ML17156B062

J. Stair,

Resident

Inspector,

Approved By:

Pound ~

1

gh,+ ief

RefctdF

P

jects Section

No.

3B

Division of Reactor Projects

Date

Ins ection

Summar

Areas Ins ected:

The

resident

inspectors

conducted

routine

inspections

of

plant operations,

physical

security,

plant events,

surveillance,

and mainten-

ance activities.

Specifically,

items

reviewed

in more detail

in the facility

operations

areas

were:

two automatic reactor scrams,

a forced shutdown

due to

a failed vacuum breaker surveillance,

a temporary

loss of shutdown

cooling

and

a

loss

of availability of

two

emergency

diesel

generators.

Other

items

reviewed included the licensee's

December monthly operating report.

Results:

During this period,

operations

department

personnel

generally

con-

tinued to conduct activities in

a professional

manner

and to operate

the plant

safely.

However, apparent

lapses

in the operating staff's attention

to detail

and miscommunications

between

crews resulted

in two unplanned

automatic

scrams

on Unit 1 (see Detail 2.2 and 2.4).

In addition, of particular concern

was the

failure of the operating

crew to recognize until several

days later that they

had exceeded

the Technical Specification

(TS) allowable cooldown rate following

one of the

scrams

(see

Detail 2.5).

In addition,

during the cooldown from the

first plant trip (January

4, 1989),

an

inadvertent

isolation of the

residual

heat

removal

(RHR)

system

occurred

(see

Detail 2.3).

The isolation of

RHR

continues to be

a plant problem which warrants

increased

engineering attention.

8903210202

890308

PDR

ADOCK 05000387

6

PNU

Inspection

Summary (Continued)

During this

period,

the

number

of operable

emergency

diesel

generators

was

reduced

to two for approximately

35 minutes.

A review of the licensee's

diesel

generator starting air system test

methodology

and

subsequent

determination

of

a diesel's operability demonstrated

a potential

weakness

in proper verification

of a diesel's availability as it relates

to the starting air. This item is con-

sidered

unresolved

pending

further review by the

licensee

and

the

NRC (see

Detail 5.0).

Routine

review of maintenance

activities

noted

good control

and

performance.

Licensee

monthly reports

were complete

and accurate.

In general,

sufficient management

involvement

and attention

were

applied

to operate

both

units in a safe manner.

The events

noted above,

however, indicate the need for

increased

management

attention to correct associated

weaknesses.

TABLE OF CONTENTS

~Pa

e

1.0

Introduction and Overview...................................

1. 1

NRC Staff Activities (Module Nos.

30703,

71707,

90712

92700,

92701)

1.2

Unit 1 Summary

1.3

Unit 2 Summary

1.4

Persons

Contacted

2.0

Routine Periodic Inspections.

2. 1

Scope of Review

2.2

Reactor

Due to Isolation of Instrument Air-

Unit

1 (Module No. 93702)

2.3

Temporary

Loss of Shutdown Cooling - Unit 1

(Module No. 93702)

2.4

Reactor

Due to Feedwater Transient - Unit

1

(Module No. 93702)

2.5

Excessive

Cooldown Following Reactor

Scram - Unit 1

(Module No. 93702),

2.6

Forced

Shutdown

Due to Vacuum Breaker Failed

Surveillance - Unit

1 (Module

No 93702)

2.7

Operational

Summary

3.0

Surveillance

and Maintenance Activities.....................

3. 1

Surveillance Observations

(Module No. 61726)

3.2

Maintenance

Observations

(Module No. 62703)

4.0

Review of Monthly Operating

Reports

(Module No. 90713)......

5.0

Emergency Diesel Generator Availability (Module No. 93702)..

6.0

NRC Meetings (Module No. 30703).............................

