ML17348B427

pump, the 4A waterboxes,

and the heater drain pumps.

(Refer to paragraph

9.c for additional information.)

On January

12, 1992, at 9:40 p.m., reactor

power reached

60K.

On January

14, 1992, at 5:32 p.m.,

power ascension

was

commenced.

On January

15,

1992, at 1:30 a.m., reactor

power reached

100K.

3.

Followup on Items of Noncompliance

(92702)

A review

was

conducted

of the following noncompliance

to assure

that

corrective actions

were adequately

implemented

and resulted

in conformance

with regulatory

requirements.

Verification of corrective

action

was

achieved

through

record

reviews,

observation,

and

discussions

with

licensee

personnel.

Licensee

correspondence

was evaluated

to ensure

the

responses

were timely and corrective actions

were implemented within the

time periods specified in the reply.

(Closed)

YIO 50-250,251/91-42-03,

Failure

to Maintain Axial Flux

Difference

Within TS Limits.

The licensee

responded

to this violation in

FPL letter L-91-329 dated

December

18,

1991.

The inspectors

reviewed

the licensee's

corrective

actions

discussed

in this letter

and found

them to

be adequate.

This

issue is closed.

Followup on Inspector

Followup Items

(92701)

Actions taken

by the licensee

on the item listed below was verified by the

inspectors.

(Closed)

URI 50-250,251/91-37-04,

Unit 3 Entry into

Mode

2 With

an

Inoperable

Intermediate

Range Detector.

This

event

occurred

on

September

25,

1991,

during

the dilution to

criticality on Unit 3.

IRNI channel

N-35 was declared

out of service

because it did not respond

to the increasing

neutron flux.

The operating

crew

commenced

3-ONOP-059. 7,

the

I RNI

malfunction

procedure,

and

determined

that

N-35

had failed.

The

NPS

then

ordered

the unit to be

shutdown

and

an

evaluation

of the failure to

be

performed prior to

recommencing

the startup.

Initial troubleshooting

identified that the

signal,

compensating,

and high voltage

cables

were disconnected

at the

back of the instrumentation

drawer.

At ERT was formed to analyze

the event.

The root cause

of the event

was personnel

error

by non-licensed utility

personnel

in that inadequate

control of the lifted leads

between

the N-35

drawer

and the detector

occurred.

The licensee

took prompt corrective

actions

to prevent

recurrence.

The cables for all other Unit 3 excore

detectors

were

checked to ensure

that

no other cables

were disconnected.

The maintenance

procedure

was revised to include lifted lead documentation

and

independent

verification.

Outstanding

PWOs involving mode-deferred

testing

were

reviewed to ensure

that similar concerns

for other systems

did not exist.

Maintenance

personnel

were trained

on the significance of

the event.

A policy letter

was

issued

requiring the

use of lifted lead

control procedures

for work involving lifted leads

when the leads

are not

specified

and

independently verified in

a procedure.

The licensee

also

reviewed its lifted lead controls

against

INPO

and

standard

industry

practices.

TS 6.8.1 requires that written procedures

be established,

implemented,

and maintained

covering activities

recomnended

in Appendix

A of Regulatory

Guide 1.33,

Revision 2,

February

1978.

Section 9.a of this

Appendix

recommends

that

maintenance

that

can

affect

the

performance

of

safety-related

equipment

be

properly

preplanned

and

performed

in

accordance

with written procedures,

documented

instructions,

or drawings

appropriate

to the circumstances.

The recommendations

stated

above

were

not followed in that maintenance

accomplished

on Unit 3 IRNI N-35 was not

properly

performed

causing

the detector

cables

to remain

disconnected.

This oversight

required

the unit to be shut

down while a startup

was in

progress

on September

25,

1991.

This violation is not being cited because

the criteria specified in Section

V.G.1 of the

NRC Enforcement Policy were

satisfied.

This item will be tracked

as

NCV 50-250,251/91-52-01,

failure

to follow the requirements

of TS 6.8.1 resulting in N-35 excore detector

cables

being disconnected

during

a Unit 3 startup.

5.

Onsite

Followup

and In-Office Review of Written Reports of Nonroutine

Events

and

10 CFR Part 21 Reviews

(90712/90713/92700)

The Licensee

Event Reports

and/or

10 CFR Part 21 Reports

discussed

below

were reviewed.

