ML18033A939

RHR configuration

control

continues

to

be

a problem.

A violation was identified for

not

maintaining

the

TS

required

number

of

operable

Loops,

paragraph

4.

Examples

were

found where

the licensee

has not been conservative

in

submitting

LERs within 30 days of the discovery of the event per

10 CFR 50.73.

The

approach

has

been

to fully analyze

an

event'+j()/LIVE

>2>4 ~;:~080/

I='Dt i

tlfIC'LK

O"OOOO

I;!

F Ei('

prior to submitting.a

LER although indication exists of

a problem

when the event is discovered.

A violation with three

examples

for

failure to submit

a

LER within 30 days of the discovery of the event

was identified, paragraph

6.

REPORT DETAILS

Persons

Contacted

Licensee

Employees

0. Zeringue, Site Director

~G. Campbell,

Plant Manager

R. Smith, Project Engineer

J. Hutton, Operations

Superintendent

"A. Sorrell, Maintenance

Superintendent

D. Nims, Technical

Services

Supervisor

G. Turner, Site guality Assurance

Manager

P. Carier, Site Licensing Manager

"W. Ivey, Acting Compliance Supervisor

J.

Corey, Site Radiological

Control Superintendent

R. 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 Resident Staff

J

D. Carpenter,

Site Manager

C. Patterson,

Restart Coordinator

E. Christnot,

Resident

Inspector

M. Bearden,

Resident

Inspector

K. Ivey, Resident

Inspector

Attended exit interview on July 14,

1989

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

Maintenance

Observation

(62703)

Plant

maintenance

activities

of

selected

safety-related

systems

and

components

were observed/reviewed

to ascertain

that they were conducted

in

accordance

with requirements'he

.following items were considered

during

. this review:

the limiting conditions for operations

were met; activities

were

accomplished

using

approved

procedures;

functional

testing

and/or

calibrations

were

performed prior to returning

components

or

system

to

service;

quality

control

records

were

maintained;

activities

were

accomplished

by qualified

personnel;

parts

and

materials

used

were

properly certified;

proper

tagout clearance

procedures

were

adhered

to;

Technical

Specification

adherence

and

radiological

controls

were

implemented

as requi red.

Maintenance

requests

were reviewed to determine

the status of outstanding

jobs and to assure

that priority was assigned

to safety-related

equipment

maintenance

which might affect plant safety.

The inspectors

observed

the

maintenance activities listed below. during this report period:

a.

Maintenance

of Diesel Generators

The

NRC inspector

reviewed

ongoing

maintenance

activities involved

with the Unit 1/2 "B" DG. These activities

were initiated

by eight

MRs

and

one minor modification.

The

MRs included activities

such

as

replacement

of stripped bolts,

megger

and

high potential

testing of

DG

output

electrical

cables,

governor

booster

pump

check

and

crankcase

pressure

switch

retorquing.

The

minor

modification

involved the installation of

a thermowell

and temperature

indicator

in

the

'DG

cooling

system

and

is

discussed

in

more

detail

in

paragraph 5.b.'he

review of the

MRs indicated that the work to be

done

was clearly stated

and that applicable

plant

procedures

were

referenced

such

as

SDSP

6.9,

"Cleanliness

of Fluid System",

and

PNI-6. 10,

"Maintenance Material Control."

The

NRC inspector

observed

the activities

in the field for the

following NRs:

(1)

MR A898156

This

MR required the meggering

and high potential testing of the

DG output electrical

cables

from the generator

to the

"B" 4160V

shutdown

board.

The activities

were

governed

by

procedure

SEMI-65,

"Special

Megger

and

DC High Potential

(20 KV),Test."

The responsibility for the overall

work was

assigned

to the

site

modifications

group.

The

actual

performance

of

the

meggering

and

high

poting,

using

appropriate

M&TE,

was

completed

by the

TSC group.

All personnel

were familiar with

thei r particular job assignments;

and the testing

was

successful.'2)

MR A874405

This

.MR required

that

the

OG

crankcase

pressure

switch

be

checked

and that

the bolts

holding

the

switch in place

be

adequately

torqued.

This activity was

governed

by procedures

CCI-O-PS-82-038,

"Emergency Diesel

Generator

Crankcase

Pressure

Switch

Calibration",

and

SIMI

301.4,

"Special

Instruction

Troubleshooting

Maintenance

Instruction",

and

required

the

participation of

a

gC inspector.

All personnel

were

fami 1'iar

with

the

procedures

and

showed

knowledge

in their

work

assignments.

(3)

NR A874587

This

required

the

calibration

of

a

pressure

switch

on

the

starting air

system

air

compressor

for the

DG starting air

banks.

This activity

was

governed

by procedure

SCI

202.6,

"Standard

Calibration Instruction

For Mercoid Control

Series

D

Pressure

Switches."

The Heise

pressure

indicator

used

by the

technicians

was within its calibration

period.

The

personnel

appeared

to be knowledgeable

in the job assignments.

b.

Fuse

Replacement

The

licensee

reported

an

unplanned

ESF actuation

to the

NRC per

10 CFR 50.72

on July

2,

1989

when Unit

2 received

a

containment

isolation

actuation

from the

reactor

and

refuel

zone

radiation

monitors.

This

unexpected

actuation

was

caused

by

the

deenergization

of. the monitor power supplies during fuse replacement

activities.

An

improperly

placed

jumper

which

was

intended

to

prevent

an

actuation

resulted

in the

loss of power to the

power

supplies.

Although the licensee

is still investigating the

cause

of

the event,

the

NRC inspector

was informed that the fuse replacement

activities performed in accordance

with MI-92 failed to insuqe that

the

jumper

was

properly

placed

prior to the

fuse

removals

This

occurred

notwithstanding

the

requirement

for

two

party

performance.

The

NRC

inspector

was

informed

that

a

possible

deficient

maintenance

instruction

and/or

drawings

which

did

not

explicitly show the ci rcuits could

have contributed to the failure.

Inspector

Followup Item 260/89-27-01,

Fuse

Replacement

Jumpers, will

be opened

pending further review of this event.

Followup of NRC Bulletins (92701)

(CLOSED) IEB 87-01, Thinning of Pipe Walls In Nuclear

Power Plants.

On August

31,

1988 the

NRC issued its Safety

Evaluation

Report

on the

response

of Browns Ferry Nuclear Plant to

NRC Bulletin 87-01, Thinning of

Pipe Walls in Nuclear

Power Plants

(TAC 00225,

226, 227).

The

NRC staff

reviewed TVA's past activities and plans for this topic and found them to

be

programmatically

acceptable.

The

inspector

reviewed

plant

procedures

that

were

developed

in

response

to the

IEB for monitoring

susceptible

areas

of corrosion/erosion

and the trending of results.

The

procedures

2-TI-140,

"Pipe Wall Degradation

Monitoring Program for Dual

Phase

Systems,"

and 2-TI-148, "Pipe Wall Degradation

Monitoring Program for

Single

Phase

Fluid Systems",

were found to be acceptable.

This bulletin is

considered

closed for Unit 2 only.

4.

Operational

Safety Verification (71707)

The

inspectors

were

kept

informed of 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;

onsite

and

offsite

emergency

power

sources

available

for

automatic

operation;

purpose

of temporary

tags

on equipment controls

and

switches;

annunciator

alarm status;

adherence

to procedures;

adherence

to

limiting conditions

for

operations;

nuclear

instrument

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

positions

and

system

alignment;

snubber

and

hanger

conditions;

containment

isolation

alignments;

instrument

readings;

housekeeping;-

proper

power supply

and breaker

alignments;

radiation area

controls;

tag controls

on

equipment;

work activities

in progress;

and

radiation

protection

controls.

