Text

Insp Repts 50-250/93-24 & 50-251/93-24 on 930926-1030. Violations Noted.Major Areas Inspected:Surveillance Observations,Maintenance Observations,Engineered Safety Features Walkdowns & Plant Events
	ML17352A329
Person / Time
Site:	Turkey Point
Issue date:	11/19/1993
From:	Binoy Desai, Johnson T, Trocine L; NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION II)
To:	;
Shared Package
ML17352A326	List: ML17352A325; ML17352A328; ML17352A329;
References
	50-250-93-24, 50-251-93-24, NUDOCS 9312140305
	Download: ML17352A329 (50)
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UNITED STAVES

NUCLEAR REGULATORY COMMISSlON

REGION II

101 MARIEriASTREET, N.W., SUITE 2900

ATLANTA,GEORGIA 30m-0199

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++*++

Report Nos.:

50-250/93-24

and 50-251/93-24

Licensee:

Florida Power

and Light Company

9250 West Flagler Street

Miami, FL

33102

Inspection

Conducted:

September

26 through October 30,

1993

Docket Nos.:

50-250

and 50-251

License Nos.:

DPR-31

and

DPR-41

Facility Name:

Turkey Point Units 3 and

4

Inspectors:

~

OA

0

T.

P.

Johnson

Senior Resident

Inspector

B.

B. Desai,

sident Inspector

Q. f'.

L. Trocine,

Res'dent

Inspector

pppppypd

by.

NV

K. D. Landis, Chief

Reactor Projects

Section

2B

Division of Reactor Projects

It

g

Date Signed

'l3'ate

Signed

Date Si

ned

)l 1q qg

Date Signed

Scope:

SUMMARY

This routine resident

inspection

involved direct inspection at the site

and at

the licensee's

Juno

Beach office in the areas of surveillance

observations,

maintenance

observations,

engineered

safety features

walkdowns, operational

safety,

plant events,

and management

meetings.

Backshift inspections

were

performed in accordance

with NRC policy.

Results:

Within the scope of this inspection,

the inspectors

determined that the

licensee generally demonstrated

satisfactory

performance

to ensure

safe plant

operations.

A violation of operating

and administrative

procedure

was

identified.

A reactor control operator failed to properly monitor

and log

a

reactivity addition evolution.

In addition, the licensee,

through self

assessment,

took prompt action to correct

a non-cited violation involving

lifting the wrong electrical

leads

and related

independent verification

failure by Instrumentation

and Control technicians.

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PDR

ADOC<

8

This inspection resulted

in the following findings:

Non-Cited Violation 50-250,251/93-24-01,

Wrong Leads Lifted/Independent

Verification Failure (section 7.2.4).

Violation 50-250,251/93-24-02,

Inadvertent Dilution Event (section

9.2.6).

During this inspection period,

the inspectors

had

comments

in the following

Systematic

Assessment

of Licensee

Performance

functional areas:

Plant

0 erations

An unresolved

item regarding operator

rounds

and falsification of

records

was elevated to

a violation with no severity level

and was

closed

(section 4.2.2),

The licensee's

actions with regard to the Unit

3 reactor trip signal while subcritical

and during pressurizer

manway

repair were conservative

and appropri ate (sections

3. 1, 6.2. 1, 7.2. 1,

9.2. 1,

and 10.2.3).

The Unit 3 short notice outage

was well planned,

and the subsequent

unit startup activities were conducted

in

a

professional

manner (section 9.2.3).

The auxiliary feedwater

and safety

injection systems

were appropriately aligned for automatic actuations

(section 8.2. 1).

However,

a weakness

was noted in that the auxiliary

feedwater

pump was not declared

inoperable

during the time that the oil

filter rig was aligned to the oil tank (section 7.2.5).

Shift turnover

meetings

and relief activities were effective in communicating

information and plant status to the oncoming operating

crews.

However,

minor weaknesses

were noted relative to the professional

conduct of the

meetings

(section 9.2.2).

The control of operator aids

and information

related documentation.

The

inspector also reviewed the licensee's

root cause failure analysis

and related corrective actions.

The licensee

concluded that there were three likely root causes:

(1) excessive

gasket

crush

due to a recent

change

in the vendor

recommendations,

(2) interference

between the insert retaining

screws

and the

manway cover due to the existing small clearances

which may have

impeded gasket loading,

and

(3) potential

gasket

damage during installation of gasket

in 1991.

The licensee

was

unable to conclude which root cause

was the most probable.

However,

the licensee

implemented corrective actions to ensure

that all root causes

would be appropriately

addressed.

The inspector

reviewed the licensee

root causes

and related

corrective actions,

Selected

corrective actions

were verified to

be implemented.

The inspector

concluded that licensee repair

and

replacement activities for the pressurizer

manway leak were

appropriate

and were effectively coordinated.

In addition,

the

inspector

noted strong engineering

support for these repair

activities.

7.2.2

Leak Sealant

Practices

at Turkey Point

" The inspector

assessed

the licensee's

policy and procedures

concerning the use of leak sealants

on both safety-related

and

non-safety-related

components.