6. 1

Engineering Organizational 'Status

Meeting

6.2

Resident

Monthly Exit Meeting

13

15

DETAILS

1.0

Introduction and Overview

1.1

NRC Staff Activities

The purpose

of this inspection

was to assess

licensee activities at

Susquehanna

Steam

Electric Station

(SSES)

during

power operation

as

it related to reactor safety

and worker radiation protection,

Mithin

each area,

the inspectors

documented

the specific purpose of the area

under review,

scope of inspection activities

and findings, along with

appropriate

conclusions.

This assessment

is based

on actual

observa-

tion of licensee

activities,

interviews

with

licensee

personnel,

measurement

of

radiation

levels,

or

independent

calculation

and

selective

review of applicable

documents.

1.2

~2

On January

4,

1989, at 2:40 a.m.,

an automatic reactor scram from 100

percent

power occurred

as

a result of the isolation of instrument air

to the cooling .tower

basin

level

instrumentation

(see

Detail 2.2).

The unit was cooled

down

and entered

condition 4,

Cold Shutdown,

in

order to accommodate

a short outage in which miscellaneous

work items

were

accomplished.

On January

7, while in cold shutdown,

a loss of

shutdown

cooling

occurred

for approximately

one

and one-half

hours

following an exchange

of Residual

Heat

Removal

Pumps in the 'A'oop.

(See

Detail

2.3)

Startup

commenced

on

January

11,

at

5:45 a.m.

On January

12, at 4: 15 a.m.,

a reactor

occurred

from approxi-

mately

24 percent "power during

power ascension

while operators

were

in the

process

of transferring

from reactor vessel

startup

level control to automatic level control

(See Detail 2.4).

The unit

remained

in hot

shutdown until several

maintenance

items identified

following the

scram were completed.

The unit was placed in condition

2 (i.e.,

Startup

Mode)

on January

15 at

5:55 p.m.

with full power

being achieved

on January

18.

On

February 4,

the unit

was manually shut

down to allow entry into

the

suppression

chamber

in order to investigate

and repair the sup-

pression

chamber to drywell vacuum

breaker

testing

system for vacuum

breaker

PSV-15704B2

( see Detail 2.6).

1.3

Unit 2 Summar

Unit

2

operated

at

or

near full

power

throughout

the

inspection

period.

Scheduled

power reductions

were

conducted

during the period

for

control

rod

pattern

adjustments,

surveillance

testing,

and

scheduled

maintenance.

No unit related

events

occurred

during this

inspection period.

1.4

Persons

Contacted

During the course

of the inspection,

the inspector interviewed, dis-

cussed

issues,

and

received

information

from

various

licensee

employees.

Listed

below are

the licensee

management

and

employees

who supplied

substantive

information.

Members

who attended

the exit interview on

February 6,

1989; are. indicated

by an asterisk.

J. Blakeslee,

Assistant Superintendent

of Plant,

F. Butler, 'Supervisor of Maintenance,

" R.

Byram, Superintendent

of Plant,

" T. Dalpiaz, Supervisor of Technical

Support,

J.

Doxsey,

Reactor Engineering Supervisor,

" E. Figard, Supervisor of IKC/Computer,

A. Dominguez, Operations

Senior Results

Engineer

" G. Glaser,

Temporary

IEC Supervisor,

" J.

Graham, Assistant

Manager,

NQA

C.

Lopes, Security Supervisor,

T. Markowski, Day Shift Supervisor,

W. Morrissey, Radiological Protection Supervisor,

T. Nork, Plant Engineering

Group Super visor,

" J. O'ullivan, Insulation Engineering

Group,

H. Palmer, Jr. Superintendent

of Operations,

" N. Pitcher,

Construction Superintendent,

R. Prego,

Supervisor of QA Operations,

NQA

H. Riley, Supervisor of Health Physics/Chemistry,

D. Roth, Senior Compliance Engineer,

" R. Stotler, Supervisor of Security,

H. Stanley, Assistant Superintendent-Outages,

2.0

Routine Periodic Ins ections

2.1

The

NRC resident

inspectors

periodically inspected

the facility to deter-

mine the licensee's

compliance with the general

operating

requirements

of

Section

6 of the

Technical

Specifications

(TS)

in the

following areas:

1

review of selected

plant parameters

for abnormal

trends;

plant status

from a maintenance/modification

viewpoint, includ-

ing plant housekeeping

and fire protection

measures;

control

of ongoing, and

special

evolutions,

including control

room personnel

awareness

of these evolutions;

control of documents,

including logkeeping practices;

implementation of radiological controls;

implementation

of the

security

plan,

including access

control,

bo'undary integrity, and badging practices;

control

room

operations

during

regular

and

backshift

hours,

including

frequent

observation

of activities

in progress,

and

periodic

reviews of selected

sections

of the unit supervisor's

log,

the

control

room operator's

log

and

other

control

room

daily logs;

followup items

on activities that could affect plant safety or

impact plant operations;

areas

outside the control

room; and,

selected

licensee

planning meetings.

The inspectors

conducted backshift

and weekend/holiday

inspections

on

January

16,

from

noon

to

4:30 p.m.,

January

31,

from

4:00

to

6:00 a.m.,

and February 4, from ll:00 a.m. to 3:30 p.m.

During these

inspections,

the

inspectors

witnessed

portions

of

a plant startup,

shutdown

and power operations.

The inspectors

reviewed

the following specific

items in more detail.

2.2

Reactor

Due to Isolation of Instrument Air - Unit 1

At 2:40 a.m.

on January

4,

1989,

an unplanned

automatic reactor scram

occurred following a main turbine trip on

low condenser

vacuum.

The

trip resulted

from the

loss of instrument air to the cooling tower

basin level instruments

which was isolated

by an operator.

The loss

of instrument air caused

a false

low basin level signal to be sensed

by all the circulating water

pumps which subsequently

tripped,

thus

causing

a

loss of the main condenser

vacuum.

The loss of the

main

condenser

vacuum caused

a turbine trip resulting in

a reactor

Recognizing

that

a trip of the

unit

was

imminent,

operators

had

reduced

power

from

100

percent

to

60 percent

prior to the

reactor

scram to minimize the effect of the anticipated transient.

a

!

Prior to this,

on January

1,

the Circulating Water

Pump House

(CWPH)

Instrument Air (IA) System

loads

had been lined up'rom Unit

1 to the

Unit 2 IA System

in preparation for maintenance

on the Unit

1 'B'A

dryer tower skid.

Because

the Unit

1

IA System

Operating

Procedure

(OP-118-001)

did not contain

a section for performing this line up,

the

necessary

valve lineup

was

determined

by the

operations

super-

visor referring to the Piping

and Instrumentation

Orawing (P&ID) for

IA.

As

a result,

selected

valves

were repositioned

and the

actions

taken

were

documented

on the shift logs.

On January

4,

a different

operations

shift reviewed

the log entries

describing

the

IA lineup.

From their review of the Unit 2 IA System

procedure,

which included

the valve lineup for transferring

loads to the Unit 2 IA System,

the

new

operations

shift determined

that

the

lineup

did not properly

isolate

the

common

IA loads

from Unit 1.

. The unit supervisor

then

directed

the

operator

to alter

one valve position

in an attempt

to

place

IA in the correct lineup.

However, this action actually iso-

l.ated

the Unit

1 cooling tower basin level instrumentation resulting

in the reactor

scram described

above.

The licensee

conducted

a review of the

and concluded

that the

root cause

was

lack of proper status

control

and procedural

guidance

to the operating shifts to perform this type of evolution.

Correc-

tive actions

taken

by the licensee

included

a change to OP-118-001

to

provide for load transfers

from Unit '1, direction's

to

impTem'ent

a

more detailed

turnover

sheet

between

shifts,

and

a briefing with the

shifts concerning

the event

and its causes.