Informal

discussions

were

held

with

selected

plant personnel

in their functional areas

during these tours.

The

NRC

inspectors

reviewed

the

following issues

during this report

period:

a

~

A fai lure to maintain

TS requirements

for operabl'e

RHR Loops

The licensee notified the

NRC per

10 CFR 50 '2 at 10:33 a.m.

on June

23,, 1989 of .a condition which occurred

due to the licensee's

failure

to properly perform required

surveillance

testing

on

Loop II of the

Unit 2

RHR System. on June

18,

1989,

when the

RHR Loop II was declared

On May 22,

1989, operations

personnel

had requested

that the due date"

for 2-SI-3.2.2,

"Valves Cycled During

Cold

Shutdown",

be

extended

from its

scheduled

due

date

of

- May

26,

1989,

to its

maximum

allowable extension

due date of June

17,

1989.

This extension

had

been

approved

by plant

management

and

had

been considered

necessary

to allow a procedure

revision to reflect color changes

in the valve

and disc position indicating lights resulting

from a recent control

room

design

review.

On

June

8,

portions

of

2-SI-3 '.2

we'e

performed.

This

SI

performance

included testing

the

RHR and

Core

Spray primary containment

inboard

check valves

as

directed

by the

ASME Section

XI system

engineer.

This partial

SI

was

completed.

However,

Test

Discrepancy

¹2 identified that

scaffolding

in

the

drywell

prevented

installation

of

hoses

necessary

to test

the

Loop II testable

check

valve,

2-FCV-74-68.

After contacting

the

ASME

Section

XI

system

engineer

the

decision

not to test

these

valves

was

made

and the surveillance

was dispositioned

by use of

TD

¹2 for tracking the'teps

applicable

to testing

of this valve.

Since at this point Loop I of the

RHR system

was being maintained in

an operable

status,

the requirements

of TS 3.5.B.9 were satisfied.

Operations,

personnel

subsequently

declared

Loop II of the

system

operable

on

June

18,

1989

based

on

performance

of

2-SI-4.5..B. l.d;

however

the

Loop

II

testable

check

valve,

2-FCV-74-68,

was inoperable

because

the surveillance

band,

including

the allowable extension for testing,

had expired at midnight on June

17,

1989.

The required

ASME Section

XI testing

was not performed

on

2-FCV-74-68 until June

22,

1989.

Meanwhile the redundant

loop of the

Unit 2

RHR System

was

made inoperable

on June

18,

1989, for scheduled

Division I outage activities.

This resulted

in both

loops of

being inoperable for the period of June

18-22,

1989,

and could

have

prevented

the Unit 2

RHR system

from maintaining reactor

vessel

level

during an inadvertent draining of the

RPV.

TS 3.5.B.9 requires

that

at least

one

RHR loop with two pumps or two loops with one

pump per

loop be operable

when the reactor vessel

pressure

is atmospheric

and

irradiated fuel is in the reactor vessel.

At the time of the event,

Unit 2 was in cold shutdown with irradiated fuel in the vessel.

The

vessel

was

in the

flooded

up condition with the

fuel

pool

gates

installed.

The failure to satisfy.

TS requirements

is identified

as

Violation 260/89-27-02.

This

RHR configuration control

problem is

similar to the violation which was identified on May 25,

1989,

where

TS 3.5.B.9 for the

Unit

2

system

was

not satisfied

due

to

inadequate

post modification testing

and violation 260/89-20-01

was

issued for the licensee failure to meet

TS requirements

for operable

.

RHR pumps.

Turbine Building Spills

During this reporting period,

two separate

eve'nts

occurred resulting

in large

amounts of non-contaminated

water spilling into the Turbine

, Building.

On June

26,

1989, at approximately 9:00 p.m.,

a portion of the Unit

1

area

of

the

turbine

building

experienced

excessive

overflow of

uncontaminated

water spilling

from

an

opening

in the

Raw Cooling

Water

piping

for

the

Unit

1

Generator

Stator

Cooling

Heat

Exchangers.

The even't occurred

due to the inadvertent closure of the

1A gate

in the Circulating Water System which caused

an increase

in

the static

head

in the

CCW piping

and resultant

increase

in water

level in the affected portion of the

RCW system.

Water subsequently

spilled

out of the

RCW

system

which was

open

for maintenance,

flooding

a portion of the turbine building

and electrical

shop.

The

licensee

has not determined

the cause for the inadvertent

closure of

the

1A CCW gate.

On June

28, at approximately ll:30 a.m.,

a similar event

occurred

when

excessive

water

overflowed into

the

Unit

2

condensor

room

during

performance

of

an

operating

instruction

checklist.

This

event

appears

to

have

occurred

due

to

personnel

error

during

restoration

of

several

valves

to their

normal

configuration

and

possibility also

due to 'an inadequate

equipment clearance

associated

with the Unit 2 condensor

water box.

The licensee

is continuing to evaluate

the

causes

for both events.

Although neither spill resulted

in either

a radiological

problem

or

an uncontrolled release

and the licensee

has determined that the two

events

are not reportable,

the

NRC inspectors

are concerned that

such

'events

are indicators of poor control of work and work practices.

5.

Modifications (37700)

a.

DG Output Breaker Modification

During the

closeout

r evi ew of significant di scr epanci es identi fied

during

the

LOP/LOCA

series

of tests

the

NRC

inspector

noted

an

item involving

a modification installed

in the

logic for the

eight

DG

output

breakers.

The

modification

required

the

installation of

a time delay relay in the logic of each breaker to

ensure that the eight output breakers

would not be locked out during

a loss of power followed immediately

by

a loss of coolant accident

signal.

The time delay relay is set at

3 seconds.

However,

due to

the

band

on -the relay,

the time could

be shorter

than

3

seconds.

The

licensee

has

determined

that

each

of the

DG output

breakers

recharging

motor must

be able to recharge

the breaker

in 2.5 seconds

or less.

At the

end of this reporting period,

the

NRC inspector

was

unable

to verify in what procedure this 2.5

second

requirement

is

located.

This item is identified

as

Inspector

Followup

Item 259,

260,

296/89-27-03,

Verification That

DG Output Breakers

Recharge

In

Less

Than 2.5

Seconds.

This item applies

to all

three

units

and

must

be addressed

prior to restart.

DG Temperature

Control Modification

The

NRC inspector

reviewed a'inor modification installed

on. the "B"

DG which involved the installation of

a thermowell

and

temperature

indicator

in

the

coolant

discharge

line

from the

DG to

the

temperature

control valve.

The work activity was initiated by

DCN

W1887

and

the activity

was

governed

by

Work

Package

1022-89.

The craft

and the

gC inspector

had the

WP at the job location

and

they

appeared

to

be

knowledgeable

in the

work required.

The

gC

.inspector

appeared

to verify that

the

minor

modification

was

installed

according

to

approved

methods.

Various

sign-offs

were

performed in an acceptable

manner.

C.

EECW Piping Modifications

The

NRC inspectors

reviewed selected activities associated

with three

major modifications to the

EECW and

RCW systems.

These modifications

are

identified

by

DCNs

H5120A,

H5121A

and

H5122A.