Administrative procedure

O-ADH-723, On-Line Temporary

Leak Repairs

(revised

June

3,

1993),

and vendor procedures

N-93213

and N-92528 associated

with two leak

11

repairs that

had

been

performed earlier were also reviewed.

In

addition, this issue

was discussed

with plant staff including

engineers,

planners,

and Furmanite technicians.

A list of all

leak sealant

repairs

performed in the past three years

was also

reviewed.

The following observations

were noted

by the inspector:

Turkey Point has

used

Furmanite

as

a temporary

method to

repair leaks

on both safety-related

as well

as

non-safety-related

components.

There are two Furmanite

technicians

permanently located at the site.

Approximately

200 leaks

have

been

sealed

since

1991 using Furmanite,

predominantly

on non-safety related

components.

In

accordance

with Generic Letter No. 90-05,

the licensee

does

not perform temporary

non-code repairs

using Furmanite

without prior NRC,approval.

The procedure for a maintenance

job involving leak repair

using Furmanite,

including supporting calculations

and

limits on the

amount of sealant

to be injected,

was

developed

by Furmanite.

This procedure

was reviewed

and

approved

by Turkey Point Engineering in ,the event the

components

involved are safety-related.

Engineering

then

provided

an evaluation

associated

with the job as well as

specifies

the type and

maximum amount of compound

used.

Additionally, the

PNSC

as well

as

gC reviewed work packages

associated

with safety-related

jobs.

A

PWO for a permanent

repair or replacement

of the component

was simultaneously

written with the

PWO associated

with the Furmanite job.

Based

on the list of Furmanite jobs that have

been

performed

since

1991, the inspector

noted that

a permanent

repair was

not always performed during the next available opportunity

such

as

a refueling outage.

All safety-related

repairs

were

performed.

The inspectors

concluded that the procedure

as well as controls

imposed

on the process

were adequate.

7.2.3

Unit 4 4A Steam Generator

Feedwater

Pump Discharge

Check Valve

Repair

Inspection of the

4A steam generator

feedwater

pump discharge

check valve (valve 4-20-118)

on October

13,

1993,

per

an action

item in Condition Report

No.93-777 confirmed that

one of two disc

pins

and its retaining

screw were missing.

These

pieces

had

previously been

found inside the

6A feedwater heater during

investigations of reported noises.

(Refer to section 8.2. 1 of NRC

Inspection

Report

No. 50-250,251/93-22

for additional

information.)

The licensee

also found

a 1/16-inch

deep

gouge

on

both the valve bonnet

and seal ring which was caused

by an

embedded

piece of wire.

12

The licensee attributed the root cause of the disc pin of valve 4-

20-118 vibrating loose to be improper retaining screw tack welds.

Normally, two tack welds are provided

(one at each side) to stop

the rotation of the retaining screw.

However,

the welds

on this

failed valve provided

an inadequate

stop in that they were too

short

and sloped

away from the retaining pin.

Although there were

design requirements

for the number of tack welds

(2)

and the

maximum gap

between

the weld and the

head of the retaining

screw

(1/16 inch),

no drawing or procedure

defined the minimum size of

the welds themselves.

As

a result,

a vendor (Crane-Aloyco)

representative

recommended

a minimum height of 1/8 inch and

a

length of approximately

1/2 inch.

In, addition, it was also

identified that the installed disc did not incorporate

machined

flats at the retaining

screw locations

in order to facilitate

installation of the tack welds.

The use of machined flats is the

current Crane-Aloyco practice

as demonstrated

by the replacement

disc assemblies

stocked

at Turkey Point.

Inspection results of the remaining unaffected

and disc sleeve

verified no damage or distortion due to the extended

operating

period coupled with flutter of the disc during

pump operation.

Inspection of the 48 steam generator

discharge

check valve (valve

4-20-218)

on October

13,

1993,

also verified that

no failure had

occurred

and that the retaining screw tack welds in this valve

were adequate

to stop rotation of the retaining screws.

The licensee

documented this information in Condition Report

No.93-891,

and prior to returning valve 4-20-118 to service,

the

licensee

completed the following corrective actions:

The seating

surface of the valve bonnet

was machined in

accordance

with specific criteria,

and the vendor inspected

the completed

bonnet prior to installation.

The inspection results of the east

side disc pin and disc

sleeve

were documented

in Condition Report

No.93-891.

OTSC No.93-619

was generated

to incorporate

the revised

tack weld requirements

and to extend cleanliness

controls

through

assembly of the bonnet/pressure

seal.

In addition to these actions,

the licensee

plans to issue

a

drawing change

request

(DCR-TPN-93-479)

by October

28,

1993, in

order to incorporate

the detailed tack weld requirements

into

drawing No. 5610-H-60D-7,

Sheet

1.

The inspector witnessed

portions of the licensee's

maintenance

activities

and reviewed Condition Report

No.93-891.

The

inspectors

also verified that the changes

made

by OTSC No.93-619

met the intent of the corrective

actions specified in the

condition report.

The licensee's

efforts with regard to this

check valve repair

were both efficient and effective.