A review of the post-trip data

by the inspector

indicated that the

plant

operated

as

designed

following the

The inspector

con-

curred with the licensee that inadequacies

in OP-118-001

and turnover

of the

IA system

status

led to this event.

If proper

system status

review and turnover

had been

accomplished

an

unplanned

reactor

could

have

been

avoided.

The inspector

concluded that the operating

crew failed to follow the guidelines of AO-gA-300,

Conduct of Opera-

tions,

which state

that

an evolution may be performed without a pro-

cedure provided that shift supervision

has determined that the evolu-

tion

can

be

safely carried

out

and that

the evolution is

not too

complex to perform without a procedure.

In this

case

the determina-

tion that the valve lineup could

be

made safely without

a procedure

proved to

be incorrect.

This failure to follow station

procedures

is,

as

well

as

other

instances

of

operator

inattentiveness,

is

discussed

further in Section 2.7 of this report.

2.3

Tem orar

Loss of Shutdown Coolin

Unit

1

On January

7, with Unit l. in cold shutdown

and shutdown cooling (SDC)

in service,

operations

personnel

attempted

to

exchange

the 'A'nd

'C'esidual

Heat

Removal

(RHR) pumps for SDC.

The 'A'HR pump

had

been running and the 'C'HR pump was started,

flow adjusted,

and the

'A'HR pump shutdown.

When the

pump

was

shutdown,

the

SDC outboard

isolation

valve,

HV-151-F008,

automatically

closed.

The closure of

F008 isolated the suction

path of the 'C'HR

pump

and

caused it to

trip.

This constituted

a

loss

of

SDC

and the appropriate

Limiting

Condition for Operation

(LCO) was entered

at 7:45 a.m.

The licensee

subsequently

closed the

SDC inboard isolation valve,

HV-151-F009,

and

opened

the

F008 valve

and filled and

vented

the

system

per

OP-149-

002,

RHR Operation

In The

Shutdown

Cooling Mode.

At 8:22 a.m.,

when

the

operators

reopened

F009

a

loud

noise

which

appeared

to

be

a

waterhammer

was

heard

and

F008

reclosed.

An inspection of the af-

fected piping and

equipment

was

immediately performed with no indi-

cation of damage

as

a result of the waterhammer.

The two closures of

F008 are

considered

unanticipated

Engineered

Safety

Features

Actua-

tions.

The

licensee

subsequently

refilled

and

revented

SDC

and

placed the 'C'HR pump back in service at 9: 13 a.m.

and cleared

the

LCO at 9:30 a.m.

The

1'icensee

reviewed

the

event

and

determined

that t'e

cause

appeared

to have

been

due to actuations

of

RHR

SDC isolation instru-

mentation.

The first isolation occurred

when

a pressure

perturbation

was caused

by the 'A'HR pump discharge

check valve shutting at the

time the 'A'HR pump

was tripped.

The

second

isolation

appears

to

be

due to the

method

by which the

SDC

system

is filled and

vented

which allowed

a

section

of piping to

become

voided.

When the

F009

valve

was

opened

following fill and vent,

a flow transient

occurred

isolating

the

F008 valve.

Corrective actions

taken

by the licensee

include the installation of instrumentation

to monitor the

SDC system

in order to determine

the cause of any future isolations

and revising

the fill and

vent

procedure

to

provide

assurance

that

the

system

piping is completely filled.

The

inspector

reviewed

the significant op'crating

occurrence

report

and discussed

the

event with the

licensee.

The

inspector verified

that the appropriate

Emergency Notification System call was

made

and

the appropriate

Licensee

Event Report

was

submitted

as

required

per

10

CFR '50.72

and

10

CRF

50.73.

The

immediate

corrective

actions

taken

by the licensee

were

found acceptable,

however,

the

inspector

concluded that this type of event is

a continuing

problem

and needs

to be more aggressively

pursued

by the licensee's

engineering depart-

ment.

