ML17342A281

and the repair effort did not address

identification and correction

of the

source

problem (paragraph

9)

(250,251/85-30-04).

Failure to meet

the requirements

of TS 3.3.3,

in that

a containment isola-

tion valve

was

open

and not capable

of automatic

closure

(paragraph

14)

(251/85-30-05).

No new Unresolved

Items were identified.

Two inspector

follow-up items (IFI) were identified;

Review the extent to

which

the

purchasing

department

expedites

the

purchase

of

spare

parts

(paragragh

9)

(IFI 250,251/85-30-06);

Review

the

extent

to which the

calibration

program

addresses

the periodic calibration of newly installed

equipment

(paragraph

8) - (IFI 250,251/85-30-02).

4v

I'

The licensee

did not identify as proprietary

any of the materials

provided

to or reviewed

by the

inspectors

during this inspection.

The

licensee

acknowledged

findings one through four without dissenting

comments.

However, the licensee felt that violation 251/85-30-05

should

be

addressed

as

an additional

example of violation 250,251/85-30-01,

item (c) since the

loss of the

containment

isolation function

was

an

inadequate

(TSA).

The licensee's

position

was

considered

by the inspectors

and

NRC Region II

management.

It was

rejected

for several

reasons.

Violation 85-30-01,

item (c) deals

with inadequate

implementation

of reviews

required

by

an

existing procedure.

With respect

to violation 85-30-05,

the

loss of con-

tainment isolation capability is

a violation of a specific

TS requirement

as

differentiated

from the general

requi rement of TS 6.8. 1 to implement

procedures.

The problem involved in violation 85-30-05

was

a design error.

Though identified

and reported

by the licensee,

the mitigation factors of

10 CFR 2, Appendix C, Section

V.A(4) were not all applied.

The corrective

action to detect this type of problem would have to include

a post-

installation test.

The

NRC staff concluded

that violation 85-30-05 is

a

different violation from 85-30-01,

item (c).

Licensee Action on Previous

Inspection

Findings (92702)

Performance

Enhancement

Program

(PEP)

Summary

In late

1983,

as

a r'esult of identified deficiencies,

the licensee

developed

an

informal program to improve site performance.

Subsequent

to enforcement

discussions

held in January

1984,

licensee

management

developed

the

PEP which the

NRC formalized by a Confirmatory Order

on

July 13,

1984 (EA-84-55).

The Order also

addressed

areas

of special

and

immediate

concern.

Specifically,

the

performance

of the Quality

Control

and Quality Assurance

organizations

on site

and the independent

verification program

had not

been effective.

The

PEP was intended to

address

NRC

concerns,

improve

regulatory

compliance

and

implement

regulatory

corrective

actions,

and it is scheduled

to continue

into

1987.

The

PEP coordinated

improvements

in the following areas:

organization

structure,

Quality Assurance

(QA) program

changes,

upgrade of the TS,

establishment

of safety

engineering

groups,

allocation

of additional

resources

arid upgrade of facilities, operations

enhancement,

procedures

upgrade,

improvement of the plant configuration control

program,

and

training

and

improvements

in maintenance

management.

As

a result of

subsequent

enforcement

action

(EA 84-121),

the

licensee

added

an

additional

program to

PEP.

The

Program for Improved Operation

(PIO)

included:

reviewing the Final Safety Analysi> Report

(FSAR) to assure

plant

operation

within

the

safety

analysis;

identification

and

correction

of

surveillance

program

deficiencies;

and

increased

management

awareness

and overview of operations.

This was confirmed by

a Confirmation of Concurrence

letter

on October

11,

1984.

The combined

program schedule

tracks several

aspects

of the following:

(1)

Site facility upgrade

(2)

Operations

enhancement

(3)

Procedures

(4)

Configuration control

(5)

Training

(6)

Management

action

program

(7)

Licensing

(8)

equality

assurance

and quality control

(9)

Maintenance

management

system

( 10)

Technical Specification revisions

(11)

Operability of safety

systems

Overal

1

PEP/PIO Evaluation

In general,

the

implementation

of the

PEP/PIO

has

shown

successes

in

that adequate

management

attention

and resources

have

been

focused

on

identified

problem

areas.

Scheduler

performance

and regional inter-

faces

have

been satisfactory

in most areas.

Upper management's

commit-

ment to excellence

is apparent

not only in the Turkey Point

PEP but

also in other corporate quality improvement

programs.

A summary of the significant areas

as

addressed

by the

ORDER and the

licensee's

April ll, 1984, letter follows.

Organizational

Structure

On-site

management

involvement

and

control

has

been

improved

by

modifying the Nuclear

Energy

Department

organization.

The Site Vice

President

has

assumed

overall

management

responsibility for the nuclear

facility which has

allowed better control

and allocation

of on-site

resources.

This

has

improved the control of construction activities,

especially

during

the

on-going

fire

protection

modifications.

Corporate

engineering

has

become

more

responsive

to the plant

due to

the addition of on-site engineering

representatives.

gA Program Nodifications

The

thrust

of

the

program

has

changed

to

be

more

operationally

oriented,

additional

personnel

have

been

added

to the staffs

and

training has

been

and is being provided.

Some personnel

are receiving

operations

training similar to that of licensed

operators.

The early

on-shift

gA coverage

benefitted

operations

in establishing

procedural

compliance.

Licensee

management

is beginning

to derive insights

from

their program.