These

modifications

are part of the licensee's

corrective actions

due to

the discovery, of the

presence

of multiple discharge

flowpaths which

include vitrified clay piping in portions of the

RCW buried yard

piping.

Vitrified clay piping cannot

be seismically qualified

and

the

affected

lines

are

part of the

EECW discharge

flow path for

various safety related

components.

DCN H5120A reroutes

'the

EECW discharge

piping for the Unit 1/2

Control

Bay Chillers lA 5

1B from the Unit 1, Reactor Building

RCW discharge

line to the Unit

1

EECW discharge

piping which is

seismically qualified.

This modification was completed

on July

12,

1989.

I

DCN H5121A reroutes

the

EECW di scharge

piping for the

Unit

2

Shutdown

Board

Room Air Conditioning

Units

from the

Unit

2

Reactor

Bui ldin'g

RCW discharge

line to the Unit 2

EECW discharge

piping which is seismically qualified.

This modification

had

not started

as of July 14, being restrained

by need to maintain

Unit

2

Loop II ECCS operable

while

Loop I

ECCS

was inoperable

due to other work.

DCN H5122A reroutes

the

EECW discharge

piping for the Unit 3

Control

Bay Chi llers 3A from the Unit 3 Reactor

Building

RCW

discharge

line to the Unit

3

EECW discharge

piping which is

seismically qualified.

This modification was field complete

as

of July 14,

1989.

Although the specific activities associated

with the clay pipe issue

only involved work in the respective

unit portions of the

Reactor

Building, the modifications also

included

work to

remove

Secondary

Containment Isolation Check Valves,

1-67-556,

1-24-851,

2-67-598,

and

3-67-656

and

the

installation

of

spectacle

flanges

capable

of

isolating

EECW flow in each respective

10 inch

EECW system discharge

lines

located

in

the

RHRSW tunnels.

The

l,icensee

stated

that

although

the

check

valves

were originally installed

as

secondary

containment

boundaries

the

requirement

for these

valves

had

been

deleted

and the failure of these

check valves to open

when required

would inhibit EECW discharge

flow (constitute

an active failure which

violates

single failure criteria).

This additional

work

had

been

included within the

scope

of these

OCNs

due to the

need for common

work boundaries

and equipment clearances.

The spectacle

flanges

are

being

installed

only to

provide

a

means

to maintain

secondary

containment integrity during maintenance

to the

EECW System.

The

NRC inspectors

noted that for each of the above modifications

a

local

EECW stress

analysis

had been

performed to demonstrate

that the

new design

was within allowable stress

limits for the

EECW system

piping with

new piping

supports

and/or existing

supports

modified

based

on the revised

stress

analysis.

Additionally a pressure

drop

calculation

was

performed to demonstrate

that the

new design

would

not affect the ability of the

EECW discharge

lines to

meet

flow

requirements.

The

NRC inspectors

accompanied

the cognizant modification engineer

for, a walkdown of ongoing

and

planned

work associated

with these

modifications.

Craft

.personnel

and

responsible

foremen

had

appropriate

documentation

at the job location.

The

NRC inspectors

e

examined

several

of the

welds

and

noted that the exterior of the

welds

appeared

adequate

with

no

visible

flaws.

All

licensee

.

personnel

involved including the nuclear security officers displayed

a high level of technical

knowledge

and

a professional

attitude about

the job.

No violations were identified in modifications area.

Reportable

Occurrences

(92700)

a.

Review of Events for

LER Submission

The inspector

reviewed three

events

that

have

occurred

in the past

three

months for submission of a

LER per the requirements

of

10 CFR 50.73.

The licensee

reported

two events

per

10 CFR 50.72 along with

a voluntary

LER for one event.

However, the licensee

did not submit

an

LER within

30

days

for any of the events.

The events

were

a

failure of the fuel

pool anti-siphon

check valves,

RHR and

CS

room

coolers

at less

than

design

flow, and

a single failure of the fire

pump lockout relay.

(1)

Failure of the fuel pool anti-siphon

check valves

On

September

16,

1988, plant personnel

conducted

a special test

of Unit '2

spent, fuel

pool anti-siphon

check valves,

2-78-526

and 2-78-527,

and found the valves inoperable'n

ENS four-hour

report

of

an

unanalyzed

condition which could

have

prevented

the fulfillment of

a- safety function was

made to the

NRC under

10 CFR 50 '2.

This

item

was initially determined

to

be

reportable

per

10 CFR 50.73

on

September

22,

1988,

by

LRED

number

88-2-208.

Later,

on

October

5,

1988,

the

event

was

reclassified

as not reportable

because

a

low level

alarm would

warn of inadvertent

draining through

the

check valves.

Thus,

an

LER was not submitted.

The logic for not reporting

the event did not meet

the intent

of

the

LER

requirements

in

10 CFR 50.73.

In

NUREG 1022,

Supplement

One,

guestion

7.6,

the

answer

given

states

that

a

system

is

expected

to

perform

without

operator

action.

Similarly, the Unit

1 check valves

were

found

stuck

open

on

June

14,

1989.

The

LRED

number

89-1-103

stated

that

no

new

reporting

requirements

were

found to apply

since

this

item

had been previously reported.

This indicated that this item was

still considered

reportable.

Subsquently,

the

same Unit 3 check

valves were also found stuck open.

(2)

Single failure of the fire pump lockout relay

During the design

baseline verification review

a concern

about

the ability of the plant to meet

the single failure criterion

was identified.

On March 22,

1989,

the licensee

made

an

ENS

report per

10 CFR 50.72 of an unanalyzed

condition where the A,

B,

and

C diesel

generators

could

be

overloaded

due

to

the

single failure of the lockout relay which prevents

the three

motor

driven fire

pumps

from starting

during

an

accident

condition.

An

LER was not submitted within 30 days after the

discovery

of the

event.

A voluntary

LER (50-259/89009)

was

submitted within on

May 31,

'1989.

The

LER stated

an analysis

indicated that the relay failure could result in the overload

of one

DG.

The loss of a

DG during

a design basis

event

was

an

analyzed

condition for the plant.

Stated

in the

LER was that

the

scenario

discussed

was thought to

be

bounding

but it was

more

economical

to install

an additional

lockout relay than to

perform detailed

analysis to ensure this was the bounding

case.

Since

the original

concern

was

not totally resolved within 30

days,

an

LER was required within 30 days of discovery of this

event.

RHR and

CS room coolers less

than design flow

On May'5,

1989

an flow verification test

performed

on the

2C

room cooler air

found

the

flow to

be

less

than

design.

Tests

were

performed

on

the

other

room coolers

and similar

results

were

obtained.

These

results

contradicted

results

obtained

in

March

1988 after

replacement

of the

cooler

fan

motors with

Eg motors.

A

summary

of the

results

obtained

follows,:

Cooler

Desi

n

March 1988

Ma

1989

2A RHR

2B

2C

2D

2A8(C

2BED

10,000

12,700

10,000

10,671

10,977

10,687

10,811

13,195

10,919

8,263

7,443

8,786

8,154

8,328',415

All values

are

given

in

cfm with

an uncertainty

of plus or

minus

10%.

The

licensee

determined

this

event

not

to

be

reportable

because it was

not

known if the condition existed

while the plant

was .operating.

No

LER was

submitted within '30

days after the discovery of the condition.

The

low flows were

reviewed

and

determined

acceptable

by the

licensee

for the

plant conditions.