This item will remain

unresolved

pending completion of licen-

see corrective

actions to preclude

recurrence

(UNR 89-01-01).

2.4

Reactor

Due to Feedwater Transient

Unit 1

At 4: 15 a.m.

on January

12,

a turbine trip and reactor

from 24

percent

power occurred.

The unit was in power ascension

following a

7

day

outage

as

a

result

of

the

automatic reactor scram

on

January

4,

1989.

The

operator

was

in

the

process

of transfer ring

level control fry) the

low load

valve

onto

the

reactor

turbine control valve fast closure.

pump

(RFP)

master

controller.

When

the operator

opened

both

the '8'nd 'C'FP

discharge

valves

concurrently,

a

rapid influx of feedwater

into the

reactor

vessel

occurred

causing

level

to rise to the

54-inch

high level

turbine trip.

Due to the

cold water influx,

a

power

spike to approximately

24 percent

power

occurred

which enabled

the

Reactor

Protection

System

(RPS) trip

on

The reactor

then

scrammed

due to

the main turbine trip.

The licensee

conducted

a review of the

and determined that the

root

cause

was

operator

inattention to detail

and the lack of suf-

ficient procedural

guidance for performing this evolution.

Proced-

ural changes

made following the

scram included the addition of a note

to

make

the operator

aware that only one

RFP is to

be

used

to

feed

the reactor

vessel

at

the

time of transfer

and

only one discharge

valve is to be

opened

at that time,

and

a

change

to step

6. 11. 14 f.

to

make

the operator

assure

that level

remains

at

35 inches

and

RFP

speed

decreases

when the low load valve is fully opened.

Additional

corrective

actions

included training

on the event

and its cause

for

all licensed

operators

prior to restart.

This

included

the

Super-

visor of Operations

addressing

each

shift

on

the

recent

operating

errors

and the root causes.

The operator

on the control

panels

dur-

ing

the

event

reviewed

the

sequence

of events

involved with the

transient

and presented

his perspective

and conclusions

to the other

operators.

Each operator

performed

a hands

on manipulation of trans-

ferring from start-up level control to automatic level control

on the

simulator with an

emphasis

on teamwork between

the two Plant Control

Operators

(PCOs)

and the Unit Supervisor.

The

inspector

reviewed

the post-trip

data

and

discussed

the

event

with the licensee.

A review of the controlling procedure

for power

operation

(GO-100-003)

noted

that

the

procedure

provides

specific

steps

for the operator to establish

automatic

feedwater control,

how-

ever,

the procedure

did not restrict the

number of RFPs

feeding

the

reactor

vessel

at this

power level

and allowed the operator to open

two RFP discharge

valves concurrently

when transferring

from the

low

load feedwater

valve.

The inspector

noted that the operator did not

verify that the

RFP speed

control/demand controller was in automatic.

A review of the

licensed

operator

interview

sheet

indicated

that

the operator,

though

he

had

placed

RFP

speed

control/demand control-

ler

in

automatic,

never re-verified this~rocedural

step prior to

proceeding

to the next step.

The operator,

plus the operating

crew,

did

not

recognize

that

reactor

vessel

level

had

increased

to

38

inches

and

RFP, speed did not decrease

following full open

on the

low

load

valve.

In

addition,

the

operator

opened

the

RFP

discharge

valves at approximately

150 psig above reactor

system pressure

versus

the

50-100

psig .specified

in the procedure.

As a result,

the inspec-

tor

concurred

with the

licensee

that

procedural

inadequacies

and

operator

inattention

to detail

led

to this

event.

This

issue

is

discussed

further in Section 2.7 of this report.

2.5

Excessive

Cooldown Followin

Reactor

Scram - Unit 1

On January

16, at 7:00 p.m., during

a review of surveillance

proced-

ure

S0-100-011,

Reactor

Vessel

Temperature

and

Pressure

Recording,

the Unit Supervisor

discovered

that

cooldown

during

the first hour

following the

on January

12 had exceeded

the allowable cooldown

rate

of

100

degrees

per

hour at

the

bottom

head

drain

line.