13

7.2.4

Unit 3 HSIV Troubleshooting

On October

18,

1993, during troubleshooting of a potential

DC

ground

on

a solenoid valve associated

with the

3B NSIV, leads

associated

with the

C MSIV were inadvertently lifted.

At the time

of the event,

Unit 3 was in Node

2 with the

B HSIV closed for

troubleshooting

associated

with the ground.

The

A and

C HSIVs

were open.

Inadvertent lifting of the leads

associated

with the

C

HSIVs made the

C HSIV inoperable

from the alternate

shutdown

panel.

Troubleshooting for the ground including meggering

was being

conducted

in accordance

with procedure

0-GHI-102. 1,

Troubleshooting

and Repair Guidelines.

An inspection

plan with

specifics

was also developed

by component

engineering

as

a

reference for the

I&C technicians.

The job involved initially identifying the terminal points for the

leads to be lifted and noting them on the lifted lead data sheet.

This data sheet

was then to be used to document the appropriate

lifting and landing of the leads.

The task associated

with the

identification, lifting, and landing of the leads

was required to

be independently verified in accordance

with procedure

O-ADN-031,

Independent Verification, and procedure

0-GNI-102. 1.

During the identification of the terminal points for lifting the

leads,

a cable'tag

was misread,

and two terminal points associated

with the misread

cable

were documented

in the lifting and landing

data sheet.

The leads identified to be lifted were for the

3C

HSIV as

opposed to the

3B HSIV.

This identification was performed

by an

I&C technician

and independently verified by his job

supervisor.

The leads identified on the data sheet

were then correctly lifted

and independently verified.

The lifted leads

were for the

C HSIV

versus for the

B HSIV.

The leads

were relanded following completion of troubleshooting.

The

C HSIV was degraded

from approximately

11:00 p.m. until 11:30

p.m.

on October

18,

1993.

The fact that wrong leads

had

been

lifted was realized later during

a conversation of the activities

performed

between

I&C and engineering

at 1:45 a.m.

on October

19,

1993.

The control

room was notified of the occurrence.

With the

B HSIV

de-energized

closed

and the

C MSIV in degraded

mode,

TS 3.0.3

was

initially entered.

After further review, the licensee

retracted

this entry as the

B HSIV was closed,

which is the safe position

for the valve.

The inspector

concluded that the licensee

appropriately

determined that

TS 3.0.3

was not applicable.

The

C

NSIV was tested satisfactorily,

and returned to service at 2:25

a.m.

on October

19,

1993.

14

The inspectors

discussed

this event with the

I&C supervisor.

Both

individuals involved in the job were counselled

by the

IKC

supervisor.

Additionally, the licensee

pl'ans to discuss this

event with all field supervisors

as well as

ILC technicians.

Because

the criteria in Section VII.B of the

NRC Enforcement

Policy were met, this failure to identify and lift the correct

leads

and to implement the independent verification procedure

is

identified as

a licensee-identified

NCV.

This item will be

tracked

as

NCV 50-250,251/93-24-01,

Wrong Leads Lifted/Independent

Verification Failure.

7.2.5

AFW Pump Inspection

The licensee installed

a portable oil cleaning rig on the

AFW oil

tanks without declaring the

AFW pump(s)

inoperable.

A temporary

hose

was dipped into the oil tank, routed through the filter, and

returned

back to the tank.

The inspector

noted that though

appropriate

precautions

were taken,

the

AFW pump(s)

should

have

been declared technically inoperable during the time that the rig

was aligned to the tank.

This issue

was discussed

with plant

management,

and the Plant General

Manager

was in concurrence.

The

inspectors

concluded that the

pump would have functioned in this

condition.

This issue

was identified by the inspector during the

system

walkdown discussed

in section 8.0.

The inspector

considered

not calling the

pump inoperable during the time that

the oil rig was installed

a weakness.

8.0

Engineered

Safety Features

Walkdown (71710)

8.1

Inspection

Scope

The inspectors

performed

an inspection

designed

to verify the

status of the

HHSI and

AFW systems.

This was accomplished

by

performing

a complete

walkdown of all accessible

equipment.

The

following criteria were used,

as appropriate,

during this

inspection:

systems

lineup procedures

matched plant drawings

and as-

built configuration;

housekeeping

was adequate,

and appropriate levels of

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;

15

valves in the flow paths

were in correct position

as

required

by the applicable

procedures

with power available,

and valves were locked/lock wired as required;

local

and remote position indication was

compared,

and

remote instrumentation

was functional;

and

8.2

8.2.1

major system

components

were properly labeled.

Inspection

Findings

HHSI and

AFW System

Walkdowns

The inspectors

walked down the Unit 3 and

4 HHSI systems

and the

common

AFW system.

Minor deficiencies

were discussed

with the

appropriate

engineering,

maintenance,

and operations

personnel.

The inspectors

concluded that the

HHSI and

AFW systems

were

appropriately aligned for the standby/automatic

condition.

Several

questions

concerning

accuracy of PKIDs, adequacy of

installed hangers,

and vulnerability of a

common

mode failure of

the

AFW system following a main steam line rupture

wer e raised

by

the inspectors.

Engineering

response

to these

questions

was

thorough

and aggressive.

