ML17353A718

Insp Repts 50-250/96-04 & 50-251/96-04 on 960324-0504. Violations Noted.Major Areas Inspected:Plant Operations, Maint,Engineering & Plant Support

ML17353A718
Person / Time
Site:	Turkey Point
Issue date:	06/03/1996
From:	Johnson T, Landis K NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:
Shared Package
ML17353A716	List: ML17353A715 ML17353A717 ML17353A718
References
50-250-96-04, 50-250-96-4, 50-251-96-04, 50-251-96-4, NUDOCS 9606070166
Download: ML17353A718 (65)

See also: IR 05000250/1996004

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION II

101 MARIETTASTREET, N.W., SUITE 2900

ATLANTA,GEORGIA 303234199

gpR REoy,

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U. S. NUCLEAR REGULATORY COMMlSSION

REGION II

Docket Nos.:

50-250

and 50-251

License Nos.:

DPR-31

and

DPR-41

Report Nos.:

50-250/96-04

and 50-251/96-04

Licensee:

Florida Power

and Light Company

Facility:

Turkey Point Units

3 and

4

Location:

9250 West Flagler Street

Miami, FL

33102

Dates:

March

2

roug

May 4,

1996

Inspectors:

T.

P.

Johnso

, Senior Resident

Inspector

Date Signed

B.

B. Desai,

Resident

Inspector

B.

R. Crowley,

DRS Inspector (sections

Ml. 1 to Ml.3)

f. Lea

DRP Ins

ctor

Approved by:

K. D. Landes,

Chief

Reactor Projects

Branch

3

Division of Reactor Projects

D te Signed

9606070l66

960603

PDR

ADOCK 05000250

G

PDR

EXECUTIVE SUMMARY

TURKEY POINT UNITS 3 and

4

Nuclear Regulatory

Commission Inspection

Report 50-250,251/96-04

This integrated

inspection

was conducted

by the resident

and regional

inspectors

to assure

public health

and safety. It involved direct inspection

at the site in the following areas:

plant operations

including engineered

safety features

walkdowns, operational

safety;

and plant events;

maintenance

including surveillance observations;

engineering;

and plant support including

radiological controls,

chemistry, fire protection,

and housekeeping.

Backshift inspections

were performed in accordance

with Nuclear Regulatory

Commission

inspection guidance.

Within the scope of this inspection,

the inspectors

determined that the

licensee

continued to demonstrate

satisfactory

performance to ensure

safe

plant operations.

The inspectors

identified the following one cited

and two

non-cited violations,

and

one inspector followup item.

Inspector

Followup Item, 50-250,251/96-04-01,

Charging

Pump

Response

During

a Safety Injection (section

03. 1)

Violation, 50-250,251/96-04-02,

Failure to Follow Chemical

Volume

Control

System Operating

Procedure

(section

04. 1)

Non-cited violation, 50-250,251/96-04-03,

Failure to Perform

an Adequate

Safety Evaluation (section

E2.2)

Non-cited violation 50-250,251/96-04-04,

Contaminated

Flashlight

Found

Outside the Radiation Controlled Area (section

R1.2)

During this inspection period, the inspectors

had

comments

in the following

functional

areas:

Plant

0 erations

Unit 4 mode changes

and startup

from the refueling outage

were all well

performed with noted strong oversight

and very good communications

(section 01.1).

Safety

system

walkdowns of the

common high head safety injection system

and the Unit 4 emergency diesel

generators

noted satisfactory

alignment.

Specific minor labelling

and material condition issues

were

appropriately

addressed

(sections

02. 1 and 02.2).

An issue regarding charging

pump response

on

a safety injection (e.g.,

the

pumps

are tripped

and locked out for two minutes)

was

an inspector

followup item (section

03. 1).

Weaknesses

were identified relative to the condensate

polishing

demineralizer

system procedures

and safety analysis description

(section

03.2).

~

Failure to follow the Chemical

and

Volume Control

System operating

procedure

during

a Unit 4 blender flushing evolution was

a cited

violation (section

04. 1).

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Operators

appropriately

and conservatively

made

a decision to trip Unit

4 following plant response

to an increase

in generator

load due to

turbine governor problems.

Operator response

during startup following

the reactor trip was cautious,

deliberate,

and well supervised

(section

04.2).

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Management's

self-assessment

capability relative to Unit 4 startup

readiness

was noteworthy (section

07. 1).

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The on-site

and off-site safety committees

and the quality assurance

organization

were functioning well and were focused

towards nuclear

safety (section 07.2).

~

An open item regarding

core exit thermocouples

was closed

(section

08.01).

~

Operator

response

to

a Unit 3 loss of the

3C bus

was very good,

including initiating a manual reactor trip.

However,

enhancements

were

needed

in the loss of C bus off-normal operating

procedure

(section

M1.4) .

~

An 'excellent questioning attitude exhibited

by a Nuclear Plant

Supervisor led to the identification of a problem associated

with the

cross-connecting

of two safety

buses

during outages

was considered

a

strength

(section

E2.2).

Maintenance

For the Unit 4 outage

maintenance

work activities observed,

the

inspectors

found that detailed

procedures

were in place

and were being

followed.

Work activities were being performed in accordance

with

requirements

by knowledgeable

and qualified personnel

in a professional

manner (section Ml.1).

The Flow Accelerated

Corrosion

program

was working well and the process

for evaluation

and disposition of results

was identified as

a strength

(section M1.2).

Except for a weakness

associated

with one radiographic technique,

performance

associated

with safety-related

welding was good.

Personnel

were well qualified and work was well documented.

Weld quality was

determined

to be good (section M1.3).

Unit 4 maintenance

testing activities resulted

in

a Unit 3 manual trip

when the

3C bus

was lost.

Root cause

was inadequate

design of the

3C

bus floor (metal

deck plates).

Root cause

analysis

and corrective

actions

were thorough,

prompt,

and effective (section M1.4).

Appropriate actions

were initiated to address

foreign material exclusion

related

concerns

applicable to main turbine maintenance

that were

identified following a reactor trip (section Hl.5).

Unit 4 rod testing following a manual trip demonstrated

adequate

drop

times with no observed

rod recoil.

Good test coordination

was also

noted (section

H2. 1).

Feedwater

heater related

issues

caused

a Unit 4 power reduction (section

H2.2).

Unit 4 integrated

safeguards

testing

was well performed.

However,

an

instrumentation

and control error during test

setup

caused

an engineered

safeguards

features

actuation

(section

H3. 1).

The post maintenance

testing

program was functioning well (section

H6.1).

En ineerin

The licensee

demonstrated

effective control

and conduct of the Unit 4

startup

and physics testing

program (section El. 1).

The licensee

appropriately

addressed

and dispositioned

a switchgear

stationary switch failure, including generic

issues

(section

E1.2).

Identification

of the vulnerability during nitrogen

and water fill

evolutions to the cold leg accumulators

was

a strength

in the operating

experience

feedback

program (section

E2. 1).

Failure to consider the effects of cross-connecting

480 volt load

centers

during safety evaluations

performed in 1988

and

1989 was

a non-

cited violation (section E2.2).

Continued attention related to Emergency

Containment

Cooler reliability

was warranted

(section

E2.3).

Periodic

and special

reports

(licensee

event reports)

were well written

and appropriately

submitted

(sections

E3. 1 and E3.2).

Updated final safety analysis report reviews detected

several

errors

(section

ES. 1).

Plant

Su

ort

Radiation protection

and health physics

performance

during the Unit 4

refueling was very good.

Performance

goals

were met including radiation

dose (section Rl, 1).

The discovery of a contaminated flashlight outside the radiation

controlled area

was

a non-cited violation (section R1.2).

NRC was conservatively

and appropriately notified of a non-credible

bomb

threat (section Sl. 1).

The licensee

appropriately

responded

to and reported

a fitness for duty

event (section S1.2).

TABLE OF

CONTENTS

Summary of Plant Status

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Unit 3

Unit 4

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Operations

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Inspection

Scope .......................,..

Inspection

Findings .....

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II.

Haintenance

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Inspection

Scope

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III.

Engineering

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Inspection

Scope

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Inspection

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V.

Plant Support

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Inspection

Scope ....

Inspection

Findings .....

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V.

Hanagement

Heetings...

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Partial List of Persons

Contacted... ..................

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List of Items

Opened,

Closed

and Discussed Items....................30

List of Acronyms

and Abbreviations.. ...............................31

REPORT DETAILS

Summary of Plant Status

Unit 3

At the beginning of this reporting period, Unit 3 was operating

at or

near full reactor

power and

had

been

on line since February

22,

1996.

The unit was manually tripped

on March 27,

1996 when the

3C 4KV bus

was

lost (see section M1.4).

The unit restarted

on March 28 and went on-

line March 29,

1996,

(section

04. 1).

The unit operated

at or near full

power the remaining portion of the inspection period.

Unit 4

I.

0

At the beginning of this repo} ting period, Unit 4 was in the cycle

16

refueling outage

which began

March 4,

1996.

The unit restarted

on

April 6,

1996

and went on-line April 8,

1996.

The cycle

16 refueling

outage lasted 35'ays.

An overspeed trip test

was satisfactorily

performed

and the unit was placed

back on-line April 9,

1996.

During

turbine power increase,

a manual trip was initiated in response

to

abnormal

turbine generator

response

(sections

04.2

and M1.5).

The unit

restarted

on April 10,

1996.

On April 18 and 21,

1996,

the unit was

operated

at reduced

power

(90X and

60K) to accommodate

troubleshooting

and repairs

on the feedwater

heater

system

(section M2.2).

The unit was

returned to

100X reactor

power on April 22,

1996.

On April 29,

1996,

the unit was reduced to 60X as

a precaution to repair

a

SGFP suction

pressure

switch.

The unit operated

at or near full power for the

remainder of the inspection period.

erations

Inspection

Scope

(40500,

60710,

71707,

71711,

73753,

92901,

and

93702)

The inspectors verified that the licensee

operated

the facilities safely

and in conformance with regulatory requirements.

The inspectors

accomplished

this by direct observation of activities, tours of the

facilities, interviews

and discussions

with personnel,

independent

verification of safety

system status

and technical

specification

compliance,

review of facility records,

inspections

of outage

activities,

and evaluation of the licensee's

management

control.

The

inspectors

also reviewed activities associated

with restart

from

refueling.

The inspectors

reviewed plant events

to determine facility status

and

the

need for further followup action.

The significance of these

events

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 and that licensee

followup including event chronology, root cause determination,

and

corrective actions

were appropriate.

The inspectors

performed

an inspection

designed

to verify the status of

the Unit 4 emergency diesel

generator

and

common

HHSI systems.

This was

accomplished

by performing

a complete

walkdown of all accessible

equipment.'he

inspectors

reviewed

system procedures,

housekeeping

and

cleanliness,

major system

components,

valves,

hangers

and supports,

local

and remote instrumentation,

and component labelling.