The

actual

cooldown

rate

was

101 degrees

F.

Additionally, the

tempera-'ure

decrease

during the first 45 minutes

was

137 degrees

F prior to

natural

circulation being established.

Temperature

had dropped

from

520

degrees

F to

383

degrees

F.

The Shift Supervisor

immediately

informed operations

department

management

of the finding.

The plant

was held at 27 percent

power and power ascension

was terminated until

the resolution of the finding.

The Shift Supervisor,

upon determin-

ing that the plant had

been cooled

down faster

than allowed

by tech-

nical

specifications

(TS)

considered

the plant to be in the action

statement

associated

with TS 3.4'. 1.

TS 3.4.6. 1 action

states

that

if a

maximum

cooldown

of

100

degrees

F

in

any

1

hour period

is

exceeded,

restore

the

temperature

to within

the

limits within

30

minutes;

perform

an engineering

evaluation

to determine

the effects

of the out-of-limit condition

on

the

structural

integrity of the

reactor

coolant

system;

determine

that

the

reactor

coolant

system

remains

acceptable

for continued

operation

or

be

in at

least

Hot

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

and in Cold Shutdown within the following 24

hours.

Nuclear

Plant

Engineering

(NPE)

personnel

were notified in

order to determine

the effects

on

the structural

integrity of the

reactor coolant

(RC) system.

At 1:15 a.m.

on January

17, power ascen-

sion

was

resumed

following the

conclusion

from

NPE that the struc-

tural integrity of the

RC

pressure

boundary

was

not

compromised.

However,

because

the plant

had

been

subject to

a cyclic stress,

the

excessive

cooldown transient will be factored into the

number of the

fatigue cycles allowed during the life of the plant.

I

The

licensee's

operations

department

immediately

commenced

a review

of this event.

The licensee

determined

that the

operators

properly

followed applicable operating

procedures

E0-100-101,

Scram Bases,

and

G0-100-011,

Plant

Cooldown

Following

A Scram,

to establish

natural

circulation

and

subsequent

restart of the recirculation

pumps.

The

licensee, determined

that the plant response

to the reactor trip and

subsequent

cooldown is what should occur.

This conclusion

is based

on

the fact that

the

proper

conditions

did

not exist

to

support

natural circulation.

The reactor water level

was not high enough to

support natural circulation and the reactor recirculation

pumps

were

not started until one hour after the scram.

Because

natural circula-

tion had not been established,

thermal stratification occurred in the

bottom

head

area of the reactor vessel.

The licensee

noted that the

CRD flow had only been

decreased

to

60

gpm

as

compared

to 20-25

gpm

as specified

by EO-100-101.

This excess

cold water was

added to the

bottom

head

area

contributing

to

thermal

stratification.

Once

natural

circulation

was established,

temperature

at the bottom

head

drain increased

to

419 degrees

F.,

and at

5:30 p.m., after

the

'A'eactor

recirculation

pump start

induced forced circulation, tempera-

ture

increased

to

432

degrees

F.

As

a

result

of

reestablishing

forced

flow,

the

subsequent

cooldown

rate

was

reduced

to approxi-

mately 24 degrees

per hour.

Although the

heatup/cooldown

procedure,

S0-100-011,

was

implemented

following the

scram,

the

licensee's

review noted that the operating shift failed to identify the

exces's-

ive cooldown.

As

a result,

the excessive

cooldown rate

was not dis-

covered until

several

days

later

on

January

16,

when

a

review of

SO-100-011

was being performed.

The licensee's

review concluded that

the root

cause

was

operator

inattention

to detail

and

a potential

weakness

in the post-trip review program

which allowed the

cooldown

temperature

data to go unreviewed unti 1 startup

had commenced.

