ML17228B568

S stem Walkdowns

~

During the week of June 3, the inspector performed

a walkdown of

portions of the Unit 2 Low Pressure

Safety Injection System

2B and

High Pressure

Safety Injection System

2B.

This walkdown was

performed to verify proper valve alignment in accordance

with the

following procedure

and applicable plant drawings

as well as

observe

the general

material condition of the system

components:

OP 2-0410020,

Rev 30,

"HPSI/LPSI - Normal Operation"

Drawing 2998-G-078,

Sheets

130A and

130B,

Rev 12,

"Flow

Diagram Safety Injection System"

The inspector

noted that the system

and area

was generally clean

and free of debris.

No valves or pumps were observed

to have

packing or oil leaks.

Valve alignments

were verified to be in

agreement

with the procedure.

The inspector

noted

one discrepancy

on drawing 2998-G-078,

sheet

130B.

The drawing did not indicate

that the

2B LPSI

Pump Recirc Isolation valve,

V3205,

was locked

open

as required

by OP 2-0410020,

valve alignment.

06

Operations

Organization

and Administration

06.1

Mana ement

Chan

es

On May 12, Mr. A. Stall

assumed

the position of Site Vice President,

relieving Mr.

W. Bohlke,

who had

been serving in an interim capacity.

After a turnover period,

Mr. Bohlke was to return to his previous

position

as Vice President of Engineering.

07

guality Assurance

in Operations

07. 1

Review of

A Activities

40500

The inspector

reviewed the following gA documents

during the inspection

period:

~

ITR 96-013

~

gSL-VTM-96-10

~

gSL-PM-96-06

~

ITR 96-011

"Safety System

Walkdown (Partial): Auxiliary

Feedwater

System,

Unit 1"

Vendor Technical

Manual Audit

Performance

Monitoring Activities - April/May

"24 Hour On-Shift Assessment

of Conduct of

Operations

in the St.

Lucie Unit

1

& 2 Control

Rooms"

08

08.1

In general,

the inspector

found that the

gA organization

had performed

reviews which were broad in scope

and directed at areas

which had

been

previously identified as weak.

As

a result of these activities,

12

Findings were generated,

indicating

a detailed review of the activities

monitored

and

an aggressive

application of appropriate

standards.

Miscellaneous

Operations

Issues

Closed

LER 50-389 95-001

"Low Pressure

Safet

In 'ection

um

Found to be Ino erable Durin

ASME

uarterl

Code

Run

Due to Air

Bindin "

92700

08.2

Air binding was identified during the performance of a routine

ASME pump

test for LPSI

pump 2B.

This item was discussed

in IR 50-335,389/95-04.

The licensee's

investigation determined that the air binding to this

pump was caused

by air which had

been trapped

in the Unit 2B Emergency

Core Cooling System

(ECCS) during maintenance activities performed in

the

1994 spring refueling outage.

The inspector

reviewed the corrective

actions initiated to resolve this issue

and verified that the following

corrective actions

had

been completed:

2B pump and suction check

valve were disassembled,

inspected

and found satisfactory;

seals for

pump

2B were replaced

as

a precautionary

measure;

ECCS suction

headers

were vented

and air was found upstream of 2B

ECCS containment

sump valve;

procedures

were issued to vent

ECCS systems

following

maintenance

and

ASME surveillance test runs;

and

ASME surveillance tests

were satisfactorily performed

on all Unit

1 and Unit 2

pumps.

The

pump casing for LPSI

pump

2B was initially vented

each shift to ensure

pump's continued operability.

No air was being identified in the

pump

casing; therefore,

venting of the

pump casing

was changed, initially, to

three times per week and then to monthly.

Venting of the

pumps

was also

to be performed following each refueling outage,

maintenance

or test

activity.

Currently, all

and containment

spray system

pumps are

vented following ASME testing,

maintenance,

shutdown cooling and other

activities for which gas

or air may have

been introduced into the

system.

The

LPSI and containment

spray

pumps

are vented the fourth

Thursday of each

month.

This program should prevent future air binding

problems in the

~

This item is closed.

Closed

LER 50-389 95-002

"Automatic Re ctor Tri

on

Low Steam

Generator

Water Level due to

a Failed Level Transmitter"

92700

This item was discussed

in IR 50-335,389/95-04,

Section 3.b.3.

The

inspector

reviewed the licensee's

correction actions

and verified that

these actions

had

been completed.

Engineering

evaluated

the feasibility of design modifications to

minimize or eliminate plant trip single point vulnerability in the

feedwater control

system.

Several

options were evaluated.

The

modification option selected

was the installation of position switches

for the main feedwater regulating valves to provide alarms

on valve open

and closed positions.

Engineering

had initiated action to prepare

the

necessary

documentation for this modification.

At the close of this

inspection,

the installation date

had not yet been established.

08.3

Closed

IFI 50-335 389 96-01-03

"Conformance with UFSAR Assum tions

on

ECCS Leaka e"

92901

This IFI was opened

as

a result of the identification of an active leak

past the seat of a Unit 2

CS

pump casing vent valve.

The inspectors

questioned

whether the observed

leakage

was

bounded

by UFSAR-assumed

leak rates

and

how the licensee

ensured that they were within assumed

leak rates overall.

On February

15,

a leak by the seat of V07453,

a casing vent for the

2B

Containment

Spray

pump,

was identified.