The inspectors

also performed

a review of the licensee's

self-assessment

capability by including

PNSC

and

CNRB activities,

QA/QC audits

and

reviews, line management

self-assessments,

individual self-checking

techniques,

and performance

indicators.

In addition,

the inspectors

reviewed

one previous

open item to assure

that corrective actions

were adequately

implemented

and resulted

in

conformance with regulatory requirements.

Inspection Findings

Ol

01.1

02

02.1

Conduct of Operations

Unit 4 Mode Changes

and Startup

Unit 4 transitioned

from Mode 6 to Mode

1 during the period March 29 to

April 8,

1996.

The unit achieved criticality at 3: 16 a.m.

on April 6,

1996,

and was placed

on line April 8,

1996.

This ended the Unit 4 cycle

16 refueling outage.

The outage

was originally scheduled for 32 days

and

was completed

in 35'ays.

Following completion of the turbine

overspeed

test,

the unit was placed

back online on April 9,

1996.

However,

a manual trip was initiated during

an unexpected

turbine load

increase

(sections

04.2

and M1.5),

The inspectors

noted that the Unit 4 outage

delays

were caused

by crane

problems

(see

NRC Inspection

Report 50-250,251/96-02),

ECC valve issues

(section E2.3),

and turbine oil

FME issues

(e.g

~ , rag found in the

bearing oil eductor

and corrosion of an oil orifice).

Notwithstanding

these

delays,

the licensee

demonstrated

conservatism

and aggressiveness

in dealing with these

issues.

The inspectors

observed

portions of the startup activities,

power

ascension,

turbine testing,

and other related activities.

The

inspectors

noted strong oversight

and good communication

and concluded

that the Unit 4 startup

was professionally

conducted.

Operational

Status of Facilities

and Equipment

Units

3 and

4 High Head Safety Injection Systems

Walkdowns

The inspectors

performed

a walkdown to verify the status of the Units

3

and

4 HHSI systems.

This was accomplished

by performing

a complete

walkdown of all accessible

equipment,

The following criteria were used,

as appropriate,

during this inspection:

system lineup procedures

matched plant drawings

and as-built

configuration;

appropriate

levels of housekeeping

cleanliness

were being

maintained;

valves in the system

were correctly installed

and did not exhibit

signs of gross

packing leakage,

bent stems,

missing handwheels,

or

improper labeling;

hangers

and supports

were

made

up properly and aligned correctly;

valves in the flow paths

were in correct configuration;

local

and remote position indication was compared,

and remote

instrumentation

was functional;

major system

components

were properly labeled;

surveillance testing procedures

and activities were appropriate;

and

maintenance activities (past, current,

and planned)

were

appropriate.

The inspectors

concluded that the Units 3 and

4 HHSI systems

were

satisfactorily aligned for normal

and

emergency operation.

Hinor

labelling

and material condition deficiencies

were discussed

with

engineering,

operations,

and maintenance

personnel.

The walkdown also

verified the completion of the Unit 4 BIT bypass modification (see

NRC

Inspection

Report 50-250,251/94-04,

section

E2.3).

The BIT and related

equipment

have

been

abandoned

in place.

The inspector

noted that the

affected

equipment

was not marked

as such.

The licensee

stated that

they would address

this issue.

02,2

Unit 4 Emergency Diesel

Generator

Walkdown

The inspector walked

down

a significant portion of the Unit 4 Emergency

Diesel

Generator

System,

including the fuel oil system,

cooling water

system,

lube oil system, air start system,

and electrical

system for the

4A and

4B EDGs.

The walkdown included observation of system material

condition,

open maintenance

work requests,

housekeeping,

valve

alignment, and'lectrical

breaker alignment.

For the portions observed,

the inspector did not observe

any

abnormalities

associated

with the system or the system drawings that

were

used for the system walkdown,

The inspector

concluded that system

configuration

was appropriately maintained.

03

03.1

03.2

Operations

Procedures

and Documentation

Charging

Pump Response

During Safety Injection

As followup to the manual

Unit 4 trip on April 9,

1996,

(section 04.2),

the inspector

reviewed

EOP adequacy

and charging

pump effects.

The

resultant

cooldown

and decrease

in pressurizer

level

caused

a letdown

isolation at

14%.

Operators

had already

responded

by starting

a third

pump (two charging

pumps

were already running).

As pressurizer

level

approached

12% (12.4% was the lowest recorded value),

the control

room

licensed operators,

management,

and the

STA were aware of the SI

actuation criteria as delineated

in emergency

operating

procedure

4-EOP-

E-O, Reactor Trip or Safety Injection, foldout page step

No. 5.

This

step required

a manual

SI if RCS subcooling

(based

on CETs)

was less

than 30'F'r if pressurizer

level could not be maintained greater

than

12%.

Based

on cooldown being controlled with the MSIVs closed,

and

pressurizer

level being restored with charging,

and greater

than

12%

level,

manual

SI was not required

and therefore

was not initiated.

At Turkey Point, the

HHSI pumps are designed

as

1600 psig discharge

pumps.

Therefore,

there

are

no

RCS operating

pressure

ECCS

pumps.

(A

manual

or automatic

SI signal trips all operating

and available charging

pumps.)

The charging

pumps are therefore unavailable for at least

2

minutes, until SI can

be reset

per procedure

4-EOP-E-0 step

16,

and

charging is re-established

per step

41.

The inspector

expressed

concern that charging would be lost to recover

pressurizer

level in the case of a manual

SI.

The inspector

noted this

issue

was also raised at the

PNSC post-trip review meeting.

Licensee

actions

were to make

an

open item (PMAI) to initiate

a

REA

investigation.

Further,

the inspector reviewed the

UFSAR to confirm the

charging

pump trip design

on SI.

UFSAR sections

reviewed included 9.2

(CVCS), 6.2

(ECCS),

14. 1.5

(CVCS Malfunction),

and

14.3

(RCS Pipe

Rupture).

Section

14.3, 1 stated that the charging

pumps

have the

capability to make

up for RCS leakage

from ruptures of small cross

sections,

permitting

an orderly shutdown.

Based

on the above,

the inspector

considered this issue to be

an

inspector followup item.

The item will be tracked

as IFI, 50-

250,251/96-04-01,

Charging

Pump

Response

During SI.

Condensate

Polishing Demineralizer

System

On April 12,

1996, during

a periodic plant tour, the inspector

noted

abnormal

conditions at the Unit 4 condensate

polishing system control

room and control panel.

The conditions included

a high

DP alarm for an

inservice demineralizer,

instrumentation

OOS,

poor material condition,

and weaknesses

in procedure

OP-7001.3,

Condensate

Polishing System-

Powdex Vessel

Operation.

The licensee

only uses this system following a

refueling outage with the unit shutdown or at low power,

and not as

a

full flow system.

Only

a portion of the condensate

system is diverted

through the polisher system.

UFSAR section

10.2,

stated that the condensate

polishing demineralizer

system treats full flow from the condensate

pumps

(pages

10.2-8

and

10.2-3).

The licensee

has

had previous plant trips due to loss of

condensate

and feedwater flow from this system.

As

a result,

the system

is only operating

in a "Kidney Loop" (e.g., diverted flow) method.

The inspector

informed licensee

management

of these

issues.

The

licensee initiated condition report No.96-596

and immediately corrected

the abnormal

conditions.

Operations,

chemistry,

and management

personnel

were responsive

to the inspector's

concerns.

Plant personnel

were already in the process

of revising the

OP.

Other corrective

actions

included addressing

the material condition deficiencies,

submitting

an

UFSAR change,

and informing plant personnel

of those

issues.

04

04.1

The inspector

concluded that weaknesses

existed in the operating

procedure

and

UFSAR description for the non-safety related

condensate

polishing demineralizer

system.

Operator

Knowledge

and Performance-

Chemical

and

Volume Control

System Operation

On March 28,

1996, Unit 3 was restarted

from a manual trip (section

Ml.4).

During control

room observation of startup activities,

the

RCO

momentarily aligned the

CVCS system in a configuration not described

in

procedure

3-0P-46,

CVCS Boron Concentration

Control.

At the time, the

RCO was periodically borating in accordance

with section 5.2, Boration,

of procedure

3-OP-46 in order to compensate

for Xenon burnout.

Following one

such boration,

the

RCO manually opened

valves

3-113B and

3-114A such that primary water was aligned through the blender

and

directly to the suction of the charging

pumps.

This was done to flush

out the boric acid from the blender following the boration.

This

alignment

was momentarily maintained until approximately five gallons of

primary water flowed through the blender.

Procedure

3-OP-46

has

provisions for dilution through two flow paths.

The preferred

path is

through the blender

and to the

VCT.

An alternate dilute path which

simultaneously

aligns primary water to the

VCT and directly to the

charging

pumps

can also

be used

as described

in section 5.3, Dilution,

of procedure

3-OP-46.

However,

opening valves

3-113B and 3-114A to

flush the blender

was not specifically described

in procedure

3-0P-46.

Further,

UFSAR section

9.2 only addressed

boration,

normal dilute,

alternate dilute and did not address

this "flushing" evolution.

Procedure

steps

involving boration or dilution did not require signoffs.

Further,

procedure

3-OP-46

was not required to be open (i.e., referred

to during performance of boration or dilution) to perform these

frequently performed evolutions.

The inspector discussed

the issue with the

RCO, the ANPS, the Operations

Supervisor

as to the need for this alignment

and whether the

RCO was

aware that flushing/diluting via valves

3-113B and 3-114A was outside

the scope of the

CVCS procedure.

The

RCO and the

ANPS had not

considered

the procedural

scope

when performing this evolution.

Apparently,

in the past,

the Turkey Point boric acid system

was designed

for highly concentrated

boric acid.

During this time, flushing the

blender with primary water following boration

was

common practice

procedurally to ensure

the blender did not crystalize with the boron.

However, with the boric acid system currently designed for approximately

2000

ppm, the need for flushing the blender

does not exist.

The inspector

co'nfirmed th'rough discussion

with other

RCOs that flushing

the blender following boration

was

no longer performed

by any of the

other

RCOs contacted,

nor recommended

during training.

Further, for the

RCO involved,

he stated that this activity was not normally performed.

This was confirmed by supervisory interviews.

Following discussions,

the Operations

Supervisor

immediately issued

a night order stressing

the

importance of operating

the plant,

and specifically the

CVCS, within

existing procedures.

The night order also stressed

that flushing the

blender following boration

was

no longer necessary.

The inspector considers this to be

an isolated incident.

Further,

no

observable

RCS power or temperature

changes

occurred.

Recent

observed

boration

and dilution evolutions

were all well performed in accordance

with procedures,

and with good oversight.

Further,

the operator

kept

positive control over this flushing evolution.