Corrective actions

taken

by the licensee

include initiating an Engi-

neering

-"Work Request

(EWR) which requests

a generic

evaluation

of

cooldowns following scrams

with

a loss of reactor recirculation

and

performing

an evaluation of the post-trip review program.

The licen-

see believes that exceeding

the cooldown rate within the first 60-90

minutes

following a

may

be unavoidable.

Also, the

importance

of monitoring

cooldown

and

notifying

supervision if limits

are

exceeded

was stressed

during crew briefings.

Following discussions

of the event with the licensee,

and

a review of

the Significant Operating Occurrence

Report

(SOOR)

on the event,

the

inspector

concurred

with

the

licensee's

characterization

of this

event.

Inattention to detail

on the part of the operator

caused

the

excessive

cooldown

rate

to not

be identified per

the

surveillance

procedure.

The

inspector

noted

that

the

surveillance

procedure

allowed the operators

to record the required

temperature

data for a

cooldown

and

subsequent

heatup

without review

by shift supervi sion

until completion of the heatup.

Since the procedure did not require

a

separate

surveillance for each

heatup

or cooldown,

the Unit Super-

visor did not formally review the

data

and identify the violation

until the unit was in power ascension.

The inspector

noted that the

post-trip review by the Shift Technical

Advisor (STA) did not iden-

tify the excessive

cooldown.

The post-trip

review process

requires

the

STA to look at the

cooldown rate but does

not require

a formal

calculation

to

be

performed.

Based

on

the

fact that

neither

the

post-trip

review

nor

the

surveillance

procedure

identified

the

excessive

cooldown,

the

inspector

concluded

that

the

significant

deficiency

existed

in

the

licensee's

program to

assure

compliance

with this section of the Technical

Specifications.

From

a review of

data

from previous

reactor trips

and discussions

with the licensee,

the inspector

concurred with the licensee's

analysis

of the plant's

response

to

a

scram with loss

of recirculation flow.

As designed,

the plant's

cooldown rate for the first one to one

and one-half hours

may exceed

100 degrees

per hour for automatic scrams with recircula-

tion pump trips.

The .licensee

is reviewing historical data to deter-

mine if other cases

of excessive

cooldown rate exist.

Based

on

the

information

above,

the

inspector

concluded

that

the

licensee

had violated Technical Specification 3.4.6. 1.

This specifi-

cation requires that if a

maximum cooldown of 100 degrees

F in any

1

hour period is exceeded,

the licensee

shall restore

the

temperature

to within the limits within 30 minutes;

perform an engineering

evalu-

ation to determine

the effects of the out-of-limit condition

on the

structural

integrity of the reactor

coolant

system,

and;

determine

that

the

reactor

coolant

system

remains

acceptable

for

continued

operations

If the

above

action

is

not

taken,

the unit is to

be

placed

in Hot Shutdown within

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

and

in Cold

Shutdown within

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

The inspector

noted that although

cooldown

rate decreased

to within the limits within 30 minutes after exceeding

the

maximum

allowable

cooldown,

an

engineering

evaluation

was

not

performed until several

days later on January

16 and the unit was not

placed

in cold

shutdown within the required

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

Additionally,

the

unit

was

placed

in

startup

(Condition

2),

at

5:55 p.m.

on

January

15,

the

reactor

was

made critical

and

power

ascension

had

begun prior to the licensee

discovering that the cooldown limits were

exceeded.

Specifically, the inspector determined that the failure to

take the Technical Specification

required action within the allotted

time

is

an

apparent

violation of Technical Specification 3.4.6. 1

(UNR 89"01-02).

10

2.6

Forced

Shutdown

Due to Vacuum Breaker Failed Surveillance - Unit 1

On February 2,

1989,

a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months Limiting Condition for Continued Oper-

ation's

(LCO)

was

entered

when

primary

containment

vacuum

breaker

PSV-15704B2 failed to open during its monthly surveillance.