Standard

Technical Specifications

(STS)

The existing

TS are being modified to make the format and contents

more

explicit and consistent with STS.

Some questions

as to philosophy

have

arisen

in this area.

The submittal is scheduled

to be sent to the

NRC

Office of Nuclear Reactor

Regulation

in November

1985.

Safety Engineering

Group

(SEG)

The

SEG was established

to provide

an overview of nuclear safety issues

and

reports

to the Site

Vice President.

Duties

include

procedure

review,

system

walkdowns

and

review of operating

and

maintenance

practices.

Permanent

staff

positions

have

been

filled

and

the

expertise of these

engineers

is being utilized.

Resources

and Facilities

The on-shift administrative

burden of the shift supervisors

has

been

greatly alleviated

by the addition of shift administrative technicians.

Seventy-six

people

have

been

added to the plant staff including system

engineers

and training instructors.

Licensed

operator

classes

have

been provided with sufficient enrollment to alleviate the current shift

manning

problems

and to augment

the shifts by the spring of 1986.

The procedure

upgrade

project

has rewritten

and developed

many proce-

dures that have significantly aided in the plant's operational

enhance-

ment.

The

schedule

for completion

extends

to

1987 but the prioriti-

zation

of procedures

has

allowed essential

procedures

to

be either

changed

or developed

on

an

expedited

basis.

The project staff

has

responded

to the plant's

needs

by providing real

time

support

for

changes

to procedures

as the

need arises.

The effort to

achieve

Institute of Nuclear

Power

Operations

( INPO)

accreditation

for the training programs

in the operator licensing area

and

maintenance

area

is progressing

and

an

INPO progress

audit

was

completed

in

September

1985.

However,

the current training

program

for maintenance

personnel

has

been greatly curtailed while the licensee

utilizes instructors to develop the

INPO accreditation

program.

Formal

training lectures

addressing

mechanical

maintenance

techniques

have not

been

presented

since August 1984.

The

improvement to the site facilities includes

the following new or

refurbished buildings:

Health Physics building

Administrative building

Training and simulator building

Maintenance building

The progress

on the buildings

has

been

on schedule

The commitment to

upgrade

the facilities,

in conjunction with the actual

expenditure of

funds,

has

improved the morale of the plant staff.

Consolidation of

the

nuclear

plant staff

should

improve

management

effectiveness

and

overall

efficiency.

The

plant

specific

simulator

is

expected

to

enhance

operator training.

TS and

FSAR Operability Review

Reviews

of the

TS

and

FSAR

were

performed, to identify systems

and

components

which were not receiving comprehensive

operability testing.

The results

of these

reviews are being. included in the

TS rewrite and

in the surveillance

program.

The comprehensiveness

of these

programs

is an area of concern

since the reviews performed to date are

known to

have

not identified all

components

which would benefit

from enhanced

operability testing.

Previously Identified Item Follow-up

(Closed)

UNR 250,251/85-26-04.

It

has

been

determined

that

the

licensee failed to aggressively

pursue

and identify the root cause

of

two electronic

over speed

trips of the

B

AFW pump

on June

26,

1985.

This omission contributed to the electronic

of the

same

pump

on

July 22,

1985.

The

unresolved

item

has

been

resolved

as

a

violation.

The failure of the licensee

to establish

measures

to assure

that

conditions

adverse

to

quality

are

promptly identified

and

corrected is

a violation of the requirements

of 10 CFR 50, Appendix B,

Criterion XVI.

Corrective action for this occurrence will be tracked

as violation 251/85-30-04.

The details of the violation are

discussed

in paragraph

9 of this report.

(Open)

UNR

250,251/85-26-05.

The

licensee

has

acknowledged

that

extrapolation

of approximate

power

range

nuclear

instrument

currents

would provide information of value to the control

room operators

in

analyzing radial flux tilt.

However,

the

licensee

does

not feel that

interim currents

should

be

installed

in

the

power

range

nuclear

instruments

because

of the time constraints

the maintenance

places

on

the

instrument

and control

department.

The licensee

plans to provide

the

interim

information

to

the

control

room

operators

without

installing the currents.

The lengthy time presently

needed

to install

the currents is related to the relative inexperience

of the instrument

and control staff.

This item will remain

open pending

an evaluation of

the licensee's

proposal

by

a regional

reactor physics specialist.

4.

Unresolved

Items

An unresolved

item is

a matter about which more information is required to

determine

whether it is acceptable

or may involve

a violation or deviation.

No

new

unresolved

items

were

identified

during this

inspection.

Two

previously identified unresolved

items are discussed

in paragraph

3.

Licensee

Event Report

( LER) Follow-up (92700)

The following LERs were reviewed

and closed,

except where specifically noted

as remaining

open.

The inspectors verified that: reporting requirements

had

been

met,

causes

had

been identified, corrective actions

appeared

appro-

priate,

generic applicability had

been

considered,

and

the

LER forms were

complete.

A more detailed

review was

then

performed

to verify that:

the

licensee

had

reviewed

the

event,

corrective

action

had

been

taken,

no

unreviewed

safety questions

were involved,

and

no violations of regulations

or

TS conditions

had

been identified.

Exceptions

to the

above

evaluation

criteria are itemized below,

as applicable.

(Closed)

LER 251/84-07.

On

May 9,

1984, three Unit 4 480 volt load center

feeder

breakers

tripped

due to procedural

inadequacies

which allowed

the

connection

of direct current

(dc) electrical

power to alternating

current

(ac) coils.