Technical Specification 6.8. I and

NRC Regulatory

Guide 1,33

(Rev.

2) section 3.n requires

written procedures

for the

CVCS to be followed.

The failure to follow

procedure

3-OP-46 during

a Unit 3

CVCS blender flushing evolution is

considered

a Violation.

The item is tracked

as

VIO 50-250,251/96-04-02,

Failure to Follow CVCS Operating

Procedure.

Operator

Response

to

a Unit 4 Hanual

Reactor

Trip

Operators initiated

a manual reactor trip of Unit 4 from approximately

17 percent reactor

power at approximately 6:00 p.m.

on April 9,

1996.

Just prior to the trip, operators

noted sluggish

main turbine governor

behavior

and ultimately

a rapid increase

in generator

load from 90 to

240

Hwe without operator

demand.

The

4A S/G level swelled to

71% caused

by further opening of the turbine control valves

and

steam flow was

noted to be greater

than feed flow on all three

S/Gs.

A manual reactor trip was initiated which caused

the main turbine to also trip.

Procedures

4-EOP-E-O,

Reactor Trip/SI and 4-EOP-ES-0. I, Reactor Trip

Recovery,

were appropriately entered.

RCS T,

reduced

from

approximately

552 degrees

F to 531 degrees

F Sue to the low decay heat

levels.

Minimum RCS pressurizer

level

reached

was approximately

12.4X.

The HSIVs were closed to prevent further cooldown

and decay heat

was

rejected

through the atmospheric

dumps,

Post trip response

was normal

with few exceptions.

Significant

among these

was shutdown

bank A,

control rod N-9 RPI not indicating

0 steps until approximately

two hours

after the trip.

The rod bottom light came in within the expected

time

frame

(see section

M2.1 for more details

on control rod N-9 testing).

The licensee attributed the governor sluggishness

to

a blocked (from

corrosion buildup) orifice within the governor impeller oil pressure

line.

The orifice was cleaned

and the governor refurbished.

The

maintenance

aspect of the Turbine control

system is further discussed

in

section Ml.5 of this report.

The inspector

responded

to the site

upon notification.

A 10 CFR 50.72

(b)(2)(ii) notification was

made

by the licensee

at 7:00 p.m.

on April

10,

1996.

The unit was restarted

on April 10,

1996 at approximately

5:00 p.m. after

an Event

Response

Team reviewed the event

and the onsite

safety committee

and plant management

authorized restart.

Further,

Unit

4

LER 96-01

was written and submitted.

The inspector monitored control

room activities following the reactor

trip as well as during startup.

The inspector

concluded that the

operators

appropriately

and conservatively

made

a decision to trip the

unit following plant response

to the increase

in generated

Mwe due

turbine governor problems.

The inspector also concluded that the

operator

performance

during startup

was cautious,

deliberate,

and well

supervised.

The inspector

reviewed

and closed

LER 96-01 for Unit 4.

07

quality Assurance

in Operations

07. 1

Unit 4 Startup

Readiness

In addition to the normal general

operating

procedural

controls for

heatup

and startup

(procedures

4-GOP-503,

Cold Shutdown to Hot Standby,

and 4-GOP-301,

Hot Standby to Power Operation),

the licensee

performed

independent

verifications

and checks

by implementing administrative

procedure

O-ADM-529, Unit Restart

Readiness.

This included:

system engineer

completion of readiness

checklists for their

specific systems;

review of the clearance

log,

open issues

(PMAIs, fire impairments,

PC/Ms,

TSAs, condition reports,

system lineups,

and surveillances;

letters

from each department

head

documenting

readiness

for

restart;

PNSC reviewed readiness;

and

plant general

manager final review and determination.

The inspectors

assessed

the licensee's

process,

attended

the related

PNSC meetings,

reviewed the completed restart

readiness

procedure,

and

discussed

the process

with licensee

management.

The inspectors

concluded that this process

appeared

effective

and demonstrated

conservatism

in assuring that Unit 4 would be safely returned to service

following the refueling outage,

0

The inspectors

independently

assessed

Unit 4 restart

readiness

by

performing the following tasks:

reviewed selected

open

and closed work items including post-

maintenance

testing, deficiencies,

and commitments (e.g.,

condition reports,

PWOs,

PMAIs,

CTRAC items, etc.);

verified system lineups

and equipment availability by checking

TSAs,

system operating

procedure checklists,

the

TSA log,

clearances,

and the equipment out-of-service log;

toured the facility including the Unit 4 containment;

reviewed control

room instruments,

alarms,

and controls;

reviewed general

operating

procedure

implementation;

reviewed operator training and readiness;

reviewed outage

PC/H completion, testing,

and turnover (e,g,,

ITOP

and

SATS);

reviewed startup testing procedures

and readiness;

reviewed surveillance testing completion;

reviewed

and verified local leak rate testing

and containment

integrity;

and

reviewed

ISI and erosion/corrosion

inspections

and repairs.

The inspectors

concluded that Unit 4 was ready to support

power

operation.

One noteworthy item was management's

self-assessment

process.

Hanagement

self-assessment

included the restart

readiness

procedure

process

discussed

above.

07.2

Independent

Reviews

and Self-Assessment

The inspector

attended

a portion of CNRB meeting

No.

429 held at Turkey

Point on April 16,

1996.

The inspector verified that the meeting

was

conducted

in accordance

with Technical Specification 6.5.2,

NP-803

(Nuclear Policy - CNRB),

CNRB implementing procedures.

Generally,

the

CNRB meets monthly, rotating the location of the meeting

among the three

FPL sites (e.g.,

Turkey Point, St.

Lucie and Juno Beach).

Normally

representatives

from all three locations

are present

at each meeting.

The inspectors

also attended

several

PNSC meetings during the period.

Technical Specification

and procedure

requirements

were verified,

including meeting frequency,

quorum,

and review responsibilities.

The inspectors

reviewed the licensee's

recent

gA activities including

the quality trend report for the first quarter of 1996.

The inspectors

also met with QA supervisory

and management

personnel.

QA identified

negative

performance

trends

in several

areas.

This included root cause

analysis

improvements,

welding qualification record problems,

procedure

adherence

issues,

and

FHE concerns.

QA issued findings in their

periodic reports

and discussed

these

issues

with plant

and site

management.

The inspectors

discussed

these

issues with QA personnel.

The inspectors

concluded that the

CNRB,

PNSC,

and

QA organizations

were

functioning well and were focused

towards nuclear safety.

08

Hiscellaneous

Operations

Issues

08. 1

Core Exit Thermocouple

Open

Item

(Closed)

IFI 50-250,251/94-11-01,

Core Exit Thermocouple

Status

and

Technical Specifications.

This item dealt with the operability of the

CETs, the implementation

and interpretation of the technical

specifications,

and other related

issues.

The inspector verified

appropriate corrective actions

and ensured

that the current status of

the Unit 3 and

4 CETs was per the regulatory requirements.

Based

on

this review, the IFI is considered

closed.

II. Haintenance

Inspection

Scope

(61701,

61726,

and 62703)

The inspectors verified that station maintenance

and surveillance

testing activities associated

with safety-related

systems

and components

were conducted

in accordance

with approved

procedures,

regulatory

guides,

industry codes

and standards,

and the technical

specifications.

This was accomplished

by observing maintenance

and surveillance testing

activities, reviewing refueling startup testing,

performing detailed

technical

procedure

reviews,

and reviewing completed

maintenance

and

surveillance

documents.

Inspection

Findings

Hl

Conduct of maintenance

The inspectors

witnessed/reviewed

portions of the following maintenance

activities in progress:

WO 95031948,

Calibration of flow indication

and control

instrumentation for Unit 4

AFW Train

B in accordance

with

procedure

4-PHI-075.2 (section Hl.1).

WO 95024862,

HOVATS testing of Unit 4

CS Valve HOV-4-880B (section

Hl. 1) .

WO 95018976,

Disassemble,

clean

and inspect Unit 4

CS

Pump "B"

Discharge

Check Valve 4-890B (section Hl. 1).

e

10

WO 95024862,

Disassemble,

inspect,

clean

and repair the operator

for Unit 4

CS

Pump

B Discharge Isolation Valve MOV-4-880B in

accordance

with procedure

0-GME-102. 11 (se'ction Hl.1).

WO 96007617,

Troubleshooting,

inspection,

and testing of Unit 4

Excore Neutron Detector N-36 in accordance

with procedures

0-CMI-

059. 10 and 0-GHI-102. 1 (section Ml.1).

WO 95025025,

Overhaul

actuator,

valve checks,

stroke

and

calibration of Unit 4 "A" Train Feedwater

Flow Control Valve FCV-

4-478 in accordance

with procedure

4-PHI-074. 18

(section Hl. 1).

WO 95000530,

Install

and test

Rosemount

I/P Transducer for Unit 4

"A" Train Feedwater

Flow Control Valve FCV-4-478 (section Hl.l).

WO 95025024,

Overhaul

actuator,

valve checks,

stroke

and

calibration of Unit 4 "B" Train Feedwater

Flow Control Valve FCV-

4-488 in accordance

with procedure

4-PHI-074. 18 (section

Hl. 1).

WO 95026622,

Overhaul

and calibrate actuator for Unit 4 "B" Train

Feedwater

Bypass

Flow Control Valve FCV-4-489 (section Ml.l).

WO 95030557,

Inspect,

clean,

and repair Unit 4 basket strainer to

intake cooling water supply for CCW heat

Exchanger

"A" (section

M1.1) .

Disposition of current Unit 4 outage

FAC inspection findings

(section H1.2).

Welding of replacement

piping components

for Unit 4

RHR and

FW

systems

(section M1.3).

3C bus troubleshooting

(section H1.4).

Unit 4 turbine governor

and control oil troubleshooting

(section

H1.5) .

Unit 4 feedwater

heaters

(section H2.2)

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.

The inspectors

witnessed/reviewed

portions of the following test

and

inspection activities:

Procedure

O-SMH-051.3, Unit 4 Containment

and Closeout

Inspection.

Procedure

4-OSP-089. 1, Turbine Generator

Overspeed

Trip Test

(section 01.1).

Unit 4 mode change

and startup testing

(sections

Ol. 1 and 07. 1).

Unit 4 control rod N-9 testing

(section M2.1).

Unit 4 integrated

safeguards

testing (section

H3. 1)

The inspectors

determined that the above testing activities were

performed in

a satisfactory

manner

and met the requirements

of the

technical'specifications.

Unit 4 Outage

Maintenance Activities

For the general

maintenance

activities identified in section

Ml above,

the inspectors

observed

a portion of the in-process activities

and

verified compliance with applicable requirements.

For the work

activities observed,

the inspectors

found that detailed

procedures

were

in place

and were being followed,

Work activities were being performed

in accordance

with requirements

by knowledgeable

and qualified personnel

in

a professional

manner.