Operational

Safety Verification (71707)

9.1

Inspection

Scope

The inspectors

observed

control

room operations,

reviewed

applicable

logs,

conducted

discussions

with control

room

operators,

observed shift turnovers,

and monitored

instrumentation.

The inspectors verified proper valve/switch

alignment of selected

emergency

systems,

verified maintenance

work

orders

had

been submitted

as required,

and verified followup and

prioritization of work was accomplished.

The inspectors

reviewed

tagout records,

verified compliance with TS LCOs,

and verified the

return to service of affected

components.

By observation

and direct interviews, verification was

made that

the physical security

and emergency

plans

were being implemented.

The implementation of radiological controls

and plant

housekeeping/cleanliness

conditions

were also observed.

Tours of the intake structure

and diesel, auxiliary, control,

and

turbine buildings were conducted to observe plant equipment

conditions including potential fire hazards,

fluid leaks,

and

excessive

vibrations.

The inspectors

walked

down accessible

portions of the selected

safety-related

systems/structures

to verify proper valve/switch

alignment.

16

9.2

9.2.1

Inspection

Findings

Unit 3 Containment

Entries

The inspectors

made

two Unit 3 containment entries during the

inspection period.

The first occurred

on September

30,

1993, with

the unit at full power.

The second entry occurred

on October 6,

1993, with the unit shut

down in Node

3 (Hot Standby)

at rated

temperature

and pressure.

The entry at power was

made to inspect the containment

due to the

high

RCS leak rate.

(Refer to section 6.2. 1 for additional

information.)

The licensee

assembled

several

inspection

teams

with personnel

from HP, operations,

engineering,

security,

and

safety.

Plant

management

personnel

were also involved.

The

entries

were performed in accordance

with procedure

O-ADM-009,

Containment Entries

When Containment Integrity Is Established.

The inspector

attended

the pre-entry briefing and reviewed the

associated

RWP.

The inspector verified that entry precautions

and

requirements

were met.

These

included

RWP review, heat stress

precautions,

confined

space

entry requirements,

security

and

safety coverage,

neutron

and

gamma

dose monitoring, radioactivity

airborne monitoring,

and containment integrity precautions.

During the entry,

a leak from the pressurizer

steam

space

manway

was identified.

Licensee

actions

are detailed in section 7.2. 1 of

this report.

The inspector

concluded that management

responded

conservatively

and appropriately to the identified leak.

Further,

the entry was

professionally

conducted

and management

oversight

was effective in

assuring

a safe at-power containment entry.

The second entry was

made

by the inspector to independently verify

containment conditions prior to restart

from the Unit 3 outage.

.(Refer to section 9.2.3 for additional information.)

The

inspector

performed the entry per procedure

0-ADN-009.

Items

checked

included

RCS leakage,

housekeeping,

material conditions,

cleanliness,

equipment status,

and radiological conditions.

The

inspector

concluded that the containment condition and related

safety equipment

was appropriate to support Unit 3 restart.

17

9.2.2

9.2,3

Operations

Shift Turnover/Relief

The inspectors

reviewed the control

room shift turnover procedures

and practices.

Administrative procedures

O-ADH-200, Conduct of

Operations,

and

O-ADM-202, Shift Relief and Turnover, delineate

the licensee's

requirements for these activities.

The inspectors

reviewed the procedures

and verified implementation during

numerous shift turnover periods

on various shifts

and operating

crews.

The inspectors

noted that the turnover activity included

a

shift briefing by the

NPS,

ANPS,

and

NWE.

The inspectors

found

these briefings to be very informative,

and supervision

discussed

equipment

problems,

special

conditions,

and shift priorities.

Further,

maintenance

personnel

also attended

these

meetings

to

discuss

work priorities.

However, the inspectors

made the following observations

while

attending

these

meetings:

individuals'would at times sit on

panels

and desks;

hard hats

were either worn in the control

areas

or were rested

on control panels;

eating, drinking,

and tobacco

chewing occurred;

and drinks were rested

on control

room panels.

Although these activities did not degrade

the effectiveness

and

thoroughness

of turnover briefing information, the inspectors

stated that these

issues

could have

a negative

impact.

The

inspectors

discussed

these

issues with operations

and plant

management

personnel.

Operations

night orders

were issued

addressing

these

items

and discussions

were held at turnover

meetings.

The inspectors

noted the licensee to be very responsive

to these

concerns,

and

no further problems

were noted during the

rest of the inspection period.

Unit 3 Outage

and Restart

On September

30,

1993, Unit 3 began

a

SNO to repair the

pressurizer

manway leak.

(Refer to sections

3. 1, 6.2. 1,

and 7.2. 1

for additional information.)

Additional work items

and

surveillance testing activities were scheduled

and performed

during the outage.

The inspectors

reviewed the licensee's

SNO schedule,

attended

periodic turnover

and status

meetings,

discussed

the outage

progress

and issues with the shift managers

and other personnel,

and observed

work and test activities.

The inspectors

concluded

that the licensee

demonstrated

conservatism

in beginning

an outage

prior to exceeding

the

TS

RCS unidentified leakage limit.

Further,,

the inspectors

concluded that the outage

was well planned

and controlled

and that the shift outage

managers

were effective

in providing oversight

and control of all outage-related.

activities.