The

inspector

reviewed

the

licensee's

Incident Investigation

Report

89-41

and

noted

the

apparent

cause

was

an

inadequate

procedure,

the basic

cause

was not used,

and the root cause

was

no

procedure.

There

was

no

procedure

for periodically

or

conditionally measuring

the air flow.

As

a result of the lack

of

a

procedure

and

no historical

data, it could

not

be

determined if the air flow had deteriorated

over time or if

there

was

a step

change

in air flow.

Due to the lack of data

this

item,

was

classified

as

not

reportable

until

more

information was available.

10

The inspector did not agree

with the licensee's

reportability

determination.

First,

the

room coolers

are

a

TS requirement.

The

TS state

that

the

associated

RHR or

CS- pumps

cannot

be

considered

operable

unless

the

room coolers

are operable.

With

degraded ventilation flows for RHR and

CS, this condition could

have

lead to the'inability of all

low pressure

emergency

core

cooling

systems

to -function

as

designed.

Second,

sufficient

information

was

available

to

determine

that

the

conditions

could

have

occurred while the plant

was operating.

The

cause

of the flow difference

between

March

1988

and

May

1989 could

not be determined.

Test results

in May 1989, which indicated

a

low flow condition,

were, checked

and

rechecked.

The original

raw data

used in, the March 1988 test

was unavailable,

suggesting

a testing error as

a possible

cause.

In conclusion,

10 CFR 50.73 requires that

an

LER be submitted within

30 days after the discovery of an event or condition. that resulted

in

the

plant

being

outside

the

design

basis

and for any

event

or

condition that

alone

could

have

prevented

the fulfillment of the

safety

function of structures

or

systems

that

are

needed

to

(A)

shutdown

the reactor

and maintain it in

a

safe

shutdown condition;

(B)

remove

residual

heat;

(C) control

the

release

of radioactive,

material;

or

(D) mitigate

the

consequences

of

an, accident.

This

requirement

was not met for the three

examples

above

(A,B,C) and is

a violation of 10 CFR 50.73 for failure to submit

an

LER within 30

days.

(259,260,296/89-27-04)

Furthermore,

the

licensee

was

not

following

Plant

Managers

Instruction

PMI-15.4,

"Unique

Reporting

Requirements,"

Procedure

step

4. 1.4 stated

the following:

"It is

NRC policy and plant position "that when there is doubt

regarding

whether

to report

a situation

or not

the

licensee,

should

make

the

report.

This will ensure

conservatism

is

employed

when utilizing engineering

judgment

and

experience

to

determine

the significance of an event or condition."

The

inspector

acknowledges

that- the licensee

had identified these

problems

and in two cases

made

a four hour report per

10 CFR 50.72.

b.

Review of LERs

The

Licensee

Event

Reports listed

below were

reviewed to determine

if the information provided'met

NRC requirements.

The determination

included

the verification of

compliance

with- TS

and

regulatory

requirements,

and

addressed

the

adequacy

of the event description,

the corrective

action

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

(CLOSEO)

LER 296/83-47,

Rev.

1,

Cooling Water Flow Blockage to

RHR Pump.

This

LER addressed

the significant loss of

EECW cooling water

flow thr u the

~ RHR

pump

seal

water

heat

exchangers

due to

a

buildup of clams

and sediment.

The system

was flushed until flows reached

acceptable

levels

and

the

system returned to service.

TVA stated

in

an internal

memorandum

dated Sept.

10,

1986 that

,GE determined that seal

water cooling was not normally required

for

pump operability.

Only under certain

extreme

emergency

operating

conditions

would

seal

damage

occur

after

extended

periods with high temperature

seal

water.

Therefore

the loss

of cooling water to'he

seal

water

heat

exchangers

was

not

considered

as

adversely

affecting

pump operability

and

system

operating instructions

were changed

accordingly.

The

NRC

inspector

reviewed

this

issue

with

emphasis

on

the conditions leading

up to the loss of cooling and actions to

prevent recurrence

as well as the impact

on

pump seals from'oss

of seal

water cooling.

Loss of cooling water to heat exchangers

from clam and sediment

fouling of open

systems

had been'addressed

in IEB 81-03

and

IEN

86-96.

The

NRC continues

to review this important topic through

proposed

requirements

for improving the reliability

of

open

cycle service

water systems

discussed

in Generic

Issue

51.

TVA

was found to have

a program of system testing to diagnose

system

flow degradation

resulting

from

such

fouling.

This

program

should predict

and prevent recurrence

of this condition.

The

licensee

position that

seal

water

coolers

were

not

required

for

pump

operability

'as

evaluated

by the inspector.

The

inspector

found that

the

seal

water

coolers

serve

2

functions:

1) to provide

a flow path

from the

pump discharge

to the

pump

seals

for lubrication water

and

2) to provide

for the

cooling

of

the

"lubrication" water.

The

TVA memo

discussed

earlier permits deleting

the

cooling function.

The

pump vendor

manual

and

GE specs still require the seal

faces to

be lubricated at all times by pumpage

or liquid from an outside

source.

Therefore

the

seal

water

side of the heat

exchanger

must

remain in-service for

pump operability.

Since

the

seal

water

side of the

Heat

Exchanger

cannot

be isolated

from the

pump,

the lubrication function cannot

be

bypassed.

This fact

combined

with the

minimum flow capability of the

RHR system

12

ensures 'ome

cooler

seal

water is

forced

through

the

system

which aides in cooling the

pump seals

under low flow conditions.

Therefore isolation of the cooling water

side of the seal

water

heat

exchanger

does

not negate

the lubrication function of the

system.

The

NRC inspector

reviewed

the

changes

to

RHR system

operating

instruction

(OI-74),

and'bserved

the

physical

installation in the field of several

Unit 2 heat exchangers,

and

had

no comments.

The

LER is considered

closed.

(2)

(CLOSED)

LER 260/88-04,

Personnel

Error Initiates

Engineered

Safety Features.

On July

1,

1988,

at

12:05 p.m.,

and

again at 1:10 p.m.,

a low

reactor

water

level

signal

was

received

by the

RPS.

Thi s

initiated various engineered

safety features.

The

second

event

occurre'd

during

the investigation

of the first event.

Both

events

were

caused

by the

performance

of

a modification

on

a

Unit 2 reactor

vessel. level transmitter

and

a reactor pressure

transmitter.

The

NRC inspector

reviewed the

LER, dated July 29,

1988,

and the

LER

closure

package,

and

verified

that

the

LER

met

the

requirements

for timeliness,

content,

and corrective

action.

The root

cause

was

determined

to

be

an

incomplete

clearance

request

which

did

not

identify all

adverse

actions,

and

improper

establishment

of the final clearance.

The

licensee

immediately

corrected

the

actuations

and

issued

a

new

clearance.

The licensee

also

counseled

the personnel

involved

and required that. operations

and modifications

personnel

review

the

event

(Operations

Critique 88-041).

Based

on in-office

review of the

LER and corrective

actions

taken,

this item is

closed.

(CLOSED)

LER 260/88-07,

Inadvertent

Transfer

Switch Operation

Initiates. Engineered

Safety Features.

This item involves the actuation

of engineered

safety features

during

post

maintenance

testing

of the

2A motor generator

set

on September

4,

1988.

The licensee

determined

the cause

of

this

event

to

be

personnel

error.