Flow Accelerated

Corrosion Activities

The

FAC program

was reviewed during

NRC Inspection

Report 50-250,251/96-

02.

This included the documentation of inspection of the

FAC program

and the planned

inspections for the Harch

1996 Unit 4 refueling outage.

During

FAC inspections for the Unit 4 outage,

the licensee identified

several

components

in the Hain Steam

(HS)

and Feedwater

(FW) Systems

that did not meet the minimum thickness

screening

requirements

specified

in the program.

The screening criteria is conservatively

set to ensure

that

a component will not degrade

below minimum wall thickness

before

the

end of the next cycle

and is based

on adding

a wear allowance for

one cycle to the minimum required wall thickness.

The wear rate is

determined

by actual

thickness

measurements

taken over

a given time

period (usually one operating

cycle), or by subtracting

an actual

thickness

measurement

from an

assumed

starting thickness'ny

components

found below the screening criteria require engineering

disposition.

The inspectors

reviewed the following 1996 Condition Reports

which

documented

resolution of HS and

FW components

found to be below minimum

thickness

screening criteria:

229,

230,

231,

301,

339,

and 355.

All of the

MS components

were determined

to be acceptable

for another

cycle of operation.

Eight

FW components

were replaced with upgraded

material

(Cr-Mo) and four were determined to be acceptable

(see section

H1.3 below for inspection of welding associated

with the replacements).

The replaced

components

were the expanders/reducers

and short pipe

sections

on either side of the "A" and "B"

FW Flow Control Valves.

The

FW components

found acceptable

for another cycle were the

same

components

on either side of the- "C"

FW Flow Control Valve.

Based

on

a

detailed

review of the engineering

analysis for disposition of the

above

12

components

and discussion of the evaluation

and disposition review

process,

the inspectors

determined that the dispositions

were

appropriate.

In addition to the above

FW piping,

one short section of

FW pipe in the

"B" feedwater line inside the containment

was replaced with Cr-Mo

material during the current outage.

All accessible

FW components

inside

the containment

have

now been

inspected.

None of the

FW piping inside

the containment

has

shown severe

FAC wall thinning.

In general,

the

thinning has

been in counterbore

areas

that started

out thinner than the

adjacent

piping.

The wear has

been general

rather than

a localized

corrosion attack.

Based

on the

above review, the inspectors

concluded that the licensee's

FAC program is working well and that the process for evaluation

and

disposition of inspection results is

a strength.

Pipe Welding

As noted in section

M1.2 above,

the licensee

replaced

a number of

sections of

FW piping during the Unit 4 outage.

These

replacements

required

making

10 pipe welds during the Spring

1996 Unit 4 outage.

In

addition,

due to

a leak in the

4A Residual

Heat

Removal

(RHR) Heat

Exchanger outlet nozzle to shell weld area

(reference

condition report

96-204),

the outlet nozzle

was

removed

and

a

new nozzle installed.

This

nozzle replacement

required cutting and rewelding

a section of the heat

exchanger outlet piping.

The inspectors

reviewed the welding and

Non destructive

examination

(NDE) records detailed

below for the

above described

pipe welds.

The

applicable

Code for this work was the

1989 Edition of Section

XI of the

ASME Boiler and Pressure

Vessel

(ASME B&PV) Code,

which allows the

use

of the original construction

code,

or later codes,

for replacements.

The welding was performed in accordance

with welding procedure

specifications that meet the original construction

codes

as well

a later

editions of ASME Section III.

The applicable

Code Class is

ASME Class

2.

Since

Code

Case

N416.1

was used,

the applicable

NDE Code

was

Subsection

NC of the

1992 Edition of ASME Section III.

The following records for RHR welds

FW-1,

FW-2,

and

FW-3 on Drawing PTN-

C-96-028-001

were reviewed:

v

WO 96006517

Process

Sheet

Weld Travelers

Radiographic

(RT) Film

gualification records for two PCI Energy Services

(welding and

NDE) and three

FPL

(RT)

gC inspectors

Welder qualification records for seven welders

PC/M 96-028

CR 96-204

0

13

The following records for Feedwater

welds

FW-3,

FW-5, ISI-IA, and ISI-18

on Drawing 5614-P-770-S,

SH 3;

FW-6,

FW-SR1, ISI-IA, and ISI-1C on

Drawing 5614-P-770-S,

SH 2;

and

FW-13R1

and

FW-14 on Drawing 5614-P-558-

S were reviewed:

Weld Travelers

RT Film

gualification records for 11 welding and

NDE gC inspectors

Welder qualification records for 10 welders

Material certification records for four heats of welding material

The inspectors

evaluated

the general

surface condition of all completed

welds,

except

FW-13R1

and

FW-14,

and verified that the surface generally

matched

what was

shown

on the

RT film.

As noted

above,

the applicable

Code for NDE was the

1992 Edition of ASME

Section III, Subsection

NC invoked by Code

Case

N416. 1.

During review

of the above

RT film, the inspectors

noted that the

RT technique

did not

fully meet this

Code relative to selection of type

and size of

penetrameter.

Subsection

NC has

a table for the selection of

penetrameters.

For all of the

above welds;

except the

RHR nozzle-to-

shell weld, the licensee

used the guidelines of ASME Section

V in lieu

the table in Subsection

NC.

After questioning

by the inspector, it was

determined that this question

had

been raised

by the

ASME Code

Authorized Nuclear Inspector

and resolved

by licensee

CR 96-460.

The

CR

identified that use of the penetrameter

selection table in Subsection

NC

was questionable

since it was originally issued for single wall exposure

RT and

has never

been

upgraded to cover double wall exposure

RT,

techniques

(the welds in question

used double wall exposures).

The

CR

further provided the argument that the

Code

Case only specified

use of

the

NDE methods

and acceptance

criteria of Subsection

NC and not the

RT

technique.

The

CR also provided

ASME Code sanctioned

calculations

showing that the technique

used provided

RT sensitivities

equivalent to

that required

by Subsection

NC.

The inspector

concluded that the licensee

had

shown that the technique

used provided

RT sensitivities equivalent to that required

by Subsection

NC and

showed

the weld quality to be good.

However, for the welds in

question,

the penetrameter

selection specified

in Subsection

NC could

have

been

used to show equivalent sensitivity as that

shown

by the

technique

used,

precluding the need for technical justification for what

was done.

This omission to use

a technique that fully meets

ASME

Subsection

NC requirements

was considered

to be

a weakness

in the

RT

program.

Except for the weakness

noted

above,

the inspector

concluded that

performance

associated, with the above safety-related

welds

was good,

Personnel

were well qualified and work was well documented.

Visual

observations

and review of RT film indicated

good quality welds.

14

Unit 3 Hanual Trip During 4C Transformer

Testing

On Harch 27,

1996 at 5:16 p.m., operators

manually tripped the Unit 3

reactor

from IOOX power due to decreasing

S/G levels.

One minute

earlier,

the

3C

4KV bus

had unexpectedly

locked out and deenergized,

resulting in

a loss of one of two SGFPs

(38).

Haintenance

protection

and control personnel

were performing breaker

checks

on the

4C

transformer,

including the

3C bus alternate

feeder

(3AC01).

The

3ACOI

breaker

was in

a test position

and

was racked out of its cubicle,

resting

on the

3C bus floor.

The

3C bus is

a metal

enclosed,

non-safety

related

4KV switchgear.

The cycling of the

3ACOI breaker

caused

actuation of a

3C bus relay (3CBTX/FT), which resulted

in

a bus lockout

and tripping of feeder breaker

(3AC16) from the

3C transformer.

Control

room operators

entered

procedure

3-0NOP-004.4,

Loss of 3C 4KV

Bus

and 3-EOP-E-O,

Reactor Trip or SI.

Procedure

3-EOP-ES-0. 1, Reactor

Trip Response

was subsequently

entered.

Safety

system

response

to the

trip was normal.

All control rods inserted

as indicated

by RPI and rod

bottom lights.

No issues

associated

with stuck or slow rod insertion

as

described

in

NRC Bulletin 96-01 occurred.

AFW auto started

(both trains

and all three

pumps),

and

no overspeed

problems occurred during startup

nor subsequent

shutdown evolutions.

No relief valves lifted,

RCS

temperature

and pressure

control

was normal,

and decay heat

was

removed

by the

RCPs

and S/Gs.

The

NRC was notified pursuant to

10 CFR 50.72

(b)(2)(ii) due to the

RPS

and

ESF actuations.

The licensee

formed

an

ERT, initiated condition report No.96-481,

and

submitted

LER 96-06.

The licensee

determined root cause to be

mechanical

induced vibration caused

by the testing

(opening) of the

3AC01 breaker

(4C transformer feeder)

which resulted

in an inadvertent

actuation of relay 3XCBTX/FT and subsequent

3C transformer/bus

lockout

and

a loss of the

3B SGFP.

Loose steel floor plates

associated

with the

3C switchgear

and close proximity of the relay,

and intrusive Unit 4

testing were all causal

factors.

Corrective actions

included the following:

ERT review and report issued,

Post Trip Review performed,

PNSC

and plant management

review completed,

Verified (reproduced)

the root cause

scenario,

Repaired

3C and

4C switchgear floor plates,

Inspected

the affected relay,

Hodified relay to include coincidence trip logic,

Restricted

3C and

4C switchgear

rooms

access

and controls,

15

Repaired

noted abnormalities

during trip (e.g.,

3C MSIV position

indication, turbine

speed indication,

runback circuitry, etc.),

Nuclear Problem Report

No.96-481 written,

and

Verified primary and secondary

plant instrumentation availability.

The Unit restarted

on March 28,

and was placed

on line at 3:47 a.m.

on

Harch 29,

1996.

Full power was achieved

on March 30,

1996 (section

04.1).

The inspector

was onsite at the time of the trip and reported to the

control

room when the

PA announcement

was made.

Post trip conditions

were verified, including safety

system performance,

control rod

insertion,

and

EOP/ONOP implementation.

Unit 3 was verified to be in

Mode

3 and Unit 4 was in Mode

6 (cycle

16 refueling outage).

The

inspector

noted that both units were affected

by

a loss of the

3C and

4C

4KV buses.

However,

the

ONOPs were written for a Mode

1 (power)

condition

and did not specifically address

a loss of both buses.

The

inspector pointed this out to licensee

operations

management

personnel,

and

a commitment to address

this issue

was made.

The inspector

noted

very good

command

and control, communications,

and

EOP use,

The

inspector also toured the

3C bus

room and examined

conditions'he

inspectors

reviewed the

ERT and post trip review reports,

attended

the

PNSC meeting, verified corrective actions,

confirmed the root cause

analysis,

and reviewed

LER 96-06.

Discussions

with operators,

maintenance

personnel,

ERT members,

and management

were held.