~

9.2.4

18

The inspectors

monitored portions of the October

5,

1993, Unit 3

restart.

Activities and evaluations

were performed effectively

and in accordance

with procedures.

Control

Room Information Tags

The inspector

reviewed the licensee's

program

and procedures

for

displaying control

room panel

information such

as operator

aids

and temporary information tags.

Administrative procedure

AP-

0103.36,

Control of Operator Aids and Temporary Information Tags,

delineates

the requirements

for posting, controlling,

and removing

such information.

9.2.5

The inspector walked

down the control boards

checking for operator

aids

and information tags,

reviewed the index for these tags,

and

discussed

this issue with licensed

operators

and management

personnel.

The inspector

noted that

a number of temporary

information tags

had

been in existence

since

1988.

The licensee's

procedure

states

that the need for a permanent

tag should

be

considered after six months.

The licensee

stated that it would

review this issue.

Further,

the inspector

noted that

some control

room board deficiencies

were identified with both

an information

fag and

a green sticker (indicating that

a

PWO was open).

This

appeared

to be duplication,

and the licensee

agreed.

The inspector

concluded that the licensee's

program generally

met

the intent of procedure

AP-0103.36

and that the licensed

operators

were knowledgeable

regarding displayed control board information.

However, minor weaknesses

were identified in the program.

The

licensee

was responsive

to these

weaknesses,

and at the close of

the period,

the licensee

was correcting long-standing

items.

FTS-2000

Out of Service

On October 7,

1993, it was discovered that the FTS-2000

ENS phones

were inoperable.

After an investigation

by the licensee, it was

determined that the problem was outside the scope of the direct

control of the licensee.

The

NRC was notified and following

troubleshooting

and maintenance

performed

by ATILT, the

FTS-2000

phones

were returned to service

on October

12,

1993.

The problem

was attributed to

a short in

a switching power supply located at

the nearby fossil plant.

This is the second

time in the past

two months that the

FTS-2000

phones

have

become

inoperable.

The inspectors will continue to

monitor issues

associated

with the

FTS-2000

phone

system to

determine if any additional

action

on both licensee's

or NRC's

part is warranted to increase

the reliability of the

FTS-2000

system.

19

9.2.6

Inadvertent Dilution Event

on Unit 3

On October

22,

1993 (Friday night) at approximately 9: 10 p.m., the

licensee

discovered that

an inadvertent dilution had occurred

on

Unit 3.

Reactor

power,

as

seen

on the analog

average of the four

power range NIs,

had increased

to approximately

102.89%,

and Tavg

had increased

from 574.0'F to 576.5'F.

Upon discovery,

a boration

was immediately initiated,

and control rods were inserted to

restore

power to below

100% and to lower Tavg to within the normal

operating

band.

Unit 3 was above

102% indicated

NI power for

approximately

10 minutes.

The problem was recognized

when the

annunciator for the overpower rod stop

was received

as

a result of

indicated

NI greater

than the setpoint of approximately

102.7%.

This event

began after

a satisfactory

completion of a 4-hour

RCS

leak rate,

the Unit 3

RCO diluted the

RCS to raise

Tavg to bring

it closer to Tref.

The intention was to add

100 gallons of

primary water (boron free) to the

RCS to compensate

for core

burnup.

The unit was in the middle of core life with the boron

concentration of approximately

424

ppm.

The dilution process

involves taking suction from the primary

water storage

tank via the primary water transfer

pump through the

batch totalizer to the

VCT.

The amount of primary water to be

added to the

RCS is set

on the totalizer.

The. charging

pump,

which takes

suction from the

VCT, then

pumps the primary water

into the

RCS through its normal injection path.

When the volume

of injected primary water equals that set

on the totalizer, the

primary water addition is terminated

by the automatic closure of

two flow control valves.

Injection of primary water via the

VCT

ensures

a gradual dilution as it mixes with water from normal

letdown.

The procedural

steps

to perform this evolution are outlined in

section 5.3 of procedure

O-OP-046,

CVCS-Boron Concentration

Control.

Since this is

a routine

and frequent evolution,

operators

do not normally have the procedure

open while performing

the dilution steps.

This is normal

and is considered

to be within

'heir expected

knowledge/performance

level.

Additionally, the

procedure

does not require

any signoffs.

The operator,

instead of entering

100 gallons in the digital

totalizer,

entered

1,000 gallons

and initiated the dilution.

The

operator then got distracted

from the ongoing dilution due to

involvement in a liquid release

that

had

been initiated earlier.

Normally, the

100 gallon addition takes

approximately

2 to 3

.minutes.

With the totalizer set at 1,000 gallons, this dilution

lasted for approximately

20 minutes.

Step 5.3.2.9 of procedure

0-OP-046 requires

the operator to observe

changes

in Tavg and stop

dilution if Tavg increases

greater

than 1.5'F above Tref.

However, this was not done,

and Tavg went

as high as 2.6'F

above

Tref.

~

20

Additionally, indicated

NI power increased

to above

102%.

With

Tavg greater

than Tref, inward control rod motion initiated to

bring Tavg closer to Tref.