The inspectors

verified that reporting requirements

had

been

met, root cause

analysis

was performed, corrective actions

appeared

appropriate,

and generic applicability had

been considered.

Additionally,

the inspectors

verified the licensee

had reviewed

each event, corrective

actions

were

implemented,

responsibility for corrective actions not fully

completed

was clearly assigned,

safety questions

had

been

evaluated

and

resolved,

and

violations of regulations

or

TS conditions

had

been

identified.

When applicable,

the criteria of 10 CFR Part 2, Appendix C,

were applied.

(Closed)

LER 50-250/91-011,

10 CFR Part 50,

Appendix R,

Safe

Shutdown

Analysis Design Inadequacy.

On

October ll, 1991,

at

7:00 a.m.,

the

licensee

identified

a

10 CFR Part 50, Appendix R, safe

shutdown analysis

design

inadequacy.

Unit 3 was

in

Node

1 at

45% reactor

power,

and Unit 4

was in Mode 6.

Unit 3

had

started

up from the dual unit outage

on September

26,

1991.

The

NCR that

identified

the

potential

design

inadequacy

provided

two potential

corrective actions,

both procedural,

which were

implemented

immediately.

Procedure

0-ONOP-105

was revised

on October ll, 1991, to manually

remove

two fuses

to prevent

the postulated

spurious actuation of the

B train

EDG

output

breaker.

A change

request

notice

was

issued

to correct

the

Appendix

R safe

shutdown analysis

manual

action list and

was

approved

on

October 11,

1991.

The licensee

took prompt

and appropriate

corrective

action.

However, the engineering disposition of the

NCR stated that there

was

no plant operability concern resulting

from the

NCR,

and therefore,

this

condition

was

not

immediately

reported.

Subsequently,

on

November 23,

1991,

the licensee

determined

the condition

was reportable

under

10 CFR 50.72(b)(1)

and

10 CFR 50.73(a)(2)(ii).

The

inspectors

consider

the failure of the engineering

safety evaluation

to recognize

that the postulated

spurious

actuation of the

B train

EDG output breaker

would

make it technically inoperable

per the

Appendix

R design

basis

document

as

a weakness

in the safety evaluation

program.

10 CFR Part 50, Appendix

R,

paragraph III.L.3, states

in part that the

alternative

shutdown capability shall

be independent of the specific fire

area(s)

and shall

accommodate

post fire conditions

where offsite power is

available

and

where offsite

power

is

not available for

72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />.

Procedures

shall

be in effect to implement this capability.

Paragraph

III.L.7 also states

in part that the safe

shutdown

equipment

and systems

for each fire

area

shall

be

known to

be

isolated

from associated

non-safety circuits in the fire area

so that hot shorts,

open circuits, or

shorts

to ground in the associated

circuits will not prevent operation of

the safe

shutdown

equipment.

No exceptions

to the noted

paragraphs

were

approved

by the

NRC.

As stated

in the

FSAR,

Appendix 9.6A,

paragraph

5.2.1,

Safety

Design

Basis, fire induced

spurious

actuation of systems

and

components

due to

hot short,

open circuit, or short to ground shall

be

assumed

to render

equipment

unusable

or place it in

an undesirable

mode.

Unit 3 went

critical

on September

26,

1991,

and operated until October

11,

1991, at

which

time

the

licensee

revised

procedure

0-ONOP-105

to require

the

necessary

manual

actions

to prevent

the spurious

actuation of the

3B or

4B

EDG output breakers.

Operation

of Unit 3 without procedures

describing

the necessary

manual

actions

to

ensure

safe

shutdown

equipment

was

adequately

isolated

to

prevent inadvertent

operation

due to hot shorts,

open circuits,

or shorts

to ground is

a violation of 10 CFR Part 50, Appendix

R.

This violation is

not being cited because

the criteria specified in Section

V.G. 1 of the

NRC

Enforcement

Policy were satisfied.

This

item will

be

tracked

as

NCV 50-250,251/91-52-02,

operation

without

a

procedure

describing

necessary

manual

action to ensure

safe

shutdown

equipment is adequately

isolated

as required

by 10 CFR Part 50, Appendix

R.

This item is closed.