The

inspectors

also reviewed the turbine runback circuitry which failed to

actuate

on the

3B SGFP trip.

Licensee

personnel

noted that the turbine

pressure

input was unexplainably isolated (e.g.,

PS-3-1604-1

was

closed).

The inspector verified that this circuit was not safety-

related.

However, the licensee

took extensive corrective actions,

including verification of all secondary

plant instrumentation prior to

restart.

The inspectors

also verified that appropriate

work controls were in

place for this

3C and

4C bus testing,

including

a

RWO, plant manager

approved

red sheet,

and appropriate

pre-job briefing.

The inspector

also reviewed

two previous events

where the

3C or 4C buses

were lost,

and

a resultant reactor trip occurred.

The inspectors verified that

corrective actions

taken in response

to the two previous events

were

completed,

and could not have prevented this recent Unit 3 manual trip.

The inspectors

also reviewed

UFSAR section

14'. 11 regarding

a loss of

normal

feedwater;

and

UFSAR sections

14C,

14. 14, 7. 1. 1,

and 7.3. 1

and

drawing 5610-T-LI Sheet

21 regarding

the turbine runback systems.

No

discrepancies

were noted.

In conclusion,

the inspectors

noted very good response

to the trip by

operators',

ERT members,

and plant management.

A good root cause

analysis

and validation were performed,

and adequate

corrective actions

16

were initiated.

Minor weaknesses

were noted in the operations'oss

of

C bus

ONOPs.

The licensee's

response

to and corrective actions for the

turbine runback issue

were appropriate.

LER 96-06 is considered

closed.

Main Turbine Related

Issues

Causing the Unit 4 Manual Reactor Trip

The inspector

reviewed the root cause attributed to the Unit 4 reactor

trip that occurred

on April 9,

1996 that is also discussed

in section

04.2 of this report,

Following troubleshooting

on the main turbine

governor,

load limit device, auxiliary governor

as well

as associated

components,

the licensee

concluded that the event

was caused

by

corrosion products that fouled the impeller oil orifice.

This impeller

oil line transmits

a signal

corresponding

to turbine

speed

to the

governor bellows.

The clogged orifice caused

the governor to sense

decreased

speed

and caused

an increase

in the control oil pressure until

the load limit took control to stop the increase.

With the increase

in

control oil pressure,

the turbine control valves

opened

causing

an

increase

in generated

Hwe.

Further, with the control valves opening,

the

S/G levels swelled,

prompting the operators

to trip the reactor.

The licensee

believes that the corrosion products

were formed

as

a

result of water intrusion into the open governor bellows hole when the

governor

was

removed

and covered with a temporary cover during the

recent refueling outage.

Water had

been cleaned

from the bellows hole

but the orifice at the bottom of the block had not been

cleaned

and

inspected after the water intrusion.

As corrective action to prevent

recurrence,

the licensee

plans to strengthen

the Foreign Material

Exclusion program

as applicable to main turbine maintenance

as well as

revise turbine maintenance

procedures

to include appropriate

and

complete inspection

requirements

should contamination

be detected

when

the turbine controls

are

opened for maintenance.

The inspector

reviewed licensee

actions

associated

with this event,

including troubleshooting

associated

with the governor.

The inspector

concluded that the licensee

appropriately initiated actions to address

maintenance

concerns

that were brought to light as

a result of this

event.

Further

LER 96-01 (Unit 4) was reviewed

and closed.

Maintenance

and Material Condition of Facilities

and Equipment

NRC Bulletin 96-01

Followup

The licensee

responded

to

a Unit 4 control rod

(N9) which indicated

approximately

16 steps after

a unit manual reactor trip on April 9,

1996

(section H1.5),

NRC Bulletin 96-01, action 4, required the licensee

to

assess

control rod performance

during all trips.

Further,

the bulletin

required the licensee to conduct tests

to measure

and evaluate

rod drop

times

and rod recoil,

After the trip, the control

room RPI for control rod

N9 (shutdown

bank

A, group 2) went from full out (230 steps)

to

16 steps.

The rod

positian then drifted to full-in position

and the rod bottom light

17

illuminated (setpoint of 20 steps).

Further,

the time from the opening

of the reactor trip breakers

to illumination of the rod bottom light was

about

1.75 seconds.

The licensee initiated troubleshooting

on the

RPI

and duplicated "stickiness" of the indicator at several

locations of the

needle travel.

Based

on these observations,

the

RPI was replaced.

Subsequently,

rod N-9 was tested

pursuant to procedure

4-PMI-028.3,

RPI

Hot Calibration,

CRDM Stepping Test,

and

Rod Drop Test.

Three tests

were performed during the midshift on April 10,

1996.

All three

resulted

in drop times of about

1.35 seconds

to dashpot

region entry

(e.g.,

24 inches)

and about

1.85 seconds

to full-in position.

(The

Technical Specification 3. 1.3.4 requirement

is

a drop time of less

than

2.4 seconds

to dashpot entry).

During day shift on April 10,

1996,

the rod was again tested

and results

were similar.

Further,

the replaced

RPI was also verified to be

properly functioning during rod stepping

and rod drop testing.

The inspector

reviewed the rod drop chart traces,

and independently

confirmed that drop times were 1.35 seconds

to

RCCA dashpot

entry and

that little or no recoil occurred.

The inspector also

examined

the

RPI

module during bench testing.

NRR also reviewed these results,

including

chart traces.

Based

on these

NRC reviews,

the inspector

concluded that

Unit 4 control rod N-9 exhibited proper performance

and that the

licensee

appropriately replaced

a faulty RPI.

The inspector

noted

good

test coordination

among maintenance,

operations,

and reactor engineering

personnel.

The inspector

also observed effective briefings,

conservative

operations,

and strong

teamwork being displayed.

M2.2

Feedwater

Heater Related

Issues

Following Unit 4 startup

from refueling, the high level annunciators

associated

with the

1A, 2A,

and

3A feedwater heaters

did not clear

as

expected.

The licensee,

following troubleshooting, initially postulated

that the

3A feedwater heater

had

a tube to shell leak.

The

3A and

4A

feedwater

heaters

were isolated following a power reduction to 90X.

Investigation of the

3A feedwater

heater did not reveal

a leak.

Upon

further investigation,

the licensee

determined that the

1A and

2A

feedwater three

way bypass

valve stem

had separated

from the disc such

that the valve had failed in the feedwater

bypass position.

With

condensate

through the

1A and

2A feedwater

heaters

bypassed

the unit is

operating inefficiently with a loss of approximately

10 Mwe.

Repair of

the bypass

valve would involve

a unit shutdown.

The licensee

reviewed

the effects

on the plant of long term operation with the

1A and

2A

feedwater

heaters

bypassed.

Further, with the flow characteristics

different, the licensee

evaluated

the effects

on secondary

pipe erosion.

During the valving of the

3A and

4A heaters

following tube inspection,

a

portion of the extraction

steam piping to the feedwater heaters

experienced

a water

hammer that resulted

in a vent valve pipe being

severed.

The unit had to be reduced to

60'A power to effect repairs of

that line.

18

The inspectors

also reviewed applicable sections

in the

UFSAR (section

10.0)

and noted that besides

the system drawing, the

UFSAR did not

detail feedwater heater operations.

Nevertheless,

the inspector

questioned

the licensee if there were plans to address

the affects

on

the

UFSAR related to operation with the

1A and

2A feedwater

heaters

bypassed.

Based

on, inspector questions,

the licensee

plans to look into

the matter.

The inspector

concluded that licensee

appropriately reacted

to the Unit 4 feedwater heater related

issues

and abnormalities.

Maintenance

Procedures

and Documentation

Unit 4 Integrated

Safeguards

Testing

The licensee

performed Unit 4 procedures

4-OSP-203. 1, Train A Engineered

Safeguards

Integrated Test,

and 4-0SP-203.2,

Train

8 Engineered

Safeguards

Integrated

Test,

during the Unit 4 Cycle

16 refueling outage.

Technical specifications

required testing various engineered

safeguards

features

including SI

(LOCA) with and without

LOOP, containment

phase

A

and

B isolation,

LOOP, feedwater isolation,

main steam line isolation,

control

room ventilation isolation,

and containment ventilation

isolation.

On March 29,

1996, during pretest

preparations

for Train A, per

attachment

2 of procedure

4-OSP-203. 1,

a personnel

error occurred

resulting in an unplanned

ESF actuation.

An invalid SI signal

was

initiated when pressurizer

pressure

test potentiometers

were incorrectly

installed

on two channels

simultaneously.

This action resulted

in

unblocking of the low pressure

SI signal

on Unit 4, causing Unit 4 and

Unit 3

ESF equipment actuations

(e.g.,

HHSI pumps,

EDGs, cooling pumps,

etc.).

No injection occurred

on Unit 4 as it remained

in Mode 5.

Unit

3 was in Mode

1 at

100X power.

RHR decay heat

removal

on the

4B train

was unaffected

on Unit 4.

Operators

secured

the affected

equipment,

notified the inspector, initiated condition report

No.96-509,

and

made

a

10 CFR 50.72 notification.

LER 96-07 was also written and submitted.

Corrective actions

included stopping the test until

a root cause

analysis

and corrective actions

were completed,

individual counselling,

and procedure

enhancements.

Further,

the

I&C department

was briefed

on

the event.

The inspectors

reviewed the

ESF actuation

event

and observed

portions of

the Unit 4 safeguards

testing.

Based

on problems

noted with the last

Unit 4 test in November

1994,

as discussed

in

NRC Inspection

Report 50-

250,251/94-23,

the licensee

made several

enhancements.

These

included

operations

management

coverage,

a dedicated

team of personnel

to perform

the tests,

simulator checkout of the revised test procedure,

improved

test briefings,

and other noted items.

The inspector also noted that

positive control

and strong communications

were maintained during the

testing.

During A train testing,

a

4KY bus stationary switch failed

(see section

E1.2) which required retesting.

Notwithstanding the error

that occurred during the pre-test evolution, the inspectors

concluded

that testing

was professionally

performed with good procedure

compliance

and strong

teamwork.

Further,

a strong safety perspective

was

19

maintained for the operating unit (Unit 3).

LER 96-07 was reviewed,

determined

to be adequate,

and

was closed.

Maintenance

Organization

and Administration

Post Maintenance

Testing

The inspector

reviewed procedure

O-ADH-737, Post Maintenance

Testing

as

well as discussed

the process

related to post maintenance

testing with

emphasis

on the role of the maintenance

planner.

Further,

the inspector

also

assessed

a Speakout

review associated

with the post maintenance

tes'ting

process

that was conducted to ensure

compliance with existing

procedures.

The Speakout

review had also selected

a large

sample of

completed

PHTs to ascertain

compliance.

The Speakout

review did not

have

any adverse

findings.