Maintenance

Procedure

(MP) 4107.5, Electrical

Preparations

for

Integrated

Test of Engineered

Safeguards

and

Emergency

Power

Systems,

has

been modified to preclude

recurrence

of this problem.

(Closed)

LER 251/84-08.

On June

1,

1984, Unit 4 experienced

a reactor trip

from 10 percent

power.

The root cause

was determined

to be personnel

error

in that the control

room operator allowed reactor

power to reach

10 percent

while the turbine generator

was

not latched.

This condition results

in an

automatic reactor trip.

Both units

have tripped previously during efforts

to

open

the

main

steam isolation valves.

The valves

are

not designed

to

open

when

a large differential pressure

exi sts

across

the valve seat.

To

equalize

the pressure,

the

steam

bypass

valve is opened.

Leakage

in the

secondary

system

precludes

full pressure

equalization.

Since

downstream

pressure

can not be raised,

the control

room operators

lower steam generator

pressure

by releasing

steam through the atmospheric

steam

dump valves.

The

resultant

steam generator

cooldown is compensated

for by increasing

reactor

power.

During this event,

the reactor operator

allowed power to exceed

the

one or two percent

which should

be maintained

during the evolution.

The

licensee

does

not consider the amount of secondary

leakage

to be excessive.

Diligent control

room operators

are

able to perform the desi red evolution

without tripping the reactor.

(Open)

LER 251/84-09.

On

May

27,

1984,

the

licensee

isolated

a failed

containment

isolation

valve

by closing

upstream

valves that

were

not

containment

isolation valves

and

had not

been

leak tested.

The resultant

violation of containment

isolation criteria

prompted corrective action to

develop

a procedure listing all containment

boundary valves

and specifying

the conditions necessary

to heat the primary coolant above

200 degrees.

As

of October

15,

1985,

the

procedure

had

not

been

implemented.

This

LER

remains

open pending final approval of procedure

4-0SP-053.4

by the

PNSC.

(Closed)

LER 251/84-23

and

(Closed)

LER 251/84-14.

Both of these

LERs

pertain

to reactor trips that resulted

from failed

source

range

nuclear

detectors.

The first failure occurred

on July 16,

1984.

The detector

failed again

on October

16,

1984.

Both times

the detector

was replaced

and

calibrated.

The

licensee

was

not

able

to determine

a

reason

for

the

failures.

The procedures

used in the replacement

have proven to be adequate

during

subsequent

detector

change

outs.

Additional failures of this type

have not recurred during the past year.

(Closed)

LER 251/84-20.

The licensee

has

developed

procedures

to control

and verify the position of containment isolation valves.

These administra-

tive controls

should

preclude

the mispositioning of containment

isolation

valves in the future.

(Closed)

LER 251/84-25.

The licensee

has

implemented

improved cleanliness

criteria for the switchgear

rooms which should

preclude

additional

foreign

material

contamination

inside

the

breaker

cubicles.

All

4160

volt

electrical

switchgear

have

been

cleaned

and

inspected.

No additional

breakers

were

identified

as

having

severe

cleanliness

problems.

The

licensee

has

implemented periodic switchgear cleaning

on

a refueling outage

basis.

(Open)

LER 250/85-21.

This

LER fails to meet the content

requirements

of

10 CFR 50.73(b).

Several

significant discrepancies

have

been

discussed

with

the

licensee.

The licensee

has

agreed

to submit

a revision to this

LER

within 30 days.

(Closed)

LER 250/84-20

Inadequate

Emergency

Diesel

Generator

(EDG)

Surveillance

Procedure

(OP 4304.3,

Narch 18,

1983).

This procedure

was the

subject of a violation (250/84-14-03)

which was closed

by Inspection

Report

( IR) 50-250/84-18.

The procedure

had been revised to increase

the amount of

data taken to evaluate

EDG performance.

(Closed)

LER 250/82-21

Inadequate

EDG Surveillance

Procedure

(OP 4304. 1).

The current revision

(June

12,

1985) of the procedure specifically directs

the operator to load the

EDG to

> 2500 kilowatts within ten

minutes after

starting

the engine.

Additionally, the licensee

has revised Administrative

Procedure

(AP) 103. 18 (February 7, 1985), Facility Operating

License

Amend-

ments and/or

Changes,

to ensure that

TS amendments

are tracked

and that all

associated

procedures

are appropriately

revised within 60

days after the

amendment

issued.

(Closed)

LER 250/83-09

and (Closed)

LER 250/83-12 - Failure of the Auxiliary

Feedwater

(AFW)

Pump

To

Reach

Operating

Speed

and

Deliver

Flow.

The

licensee

evaluated

the failed differential pressure

transmitter

(DPT-2401)

as

unnecessary

for system

operation

and simplified the

pump turbine

governor

control

scheme

Change/Modification

(PC/M)

inspected

and evaluated

in

accordance

with IR 50-250,

to

operate

at

constant

speed

(Plant

83-49).

The entire

LER 250/84-22 - Missed Surveillance

system

was

recently

detail; all corrective actions will be tracked in

251/85"32.

(Closed)

LER 250/84-17 - Primary Water

Storage

Tank

(PWST)

Valve

Leakage.

Removing

the

PWST from service

was not specifically addressed

by an action

statement

in the facility's TS.

The licensee

therefore applied

TS 3.0. 1 and

placed

the plant in

a 6-hour hot shutdown limiting condition for operation

(LCO).