Monthly Surveillance Observations

(61726)

The inspectors

observed

TS required surveillance testing

and verified that

the test

procedures

conformed to the requirements

of the TSs; testing

was

performed in accordance

with adequate

procedures;

test instrumentation

was

calibrated;

limiting conditions for operation

were met; test results

met

acceptance

criteria requirements

and were reviewed

by personnel

other than

the

individual directing

the test;

deficiencies

were identified,

as

appropriate,

and

were

properly

reviewed

and

resolved

by

management

personnel;

and system restoration

was adequate.

For completed tests,

the

inspectors

verified testing frequencies

were met and tests

were performed

by qualified individuals.

The

inspectors

witnessed/reviewed

portions

of

the

following test

activities:

3-0SP-049.1,

Reactor Protection

System Logic Test;

O-OSP-024.2,

Emergency

Bus

Load

Sequencers

Manual Test, for the

3A

sequencer;

and

3-0SP-075.3,

AFW Nitrogen Backup System

Low Pressure

Alarm Setpoint

Verification.

The inspectors

determined that the above testing activities were performed

in a satisfactory

manner

and met the requirements

of the TSs.

Violations

or deviations

were not identified.

7.

Honthly Maintenance

Observations

(62703)

Station

maintenance

activities of safety-related

systems

and

components

were observed

and reviewed to ascertain

they were conducted

in accordance

with approved

procedures,

regulatory guides,

industry codes

and standards,

and in conformance with the TSs.

The following items

were considered

during this review,

as appropriate:

LCOs were

met while components

or systems

were

removed

from service;

approvals

were

obtained

prior to initiating work; activities

were

accomplished

using

approved

procedures

and were inspected

as applicable;

procedures

used

were

adequate

to control

the activity; troubleshooting

activities

were controlled

and repair records

accurately

reflected

the

maintenance

performed;

functional

testing

and/or

calibrations

were

performed prior to returning

components

or systems

to service;

gC records

were maintained;

activities

were

accomplished

by qualified personnel;

parts

and materials

used

were properly certified; radiological controls

were properly implemented;

gC hold points

were established

and observed

where

required;

fire prevention

controls

were

implemented;

outside

contractor

force activities

were

controlled

in

accordance

with the

approved

gA program;

and housekeeping

was actively pursued.

The inspectors

witnessed/reviewed

portions of the following maintenance

activities in progress:

repair of a base

plate leak on the

4B heater drain

pump,

weld r epair of a leaking manway

on the

4A north waterbox,

and

repair of one of two flow control valves supplying seal

water to the

48 steam generator

pump's shaft seals

(CV-2209).

For those

maintenance

activities observed,

the inspectors

determined that

the activities were conducted

in

a satisfactory

manner

and that the work

was

properly

performed

in accordance

with approved

maintenance

work

orders.

Violations or deviations

were not identified.

8.

Operational

Safety Verification (71707)

The inspectors

observed control

room operations,

reviewed applicable logs,

conducted

discussions

with control

room

operators,

observed

shift

turnovers,

and monitored instrumentation.

The inspectors verified proper

valve/switch alignment of selected

emergency

systems,

verified maintenance

work orders

had

been

submitted

as required,

and verified 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.

By observation

and direct interviews, verification was

made that the

physical

security

plan

was

being

implemented.

The

implementation

of

radiological

controls

and plant housekeeping/cleanliness

conditions

were

also 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-related

systems/structures

to verify proper valve/switch alignment:

A and

B emergency

diesel generators,

control

room vertical panels

and safeguards

racks,

intake cooling water structure,

4160-volt buses

and 480-volt load and motor control centers,

Unit 3 and

4 feedwater platforms,

Unit 3 and

4 condensate

storage

tank area,

auxiliary feedwater area,

Unit 3 and 4 main steam platforms,

and

auxiliary building.

The licensee

routinely performs

QA/QC audits/surveillances

of activities

required

under its

QA program

and

as

requested

by management.

To assess

the effectiveness

of these

licensee

audits,

the inspectors

examined

the

status,

scope,

and findings of the following audit reports:

Audit Number

QAO-PTN-91-061

QAO-PTN-91-063

QAO-PTN-91-070

QAO-PTN-91-072

QAO-PTN-91-077

QAO-PTN-91-078

Number of

~Findin

s

T

e of Audit

Multi-Amp Services

Material

and Services

Control

Programs

Engineering

Planning

and

Management,

Inc.

TS 6.5.2.8(c), Corrective Action

November Performance

Monitoring

Audit

TSs 6.6, 6.9, 6.13.2, 6.14.2,

and

6.15 Reports

No additional

NRC followup actions will

be

taken

on

the

findings

referenced

above

because

they were identified by the licensee's

QA program

audits

and corrective actions

have either

been

completed or are currently

underway.