However,

Speakout

made

a recommendation

with

regard to the maintenance

planner involvement in PMTs.

The

recommendation

involved documenting

the source of information upon which

the planner relies to sign-off that

a

PHT was completed.

This

documentation

of the source

on the completed

PHT attachment

to the work

package

would alleviate potential

concerns

regarding verification of

completion of PMTs.

The inspector

confirmed that the licensee

plans to adopt this

recommendation.

The inspectors

plan to continue to determine

licensee

process

and implementation of the post maintenance

program during future

inspections.

Further, for the recent inspections

performed,

the

inspectors

have noted

no significant abnormalities

in the implementation

of the post maintenance

test

program.

En ineerin

Inspection

Scope

(37551,

90712,

90713,

and 92700)

The inspectors verified that licensee

engineering

problems

and incidents

were properly reviewed

and

assessed

for root cause

determination

and

corrective actions.

They accomplish this by ensuring that the

licensee's

processes

included the identification, resolution,

and

prevention of problems

and the evaluation of the self-assessment

and

control

program.

The inspectors

reviewed selected

PC/Hs including the applicable safety

evaluation, in-field walkdowns, as-built drawings,

associated

procedure

changes

and training, modification testing,

and changes

to maintenance

programs.

The inspectors

also reviewed the reports

discussed

below.

The

inspectors verified that reporting requirements

had been met, root cause

analysis

was performed,

corrective actions

appeared

appropriate,

and

generic applicability had

been considered.

When applicable,

the

criteria of 10 CFR Part 2, Appendix C, were applied.

20

Inspection

Findings

Conduct of Engineering

Unit 4 Startup

and Physics Testing

The inspectors

observed

portions of the Unit 4 initial criticality,

startup,

and physics testing evolutions (section

01. 1).

The licensee

performed procedures

0-0SP-040.6,

Initial Criticality After Refueling,

and 0-0SP-040.5

Nuclear Design Verification.

These tests verified that

nuclear design criteria

and related predictions

were satisfactory.

Specific tests

included critical boron concentrations,

control

rod

worths,

temperature

coefficients of reactivity,

and power distributions.

Technical Specifications

3/4. 1. 1.3, 3/4.2.2,

and 3/4.2.3 were also

verified.

The inspectors

reviewed the test results

and independently

confirmed

that acceptance

criteria were met.

The inspectors

noted very good test

coordination

between operations

and reactor engineering

personnel.

The

inspectors verified that these tests

were conducted

in accordance

with

procedure

O-ADH-217, Conduct of Infrequently Performed Tests or

Evolutions.

Overall, the licensee

demonstrated

effective test control

and conducts

4KV Bus Stationary

Switch Failure

During performance of Integrated

Safeguards

testing of the

4A 4KV bus

(see section

M3. I), the licensee

determined that one of the bus clearing

relays failed to actuate.

The licensee

concluded

the failure to actuate

was caused

by breaker

4AA19 stationary switch failing to operate its

contacts

as required.

The

4AA19 breaker supplies

the motor for the

4A

ICW pump.

Upon disassembly

of the

4AA19 stationary switch, the licensee

determined

that one of the internal

cam followers had failed (cracked)

such that

its respective

contacts

were not closed.

This internal

cam follower is

manufactured

of "Lexan" (polycarbonate).

In 1976 the manufacturer

(GE)

replaced this material with a different type due to problems with

cracking of the "Lexan" material.

BWRs were provided with this generic

information.

Subsequently,

NRC Information Notice 80-13

was also

issued.

The licensee

reviewed their data

base

and determined that this switch

was

used in the

4KV safety

buses

as follows:

3A

three switches

3B

-

two switches

4A

-

16 switches

4B

none

Inspection of several

of the installed accessible

stationary

switches

confirmed the cracking issue,

Condition report

No.96-523

was written

21

including an operability assessment.

This included

a failure effects

analysis.

The licensee

concluded that all four 4KV buses

were operable.

The basis for this conclusion

was:

isolated

random failures reported

by the manufacturer

and

by the

industry,

Turkey Point failure data limited to one occurrence,

Manufacturer's

assessment

that the switches

would function 45,000

cycles with existing cracks,

minimal stress

on the

cam followers and roller pins,

limited number of the affected switches currently in use,

random failure events

bounded

by single failure criteria,

plans to change

out affected switches at the next opportunity.

The inspector

reviewed the issue,

including the condition report.

Selected

switches

were inspected

and the inspector confirmed the failure

mechanism.

The operability assessment

was reviewed,

and the issue

was

discussed

with engineering

and technical

personnel.

The inspector

concluded that the licensee

appropriately

addressed

and dispositioned

this switch issue

including the extent of the condition.

E2

Engineering

Support of Facilities

and Equipment

E2. 1

Cross-Tie of Safety Injection Cold Leg Accumulators

Based

upon

a review of a recent

10 CFR 50.72 notification made

by Indian

Point

2 involving cross-tie of safety injection cold leg accumulators,

Turkey Point performed

a review of current plant procedures

and practice

to determine applicability.

During this review, it was determined that

Turkey Point procedures

for transferring nitrogen or water through

'ommon

fill lines allowed the cross-tieing

safety injection

accumulators.

Further,

operators

were interviewed

and the practice of

simultaneously filling the accumulators

had

been

performed in the past.

Thus,

in the event of a loss of coolant accident requiring accumulators

during

an ongoing fill of two or more accumulators,

the accumulators

not

attached

to the severed

RCS cold leg had the potential for being

depressurized

via the cross-tied lines through the break.

This loss of

accumulator

pressure

could prevent the core reflood capabilities of the

accumulators

in the early stages

of response

to

a loss of coolant

accident.

The Turkey Point accident analysis

assumes

that the content of two

accumulators,

or 1750 cubic feet of water,

are utilized during core

reflood.

Consequently,

Westinghouse's

preliminary assessment

was that

the reflood analysis

had insufficient margin to accommodate

the

potential

pressure

loss in the accumulators

attached

to the intact

/~

22

reactor coolant

system loops.

Thus the licensee

concluded that the

practice of cross tying multiple accumulators

during fill evolutions

was

considered

reportable

under

10 CFR 50.72

(2) (iii) (D),

an event or

condition that alone could have prevented

the fulfillment of the safety

function of the accumulators

to mitigate the consequences

of an

accident.

The licensee

performed

a

PSA analysis of the core

damage

frequency

increase

due to the cross-tie of accumulators.

A bounding time of 30

minutes

per

day was

assumed

in which all three accumulators

were

considered

out of service simultaneously.

No other risk significant

components

were considered

to be removed

from service.

Based

on these

conservative

assumptions,

the licensee

calculated

an increase of 4.2N in

the core

damage

core

damage

frequency.

The assumptions

did not take

credit for any operator actions.

As corrective action,

the licensee

updated

procedures

3/4-0P-064,

Safety

Injection Accumulators,

to allow only one fill valve open at

a time when

RCS pressure

is above

1000 psig.

This would preclude the cross-tie of

the accumulators.

Further,

operations

reviewed other applicable

systems

for cross-tie affects.

No other similar systems

were found.

The

licensee

submitted

LER 96-05 pursuant

to

10 CFR 50.73

(a) (2)(V)(D).

The

LER remains

open.

The inspector

concluded that the identification of this issue during the

review of events

at other plants is considered

a strength.

Cross-Tie of the

Two Safety

Buses

The inspector

reviewed Condition Report

number 96-373 dated

March 18,

1996, that

was originated

by an

NPS.

The issue

was associated

with

electrical configuration that momentarily cross-tied

the two independent

4KV buses

(4A and 4B), through the

480

VAC load centers.

During

a

refueling outage or other defueled period,

each unit's

4

KV buses

are

de-energized

(non-concurrently)

to allow for modifications or periodic

maintenance.

This de-energization

also effectively takes

the associated

EDG out-of-service,

While each

4

KV bus is de-energized,

the

480 volt

load centers

normally fed from that

bus are cross-connected

to the

opposite train 480 volt load center to allow equipment required to

maintain cold shutdown

and refueling modes to perform outage related

components

energized.

For example,

when the Unit 4 4A bus is not

energized,

the

4A 480 volt load center is fed from the

4B 480 Volt load

center.

The

4B 480 volt load center is energized

from the

4B 4KV bus.

To accommodate

a live transfer, i.e,, without de-energizing

the

4A load

center,

the cross tie is accomplished

before the

4A 4

KV bus is

deenergized.

Thus,

from the time that the

4A and

4B load centers

are

cross-tied until the

4A load center is disconnected

from the

4A 4

KV

bus,

the

4A and

4B 4

KV buses

are electrically tied.

The condition also

occurs during the cross-tie of the

4C and

4D 480 volt load centers

as

well as

on Unit 3.

Further,

the buses

are tied prior to returning the

configuration to accommodate

continuous

energization of the load center.

This cross-connecting

of the load centers

to the opposite trains

4

KV

23

bus is permitted

by Technical Specification 3.8.3.2 provided

a safety

evaluation

ia performed,

The breakers

associated

with the load centers

that are required to be

operated

are located in each unit's

480 volt load center

rooms

and are

operated

in accordance

with procedure

3 or 4-0P-006,

480 Volt Switchgear

System.

The duration during which the two 4 KV buses

are cross-tied

is

very short

(few seconds).

If a

LOOP were to occur during this

condition,

where the two 4

KV buses

are cross-tied,

the

4A and

4B

EDGs

would attempt to energize their respective

buses electrically out of

phase,

potentially damaging

both the

EDGs.

As immediate corrective action,

the licensee

modified procedures

3 and

4-OP-006

such that it cautioned

the operator to complete the alignment

such that the interval

when the busses

are interconnected

would be

limited to 16.5 seconds.

16.5 seconds

corresponds

to the time required

for the

EDG startup

and complete

sequencing

of the first load block.

Further,

the licensee

plans to update Unit 3 and

4 safety evaluations

JPN-PTN-SEEJ-88-042

and JPN-PTN-SEEJ-89-085.

These safety evaluations

were performed to address

the cross-connection

of load centers

during

the

4

KV bus outage.

However,

the safety evaluation failed to recognize

and therefore consider the effect of cross-connecting

the

4 KV buses.

The failure of the safety evaluations

to consider fully the effects of

cross-connecting

the load centers

is considered

a Non-Cited Violation,

50-250,251/96-04-03,

Failure to Perform

an Adequate Safety Evaluation.

This meets

the criteria specified in section VII.B of the

NRC

Enforcement Policy.

The

NCV is closed.

The inspectors

also reviewed

UFSAR chapter

8,

and noted that section,

8. 1. 1.3 stated that "each of the four

EDG is connected

to a separate

power train".

This

UFSAR design basis

was not met momentarily for the

situation described

above.

Further,

the Technical Specifications

allow

this deviation during Node 5/6 operations.