The

assistant

shift

operations

supervisor

inadvertently

operated

the

normal/alternate

transfer switch while removing

a clearance

tag,

causing

a loss of power to the bus,

which in turn actuated

and

ESF.

The unit operator,

after

determining

the

cause

of. the

event

and

verifying that

ESF initiation signals

were

not

present,

returned

the affected

systems

to normal.

Subsequently,

the

ASOS

was individually counseled,

the

event

was

discussed

with the remainder of the operating

group

on shift at the time,

and other

operating

groups

were required to read

a review of

the

event.

The

'inspector

reviewed

the

licensee

actions

described

above

and determined

them to be

appropriately

13

This item is closed.

(4)

(CLOSED)

LER 260/88-08,

Unplanned

Actuation

During

Electrical

Board Power Transfer.

This event involves the unplanned

actuation of engineered

safety

features

due

to

loss

of power to the

2B Reactor

Protection

System

bus.

This

occurred

when

power

for

the

2B

480V

shutdown

board

was

transferred

back

to its

normal

supply

following special test 88-24 of Diesel Generator

D.

The breaker

on the

D 4KV shutdown board,

which supplies transformer

TS2B and

is the

normal

power

source for the

2B 480V shutdown board,

was

inadvertently . left

in

the

open

position.

Therefore,

transferring

power

to deenergized

transformer

TS2B

caused

a

loss of power at the

2B 480V

shutdown

board,

with

a

subsequent,

loss of power at the

2B

RPS

bus.

The licensee

determined

the

cause

of this event to

be

personnel

error

on the part of the

assistant

shift operations

supervisor

in that

he

did

not

verify the

presence

of voltage at

TS2B prior to transferring

power

sources.

A contributing factor was determined to be that

the

test

procedure

did

not

contain

adequately

specific

instruction

on

how to return

the plant to normal configuration

following completion of the test.

Licensee

actions

taken to prevent recurrence

are

as follows:

The

ASOS involved was individually counseled

and the event

was

discussed

with the

remaining

members

of the shift.

These

discussions

focused

on

the

necessity

for strict

attention

to detail

and attentiveness

to the task at hand.

The other operations

groups

reviewed the event

as

required

readihg.

A memorandum

(RIMS

R42881024940)

was distributed

to all

Plant Operations

Review Committee

members

and -alternates

describing

the

event

and directing

them to

ensure

that

special

test

instructions

include

adequate

specific

'irection for returning

systems

to normal

upon

completion

of the test.

The

NRC

inspector

reviewed

the

above

licensee

actions

and

determined

them to be appropriate.

This item is closed.

(5)

(CLOSED)

LER 259/88-21,

Unplanned Start of RHRSW Pump.

This item involves the

unplanned

start of the

B1 Residual

Heat

Removal

Service Water

pump during the monthly operability test

of the

3A diesel

generator

performed

on July

18,

1988.

The

cause

of this inadvertent

pump start

was determined

to

be the

transfer of 250V

DC control

power

on the

3EC

4KV shutdown

board

while the dieselwas

running,

causing

a

momentary

voltage

drop

14

to the

pump start logic, allowing the time delay start relay

and the auto start lock-out relay to reset to their'eenergized

state

and reinitiate

the

auto start logic.

Therefore,

after

the preset .28 se'cond delay,

the

pump automatically started.

The

licensee's

original

corrective

action

was

to

revise

Special

Operating

Instruction

X-X

23

to

include

a

note

alerting operators

to this type of occurrence.

However, further

review revealed

that

SOI-23

was

a special

one-time

procedure,

and

has since

been cancelled.

Therefore it was determined

that

the

appro'priate

location

for inclusion

of

such

a

caution

statement

would be in

DC Electrical

System Operating Instruction

0-OI-57D.

The

NRC

inspector

reviewed

Revision

3 of this

instruction

and

found

that it contains

(in

two

places)

statements

to caution the operator that the transfer of 250V

DC

control

power to

a

4KV shutdown

board with

a diesel

generator

operating

may cause

an inadvertent start of a

RHRSW pump.

The

inspector

agrees

that this

instruction

is

the

appropriate

location for the caution statement.

This item is closed.

(6)

(CLOSED)

L'ER 259/88-28,

EECW Pressure

Switches

Not Purchased

to

Seismic

Class

I Requirements.

This item involves the discovery,

in February of 1988, that the

pressure

switches 'which auto-start

the

Emergency

Equipment

Cooling Water strainers

had

been

procured

in

1973

to

Seismic

Class II requirements.

Since

the

EECW system

i s identified in

the

FSAR

as

a Seismic

Class

I system, it was determined

that

these

switches

should

be replaced with new switches

procured to

Seismic

Class

I requirements.

The

installation

of

the

Seismic

Class

I

switches

was

"accomplished

via

Work

Plans

2587-88

and

2704-88,

and

was

completed

in November of 1988 and reviewed

by the

NRC inspector.

This item is closed.

(7)

(CLOSED)

LER 259/88-52,

Unplanned

Engineered

Safety

Feature

Actuations

Due to Circuit Protector

Trip

Caused

by

Damaged

Indicating Light Socket.

The

LER

involved

two

separate

actuations

of

containment

isolations

systems that resulted

from loss of

RPS

bus

1A power

due to

a blown fuse in the

RPS power supply circuit protectors.

In both cases,

the fuse operated

because

of

a short circuit in

a status

indication light socket

on the local ci rcuit protector

panel.

Immediate corrective actions

were to repair the loose

sockets of

the

indicating

lamps

and

restore

the

system

to

service.

Subsequent

investigations

revealed

that

overheating

of

the

15

indicating

lamp contributed

to the event.

Modifications were

proposed

to correct the overheating

condition.

The

NRC inspector

observed

the circuit protector panels in the

field and found Unit 2 lamps satisfactory.

However, Unit

1 and

Unit

3

lamps still

showed

distorted

lenses

as

a result of

overheating..

The

NRC inspector

found that maintenance

requests

had already

been

issued for the conditions

(MRs 881131,

881134,

881135,

881141,

881142).

The

NRC inspector

also

determined

that proposed modifications

had

been

accepted

and

DCNs

H5627A,

H5628A

and

H5629A

had

been

issued

to correct indicating

lamp

deficiencies.

The

DCNs were

found to

be logical

and thorough.

Corrective actions

were considered

timely and adequate.

This

LER is considered

closed.

(8)

(CLOSED)

LER 260/89-10,

Unplanned

locked high radiation areas.

Caused

by

Spurious

Radiation Monitor Spike.

This event involves the actuation of engineered

safety features

due

to

an

upscale

spike

experienced

by

refuel

zone

ventilation

exhaust

radiation monitor 2-RM-90-140

on

March 23,

1989.

The initiating signal

immediately cleared.

The spike was

verified to

be

erroneous

by

comparison

to

other

radiation

monitor, indications.

An

inspection

of the

monitor

and

the

surrounding vicinity revealed

the most'ikely cause

of the spike

to

be

a communications

cable with exposed

conductors within one

foot of the detector.

Readings

taken

on the

exposed

conductors

indicated

a

48 volt

DC potential.

The detector

manufacturer

confirmed that arcing of the conductors

in the vicinity of the

detector

could result

in spurious

spikes.

Immediate corrective

action

was to tape

the

exposed

conductors

and

move the cable

away from the detector,

with permanent repair being effected via

maintenance

request

A-912567

on April 25,

1989.