Valve repairs

were

completed

in about

one

and

one half hours with

sufficient time remaining

in the

LCO to permit

a controlled unit shutdown

had it become

necessary.

(Open)

LER 250/84-19

and

(Open)

LER 250/84-20

Reactor

Coolant

System

Leakage

Requiring

Unit

Shutdown.

Two

PC/Ms

(84-115

and

84-129,

respectively)

were completed to modify the leaking valves

by replacing

the

damaged

original valve gland flanges with temporary

"strong-back" plates.

In discussions

with licensee

representatives,

the inspector determined

that

the engineering

evaluation

to determine

the root cause of the fai lures

and

provide

a permanent fix recommendation

had not been completed.

(Closed)

Caused

by Operator Oversight.

Operating

Procedure

0204.2,

Schedule

of

Periodic

Tests,

Checks,

and

Operating

Evaluations,

has

been

revised

to incorporate

the required daily

power

range

nuclear

instrumentation

system

thermal calibration if power is

greater

than ten percent.

The operator initials the check sheet to certify

completion of the test

and the day shift Plant Supervisor-Nuclear

(or Senior

Reactor Operator

Designee)

signs the check sheet to verify the completion of

all periodic tests.

The inspector

reviewed the facility's training records

and verified that this

LER was

addressed

during

operator

requalification

training.

(Closed)

LER 250/84-24

Missed Surveillance.

The equality

Control

(gC)

surveillance

tracking program

has

been

upgraded.

When

a surveillance's

due

date is passed,

a written reminder is sent to the cognizant department

head;

a follow-up reminder,

with a

copy to the Plant

Manager,

is sent

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

before

the expiration of the grace period.

The

IKC technicians

responsible

for the

missed

surveillance

were

counselled

regarding

the

importance

of

meeting

TS surveillance

requirements.

The plant

has

also

instituted

a

special

form for

documenting

counselling

and

instructional

sessions

performed

as corrective action for inspection findings,

LERs, etc.

(Closed)

LER 251/83-09

Failure of the

4A Steam

Generator

(SG)

Blowdown

Isolation Valve to Close.

The root cause,

isolation of instrument air to

the

valve actuator,

has

been

corrected

by modifying the valve actuators

(PC/M 83-13) to ensure

positive closure of the

SG blowdown valves

upon

a

loss of instrument air pressure.

ll

l

10

Post Three Mile Island Implementation

Follow-up (NUREG-0737)

(Closed

Units

3 and 4) Item II.F.1/1.B.2 and 2.B.2

Accident Monitoring-

Noble

Gas Monitor and Iodine/Particulate

Sampling.

The

PC/M (¹80-131)

under

which the facility's wide

range

noble

gas

monitors

were

installed

was

implemented

on February

25,

1982.

The inspector verified that monitors for

the air ejector vents (Units 3 and 4), the fuel pool vent stack

(RAD-6418),

the

common vent stack (RAD-6304),

and the

main

steam line were operational

and

they

had

been

calibrated

within the

periodicity

required

by

the

facility's TS.

(Closed

Unit 3) Item II.F. 1.3 - Containment

High Range

Radiation Monitors.

The

monitors

have

been

installed

and

are

operational.

The

inspector

verified that

the

instruments

were calibrated

during

the last refueling

outage

as required

by

TS 4. 1, Table 4. 1-1.

(Closed - Units

3 and 4) Item II.F. 1.4 - Containment

Pressure

Monitors.

The

narrow and wide range

instruments

on both units are fully operational.

The

inspector

verified that

the

monitors

were

calibrated

during

the

last

refueling outages

as required

by the facility's TS.

(Closed - Units

3

and

4) Item II.F. 1.5

Containment

Mater

Level Monitor.

The

PC/Ms

under which the level

instruments

were installed

(¹70-1328

and

¹79-133B)

were

closed

on

October

22,

1983.

Calibration

records

were

verified to ensure

compliance with the facility's TS.

IR 50-250,

251/82-06

noted that the licensee

had never submitted

a request

to

NRR to deviate

from

the

NUREG-0737 requirement to monitor the containment

level to an elevation

equivalent

to

a

600,000

gallon

capacity.

A deviation

request

was

subsequently

submitted

on

May 3,

1982 (L-82-180)

and

found acceptable

by

NRR.

(Closed - Units

3 and

4) Item II.F. 1.6

Containment

Hydrogen Monitors.

Both units containment

hydrogen

monitors

are installed, fully operational,

and calibrated in accordance

with the facility's TS.

(Open

Units

3

and

4) Item II.F.2.3B - Instrumentation

for Detection

of

Inadequate

Core Cooling.

The

PC/Ms (¹81-162

and ¹81-167)

under which this

instrumentation

is being installed were still open pending resolution of the

system's operability criteria with the

system

vendor.

IE Bulletin (IEB) Follow-up (92703)

(Open)

IEB 79-18, Audibility Problems

Encountered

on Evacuation of Personnel

From High-Noise Areas.

documented

in

inspection

reports

250,251/84-11

and 250,251/85-13.

The licensee's

loud-

speaker

page

system

remains

inadequate.

There are

numerous

on site areas

in

which personnel

can

not clearly hear

announcements.

The licensee

has

been

notified of the problem by both the

NRC resident

inspectors

and subsequently

by

an

INPO evaluation

team.

The

licensee

has

shown

no inclination to

reevaluate

their

compliance with the audibility criteria set forth in the

bulletin.