Also, with indicated

NI power at

approximately

102.7%,

annunciator 8-6/3,

Over Power

Rod Stop,

was

received.

Presumably,

this alerted the operator of the ongoing

dilution.

A boration

was initiated and control rods were inserted

to restore

power to below

100% and Tavg to within the normal

operating

band.

The Acting Operations

Manager

was notified of

this event.

A decision

was

made to take the involved

RCO off

shift,

and

he was later disciplined.

The Plant General

Manager

became

aware of the event later

on that

night when

he called the control

room to get the plant status.

The resident

inspectors

and the Site Vice President

became

aware

of the event the following Monday (October 25,

1993).

i'pon

becoming

aware of the event,

the resident

inspectors

reviewed

reportability and concluded that

no notifications were required.

The TSs

and

FSAR were also reviewed with respect to the dilution

event.

The inspectors

determined that although reactor

power of

100% was briefly exceeded,

the event

was

bound

by the accident

analysis for inadvertent dilution described

in the

FSAR and that

sufficient margin existed for DNB and fuel cladding protection.

It should also

be noted that without any operator action,

the

event would have

been terminated either

by automatic

inward rod

motion or by the

OPGT,

OTBT, or the NI high flux automatic reactor trips.

A calorimetric

and

a reactivity balance

were later

performed

by reactor engineering.

They determined that

as

a

result of the reduction in density

and boron concentration

in the

RCS, the indicated

NIs were reading conservatively

high during the

dilution event.

Based

on the calculation,

actual

reactor

power

did not exceed

approximately

101.4%.

The inspectors

reviewed the

licensee's

determination,

and concluded it to be appropriate.

Notwithstanding the above,

the inspectors

are concerned

about this

overdilution event

because it brought to light a problem in the

area of conduct of operations.

This included failure to monitor

key parameters

during

a reactivity change

as reqdired

by procedure

0-0P-046, failure to log reactivity changes

in the

RCO log book in

accordance

with procedure

O-ADM-204, Operations

Narrative

Log

Books,

and the potential

impact of just having one operator in the

control

room.

Additionally, the inspectors

believe that not

having

an audible counter

when the totalizer is in service

also

contributed to the operator not noticing the overdilution event.

This failure to follow the requirements

of procedures

0-OP-046

and

0-ADM-204 will be classified

as

VIO 50-250,251/93-24-02,

Inadvertent Overdilution.

The inspectors

discussed

this event at length with senior plant

management

including the Site Vice President

and Plant General

Manager.

They are in concurrence

with the inspectors'oncerns.

21

The inspectors will continue to monitor licensee

performance

in

this area.

9.2.7

9.2.8

Emergency

Plan Drill

The inspector

observed portions of an

announced

emergency

plan

drill on October 27,

1993.

The inspector

concluded that drill

performance

was satisfactory.

Further,

the licensee

was effective

during drill conduct

and critique activities.

General

Results

As

a result of routine plant tours

and various operational

observations,

the inspectors

determined that the general

plant and

system material conditions were satisfactorily maintained,

the

plant security program was effective,

and the overall

performance

of plant operations

was generally satisfactory.

10.0

Plant Events

(93702)

10.1

10.2

10.2.1

Inspection

Scope

The following plant events

were reviewed to determine facility

status

and the need for further followup action.

Plant parameters

were evaluated

during transient

response.

The significance of the

event

was evaluated

along with the performance of the appropriate

safety

systems

and the actions

taken

by the licensee.

The

inspectors verified that required notifications were

made to the

NRC.

Evaluations

were performed relative to the

need for

additional

NRC response

to the event.

Additionally, the following

issues

were examined,

as appropriate:

details regarding

the cause

of the event;

event chronology; safety

system performance;

licensee

compliance with approved

procedures;

radiological

consequences, if any;

and proposed corrective actions.

Inspection

Findings

Personnel

Contamination

Events

During the Unit 3

SNO (Refer to section 9.2.3 for additional

information.),

two events

occurred which resulted

in personnel

skin and clothing contamination.

These

both occurred

on October

, 5,

1993.

The first event occurred in the pipe

and valve room

during

RHR system valve local leak rate testing equipment

restoration.

IKC personnel

were disconnecting

a test rig.

During

the removal process,

residual

pressure

in the lines sprayed

onto

one technician

causing

skin and clothing contamination

and also

causing floor and

shoe contamination

on four other individuals.

The second

event occurred inside containment

in the cavity area

where personnel

were disconnecting

a spool

piece associated

with

the pressurizer

manway repair work.

Residual

pressure

and water

in the line resulted

in the area

being sprayed.

No skin

22

contaminations

occurred;

however,

the two individuals received

clothing contaminations

probably during protective clothing

removal.

The licensee

reviewed

each

event

by initiating condition reports,

radiological investigation reports,

and contamination reports.

The individual with facial skin contamination

(10,000

dpm)

was

successfully

deconned,

and

a whole body count did not identify any

internal contamination.

The remaining individuals'lothing were

either deconned

or disposed of as radioactive waste.

The licensee

also performed skin dose

assessments

for the affected individuals.