Plant management

has also

been

made

aware of these

issues.

As

a result of routine plant tours

and various operational

observations,

the

inspectors

determined

that the

general

plant

and

system material

conditions

were satisfactorily maintained,

the plant security program

was

effective,

and

the overall

performance

of plant operations

was

good.

Violations or deviations

were not identified.

9.

Plant Events

(93702)

The following plant events

were reviewed to determine facility status

and

the

need for further followup action.

Plant

parameters

were evaluated

during transient

response.

The significance of the event

was evaluated

along with the

performance

of the appropriate

safety

systems

and

the

actions

taken

by the licensee.

The inspectors

verified that required

notifications were

made to the

NRC.

Evaluations

were performed relative

to the

need for additional

NRC response

to the event.

Additionally, the

following issues

were

examined,

as appropriate:

details

regarding

the

cause

of the event;

event chronology; safety

system performance;

licensee

compliance

with approved

procedures;

radiological

consequences, if any;

and proposed corrective actions.

a 0

b'.

As stated

in

NRC Inspecti'on

Report

No. 50-250,251/91-50,

all five

blackstart

diesel

generators

were taken out of service at 9:00 p.m.

on December

25, 1991, in order to facilitate repairs to the roof over

the cranking diesel

switchgear

enclosure.

Following completion of

these

planned

repairs,

the

No. 1,

3,

and

5 blackstart

diesel

generators

were

tested

and

returned

to service

at

9:05 a.m.

on

December

31,

1991,

and

the

No.

2 blackstart

diesel

generator

was

returned

to service

at

12:40 p.m.

on

the

same

day.

The

No.

4

blackstart

diesel

generator

was returned

to service at 2:06 p.m.

on

January

5, 1992.

On January

3, 1992, at 9:30 p.m., Unit 3 was shut

down for a short

outage

due to

a low oil level alarm

on the

38 RCP.

On December

13,

1991,

at

12: 10 p.m.,

annunciator

82/5,

RCP

38 Oil Reservoir

Hi/Lo

Level,

came in.

The licensee's

investigation

showed that the signal

indicated

low oil level in the

38

RCP lower bearing oil reservoir.

The oil collection tank inside containment

was not showing

a level

increase,

and the licensee

monitored the

38

RCP bearing temperatures

which were steady.

The licensee

decided

to shut

down on January

3,

1992,

to determine

the exact status

of the oil reservoir

on the

38

RCP and to perform other selected

corrective maintenance

items.

An

oil film was

found

on the lower part of the

38

RCP motor,

and the

gasket

bolts

were re-torqued

to 65 + 5 ft.-lbs.

Approximately two

quarts of oil were

added to the reservoir.

Visual inspection of the

3A

and

3C

RCP did not indicate

any oil leakage.

Some

other

maintenance/repair

items accomplished

were as follows:

control oil piping unions to the

NE,

NW, SE,

and

SW

intercept valves

were tightened;

various packing

and fitting leaks

were repaired;

three

ARNs were updated

per PC/N 91-167;

internal

pipe supports

to the control oil piping were added

to the intercept valves to reduce vibration; and

work was performed

on the

3A heater drain pump.

Unit 3 went critical again at 5: 17 p.m.,

on January 4, 1992,

and was

put back

on line at 8:55 p.m.

on the

same

day.

Unit 3 reached

100%

reactor

power at 2:45 p.m.

on January

5,

1992.

c.

At 8:30 p.m.

on January

12, 1991, the licensee

reduced

load

on Unit 4

for planned repairs.

Reactor

power reached

60K at 9:40 p.m.

on the

same

day,

and the following major work items were performed:

weld repair of a leaking manway

on the

4A north water box,

furmanite repair of

a casing

leak

on the

4B steam

generator

pump,

mechanical

maintenance

on

CV-2209

(one of two flow control

valves

supplying seal

water to the

4B steam generator

pump's shaft seals),

calibration of valve positioner

H/A-2208 for CV-2208 (the

second of two flow control valves supplying seal

water to the

4B

steam generator

pump's shaft seals),

repair of

a

base

plate leak

on the

4B heater

drain

pump

and

removal of the

pump motor for mechanical

maintenance,

and

repair of the top hat weld

and

a union leak

on the

4A heater

drain

pump.