Consequently,

audibility

has

not

improved

and

the

following

additional

problems

were noted:

a.

On

September

24,

1985,

during

a fire drill, one

member

of the fire

brigade did not respond to the drill site.

The fire brigade

member did

not

hear

the fire horn

and

did not

hear

loudspeaker

announcements

identifying the location of the fire.

One other brigade

member could

not identify the location of the fire drill site

because

he too could

not clearly hear

the

announcements.

He located

the drill site only

after questioning other members of the staff.

b.

On

September

26,

1985,

during

a fire drill, the fire brigade

team

leader

was

unable

to hear

the fire alarm

and

subsequent

information

announcements.

He was late arriving at the drill site, arriving only

after other staff members

informed him a drill was in progress.

c.

On

September

27,

1985,

the

inspectors

observed

rags

stuffed in the

loudspeaker

located in the safety injection

pump room.

Even though the

loudspeaker

announcements

sounded muffled, several

licensee

personnel,

including supervisory

personnel,

indicated that they were

unaware

of

the clearly visible obstruction.

d.

On

September

28,

1985,

the

loudspeaker

across

from the

chemistry

laboratory

was observed

to be inoperable.

This significantly degraded

the ability to hear

announcements

in the auxiliary building.

Conversations

with

members

of

the fire protection staff revealed

that

audibility problems

had interfered with fire brigade drill response

on

a

number

of occasions.

The inability to

hear

or clearly

under stand

loud-

speaker

announcements

constituted

a

common post drill critique comment.

Oue

to

past

NRC

and

INPO

comments

the

licensee

plans

to

implement

a

preventive

maintenance

plan for the

loudspeaker

system.

Guidelines

are

being

developed

and

upgraded

to create

a

formal plant

procedure

and

a

periodic test.

It is not anticipated

that this program will alleviate the

audibility

problems

in high

noise

areas

or fully correct audibility in

general

areas'owever,

if adequately

implemented, it should

improve

general

area audibility.

8.

Monthly and Annual Surveillance

Observation

(61726/61700)

The inspectors

observed

TS required surveillance testing

and verified: that

the test procedure

conformed to the requirements

of the TS, that testing

was

performed in accordance

with adequate

procedures,

that test

instrumentation

was calibrated,

that

LCOs were met, that test results

met acceptance

criteria

requirements

and

were

reviewed

by

personnel

other

than

the

individual

directing the test, that deficiencies

were identified,

as appropriate,

and

were properly reviewed

and resolved

by management

personnel

and that system

restoration

was adequate.

For completed tests,

the inspector verified that

IR y

12

testing

frequencies

were

met

and

tests

were

performed

by qualified

individuals.

The inspectors

witnessed/reviewed

portions of the following test activities:

Units

3 and

4 AFW Train

1 Operability Verification

Units 3 and

4 AFW Train

2 Operability Verification

Unit 4 Residual

Heat

Removal

(RHR) Periodic

Pump Testing

Unit 4 Containment

Spray

Pump Testing

Unit 3 Reactor Protection

System Periodic Test

Units

3 and

4

AFW Nitrogen System Testing

Unit 4 Containment

High Range

Area Radiation Monitor Calibration

Safety Injection

Pump Motor Vibration Monitoring

The Unit

4 containment

high

range

area

radiation monitors

were reported

operational

in inspection report 50-251/82-06.

The inspector contacted

the

IKC Department to determine if the surveillance

record for the monitors

was

up-to-date.

The licensee

conducted

a lengthy

search

for documentation

to

support its contention that the monitors

had

been calibrated during the last

Unit 4 refueling outage.

On September

26,

1985,

the licensee

abandoned

the

search

and concluded that periodic calibration

had not

been

performed.

It

was determined

that the

requi rements

of TS 4. 1, Table 4. 1-1,

as related to

containment

high radiation monitor survei llances,

did not

become effective

until

several

months after

the

completion

of the last Unit 4 refueling

outage.

Consequently,

no violation of the

TS

surveillance

periodicity

occurred;

however,

the radiation

monitors

were required to

be operable

by

Generic Letters 82-05

and 82-10.

Though initially calibrated,

the radiation

monitors

were

not

added

to

the

periodic

recalibration

program.

Consequently,

following a

1983

source calibration,

the

monitors

were

not

again

calibrated

until

September

1985,

when

the inspector identified the

discrepancy.

Additional evaluation will be

performed

to

determine

the

extent

to which the

licensee's

periodic calibi ation

program

incorporates

newly installed equipment - (IFI 250,251/85-30-02).

On

September

5,

1985,

the inspector

observed

the performance

of OP 3204. 1,

Residual

Heat

Removal

System

Periodic

Test,

revision

dated

December

20,

1984.

The procedure

provides instructions for performing the periodic test

of the

RHR

pumps

and

obtaining test

reference

values

used

to certify

conformance

to the

requirements

of

TS 4.5.2

and the inservice test

(IST)

program.

Section

8.8.4

of the

procedure

requires

that

a

second

person

independently

verify that four valves

are

locked

open.

The

valves

were

unlocked

and closed

in

a proceeding

step.

Section 8.8.4 of the

procedure

was initialled as

complete

by

an operator

who

had

not verified that

the

valves

were

locked

open.

Apparently the operator

misread

the requirements

of the section

and verified only that remote indicator lights indicated the

valves

were

open.

Prior to noticing this discrepancy,

the

4A RHR pump was

started.