Due to low levels of contamination

and the short time for

exposure,

no dose

was required to be assigned.

Further,

the licensee

conducted

a post-event critique meeting

on

October 6,

1993.

HP, operations,

engineering,

maintenance,

and

management

personnel

attended.

Causal

factors included poor

communication

among the workers,

weak procedural

controls,

and

a

lack of attention to detail.

Corrective actions

included

procedure

and equipment

enhancements,

discussion of the events

at

various site meetings,

modifications to training programs,

review

of the event at the

ALARA review committee,

and changes

to

protective clothing requirements

during future similar jobs.

Further,

the personnel

involved were deconned,

and the affected

contaminated

areas

outside containment

were cleaned

and released.

The inspector followed up on these

events

by reviewing the

associated

reports,

by attending

the event critique meeting,

and

by discussing

the events with HP management

personnel.

The

inspector

reviewed the root cause

determinations

and verified

selected

corrective actions.

The inspector

concluded that the

licensee

aggressively

and thoroughly followed up these

two

contamination

events partly caused

by a lack of attention to

detail

by workers

and

HP personnel.

Root cause

and corrective

action determination

appeared

to be appropriate.

10.2.2

Unit 3 Feedwater

Isolation Signal While in Mode 4

At 11:51 p.m.

on October 5,

1993, with Unit 3 in Mode 4,

a

feedwater isolation signal

was generated

on high level in the

B

steam generator.

The licensee

attributed this rise in steam

generator level to a leaking feedwater

bypass

valve (FCV-3-489)

after the

A standby

steam generator

feedwater

pump was started.

Operators

had started

the

A standby

steam generator

feedwater

pump

at approximately

11:35 p.m.

and subsequently

.noted

a rise in the

level of the

3B steam generator with the applicable

feedwater

regulating

bypass

valve (FCV-3-489)

demanded

and indicated closed.

Operators

attempted

to manually isolate the feedwater

bypass

valve, but the level in the

3B steam generator

continued to rise

due to valve leakby.

At ll:51 p.m.,

when the level in the

3B

steam generator

reached

80%,

a feedwater isolation signal

was

generated,

and blowdown was placed in service at approximately

23

midnight.

The 3B steam generator

level

peaked at

90% and

was then

brought into the normal operating

band.

The licensee notified the

NRC Operations

Center of a Significant

Event in accordance

with 10 CFR 50.72(b)(2)(ii),

ESF Actuation, at

1:53 a.m.

on October 6,

1993.

At 12:30 p.m.

on October 8,

1993,

the licensee

retracted this event notification on the basis that

the main feedwater

system is not required while the unit is in

Mode

4 (Hot Shutdown), that the system

was isolated at the time of

the

ESF actuation signal,

and that

no valve actuation

occurred

as

a result of the

ESF signal.

As

a result of this event,

the licensee

generated

Condition Report

No.93-860

and

an Operational

In-House

Event Preliminary

Investigation Report,

The licensee initiated

a root cause

review

and

implemented corrective actions.

The inspectors

reviewed the licensee's

Operational

In-House

Event

Preliminary Investigation Report

and Condition Report

No.93-860

and determined

the licensee's

corrective actions to be adequate.

However, the inspectors

noted

a weakness

in that it was not

recognized

by the involved operators

that the steam generator

level increase

could easily have

been terminated

by securing the

standby

steam generator

feedwater

pump which was feeding the steam

generators.

10.2.3

Unit 3 Reactor Trip While Subcritical

During the September

30,

1993, controlled plant shutdown to effect

repairs

on the leaking Unit 3 pressurizer

manway discussed

in

section 7.2. 1 of this report,

an automatic reactor trip occurred

at approximately

10:05 p.m.

Just prior to the trip, control rods

were being inserted

manually into the core.

When the reactor

power decreased

to below

1 x 10'mps

on the

IR detectors,

both

the

SR high voltage

power supplies

energized

as required.

SR

channel

N32 responded

normally.

However,

SR channel

N31 was

observed

to peg high at greater

than

1 x 10

counts

per second.

With N31 greater

than the reactor trip setpoint of

1 x 10'ounts

per second,

the one out of two coincidence logic for RPS actuation

was met,

and

an automatic reactor trip occurred.

Post-trip response

was normal with a few exceptions.

Notably, the

count rate for N31 remained

about

200 cps

above the

N32 count rate

following the trip.

Additionally, the green indication light on

MSIV POV-3-2604 did not come

on upon

MSIV closure.

WRs were

written to investigate

and repair the cause of the

SR instrument

failing high upon energization

and the

MSIV indication problem.

IKC performed troubleshooting

on the

SR detection

system

and

determined that the high voltage

power supply to N31 had failed.

Nominally the high voltage power supply, located in the source

24

range drawer in the control

room, provided

1800 volts

DC

excitation to the

SR detector.

During troubleshooting,

I&C

personnel

observed

the output voltage of the power supply spike to

approximately

2300 volts

DC.

The output voltage

was also noted to

be unstable

when the voltage adjustment

potentiometer

was

manipulated.

The cause for N31 count rate to be 200 cps

above

N32

following the trip was found to be due to the setting of the

gamma

discriminator bias.