The licensee

intends to

address

this issue

on

an

UFSAR revision.

The inspector

concluded that the questioning attitude exhibited

by the

NPS that led to the identification of the problem is

a strength.

Emergency

Containment

Cooler Valve Failure

On April 2,

1996,

the

4C

ECC outlet valve,

CV-4-2908, failed to open

during the air fail test portion of procedure

4-OSP-055. 1,

Emergency

Containment

Cooler Operability Test.

The

ECC outlet valve supplies

CCW

to the

ECC heat

exchangers

located in containment.

The

ECC outlet

valves

are normally closed

and

open

upon

an

ECC demand signal following

an SI.

The

ECC inlet valves

are normally maintained

in the open

position.

There

have

been other recent

problems with the

ECC valves

previously discussed

in

NRC Inspection

Report

Number 50-250,251/96-01,

Section 5.2.5.

The valve failure placed Unit 4 in a hold for entry into mode 4.

The

pilot lockup valve associated

with CV-4-2908 apparently did not shift as

24

designed

upon test conditions simulating loss of instrument air.

An

ERT

was formed to identify and correct the problem(s) that contributed to

the failure and Condition Report

number 96-535

was originated.

Fur'ther,

the licensee

concluded that the Unit 3

ECC outlet valves

and the other

Unit 4

ECC outlet valves

remained

operable

based

on successful

completion of surveillance testing per procedures

3/4-OSP

055. 1.

The

pilot lockup valve acts

as

a pneumatic

switch

and changes

position when

the instrument air supply pressure

drops to

below 45 psig and

60 psig

on Unit 4 and Unit 3, respectively.

When the pilot lockup valve changes

position, the air accumulator

mounted

on the isolation valve actuator is

aligned to the actuator cylinder to open the valves.

The

ERT troubleshooting

and investigation

concluded that:

The pilot portion of the lockup valve bled

as required.

The accumulator

check valve operated

as required.

The spool

piece associated

with the pilot lockup valve did not

shift during field testing

as well

as

on bench,

thereby recreating

the failure.

The measured

force to shift the spool

piece toward the air fail

direction

was greater

than the spring force.

After initial

shifting of the spool pieces,

the measured

forces were acceptable,

repeatable

and equivalent to the forces

measured prior to

installation.

Thus,

the spring was at times incapable of

overcoming

spool

piece drag.

Further,

the

ERT also noted that the failed pilot lockup valve had

"Viton" "0" rings installed.

This change

from "Buna-N" to "Viton" "0"

rings

had

been

made earlier this year

on most pilot lockup valves

due to

age related degradation

issues

associated

with "Buna-N" "0" rings.

The

licensee

also postulated,

but could not definitively conclude,

that the

"Viton" "0" rings increased

the resistance

within the pilot lockup valve

such that the existing spring force was insufficient to overcome the

resistance.

Further,

the other pilot lockup valves that utilized

"Viton" "0" rings did not fail during testing.

Subsequent

testing

concluded that the "0" ring type did not affect lockup valve

performance.

Consequently,

the licensee

implemented

PC/M number 96-039 to increase

the pilot lockup valve spring stiffness

from approximately 5.5 lbs to

12

lbs.

This increased

spring stiffness is designed

to overcome

any drag

forces prohibiting spool

movement.

Further,

the licensee

also

has

decided to revert to the

"Buna-N" type "0" rings.

The

age degradation

related to the "Buna-N"

material will be addressed

through periodic

inspection.

Additionally, as

a temporary solution to enable Unit 4

startup,

the pilot lockup valve for CV-4-2908 was replaced with one

composed

of "Buna-N" "0" rings.

However, it maintained

the original

spring

as the

PC/M had not been

implemented.

Operability of CV-4-2908,

as well

as the other five

ECC outlet valves affecting both units,

was

maintained

through successfully

completion of procedures

3 and

4-OSP-

55.1

on

a daily basis.

No further failures

have since occurred.

r

25

As of the

end of the inspection report period, all

ECC pilot lockup

valves

had

been modified.

Testing

was changed

to every

3 days

and the

licensee

is pursuing another

change to do weekly testing.

The inspector

observed

portions of the troubleshooting

and investigation

as well as

reviewed

and discussed

the issue,

including the

PC/H, with the licensee.

The inspector

concluded that continued attention related to the

reliability of the

ECC is warranted.

The inspectors

intend to continue

to review this issue during future inspections.

No technical

specification violations were identified.

E3

Engineering

Procedures

and Documentation

E3. 1

Monthly Operating

Report

The inspectors

reviewed the March and April 1996 monthly operating

reports

and determined

them to be complete

and accurate.

E3.2

License

Event Reports

Four

LERs were reviewed

and dispositioned

during the period including:

LER

~UNIT S

REPORT

SECTIONS

STATUS

96-05

96-06

96-07

96-01

3/4

3/4

3/4

4

E2. 1

H1.4

H3.1

H1.5, 04.2

Open

Closed

Closed

Closed

The inspectors

concluded that the

LERs were appropriately written,

timely and met

NRC requirements.

Specific

comments

were discussed

with

licensing personnel.

E8

Miscellaneous

Engineering

Issues

ES. 1

Review of Updated Final Safety Analysis Report

Commitments

A recent discovery of a licensee

operating their facility in

a manner

contrary to the

UFSAR description highlighted the

need for a special

focused

review that compares

plant practices,

procedures

and/or

parameters

to the

UFSAR descriptions.

While performing the inspections

discussed

in this report,

the inspectors

reviewed the applicable

portions of the

UFSAR that related to the areas

inspected.

The

inspectors verified that the

UFSAR wording was consistent

with the

observed

plant practices,

procedures

and/or parameters.

The following

UFSAR Sections

were reviewed:

UFSAR Section

8,0

6.4, 9.3,

9.11

6.2, 9.2,

14.1.5,

14.3

6.2

9.2

Re ort Sections

02. 2

Hl

03.1

E2. 1

04.1

26

However,

the following inconsistencies

were noted

between

the wording of

the

UFSAR and plant practices,

procedures,

and parameters

observed

by

the inspectors.

UFSAR Section

Re ort Sections

10.2

8.1.1.3

10.2

03.2

E2.2

H2.2

Plant Support

Inspection

Scope

(71750,

64704)

The inspectors verified the licensee's

appropriate

implementation of the

physical security plan; radiological controls;

the fire protection

program;

the fitness-for-duty program;

the chemistry programs;

emergency

preparedness;

plant housekeeping/cleanliness

conditions;

and the

radiological effluent, waste treatment,

and environmental

monitoring

programs.

Inspection

Findings

Radiological Protection

and Chemistry

(RPKC) Controls

Unit 4 Refueling Outage

Performance

The inspector

reviewed the licensee's

radiological

performance

during

the Unit 4 Cycle

16 refueling outage.

Attributes reviewed

included

radiation dose,

personnel

contamination

events

(including skin dose

assessment),

spill prevention,

radwaste

accumulation,

and contamination

control (including contaminated floor space).

All goals established

before the outage

were met.

Further,

the inspector

noted that the goals

have

become

more aggressive

(e.g.,

lower value) over the past

few

refuelings outages.

The inspector

independently

assessed

HP performance

during the outage,

including maiztenance

and test activity coverage,

RWP review,

ALARA and

ARB activities,

containment

inspections,

and other in process

reviews.

The inspector

noted that the licensee

continued to use remote monitoring

of jobs

(see

NRC Inspection

Report

No. 50-250,251/96-02).

The inspector

also noted that the radiation

dose estimate

was

215

Rem,

and the actual

dose

was

158.5

Rem.

This represents

the best

ever radiation exposure

for Turkey Point during

a refueling outage.

Contaminated

Flashlight Event

On March 27,

1996,

an

IKC technician

noted

a purple painted flashlight

in the turbine building elevator vestibule,

outside the

RCA.

HP

27

personnel

were immediately notified.

A survey confirmed fixed and loose

contamination

(1.0 k dpm).

A survey-of the area did not find any

contamination

spread.

The licensee initiated Condition Report

No.96-480

and

an investigation.

The licensee

could not conclusively determine

how the flashlight passed

through the

RCA control'oint.

However,

they believe it probably

bypassed

the normal controls through the auxiliary (turbine building)

control point.

Licensee corrective actions

included:

Temporarily closed

the auxiliary control point;

Posted

HP technicians

(part time)

and

a camera at auxiliary

control point to provide surveillance;

Surveyed all areas

outside of the

RCA for purple material

and

possible contamination.

None was found;

Informed all site personnel

of the event;

Briefed

HP personnel

on the event;

Mrote

a Nuclear Problem Report

No.96-480;

Plans to inventory and

number all purple material

by June 3,

1996;

Revised training to include this issue

and corrective actions;

and,

Modified HP routine surveillance

checks to include purple material

surveys.

The inspector

reviewed this event,

examined

the flashlight and survey

data,

reviewed the condition

and problem reports, verified corrective

actions,

and independently

inspected

the

RCA and

non-RCA for purple

material.

The inspector did not find any additional purple marked

material

outside the

RCA.

The inspector

concluded that this issue is

a

licensee identified violation.

The violation will not be subject to

enforcement

action

because

licensee corrective actions

were prompt

and

appropriate.

This meets

the criteria specified in Section VII.B of the

NRC Enforcement Policy.

The item is tracked

as

NCV 50-250,251/96-04-04,

Contaminated

Flashlight

Found Outside the

RCA.

The

NCV is closed.

28

Conduct of Security

and Safeguards

Activities

Non-Credible

Bomb Threat

On April 15,

1996, at approximately

2:00 p.m.,

a former Turkey Point

security officer was involved in a motor vehicle accident

on U.S.

Route

1, approximately

30 miles from Turkey Point.

The Florida Highway Patrol

responded

and

upon search of the vehicle discovered

a device containing

an aerosol

can, wires,

and

a timing device.

The Metro-Dade

Bomb Squad

responded

when contacted

by the

FHP.

The device

was determined to be

a

non-explosive training aid which had previously been

used at Turkey

Point.

The individual when asked stated that "the device

was to test

his friends at Turkey Point".

The individual was previously employed

by

Security Bureau,

Inc.,

a contractor serving Turkey Point.

The

individual was not enroute to Turkey Point

on the day of the vehicle

accident.

The non-explosive training devise

was destroyed

by the

bomb squad.

This

event

was witnessed

by

a local

TV news crew.

The individual was

arrested

and later released.

Though the licensee

did not consider this to be

a credible threat,

the

licensee

conservatively reported this incident to the,NRC.

The

inspector discussed

the incident with the security supervisor

and

concluded that the licensee

actions

were appropriate.

Fitness

For Duty Event

On Hay 2,

1996, at 1:33 p.m., the licensee notified the

NRC per

10 CFR 26 that

a licensed operator

(RCO) tested positive for marijuana.