Thus,

the

pump was operated prior to the completion of the lineup

procedure.

When questioned

about the discrepancy,

the operator

immediately

acknowledged

his

error

and

the

required

independent

verification

was

properly

performed.

The breakers

were verified to have

been positioned

and

locked as required

when the

pump was operating.

I

13

Technical Specification (TS) 6.8.1

requires

that written

procedures

and

administrative policies

be established,

implemented

and maintained that meet

or exceed

the requirements

and

recommendations

of sections

5. 1

and 5.3 of

ANSI N18.7-1972

and Appendix

A of USNRC Regulatory

Guide 1.33.

The failure to fully implement

OP 3204. 1,

section 8.8.4,

is

one of three

examples

of the failure to meet

the

requirements

of TS 6.8. 1 contained

in

this report (250,251/85-30-01)

.

Maintenance

Observations

(62703/62700)

Station maintenance activities of safety-related

systems

and components

were

observed

and

reviewed to ascertain

that they were

conducted

in accordance

with approved

procedures,

regulatory guides,

industry

codes

and

standards

and in conformance with TS.

The

following items

were

considered

during this

review,

as appropriate:

that

LCOs were

met while components

or systems

were

removed

from service;

that approvals

were obtained prior to initiating work; that activities were

accomplished

using

approved

procedures

and

were

inspected

as applicable;

that procedures

used

were

adequate

to control

the activity; that trouble-

shooting activities were controlled

and repair records accurately reflected

what took place; that functional testing and/or calibrations

were

performed

prior to returning

components

or systems

to service;

that

gC records

were

maintained;

that activities

were

accomplished

by qualified personnel;

that

parts

and materials

used

were properly certified; that radiological controls

were properly implemented;

that

gC hold points were established

and observed

where required; that fire prevention controls were implemented;

that outside

contractor force activities were controlled in accordance

with the

approved

gA program;

and that housekeeping

was actively pursued.

The following maintenance activities were observed

and/or reviewed:

Unit 4 Steam Generator

Blowdown Isolation Valve 6275C Repair

Unit 3B Safety Injection

Pump Repair

AFW Pumps

A,

B and

C Steam Trap Repairs

AFW Pumps A,

B and

C Drain Line Repairs

AFW Pump

C Governor Valve Repair

Unit 3 Wide Range Fission

Chamber -Troubleshooting

B Diesel Generator Air Start Regulator

Replacement

AFW Pump

C Electronic Overspeed

Trip Troubleshooting

Unit 4 Containment

Water Level Monitor Indicator Repair

AFW Pump

B Electronic Overspeed

Trip Repair

During

a review of, outstanding

maintenance

activities, the inspector

noted

that the Unit 4 containment water level monitor narrow range level indicator

(LI-6308 B) was

inoperable

and that

a plant work order

(PWO) was initiated

'on February 7,

1985 to repair the failed indicator.

The inspector

requested

a current

status

report for the repair effort and

was informed that

a

new

gauge

was

on order.

Upon further investigation,

however, it was discovered

that the purchase

order

had

been lost during internal routing and

had never

been

submitted to the supplier.

Action was promptly taken to ensure that

a

replacement

gauge

was

purchased.

The failure of the purchasing

department

to properly expedite

the

purchase

of repair parts will be tracked

as IFI

250,251/85-30-06.

On

September

20,

1985,

the Unit 4 instrument air dryers were

removed

from

service

due to

a failed purge valve.

Procedure

4-0P-013,

Instrument Air

System,

requires,

in section

6. 1, that the Unit 4 air compressor

output

be

routed through the Unit 3 instrument air dryers

when the Unit 4 dryers

are

inoperative.

A specific caution

in the

procedure

states

that inoperative

Unit

4 dryers

shall

be

bypassed

only

when

the

Unit

3 dryers

are

also

inoperative.

In addition,

4-OP-013

requires,

in section

7.5. 1, that the

bypassing

evolution, if performed,

be

documented

by initialing numerous

procedural

steps.

Contrary to these

requirements,

the Unit 4 dryer bypass

valve was opened,

allowing air to bypass

the Unit

4 dryers without passing

through

the

Unit

3 dryers.

Consequently,

for approximately

six hours,

potentially moist instrument air was

being

supplied to safety-related

air

operated

control

valves

which are

known to

be susceptible

to failure from

water in the air system.

In July 1985, it was determined that water in the instrument air system

was

responsible

for numerous

failures of

AFW flow control valves.

The water

entered

the

system

because

the instrument air water separators

and dryers

were not properly operated

and maintained.

The problem forced the cooldown

of the Unit 3 reactor

and contributed to

a malfunction of the

AFW system.

AFW valve operability

was

restored

only after

a

time

consuming

repair

effort.

Violation 250,251/85-26-03

was written.

Corrective

action for the

violation

stressed

the

need

to

properly

implement

the

instrument

air

procedure

[4-OP-013]

to

assure

that

the

AFW system,

as

well

as

other

important systems

remained fully functional.

The breakdown of the corrective action

program for the instrument air system

shortly after its

implementation

is disconcerting.

While

the

licensee

identified the

discrepancy

within six hours,

the discrepancy

should

have

been precluded

by the licensee's

corrective action for the

events

of July

1985.

Consequently,

this event

does not meet the requirements

of 10 CFR 2,

Appendix C, item V.A(5) and is

a violation in that the

requirements

of TS 6.8. 1 were not met.