It was concluded that the

gamma discriminator

bias did not contribute to the reactor trip.

The power supply to N31 was replaced.

Additionally, detector

cables

associated

with N31 were meggered with satisfactory

results.

The inspectors

observed

portions of the troubleshooting

associated

with the failed power supply

as well

as attended

various meetings

associated

with the trip as well as the investigation concerning

the failed

SR detector

power supply.

The inspectors

concluded

that licensee

actions

were conservative

and appropriate.

Following the performance of troubleshooting activities

and

repairs

on the pressurizer

manway,

the licensee

returned the unit

to service

on October 7,

1993,

and

100% reactor

power was re-

achieved

on October 8,

1993.

The inspectors

observed

portions of

this startup

and concluded that the startup activities were

conducted

in a professional

manner.

11.0

Management

Meetings

(30702)

Inspection

Scope

The inspectors

attended

the meetings

discussed

below.

11.2

11.2.1

Inspection

Findings

Enforcement

Conference

The inspector

attended

an Enforcement

Conference

on October

5,

1993, in the Regional Office.

At the conference,

issues

associated

with two 1987

DOL discrimination cases

were discussed.

The results of the meeting

and any

NRC disposition of the issues

will be forwarded

by separate

correspondence.

11.2.2

Engineering Heeting

A meeting with representatives

from the

FPL engineering staff and

the

NRC resident

and regional offices was conducted

at the

FPL

Corporate Office in Juno

Beach,

Florida,

on October

20,

1993.

The

topics of discussion

included organization

and staffing changes;

engineering initiatives in the areas of nuclear safety,

availability, cost,

and employee

development;

engineering self

assessment;

and

1994 complex modifications for both the St.

Lucie

I

25

12.0

and Turkey Point facilities.

This meeting

was beneficial

in

keeping the

NRC informed of licensee initiatives and

aware of the

status of ongoing enhancements.

Exit Interview

The inspection

scope

and findings were summarized

during management

interviews held throughout the reporting period with the Plant, General

Manager

and selected

members of his staff.

An exit meeting

was

conducted

on October 29,

1993.

The areas

requiring management

attention

were reviewed.

The licensee

did not identify as proprietary

any of the

materials

provided to or reviewed

by the inspectors

during this

'nspection.

Dissenting

comments

were not received

from the licensee.

The inspectors

had the following findings:

Item Number

50-250,251/93-24-01

Descri tion and Reference

NCV - Wrong Leads Lifted/Inadequate Verification

(section 7.2.4).

13.0

50-250,251/93-24-02

VIO - Inadvertent Overdilution (section 9.2.6).

Acronyms

and Abbreviations

ADH

ANPS

ATILT

CFR

cps

CV

'VCS

dpm

FL

GHI

GMM

Administrative

Auxiliary Feedwater

As Low as Reasonably

Achievable

Assistant Nuclear Plant Supervisor

Administrative Procedure

American Telephone

and Telegraph

Component

Cooling Water

Code of Federal

Regulations

Counts

Per

Second

Control Valve

Chemical

and Volume Control

System

Direct Current

Drawing Change

Request

Departure

From Nucleate Boiling

Department of Labor

Disintegrations

Per Minute

Docket

Power Reactor

(Plant License)

Emergency

Containment

Cooler

Emergency Notification System

Engineered

Safety Feature

Fahrenheit

Flow Control Valve

Florida

Florida Power

8 Light

Final Safety Analysis Report

Federal

Telecommunications

System

General

Maintenance

-

I&C

General

Maintenance

- Mechanical

~

1

26

gpm

HHSI

HP

HPS

I&C

IR

LCO

LER

NI

NRC

NWE

OM

OP

OPBT

OSP

OTSC

OTZiT

PMM

PNSC

POV

ppm

PTN

PWO

QA

OC

RCO

SR

Tavg

TPCW

TPM

Tref

TS

WS

Gallons

Per Minute

High Head Safety Injection

Health Physics

- Surveillance

Instrumentation

and Control

Intermediate

Range

Limiting Condition for Operation

Licensee

Event Report

Motor Operated

Valves

Main Steam Isolation Valve

Non-Cited Violation

Non-Destructive

Examination

Nuclear Instrument

Nuclear Plant Supervisor

Nuclear Regulatory

Commission

Nuclear Watch Engineer

Operating

Manual

Operating

Procedure

Over Power Delta Temperature

Operations

Surveillance

Procedure

On-the-Spot

Change

Over Temperature

Delta Temperature

Preventative

Maintenance

- Mechanical

Plant Nuclear Safety Committee

Power Operated

Valve

Parts

Per Million

Project Turkey Nuclear

Plant

Work Order

guality Assurance

guality Control

Reactor Control Operator

Reactor Coolant System

Residual

Heat

Removal

System

Reactor Protective

System

Radiation

Work Permit

Short Notice Outage

Source

Range

Average Temperature

Turbine Plant Cooling Water

Turkey Point Modification

Reference

Temperature

Technical Specification

Unresolved

Item

Volume Control Tank

Violation

Work Request

Waste

System

Welding Services,

Inc.

I

ML17352A329

Text

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