The

testing

was randomly performed

on April 29,

1996,

and the results

became

known at 11:20 a,m,

on Hay 2,

1996.

Condition Report

No.96-667

was

written.

The licensee

suspended

the

RCO's

access

and relieved the individual of

licensed duties.

The licensee

confirmed

no on-site

usage

and reviewed

the individual's work activity history.

No abnormalities

were

identified.

The inspector

reviewed the condition report,

the

NRC notification work

sheet,

and other pertinent documentation.

Discussions

were held with

plant and operations

management,

and with security

and

FFD personnel.

The inspector

concluded that licensee

appropriately reacted

to this

issue.

The inspector

independently

reviewed the

RCO's work history and

did not identify any problems,

The inspector

noted that management

reacted

aggressively

and promptly to this issue,

including meetings with

all licensed

operators.

29

V.

Mana ement Meetin s

Xl Exit Meeting

Summary

The inspection

scope

and findings were summarized during management

interviews held throughout the reporting period with both the site vice

president

and plant general

manager

and selected

members of their staff.

An exit meeting

was conducted

on Hay 15,

1996.

(Refer to listing for

exit meeting attendees.)

The areas

requiring management

attention

were

reviewed.

The inspector described

the areas

inspected

and discussed

in

detail

the inspection results,

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.

Partial List of Persons

Contacted

• T.'.

R. J.

J,

C.

P.

H.

• C. R.

T. J,

J.

H.

B. 00

R. J,

S.

H.

R. J,

• R.

G.

J.

R.

• P.

C.

• G.

E.

• R. J.

H.

P.

• D

H.

H.

• T

O

M. D.

• V. A.

J,

E.

J.

E.

G.

D.

H. L.

J.

D.

L. T.

E.

Ly

F.

E.

R.

B.

D.

D.

• CD L.

H.

N.

Abbatiello, Site guality Manager

Acosta,

Company Nuclear Review Board Chairman

Balaguero,

Reactor

Engineering

Supervisor

Banaszak,

Electrical/I8C Engineering Supervisor

Bible, Site Engineering

Manager

Carter,

Project Engineer

Donis,

BOP Engineer Supervisor

nn, Mechanical

Engineering Supervisor

Earl,

gC Supervisor

Franzone,

Instrumentation

and Controls Maintenance

Supervisor

Gianfrancesco.

Maintenance

Planning Supervisor

Heisterman,

Maintenance

Manager

Hartzog,

Business

Systems

Manager

Higgins, Outage

Manager

Hollinger, Licensing

Manager

Hovey, Site Vice-President

Huba,

Procurement

Supervisor

Jernigan,

Plant General

Manager

Johnson,

Operations

Manager

Jones,

Acting Operations

Supervisor

Jurmain,

Electrical Maintenance

Supervisor

Kaminskas,

Services

Hanager

Kirkpatrick, Fire Protection,

EP, Safety Supervisor

Knorr, Regulatory

Compliance Analyst

Kuhn, Procurement

Engineering

Supervisor

'acal,

Training Manager

Lindsay, Health Physics

Supervisor

Luke, Site Engineering

Manager

ons,

NSSS Engineer Supervisor

Marcussen,,Security

Supervisor

Marshall,

Human Resources

Manager

Miller, Acting Projects

Supervisor

Howrey, Regulatory

Compliance Analyst

Paduano,

Manager,

Licensing

and Special

Projects

0

30

M.

K.

T.

K.

• R.

C.

• A.

R.

E.

D.

B.

G.

• R

0.

Pearce,

Projects

Supervisor

W. Petersen,

Site Superintendent

F. Plunkett,

President,

Nuclear Division

L. Remington,

System

Performance

Supervisor

E.

Rose,

Nuclear Materials

Manager

V. Rossi,

gA and Assessments

Supervisor

M. Singer,

Operations

Supervisor,

Acting Operations

Hanager

N. Steinke,

Chemistry Supervisor

A. Thompson,

Project Engineer

J.

Tomaszewski,

Component Specialist

Supervisor

C. Waldrep,

Mechanical

Maintenance

Supervisor

A. Warriner, guality Surveillance

Supervisor

West,

Technical

Engineer

Other licensee

employees

contacted

included construction

craftsmen,

engineers,

technicians,

operators,

mechanics,

and

electricians.

NRC Resident

Inspectors

B.

B. Desai,

Resident

Inspector

• T.

P. Johnson,

Senior Resident

Inspector

Attended exit interview

Partial List of Opened,

Closed,

and Discussed

Items

Item Number

Status

Descri tion

and Reference

50-250,251/96-04-01

(Open) IFI, Charging

Pump

Response

During SI

(section

03. 1)

50-250,251/96-04-02

(Open)

VIO, Failure to Follow CVCS Procedure

(section 04.1)

50-250,251/96-04-03

(Closed)

NCV, Failure to Perform

an Adequate

Safety Evaluation (section

E2.2)

50-250,251/96-04-04

(Closed)

NCV, Contaminated

Flashlight

Found

Outside the

RCA (section

R1.2)

Additionally, the following previous

item was discussed:

Item Number

Status

Descri tion

and Reference

50-250,251/94-11-01

(Closed)

Core Exit Thermocouple

Status

and

Technical Specifications

(section

08. 1)

31

List of Acronyms

and Abbreviations

AC

ADH

AFW

ALARA

a.m.

amp

ANPO

ANPS

ANSI

ARB

ARP

ASHE

BIT

BOP

B&PV

BWR

CCW

CDF

CET

CFR

CHI

CNRB

cpm

cPs

CR

CROM

Cr-Mo

CS

CTRAC

CV

CVCS

dpm

DPR

DRP

DRS

ECC

ECCS

EDG

e.g.

ENS

EOP

EP

ERT

ESF

oF

F

FAC

FC

FCV

FFD

Alternating Current

Administrative (Procedure)

Auxiliary Feedwater

As

Low As Reasonably

Achievable

Ante Meridiem

Ampere

Associate

Nuclear Plant Operator

Assistant

Nuclear Plant Supervisor

American National

Standards

Institute

Alara Review Board

Annunciator Response

Procedure

American Society of Mechanical

Engineers

Boron Injection Tank

Balance of Plant

Boiler & Pressure

Vessel

Boiling Water Reactor

Component

Cooling Water

Core

Damage

Frequency

Core Exit Thermocouple

Code of Federal

Regulations

Corrective Maintenance - I&C

Company Nuclear Review Board

Counts

Per Minute

Counts

Per Second

Condition Report

Control

Rod Drive Mechanism

Chromium-Molybdenum

Containment

Spray

Commitment Tracking

Control Valve

Chemical

Volume Control

System

Disintegr ations

Per Minute

Power Reactor

License

Division of Reactor Projects

Division of Reactor Safety

Emergency

Containment

Cooler

Emergency

Core Cooling System

Emergency

Diesel

Generator

for Example

Emergency Notification System

Emergency Operating

Procedure

Emergency

Preparedness

Event Response

Team

Engineered

Safeguards

Feature

Degrees

Fahrenheit

Fuse

Flow Accelerated

Corrosion

Flow Controller

Flow Control Valve

Fitness

For Duty

FHP

FL

FHE

FPL

FSAR

FT

FW

GHE

GHI

GOP

gpm

HHSI

HP

IA

I&C

ICW

i.e.

IFI

I/P

ISI

ITOP

JPN

JPNS

K

KV

L

ibm(s)

LC

LCV

LER

LOCA

LOOP

LPDR

HOV

MOVATS

HS

HSIV

Mwe

NCV

NDE

NI

NIS

NP

NPS

NRC

NRR

NSSS

ONOP

00S

OP

OSP

32

Florida Highway Patrol

Florida

Foreign Material Exclusion

Florida Power

and Light

Final Safety Analysis Report

Flow Transmitter

Feed

Water

General

Maintenance - Electrical

General

Haintenance

- I&C

General

Operating

Procedure

Gallons

Per Minute

High Head Safety Injection

Health Physics

Instrument Air

Instrumentation

and Control

Intake Cooling Water

That Is

Inspector

Followup Item

Current/Pressure

Inservice Inspection

Implementor Turnover Package

Juno Project Nuclear (Nuclear Engineering)

Juno Project Nuclear Safety

Kilo (1000)

Kilovolt

Letter (licensing)

pounds

mass

Level Controller

Level Control Valve

Licensee

Event Report

Loss-of-Coolant Accident

Loss of Off-Site Power

Local

PDR

milli

Motor-Operated

Valve

HOV Acceptance

Testing

System

Hain Steam

Hain Steam Isolation Valve

Megawatts Electric

Non-Cited Violation

Nondestructive

Examination

Nuclear Instrument

Nuclear Instrumentation

System

Nuclear Policy

'uclear Plant Supervisor

Nuclear Regulatory

Commission

Office of Nuclear Reactor Regulation

Nuclear

Steam Supply System

Off-Normal Operating

Procedure

Out-of-Service

Operating

Procedure

Operations

Surveillance

Procedure

PCI

PC/H

PCV

POR

p.m,

PH

PMAI

PHI

PMT

PNSC

ppm

PSA

Pslg

PTN

PWO

PWR

QA'C

RCA

RCCA

RCO

RCP

RCS

rem

REA

RHR

RO

RPI

RPS

RT

RWO

RWP

RWST

SATS

SEEJ

S/G

SI

SGFP

SMH

SRO

STA

)vg

TPCW

, TV

TSA

UFSAR

V

VAC

VCT

VIO

WO 33

Contractor

Plant Change/Modification

Pressure

Control Valve

Public Oocument

Room

Post Meridiem

Preventive

Haintenance

Plant Manager Action Item

Preventive

Maintenance

I8C

Post-Maintenance

Test

Plant Nuclear Safety Committee

Parts

Per Million

Probabilistic Safety Assessment

Pounds

Per Square

Inch Gauge

Project Turkey Nuclear

Plant

Work Order

Pressurized

Water Reactor

Quality Assurance

Quality Control

Radiation Control Area

Rod Control Cluster Assembly

Reactor Control Operator

Reactor Coolant

Pump

Reactor Coolant System

Roentgen

Equivalent

Han

Request for Engineering Assistance

Residual

Heat

Removal

Reactor Operator

Rod Position Indicator

Reactor Protection

System

Radiographic

Examination

Relay Work Order

Radiation

Work Permit

Refueling Water Storage

Tank

System Acceptance

Turnover Sheet

Safety Evaluation Electrical - Juno

Steam Generator

Safety Injection

S/G Feedwater

Pump

Surveillance

Maintenance

Mechanical

Senior Reactor Operator

Shift Technical

Advisor

average

coolant temperature

Temporary Procedure

Turbine Plant Cooling Water

Television

Temporary

System Alteration

Updated Final Safety Analysis Report

Volt

Volt AC

Volume Control

Tank

Violation

Work Order

4I