In order to

ensure

that the arcing

had not damaged

the monitor, appropriate

calibration

and testing

was

performed prior to declaring

the

monitor operable.

The

NRC inspector

reviewed

the

licensee's

actions

and determined

them to

be

appropriate.

This

item is

closed.

7.

Action on Previous

Inspection

Findings (92701,

92702)

(CLOSED)

IFI 259,

260,

296/85-53-04',

Emergency

Preparedness

Drill

Concerns.

A previous

NRC inspection

(IR 85-53)

identified various

concerns

during the

performance

of an

Emergency

Preparedness

drill conducted

on November

13,

1985.

The inspector

held discussions

with licensee

personnel

and

reviewed

the

licensee's

closure

package,

other

NRC

inspection

reports,

and

licensee

actions

to address

the

items

of

concern.

The findings are

summarized for each

issue

below.

16

(1)

Problems with TSC phones:

This issue

was also identified as IFI

86-32-12,

item

a (closed

.in

IR 88-05) during

a

subsequent

EP

drill on

September

24,

1986.

No further followup is required

and this issue is closed.

(2)

Incorrect

IP-20 drill data

sheet

for 9:30

a.m.:

This

was

a

drill specific

comment.

No

further

followup

is

required

and this issue is closed.

(3)

Communication

of

Reactor

Mater

Level:

This

issue

was

also

identified as IFI 86-32-12,

item b (closed in IR 88-05) during

a

subsequent

EP drill on September

24,

1986.

No further followup

is required

and this issue is closed.

'I

(4)

Confusion

over

a real contamination

event which occurred during

the drill: This was

a drill specific issue which was discussed

in

another

section

of

IR

85-53.

This

issue

is closed.

(5)

IP-20

Attachment

A incomplete.:

This

was

a drill specific

comment.

Also,

the

IP-20

Attachment

A has

been

updated

(see

finding 8).

No further followup is required

and this issue is

closed.

(6)

The microphone

used

by the site director

was beneficial:

This

was

a drill comment.

No followup is required

and this issue is

closed.

(7)

No guidelines

for

recovery

from

a

fuel

handling

accident:

There are

no specific requirements

for a fuel handling accident

recovery

procedure

and the licensee

does

have general

recovery

guidelines

(EPIP - 16,

Recovery

Procedures)

~

This

issue

is

closed.

(8)

IP-20 Attachment

A out of date:

This

was

a duplicate

of 'IFI

85-52-05 which was,closed

out in IR 86-33.

No further followup

is required

and this issue is closed.

b.

(CLOSED) IFI 259,

260, 296/86-25-08,

Technical Specification

Revision

on Fire Protection

System.

The plant

Technical

Specifications

did not contain

the

sprinkler

systems

as

a fire

protection

system

load.

TVA's

plant fire

protection engineer

agreed that the fire protection sprinkler

system

should

be included in the Technical Specifications.

The

inspector

reviewed

documentation

provided

by

the

licensee

including the current version of Technical

Specifications

and

noted

that section

3. 11, "Fire Protection

Systems",

has

been

revised

as of

Amendment

162

dated

December

27,

1988.

This constituted

a total

revision

of

the

section,

with

replacement

of

the

original

0

17

Table 3.11.A with s'everal

separate

tables.

The Hydraulic Performance

Criteria included in the original Table 3.11.A had been deleted.

The

current

version

of Table

3.11.A,

Fire

Detector

Instrumentation,

includes

operability

requirements

for

detections

instruments

associated

with instal

1 ed spray/sprinkl er

systems.

Tabl e

3. 11. B,

"Spray/Sprinkler

Systems",

includes

plant

areas

required

to

be

protected

by spray/sprinkler

systems.

The inspector

concluded that the licensee

had adequately

addressed

the inspector's

concerns

and this item is closed.

(CLOSED)

IFI

259,

260,

296/86-36-04,

Jet

Pump

Operabi

1 ity

Survei=l 1 ance Instructi on (SI) 4.6. E. 1

This item involved whether jet

pump plugging

can

be detected

prior

to

pump

failure

in

the

absence

of

the

performance

monitoring

techniques

contained

in Technical

Instruction

52.

This TI had

been

utilized to monitor jet

pump performance

in order to detect

cracks

in the jet pump hold-down

beams,

which would lead to jet

pump mixer

displacement

and recirculation

system

performance

degradation,

as

identified

in

General

Electric

Service

Information

Letter-330.

Subsequently,

the

hold-down

beams

were

replaced,

eliminating

the

necessity

to perform the TI-52 testing

for that

reason.

However,

SIL-330 also

recommended

that

some

form of performance

monitoring be

continued in order to preclude jet

pump degradation

due to plugging

of the

pumps.

The

concern

was that, with the discontinuation

of

TI-52 testing,

the then-current

revision of SI-4.6.E. 1 might not

be

adequate

to detect

such plugging.

A review of SIL-330, SI-4.6.E. 1

Rev.

1,

and

TVA memo dated 4-13-88

(RIMS R42880406946)

revealed

the following:

SIL-330,

paragraph

5.2.F 1

states

that jet

pump

flow or

differential

pressure

deviation

from

average

is

the

most

sensitive

indicator

of jet

pump

performance

degradation,

and

that monitoring

D/P deviation

from loop

average

on

a daily

basis

is

an

acceptable

method

of performance

monitoring

to

detect jet pump plugging.

SI-4.6.E. 1,

section

7.7 requires verifi'cation of individual jet

pump D/P within 10 percent of average

on

a daily basis.

It is therefore

determined

that SI-4.6.E. 1

now contains

adequate

provisions with which to monitor jet

pump performance

in order to

detect degradation

due to plugging.

This item is closed.

18

(CLOSED) IFI 259/86-40-09,

Tornado Missle.Protection

For Vent Towers.

This item involves

a request for the licensee

to submit

a revision to

LER 259/86-06,

Rev.

1

so that

NRC review of the

event

could

be

completed.

During

a

1986

design

evaluation

of

control

bay

ventilation modifications',

an

unanalyzed

condition

was

identified

involving tornado missile protection

for

equipment

located

in the

vent

towers.

A Probabi listic

Risk

Assessment

was

performed

which

determined 'that the risk to the subject

equipment

was sufficiently

low that

no modifications

were

required.

When

questioned

about

docketing

the

PRA,

TVA stated

that it was

considered

to

be

an

unreviewed draft from which no meaningful conclusions

could be drawn.

It was

requested

that

TVA formally submit their final position

on

the

subject,

including

the

approved

PRA,

in

the

form

of

a

revision to the

LER.

In accordance

with the

above

request,

LER 259/86-06,

Rev.

2, dated

9-18-87,

was issued to document

TVA's final position,

and the

PRA has

been

reviewed

and

accepted

by

NRC.

The

review

of

the

PRA

(RIMS B81870622050),and

closure

of the

LER

have

been

previously

addressed

in

Inspection-

Report

88-32.

Therefore,

this

item is

closed.

(CLOSED) IFI 259,

260, 296/88-10-05,

Performing Special

Test

To Meet

Restart

Test

Program

Requirements.

This item was originally identified during the review and performance

of the

RTP

and

was written to identify an administrative

concern

involving the specific plant procedures

that would be

used

to meet

RTP test

requirements.

A review of an

immediate

Temporary

Change

Notice,

dated

May 17,

1988,

and

Revision

4 of

SDSP

12. 1, "Restart

Test

Program",

clearly indicates

PMI-17. 1,

"Conduct of Testing", to

be

an acceptable

procedure

to be

used

as part of the

RTP.