Power

ascension

was

commenced

at

5:32 p.m.

on

January

14, 1992,

following completion of the

planned

secondary

work items.

Reactor

power reached

100% again at 1:30 a.m.

on the following day.

d.

At 1:37 a.m.

on January

14, 1992, with Unit 3 at

100K reactor

power,

PORV PCV-3-455C

was

inadvertently

cycled

due to excessive

demand

on controller PC-3-444J

during the investigation of a possible

malfunction of the pressurizer

control

group heaters.

In order to

determine if

the

pressurizer

control

group

heaters

were

malfunctioning,

the

control

group

heaters

were to

be

exercised

through their full range,

and

heater

output

response

was to

be

observed

as indicated

by the heater

watt meter.

This was

done

by,

placing

the

pressurizer

pressure

control

system's

auto/manual

setpoint

station

(PC-3-444J)

in

manual

and,

after

placing

the

pressurizer

spray controllers in manual

to prevent their operation in

response

to

a high pressure

response

from PC-3-444J,

by increasing

the output

on

PC-3-444J

to drive the control

group pressurizer

10

heaters

from maximum to minimum output.

During performance

of this

action,

the output of PC-3-444J

was

increased

too far,

and

PCV-3-455C

cycled

open

due

to excessive

demand

and/or

rate of

increase.

RCS pressure

was immediately verified to be less

than the

PORV liftsetpoint,

the

PORV was manually closed within approximately

20 seconds,

and

RCS pressure

was stabilized.

RCS pressure

decreased

to approximately

2172 psig

and

was

below 2210 psig (the setpoint for

the

backup

heaters)

for approximately

3 minutes.

The

licensee

attributed this event to personnel

error and considered

an inadequate

job briefing to be

a contributing factor.

TS 6.8.1 requires that written procedures

and administrative policies

be established,

implemented,

and maintained

in accordance

with the

requirements

and

recommendations

of Appendix A of

Regulatory

Guide 1.33,

Revision

2,

dated

February

1978.

Appendix

A of this

Regulatory

Guide

recommends

that written procedures

be established

for typical

safety-related

activities

carried

out

during

the

operation

of nuclear

power plants.

Section

1.b of this Appendix

recommends

administrative

procedures

which include authorities

and

responsibilities for safe operation

and shutdown.

Paragraph

5.6.16.1

of

procedure

O-ADM-200,

Conduct

of Operations,

requires

that

evolution briefings

be

conducted

for individuals

involved in

an

evolution that is to be performed

and that the detail of the briefing

is dependent

on the

degree

and complexity of the evolution and the

number of individuals involved.

The failure to conduct

an adequate

evolution

briefing prior to

the

investigation

of

a

possible

malfunction of the

Unit 3 pressurizer

control

group

heaters

per

paragraph

5.6.16.1

of procedure

O-ADM-200, Conduct of Operations,

which resulted

in the

inadvertent

opening

of

PCV-3-455C,

constitutes

a violation of TS 6.8. 1.

This item will be tracked

as

VIO 50-250,251/91-52-03,

failure to conduct

an

adequate

evolution

briefing resulting in the inadvertent

opening of a

PORV.

At ll:40 p.m.

on January

15, 1992,

the licensee

received

a low

pressure

alarm

on the Unit 3

A MSIV nitrogen backup,

and the

A NSIV

was declared

out of service

per

TS 3.7.1.5.

The

A nitrogen bottle

was

replaced,

and

the

24-hour

action

statement

was

exited

at

2:05 a.m.

on January

16,

1992.

During

a subsequent

verification of

system line up,

the

licensee

identified that the pressure

on the

Unit 3

B

and

C

NSIV nitrogen

backup

bottles

was

less

than

the

acceptance

criteria.

As

a result of this low nitrogen pressure,

the

licensee

declared

both

the

B

and

C

MSIVs out of service

per

TS 3.7.1.5

and entered

TS 3.0.3 at 5:25 a.m.

At 5:35 a.m.,

when one

of the nitrogen

backup bottles

was replaced with a spare

and nitrogen

pressure

was verified to be within acceptable limits; the

B NSIV was

declared

back

in service,

and

TS 3.0.3

was exited.

Following

replacement

of the

second

low pressure

bottle with

a spare,

the

C NSIV was declared

back in service,

and

TS 3.7. 1.5

was exited at

5:40 a.m.