In order

to

comply with Technical

Specification

action

3.6.4.2,

a

shutdown

from 100 percent

power

was initiated at 7:00 p.m.

on February 3.

A

1-hour

Emergency

Notification

System

(ENS)

call

had

been

made

in.

advance to the

NRC at 6:23 p.m.

The main turbine

was

taken off line

at

12:44 a.m.

on February 4, with reactor

power at

15, percent.

The

reactor

was then

shutdown

by inserting all control

rods

and the

mode

switch

was

placed

in shutdown

at 7:40 a.m.

on February

4.

The oper-

ator reset

the

but did not

place

the

discharge

volume

high

level trip

bypass

in

the

bypass

position.

Approximately

17

seconds

after the

was reset,

an automatic scram trip occurred

due to the

scram discharge

volume high level trip, however

no control

rod movement

occurred

since all

rods

had

been

previously

inserted.

The operator

then

placed

the

scram discharge

volume (SDV) high level

trip bypass

in the bypass position

and reset the scram.

The licensee

made

a 4-hour

ENS call

due to the Reactor Protection

System Actuation

at 8:35 a.m.

on February 4.

On February

5, the licensee

entered

the suppression

chamber to inves-

tigate

vacuum

breaker

PSV-15704B2's

failure

to

open

during its

monthly surveillance.

The licensee

determined

that

a nonfunctioning

solenoid

valve

in the testing circuit was

the

cause

of the

vacuum

breaker's

failure to

open.

The

licensee

replaced

all

ten

solenoid

valves to the ten

vacuum breakers

in the suppression

chamber.

Following discussions

with the licensee

and

a review of the Signifi-

cant Operating

Occurrence

Report,

the inspector

determined

that

the

automatic scram trip was

due to the operator

not bypassing

the

SDV

high level trip prior to resetting

the

The operator

is not

directed

to do this during

a routine manual

shutdown

by the control-

ling procedures

(G0-100-005,

Plant Shutdown

From Minimum Power Opera-

tion,

or G0-100-011,

Plant

Cooldown Following A Scram).

This event

was

due

to

a

weakness

in the

controlling

procedures.

Discussions

with operations

personnel,

however,

indicated that bypassing

the

SDV

high level trip prior to resetting

the

was

a

known requirement.

The unit shift supervisor

was observing the shutdown but was not able

to

intervene

quickly

enough

to

prevent

the

operator

error.

The

inspector

discussed

this

event with the

licensee

and

was

informed

that they intend to revise

the applicable

procedures.

The inspector

found the licensee's

actions

in response

to the failed vacuum breaker

surveillance

and

the

inadvertent

acceptable.

The

inspector

concluded

that

procedural

inadequacies

and

operator

inattention

to

detail

led to

the

inadvertent

reactor

This

is

discussed

further in Section 2.7 below.

11

2.7

I

0 erational

Summar

During this period,

two reactor

scrams

occurred

from power

and

one

reactor

occurred

while the plant

was

shutdown.

These

events

included

several

apparent

violations

of

established

procedural

requirements,

and in some

cases

inadequate

procedures.

In each

case

the

event

was

due

to either inattention to detail

by the operating

crew or weaknesses

noted

in the

procedures

guiding

the

evolution.

The first reactor

scram that occurred

on January

4,

due to isolation

of instrument air to the Unit 1 cooling tower basin

level

instrumen-

tation,

was

caused

in part

by an

inadequate

review by the operating

staff of the plant status.

The inspector

considered

this to

be the

failure of the

operating

crew to follow in-place

programmatic

pro-

cedures

to address

valve

lineups

and

status

control

of the

plant.

The

second

reactor

that

occurred

on

January

12,

due

to the

feedwater transient

appeared

to be

caused

by operator

inattention to

detail.

This situation

was

exacerbated

by limited guidance

by the

procedure that was directing this evolution.

The reactor

scram that

occurred while the plant

was

shutdown

due to high level in the