A review

of

PMI-17 '

and

section

4.4 in particular indicated that

adequate

controls

are

in place

for the

performance

and

review of special

tests.

This item is closed.

(CLOSED) IFI 259,

260, 296/88-16-01,

Review of Response

to Licensee's

guality Surveillance Monitoring Report.

This

item

was originally written

as

a result of two incidents

involving

the

di,esel

generators

and

the

subsequent

reports

(gBF-S-88-0436

and 0455)

generated

by the licensee.

The first item

(88-0436)

concerned

a

DG 'which was started with the cylinder vent

valves

open

during

a

special

test.

The

second

item

(88-0455)

concerned

a

DG which was started

with the

load limit set

on

zero

instead of maximum during the

same

special test.

Both of these

i'tems

were traced

to failure to follow procedures.

At the

time of the

incident,

the

DG was in a test configuration,

was not being tested

in

order

to return it to service,

and

was

not

under configuration

control.

The licensee

took immediate corrective

action to instruct

all personnel

involved with

DG testing

of requirements

to control

19

plant activities

and testing.

No similar incidents

occurred while

testing

the other

DGs.

This item is closed.

(CLOSED) IFI 259;

260,

296/88-18-05,

Major Discrepancies

Identified

During LOP/LOCA Test

C.

This item was identified during the-series

of LOP/LOCA tests

(A thru

D)

performed

by the

licensee

to

prove that

the

ECCS

logic

and

functional

networks

were intact

and

working

as

required

by plant

.

design.

Due to the built in anti-pumping

network of the

4160V

shutdown board'ircuit

breakers,

which prevents

a

breaker

with

a

closed

command to continually open

and close

on

a

bus with

a fault,.

three breakers failed to function as required.

These Unit 3 breakers

locked out when they received

a close

command

on

the

LOP signal,

immediately

received

a

command

to

open

on

the

LOCA signal,

and

remained

open

due to the

anti-pump

network of the

breakers.

The

licensee

initiated

a design

change

to install time delay relays to

del'ay the close

command

in order

to allow the

charging

motor to

recharge

the breaker

and thereby

reclose

the breaker to satisfy the

LOCA logic.

The

NRC inspector

observed

the retest

of

LOP/LOCA "C"

and verified that

the modification

performed 'as

adequate.

This

item is closed.

(CLOSED)

URI

259,,

260,

296/88-21-01,

violation

of

Procedural

Requirements

on Access to High Radiation Areas.

The

inspector

ascertained

through interviews with RadCon

personnel

and

an

SOS 'that high radiation

ai ea

door

keys

were

maintained

by

RadCon

and that

SOS

permission

was not sought

or obtained for all

entries

into the

locked

high radiation

areas.

The

only control

exercised

by the

SOS over the high radiation

area

door

keys

was

a

once

per shift acknowledgement

that the

SOS clerk had

performed

a

survey

of all

th'e

keys

and all

keys

were

accounted

for.

The

inspector

was concerned that the

procedures

controlling the

keys to

locked

high radiation

areas

were

confusing

and contradictory

and

this

was identified

as

an

unresolved

item pending clarification of

this issue.

TVA addressed

the

unresolved

item in the

November

23,

1988 response

to

a violation cited in IR 88-21.

TVA maintained

that the

program

for controlling locked high radiation

areas

was

adequate;

however,

implementing

procedures

would

be

enhanced

through

revisions

to

clarify lines of responsibility.

IE Circular

76-03,

IENs 82-51,

86-44,

and

88-79,

and

INPO

SOER 85-3 provide guidance

on control of locked high radiation

areas

and

were

reviewed

against

the

TVA program.

The

NRC inspector

reviewed

th'e

TVA November

23,

1989,

response,

history,

recent

gA audits

and

survei llances

of the area,

revisions

to the

implementing procedures

RCI-17 and OSIL-16,

as well

as

performed

an

20

observation

of locked high radiation

area

doors

and

key lockers for

Unit 2.

After reviewing the associated

procedures,

before

and after revision,

the

NRC inspector

determined

that while the controlling procedures

were not of high quality,

no violation of NRC requirements

occurred.

The procedures

met the

requirements

of

TS 6.8', "Radiation Control

Procedures"

as well as the industry standards

for control of keys'to

The revised procedures

provide

a better

representation

of the

actual

program.

This

item is

considered

closed.

i.

(CLOSED)

URI 259,

260,

296/89-20-03 'his

item was

upgraded

to

an

example of the violation in this report for failure to submit

a

LER

within 30 days per the requirements

of 10 CFR 50.73.

(CLOSED) VIO 296/84-45-01,

Violation of TS 6.3.A.1

This item involved concerns

about

the startup of the Unit 3 Reactor

on October

22,

1984 after completion

of

a refueling

outage

which

lasted

over

four

hundred

days.

This violation

contains

eight

examples,

each of which is discussed

below:

~Exam le l:

This

example

involved the failure to have'rywell

Floor Drain

Sump Level Transmitter 3-LT-77-1A in service

due to

a lack of specificity in procedure

OI-77, in that the data

sheet

was

common for all three units,

thereby not providing positive

identification

of

- which unit's

system

alignment

had

been

verified.

To

correct

this

condition,

the

licensee

has

individually listed

each

instrument,

referenc'ed

to

its

applicable

unit,

in later revisions

of the

Lineup Checklist,

currently

Attachment

4

(page

4 of 8)

to

Procedure

OI-77B,

Revision

2.

The

inspector

reviewed

this

checklist

and

determined it to

be

adequate

to

prevent

future

similar

occurrences.

Therefore, this example is closed.

~Exam le 2:

This

example

involved

the

Drywel1

Shield

Plug

Trolley Chain not being

padlocked prior to startup

as

required

by step I.B.2. a of procedur e GOI-100-1.

Thi s was determined

to

be the result of personnel

error.

The involved individual

was

reprimanded

and mechanical

maintenance

personnel

were retrained

in this

area

in

March of

1985.

This

example

is

considered

closed.

Exam les

3 and 4:

These

examples

involved

the

failure

to

complete

steps

27,

28,

and

29 of the

Master

Refueling

Test

Instruction prior to performing Refueling Test Instruction - 4,

"Full Core

Shutdown

Margin - Closed

Vessel".

Had these

steps

been

performed

when required,

the Shutdown Cooling System would

have

been

secured

arid the

RHR system

would have

been

The licensee, determined

that this

was

due to GOI-100-1

being

21

inadequate

to ensure

that

NRTI signoffs

were obtained prior to

plant

startup.

Revision

1

to

GOI-100-1

now contains

the

requirement

that,

for startups

following

a

r efueling

outage,

the

MRTI shall

be in the possession

of the

SOS,

who will verify

that all required

steps

have

been

performed.

These

examples

are considered

closed.

~Exam le 5:

This

example

involved

the

failure

to

perform

GOI-100-1,

Section II.A, steps

9,

10,

and

14 prior to pulling

control

rods for the initial

shutdown

margin test.

Step

9

secures

shutdown

cooling,

step

10

starts

the. recirculation

pumps,

and

step

14 secures

head vents.

The licensee

determined

the reasons

for thi s violation were that shift personnel

did not

interpret

the

pulling of control

rods for initial

shutdown

margin testing to constitute

a reactor startup

because

"reactor

'startup"

was

not clearly defined in the procedures.