The failure to implement procedure

4-OP-013 is one of

three

examples of the failure to meet the requirements

of TS 6.8. 1 contained

in this report (250,251/85-30-01).

During surveillance

testing of the

B

AFW pump

on June

23,

1985,

the

pump

failed its operability test

because it twice tripped

on electronic

over-

speed.

The

pump was determined to be running at 5980 revolutions per minute

(rpm) instead

of the desired

5900

rpm.

The electronic

setpoint

should

have

been

6200

rpm.

The

B AFW pump governor

was adjusted

such that

the turbine rotated at 5900

rpm.

The

pump was tested

and it did not trip on

electronic

over speed.

A

L

15

Discussions with technical

support personnel

indicated that the

pump was not

demonstrating

significant oscillations

in speed.

The

maximum anticipated

speed

change,

during

normal

operation,

is

no

more

than

100

rpm.

Consequently,

on June

23,

1985,

the electronic

for the

B AFW .pump

could

have

been

estimated

to

have

occurred

at

no more than

6080 rpm.

The

licensee did not perform this extrapolation

and after the overspeed

symptom

had

been corrected,

a verification of the actual

setpoint

was not performed.

Following an additional unanticipated

B AFW pump overspeed trip on July 22,

1985,

the electronic

10 CFR 50, Appendix B, Criterion XVI, as

setpoint

was tested.

The setpoint

was

found

to

beq 6066

rpm which

was

134

rpm too

low.

Apparently

the electronic

overspeed trips

on June

23 and July 22 were

due to

an incorrectly

adjusted

setpoint.

implemented

by FPL Topical Quality

Assurance

Report

(FPL-NQA-100A) Revision

7,

TQR 16.0,

Corrective

Action,

requires,

in part,

that

measures

shall

be

established

to

assure

that

conditions adverse

to quality,

such

as failures, malfunctions deficiencies,

deviations,

defective

material

and

equipment,

and

nonconformances

are

promptly identified and

corrected'PL

Quality Assurance

Manual,

Quality

Procedure

(QP)

16. 1,

Revision

8,

delineates

requirements

for assuring

that conditions adverse

to quality are

corrected.

AP 0190. 13,

dated

May 21,

1985, entitled Corrective Action for Conditions

Adverse to Quality, itemizes

the

mechanisms

by which conditions adverse

to

quality are promptly identified, tracked

and corrected.

Contrary to the

above,

the licensee failed to establish

measures

to assure

that conditions

adverse

to quality were promptly identified and corrected,

in that,

the

licensee's

corrective

action

program

was

implemented

in

a

manner

which allowed

symptom correction without requiring the identifica-

tion, evaluation

and correction of the

source

problem.

Consequently,

on

June

23,

1985,

the

B AFW pump failed its operability test, tripping twice on

electronic

overspeed,

and maintenance

repairs resulted in symptom correction

rather

than root cause

identification

and repair.

As

a result,

the

B AFW

pump again tripped

on electronic

on July 22,

1985.

Subsequent

testing

revealed

that

the electronic

of 10 CFR 50, Appendix B, Criterion XVI

trip occurred

below the

required

setpoint.

The licensee

did not fully address

the

reason

for the

June

23 overspeed trips until the problem recurred

in July.

The fai lure to meet the requirements

is

a violation (250,251/85-30-04).

10.

Operational

Safety Verification (71707)

The inspectors

observed

control

room operations,

reviewed applicable

logs,

conducted

discussions

with control

room operators,

observed shift turnovers

and confirmed operability of instrumentation.

The inspectors

verified the

operability of selected

emergency

systems,

verified that maintenance

work

i

III

16

orders

had

been

submitted

as required

and that followup and prioritization

of work was accomplished.

The inspectors

reviewed tagout records, verified

compliance with TS

LCOs

and verified the

return

to service

of affected

components'y

observation

and direct

interviews,

verification

was

made

that

the

physical security plan was being implemented.

Plant housekeeping/cleanliness

conditions

and implementation of radiological

controls were observed.

Tours of the intake structure

and diesel,

auxiliary, control

and turbine

buildings

were

conducted

to observe

plant

equipment

conditions

including

potential fire hazards,

fluid leaks

and excessive

vibrations.

The

inspectors

walked

down

accessible

portions

of the

following safety-

on Unit

3

and

Unit

4 to verify operability

and

proper

valve/switch alignment:

Emergency Diesel Generators

Auxiliary Feedwater

4160 volt and

480 volt Switchgear

Containment

Spray

Containment Penetrations

Nuclear Instrumentation

Drawers

Refueling Water Storage

High Head Safety Injection

Spent

Fuel Pit Cooling

Control

Room Vertical Panels

No violations or deviations

were identified.

11.

Engineered

Safety

Features

Walkdown (71710)

The inspector

verified operability of the

AFW system,

which is

common to

Units 3 and 4, the Unit 4 containment

spray

system

and the

common

standby

system

by performing

a complete

walkdown of the accessible

portion

of the

system.

The following specifics

were

reviewed and/or

observed

as

appropriate:

a.

that the licensee's

system lineup procedures

matched plant drawings

and

the as-built configuration;

b.

that the

equipment

conditions

were satisfactory

and

items that might

degrade

performance

were identified

and evaluated

(e.g.

hangers

and

supports

were operable,

housekeeping

was adequate,

etc.);

c.

that instrumentation

was properly valved in and functioning

and that

calibration dates

were not exceeded;

17

that

valves

were

in proper position,

breaker

alignment

was correct,

power was available,

and valves were locked/lockwired

as required;

local

and

remote position indication

was

compared

and

remote instru-

mentation

was functional;

breakers

and

instrumentation

cabinets

were

inspected

to verify that

they were free of damage

and interference.