The

decrease

in nitrogen

pressure

was attributed to

a

significant decrease

in temperature

while

a cold front was passing

through.

11

f.

At 2:30 a.m.

on January

23,

1992,

the inservice blackstart

diesel

generators

(No.

1, 3,

and 5) were declared

out of service

due to

a

blown

30A fuse in the blackstart

diesel

generator

common starting

circuitry.

The

No.

2

and

4 blackstart

diesel

generators

had

previously been

taken out of service for other reasons.

The fuse

was

replaced

and

the

No. 1, 3, and

5 blackstart

diesel

generators

were

tested

and returned to service at 10:55 a.m.

on the

same

day.

One violation was identified.

10.

Exit Interview (30703)

The

inspection

scope

and

findings

were

summarized

during

management

interviews

held throughout

the reporting period with the Plant

General

Manager

and selected

members of his staff.

An exit meeting

was conducted

on January

24,

1992.

The

areas

requiring

management

attention

were

reviewed.

The

licensee

did not identify as proprietary

any of the

materials

provided

to

or

reviewed

by

the

inspectors

during this

inspection.

Dissenting

comments

were not received

from the licensee.

The

inspectors

had the following findings:

Item Number

Descri tion and Reference

50-250,251/91-52-01

50-250,251/91-52-02

50-250,251/91-52-03

Weakness

NCV - Failure to follow the

requirements

of TS 6.8. 1 resulting

in N-35 excore detector

cables

being

disconnected

during

a Unit 3 startup

(paragraph

4).

NCV - Operation without a procedure

describing

necessary

manual

action

to ensure

safe

shutdown

equipment is

adequately

isolated

as required

by

10 CFR Part 50, Appendix

R

(paragraph

5).

VIO - Failure to conduct

an adequate

evolution briefing res ul ting in the

inadvertent

opening of a

10 CFR Part 50, Appendix R,

(paragraph

9.d).

Failure of an engineering

safety

evaluation to recognize that

a

postulated

spurious actuation of the

B train

EDG output breaker

would

make it technically inoperable

per

the

design .basis

document

(paragraph

5).

12

Acronyms

ADM

AFW

ARM

CFR

CV

ERT

H/A

IRNI

LCO

LER

NI S

NE

NRC

NW

ONOP

OSP

PC

PC/M

PCV

Main Steam Isolation Valve

psl9

PTN

PWO

QAO

TS

and Abbreviations

Administrative

Auxiliary Feedwater

Area Radiation Monitor

Code of Federal

Regulations

Control Valve

Emergency Diesel

Generator

Event Response

Team

Florida Power

5 Light

Final Safety Analysis Report

Hand/Automatic

Institute for Nuclear Power Operations

Intermediate

Range Nuclear Instrumentation

Limiting Condition for Operation

Licensee

Event Report

Nuclear

Instrumentation

System

Non-conformance

Report

Northeast

Non-Cited Violation

Nuclear Plant Supervisor

Nuclear Regulatory Commission

Northwest

Off Normal Operating

Procedure

Operations

Surveillance

Procedure

Pressure

Controller

Plant Change/Modification

Pressure

Control Valve

Power Operated Relief Valve

pounds

per square

inch gauge

Plant Turkey Nuclear

Plant Work Order

Quality Assurance

Organization

Quality Control

Reactor

Coolant

Pump

Reactor

Coolant System

Southeast

Southwest

Technical Specification

Unresolved

Item

Violation

0

UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, D. C. 20555

April 9,

1991

Docket Nos:

50-250

and 50-251

Nr. J.

H. Goldberg

President - Nuclear Division

Florida Power and Light Company

P.O.

Box 14000

Juno Beach, Florida

33408-0420

Dear Nr. Goldberg:

SUBJECT:

TURKEY POINT DESIGN VALIDATION INSPECTION

FOLLOWUP (50-.250/91-201;

50-251/91-201)

e

This letter conveys

the results

and conclusions of the followup to the design

validation inspection of the Turkey Point Nuclear Power Plant, Units

3 and 4.

The original inspection

was conducted

by the U.S. Nuclear Regulatory

Commis-

sion in October

1989

as

documented

by Inspection

Report 50-250

and 251/89-203.

The followup inspection

was performed at the Florida Power

and Light (FPL)

Company's offices at Juno

Beach, Florida, during the week of February 25, 1991.

