus

was

an expected

occurrence

since at the time it was

on its alternate

supply transformer

and

a board transfer

under these

circumstances

results

in

a trip of

RPS circuit protectors

3CI anJ

3C2.

The

deenergized

bus

caused

anticipated

isolations

of

ventilation

systems

(PCIS

Group

6)

and

the

outboard

RWCU system

isolation valves

(PCIS Group').

However, during verification of the

expected

PCIS

isolations,

the

licensee

noticed

that

RWCU valve

3-FCV-69-1, inboard isolation valve,

had also closed.

The closure of

this valve was not anticipated

in association

with the deenergization

of

bus

3B.

Further investigation

revealed

that the valve

had

closed

due to

a blown fuse

(16A-F60C) in conjunction with the

3B

bus deenergization.

The blown fuse

was

caused

by a coil failure on

relay l6A-K60C.

As

a result of annunciator

"PNL 9-47

Fuse Failure"

31

being

sealed

in

due to various modifications

and

hold orders

in

effect at the time,

and

due to the design inability of this multiple

device monitoring annunciator

to re-alarm

when

more than

one fault

has occurred,

Operations

was

unaware of the existence

of the failed

fuse at the time of transfer of the

3B 480V

RMOV to,.its alternate

supply.

This 'inability of the

main control

room annunciator

to

"re-alarm"

was, specified

by the licensee

as

the root cause

of the

event.

The licensee

stated

that .this condition could not occur

on Unit 2

since

as

a result

of

CRDR

recommended

modifications

the

RWCU

isolation logic is provided with a specific annunciator

in contrast

to the general

fuse failure alarm presently provided for Unit 3.

The

licensee's

immediate

corrective

action

was

to replace

fuse

16A-F60C

and relay

16A-K60C.

The licensee's

long term corrective

action

is to install

reflash

capabilities

for annunciators

with

multiple inputs.

This program is currently being tracked

by the

CRDR

Group

as

HED 0113.

The licensee

has

scheduled

completion of this

long term corrective action for Units

1 and

3 prior to the startup of

each unit and for Unit 2 during the cycle

6 refueling outage.

The failure to report this event to the

NRC as

an unanticipated

ESF

actuation,

within 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months of occurrence,

was cited

as

an apparent

violation of regulatory requirements

in IR 90-33

(VIO 90-33-01).

Based

on the inspector's

review of the licensee's

LER submittal

and

event

report

II-B-90-122,

in addition to discussions,

held with

various'icensee

personnel

associated

with this event,

the inspector

determined

that the licensee's

evaluation

and corrective action for

the event are adequate.

I'CLOSED)

LER 259/90-09,

Failure to Perform Surveillance

Instruction

Within Required

Periodicity

Places

Plant

Outside

the

Technical

Specifications.

This event originated

from the incorrect changing of the performance

date for 1-SI-4. 11.A.3, Monthly Functional

Test of

Non-Supervised'larm

Circuits

which

caused

a violation of the

allowable

TS

surveillance test performance

extension of 25 percent

and resulted in

the failure to provide appropriate

compensatory

actions for the

smoke

and

heat

detection

circuits

during

the

September

30,

1989

to

October 4,

1989 period.

Personnel

error is listed

as

the root cause

of the event.

'The

cognizant fire protection section engineer

entered

the wrong date for

the SI performance

completion resulting in no change

in the SI band

for the next scheduled

performance.

Subsequently,

without notifying

the

Work Control

personnel,

on

October

14,

1989

the

cognizant

engineer

changed

the

completion

date

on the

SI review form from

September

1, 1989,to August 23,

1989, in addition to maintaining in

32

his possession

the original copy of the SI for closure of open TDs.

A work control

technician

discovered

the

discrepancy

when

the

original

package

was

ultimately

received

for closure

and

transmittal

to permanent

records.

As immediate corrective action,

the licensee

reviewed approximately

.

70 fire protection

SI packages

(approximately half of which had been

processed

by the involved 'FP cognizant engineer)

to determine if any

other inconsistencies

were noted

between

logged performance

date

and

other information in the SI.

No inconsistencies

or inadequacies

were

found.

TVA is

unable

to take

any personnel

action since

the involved

FP

cognizant engineer is

no longer employed at

BFNP.

At the

time of the event,

PMI 17.1,

Conduct of Testing,

did not

contain

the

necessary

controls

to prevent this type of event

from

occurring.

As part of the corrective action,

the licensee

issued

procedure

PNI 17.12, Surveillance

Program Implementation.

Step 4.8.6

of this procedure

requires, that tests with TDs be promptly reviewed,

'igned

and submitted to Work Control;

Step 4.8.8 requires

the Work

Control section to verify that the SI performance

date is consistent

with information on the SI Review Form. prior to entering data in the

scheduling

system;

and

Step 4.8.9 stipulates

that the

Work Control

section is to be notified 'immediately, if, during the review cycle,

any information

on

an SI is changed that could have any impact on SI

scheduling

or work. control.

Although the inspector

determined that the corrective actions .taken

for this specific event,

were

adequate

to satisfy the identified

concerns,

an

assessment

of the

adequacy

of corrective

actions

associated

with broader

concerns

over inadequacies

in the overall

surveillance

program (of which this event

represents

an additional

example)

documented

in

IR 89-43, will be

performed

during

the

followup of the licensee's

response

to VIO 89-43-01.

(CLOSED)

LER 259/90-15,

Unplanned

ESF Actuation Caused

by Personnel

Error.

On September

16,

1990

an unplanned

ESF actuation

occurred

when

1D

autostarted

after receiving

a low reactor water level

ECCS initiation

signal.

The

leads

to level indicating switches

2-LIS-3-58C

and

2-LIS-3-58D were

undergoing

Raychem Splicing

when

a

DG autostart

signal

came in causing

the

DG to start.

The splicing activities were

performed

while

the

associated

circuits

were

thought

to

be

deenergized.

The

Impact Evaluation

Sheet

associated

with the work

orders

being

implemented,

had incorrectly specified

the work as