The licensee

has

proposed

using the standby

system

as

a backup for

the

AFW system in the event of a complete

loss of AFW in conjunction with a

loss of main

feedwater capability.

A walkdown of the

standby

system

was performed to ascertain its status.

The following system discre-

pancies

were noted:

Discharge

pressure

gages

for both

standby

pumps

(SFWP)

are

broken.

Work orders for-gage repair were issued

on August 5,

1985 but

repairs

have not been

accomplished.

(PI 6511

A & B).

b.

Suction

pressure

gages

for both

standby

pumps

have

been

physically disconnected

and removed.

The discrepancy is documented

on

a

work order dated August 5,

1985.

C.

d.

e.

Temperature

indicator

TX

6571 is

not installed

on the

pump suction

piping.

The indicator

has

been

removed.

Drawing 5610-T-E-4062,

Revision 8, sheet

5 of 7, incorrectly indicates

that

valves

DWDS 4-012

and

3-012

are

normally

open

valves.

These

valves

are

normally closed

and

must

be manually

opened

to provide

a

discharge

path to the

steam generators.

There is

no remote level indication for the normal water

supply to the

SFWP

from the demineralized

water storage

tank

(DWST).

Consequently,

the control

room operator s can not easily monitor tank level changes.

One of two local

DWST level indicators

has

been disconnected.

The other

level

gage (feet of water) is not

on

a routine periodic calibration

schedule

and was last verified to be calibrated

on October

19,

1983

'.

Remote

tank level

alarms

which operate

control

room annunciators

are

not

on

a routine periodic calibration

schedule

and were last verified

to

be calibrated

on January

22,

1982.

No maintenance

instructions

or

procedures

exist addressing

an approved

method of calibration.

h.

A chainfall is attached

to the discharge

piping just upstream of valve

DWDS-3-012.

The standby

piping and chainfall are temporarily

supporting

a large-diameter

section of electrical conduit.

18

i.

Several

vent valves are required to be operated

during system prepara-

tion for operation.

The valves are

capped

but are not shown

as

capped

on

drawing

5610-T-E-4062

or

referenced

as

capped

in

the

system

operating

procedure.

The motor heater light for the

A standby

pump has

been

broken

since

September

23,

1985,

making verification of heater

circuit

operability difficult. Similarly, the

pump off indicator lights are

not functioning.

Within this area,

no violations or deviations

were identified.

12.

Plant Events

(93702)

An independent

review was conducted of the following events.

On

September

30,

1985,

a

manual

actuation

of

a portion of the engineered

safeguards

features

was initiated

due to maintenance

problems

on both the

Unit

3

and Unit 4 process

radiation monitor R-ll and

R-12 filter drives.

Since

R-11 (particulate)

and

R-12 (gaseous)

monitors

were

inoperable,

the

trip logic was

inoperable

for the control

room

and containment

isolation

valves.

Fuses

were pulled which caused

all automatic isolation valves to

fail closed

to establish

the

desired

isolation'.

During the

maintenance

repairs

no actual

high radiation

conditions

existed.

Deenergizing

the

failed circuit closes

the

isolation

valves

as

a

required

precautionary

measure.

On

October

7,

1985,

a Unit

3 turbine

load limit runback

occurred while

direct current (dc)

ground isolation

procedures

were in progress

on the

3A

bus.

When

breaker

49

on

panel

3D01

was

opened,

a

false

rod

bottom

indication alarm initiated the runback.

Two fuses

were found to be blown on

the alternating

current (ac)

power supply.

Rod position indication

power

was

shifted

to

an

ac lighting panel until the

fuses

were replaced.

All

required

control

systems

operated

satisfactorily

including

automatic

rod

control

and automatic

condenser

steam

dump valves.

On October

11,

1985,

the Unit 3 startup transformer

was

removed

from service

to allow switchyard

work to

be

performed

in

support

of the

auxiliary

electrical

power

system

upgrade.

The transformer

was out of service for

approximately

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

During that time both Units

3

and

4 were

operated

at approximately

50 per cent power to preclude

the

need for the

B main feed-

water pumps-which

are

powered

from the

C buses.

All work was

performed

as

part of

a preplanned

evolution.

No unexpected

problems

were

encountered.

Both diesel

generators

were verified to be operable prior to initiating the

maintenance

evolution.

A similar

maintenance

effort

is

planned

for

October

18,

1985 to complete similar modifications for the Unit 4 switchyard

upgrade.

h%

19

On October

15,

1985, the Unit 3 reactor tripped from 100 per cent power.

A

construction

worker

in

the

cable

spreading

room is

thought

to

have

inadvertently

and

unknowingly jarred

the

main

transformer

differential

relay.

The operation

of the relay tripped the turbine generator

which in

turn tripped the reactor

through

the protection

logic matrix.

All major

systems

operated

as

designed.

The

system ,initiated

on

low

steam

generator

level

due

to

steam

generator

level

shrink.

Approximately.

40

minutes

following the trip, the

AFW system

again

initiated

due

to

steam

generator

B high level.

The high level condition tripped the main feedwater

pump which in turn initiates

AFW operation.

The high level

in the

B steam

generator

was due to leakage

through the

B flow control

bypass

valve.

The

B