To prevent

future recurrences,

GOI-100-1, Revision

1

now contains

measures

to identify steps

which must

be completed prior to every startup

and cannot

be bypassed

at the discretion of shift personnel.

In

addition,

Amendments

158 (Unit 1),

154 (Unit 2),

and

129 (Unit

3) to

the facility operating

licenses

contain

a clarified

definition of Startup

Condition.

These

amendments

were

issued

by the

NRC

on

November

18,

1988.

This example is

considered

closed.

~Exam le 6:

This

example involved the failure to attach

a graph

of K-effective to SI 4.3.B. l.a data

sheet

dated

10-22-84,

as

required

by GOI-100-1,

Pre-Startup

Checklist

step

I.R.2.

The

licensee

determined

the

cause

to

be inattention to procedural

detail,

in that

the K-effective'raph

was

not physically

attached

to the data

sheet

because it was being

used during rod

movement.

Revision

1 to GOI-100-1

no longer requires

the graph

to

be physically attached

to the data

sheet,

but that it be

posted

on Control Panel 9-5.

In addition,

personnel

have

been

counselled

regarding

attention

to

procedural

detail.

This

example is considered

closed.

~Exam le 7:

This example involved the

inadequacy

of Surveillance

Instruction

4.6.E.1

in that it did

not

accurately

reflect

the

acceptance

criteria for jet

pumps

contained

in

TS -4.6.E.

The

TS

acceptance

criteria

contained

in

Surveillance

Requirement

4.6.E.l.c

require

that

individual

jet

pump

differential pressures

be within 10 percent of the

mean

value

of all jet

pump differential

pressures.

However,

the

SI

invoked acceptance

criteria contained

in Technical

Instruction

52,

which

requires

that

individual jet

pump

differential

pressures

be within

10 percent

of established

baseline

data,

which

in effect

would

allow values

of

up

to

15

percent

deviation

from the'ean

to

be

acceptable.

The

licensee

has

revised

SI-4.6.E. 1

to correct this condition.

The

inspector

reviewed Revision

1, dated

10-27-87,

and determined

22

that all

references

to TI-52

have

been

removed

and

the

TS

acceptance

criteria

are

now

specifically

stated

in

the

procedure.

This example is closed.

~Exam le 8:

This example involved the failure of Shift Technical

Advisors to document

unacceptable

test results

as required

by

procedure.

Surveillance

Instruction 4.6.E. 1, for demonstrating

jet

pump operability,

required,

in step

20 that any exceptions

to acceptance

criteria

be

noted

and explained

in the

remarks

section.

However,

when

SI 4.6.E. 1

was

performed

on Unit 3

on

October

21,

1984, with results that did not meet the acceptance

criteria, this

exception

was

neither

noted

nor explained

as

required.

The licensee

has revised

SI 4.6.E. 1,

as

discussed

in

example

7 above,

to more clearly state

TS requirements,

and has

provided training to

STAs

in

procedural

requirements.

This

example is considered

closed.

As individually discussed

above, all eight

examples

comprising this

violation have

been adequately

addressed,

and appropriate

corrective

actions

have

been

accomplished.

Therefore, this violation is closed.

(CLOSED)

VIO 259,

260,

296/85-57-06,

Example

C, High Radiation

From

LPRM Changeout.

This

item involves

the

set

point

(100 mr/hr) for

area

radiation

monitor

2-RM-90-141

being

exceeded

during

a

local

power

range

monitor

manipulation

on

November

20,

1985

which

resulted

in

a

secondary

containment isolation

and standby

gas treatment initiation.

During

movement

of

the

LPRN it

was

damaged,

causing

increased

difficulty in handling, which resulted

in it being caught behind the

source

pin rack.

During the attempt to free it from the rack,

the

highly radioactive

end

was raised

to within 18 inches

of .the water

surface,

thereby increasing

the dose rate in the

area

above

the

ARN

set point.

The following actions

occu'rred

almost simultaneously:

The

HP technician instructed the operator to lower the

LPRM.

The

ARN alarmed.

The

LPRN was lowered by the operator.

The estimated

duration of the

event

was

2

seconds

with the

maximum

exposure

received

by

an

individual of

30

mi llirem.

The

licensee

determined

the root causes

of the incident to be:

The

use of a procedure

which did not minimize the potential for

physical

damage

to the

LPRM

A prejob briefing which did not

include all

aspects

of the

operation

0

23

An unanticipated

and

unplanned

configuration with the

damaged

LPRM caught behind the source

pin rack

The following corrective

measures

have

been

accomplished

in order to

preclude future recurrence:

Additi'onal

radiological

caution

statements

have

been

incorporated

into

procedure

SMI

192.2,

"LPRM

Maintenance

Instruction."

A statement

has

been

incorporated

into

SMI 192.2 requiring

a

formal operational

briefing prior.to starting work.

The

method of physically'oving the

LPRM has

been

revised

to

reduce

the potential

for incurring

damage

or for the

LPRM to

become

caught.

Appropriate

personnel

have

been

made

aware

of

the

above

procedural

revisions

and .have

received

a critique

of the

incident.

Subsequent

to the incorporation of the above procedural

enhancements,

seventeen

Unit 2

LPRM assemblies

were replaced

in December of 1988,

without incident,

thereby

demonstrating

that

the

above

corrective

measures

are

adequate.

Therefore,

this item is closed.

The other

examples

comprising this violation were

previously

closed

in IR's

88-34

and 88-35.

This violation is closed.

No violations or deviations

were identified during the

Followup of Open

Inspection

Items.

8.

Site Management

and Organization

(36301,

36800,

40700)

On

June

20,

1989,

the

licensee

began

a 60-day plant work schedule

to

demonstrate

to

TVA senior

management

BFNs ability to complete

a

complex

series

of work activities

on

schedule.

One of the

scheduled

activities

was to complete work on balance-of-plant

systems

such that main condenser

vacuum could be drawn

on July 20,

1989, with all required

systems fully

During this inspection period,

the licensee failed to maintain

the 60-day schedule.

This was due mainly to delays

in closing

ONE paper

work required to complete

SPOC signoffs for restart.

Concerted effort was.

expended

on the 60-day

schedule

of activities

and for the

most part the

field work

progressed

well.

Of particular

note

was

the effort

and

results

of the

Maintenance

Department;

they

exceeded

their

MR work off

rates,

decreased

the

overall

backlog,

and

reduced

unacceptable

work

rates.

The work performed

the

60-day

schedule will be

used

by TVA to develop

a

Unit 2 restart

schedule.

24

9.

Exit Interview (30703)

The inspection

scope

and findings were

summarized

on July 14,

1989 with

those

persons

indicated

in paragraph

1 above.

The inspectors

described

the areas

inspected

and discussed

in detail

the inspection findings listed

below.

The licensee

did not identify as proprietary

any of the material

provided

to or reviewed

by the inspectors

during this inspection.

The

plant manager

stated that the plant position would be to deny,

in part or

fully,

Violation

(259,260,296/89-27-04)

concerning

,LER

reporting,

because

of technical

disagreement.

Item

260/89-27-01

260/89-27-02

259,

260, 296/89-27-03

259,

260, 296/89-27-04

10.

Acronyms

Descri tion

IFI - Fuse

Replacement

Jumpers,

paragraph

2.b.

Violation -

Failure to Meet

TS

Requirements

for

Operable