The inspection report is enclosed.

The purpose of this inspection

was to assess

the status of corrective actions

for eight deficiencies

from the

1989 inspection.

All other deficiencies

and

inspector followup items were addressed

by other

NRC inspections,

as indicated

in Sections

1.0 and 2.0 of the enclosed

report.

The team closed

seven of the eight deficiencies.

Deficiency 89-203-12,

which

concerned

the adequacy

of the component cooling water

(CCW) heat exchanger

support pedestal,

remains

open.

The calculation prepared to resolve this

deficiency did not use the most current

loads to check the adequacy

of the

pedestal

even though the

new loads were about twice the magnitude of the

original loads.

Deficiency 89-203-16

was closed

based

on the team's

under-

standing that

FPL will install the Unit 4 portion of a modification package to

strengthen

the

CCW surge tank supporting platform to meet Bulletin 79-02 program

commitments.

The team designated

Deficiencies 89-203-12

and 89-203-16

as items

which should

be resolved prior to the restart of the units.

t

The team found that, irI response

to Deficiency 89-203-20,

FPL had extended

the

Design Basis Documentation verification effort to the component level.

The team

found that good initial progress

had been

made regarding the component

design

requirements

package for the safety injection system.

April 9,

1991

- 2-

There were

a substantial

number of errors present

in the calculations

reviewed.

While your staff and contractors

were able to correct these errors during the

inspection to the team's satisfaction,

the team was concerned with the quality

of contractor work products

and your lack of review of these

products.

During

the previous inspection,

oversight of contracted

engineering

was also identified

as

a weakness.

In accordance

with 10 CFR 2.790(a),

a copy of this letter and the enclosure will

be placed in the Public Document

Room.

Should you have

any questions

concerning this inspection,

please

contact

me or

Mr. Hai-Boh Wang at (301) 492-0958.

ORIGINAL SIGNED BY STEVEN A. VARGA

Steven

A. Varga, Director

Division of Reactor Projects I/II

Office of Nuclear Reactor Regulation

Enclosure:

t<RC Inspection Report 50-250/91-201;

50-251/91-201

cc:

See

page

3

Distribution:

See

page

4

See previous

concurrence

RSIB:DRIS

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D:DRIS

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DPNorkin

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BKGrimes

04/03/91

04/05/91

04/03/91

04/05/91

0:

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SAVar a

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~

I

Mr. J.

H. Goldberg

Florida Power and Light Company

3

Turkey Point Plant

Harold F. Reis, Esquire

Newman and Holtzinger, P.C.

1615

L Street,

N.W.

Washington,

DC

20036

Mr. Jack Shreve

Office of the Public Counsel

Room 4, Holland Building

Tallahassee,

32304

John T. Butler, Esquire

Steel,

Hector and Davis

4000 Southeast

Financial

Center

Miami, Florida

33131-2398

Mr. Thomas

F. Plunkett, Site

Vice President

.Turkey Point Nuclear Plant

Florida Power and Light Company

P.O.

Box 029100

Miami, Florida

33102

Joaquin Avino

County Manager of Metropolitan

Dade County

Ill NW 1st Street,

29th Floor

Miami, Florida

33128

Senior Resident

Inspector

Turkey Point Nuclear Generating Station

U.S. Nuclear Regulatory

Commission

Post Office Box 1448

Homestead,

33090

Intergovernmental

Coordination

and Review

Office of Planning

5 Budget

Executive Office of the Governor

The Capitol Building

Tallahassee,

32301

Administrator

Department of Environmental

Regulation

Power Plant Siting Section

State of Florida

2600 Blair Stone

Road

Tallahassee,

32301

Regional Administrator, Region II

U.S. Nuclear Regulatory

Commission

101 Marietta Street,

N.W. Suite 2900

Atlanta, Georgia

30323

Attorney General

Department of Legal Affairs

The Capitol

Tallahassee,

32304

Plant Manager

Turkey Point Nuclear Plant

Florida Power

and Light Company

P.O.

Box 029100

Miami, Florida

33102

Mr. J.

H. Goldberg

President - Nuclear Division

Florida Power and Light Company

P.O.

Box 14000

Juno

Beach, Florida

33408-0420

Mr. Jacob

Daniel

Nash

Office of Radiation Control

Department of Health and

Rehabilitative

Services

1317 Winewood Blvd.

Tallahassee,