The licensee later quantified

the leak rate at 14.6 cc/hr.

The valve's tailpiece

was subsequently

capped to prevent

any future leakage to the safeguards

room.

The

licensee

was

asked

how UFSAR assumptions

regarding

ECCS component

leakage

were verified on

an ongoing basis

and did not have

a ready

response.

As

a result,

the licensee initiate

STAR 0-960322 to document

the concern

and to develop

a position

and methodology to address

the

issue.

The STAR's evaluation

concluded that, while no program explicitly

verified that leak rates

were within UFSAR assumptions,

a number of

programs

addressed

the issue.

These

included:

~

Conduct of Operations

procedural

requirements

that operators

inspect

components

such

as

pumps

and valves for signs of leakage

and for the initiation of corrective actions for identified leaks.

~

The Health Physics

department

maintained

a running log of

installed drip pockets

and of tygon tubes

which routed leaks to

floor drains.

~

The

RAB Fluid Systems

Periodic

Leak Test which,

on

an

18 month

periodicity, directs walkdowns of ECCS systems

to inspect for and

quantify leakage.

The inspector

performed research

on the issue

and

has

found the

following in the St. Lucie UFSARs:

The Unit

1

UFSAR, Table 15,4. 1-2, listed

assumed

ECCS component

leakages

which were taken into account in calculating off-site

doses for DBAs.

The leakage

assumptions

in the table include

values for large

and small valve packing (not seat leakage).

The

combined leak rate from all

ECCS components

(valves

as well as

pumps,

mechanical joints, etc.) is assumed

to be 2.045 liters/hr

to the

pump room and

.210 liters/hr to the equipment drain

tank (valve leakage is presumed

to be directed to the

pump room).

The Unit 2

UFSAR did not contain

a similar table; rather, it

assumed,

in Table 15.6.6-11,

B.2, that

a 50 gpm leak developed

from a passive

ECCS system failure 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months after the onset of the

10

DBA and that the leak 'i;sted for 30 minutes.

The leakage is

assumed

to go directly to the environment

and

no credit was taken

for ECCS room filtration.

~

The Unit 2 UFSAR addressed

the licensee's

responses

to

NUREG 737.

The respon'se

to item III.D.1.1, "Integrity of Systems

Outside

Containment Likely to Contain Radioactive Haterial," included,

as

.its only commitment in this area,

a provision for leak testing of

identified systems.

This testing

was to be conducted

in intervals

not to exceed

each refueling cycle,

and the inspector verified

that the licensee

has satisfied their commitment in this regard

through the performance of OP 1 and 2-1300054,

"RAB Fluid Systems

Periodic

Leak Test."

~

The Unit 2 UFSAR included,

in Table 11.1-22,

equipment

leakage

assumptions

for the sizing of the waste

management

system.

In the

table,

valve seat

leakage

was

assumed

to be

10 cc/hr/in-seat-

diameter.

Initial investigations

indicated that the valve in

question

had

an approximate

9/16 inch seat diameter,

thus making

the observed

14.6 cc/hr leakage

in excess of what would be

an

assumed

5.6 cc/hr rate for the valve.

The licensee

stated that

this value represents

a scoping

assumption for system design,

not

an actual criterion for leakage.

The inspector

concluded that the observed

ECCS leakage

was

bounded, by

the values provided in the

UFSAR and that the licens'ee

had satisfied

their commitment in this regard.

This item is closed.

II. Haintenance

Nl

Conduct of Haintenance

Hl.l

V4111

Re air

62703

On Hay 29, during preparation for replacing the fuel from the spent fuel

pool to the Unit

1 reactor,

Valve 4111, fuel transfer tube isolation

valve,

was found closed.

This valve was

a 36 inch isolation valve that

connected

the spent fuel pool

and reactor building refueling cavity.

The valve had

a non-rising stem valve rotated

by a wheel

gearbox device

connected

by a reach

rod of approximately

35 feet.

The valve stem would

turn but the valve would not open.

Subsequent

investigation

found that

the valve stem

had

become

separated

from the yoke of the valve.

Work Request 96014057

was issued to repair the valve.

The inspectors

followed the repair work on Valve 4111.

This work

included reassembly

of the valve and the installation of a new thrust

ring with two set

screws to prevent recurrence.

Valve stem was peened

just above the packing gland

so that verification can

be

made of proper

valve stem orientation

when valve is being operated.

Engineering

was

evaluating the design of this valve to determine if any changes

should

be made to the valve to prevent recurrence.

11

The licensee's

evaluation

found

an air operated

motor was being used to

open or close the valve.

The air operated

motor turned the reach

rod

handwheel.

Several

hundred rotations

were required to fully open or

close the valve.

The air operator

was reported not used at the

beginning or end of the valve stroke.

However, the air motor may have

applied excessive

torque to the, valve.

The licensee

is evaluating the

use of this air motor to determine if it should continue to be used to

open or close this valve or if other acceptable

means

were available.

Eliminating the use of this air motor operator

would reduce the torque

applied to the valve stem but would place

an additional

burden

on the

plant operators.

The inspector

found that appropriate

maintenance

procedures

were

followed in the repair of Valve 4111.

,H1.2

Surveillance Activities

61726

a.

Ins ection

Sco

e

The inspector

reviewed the following surveillance test activities

performed during the inspection period:

OP 1-2200050B,

Rev 26,

"1B Emergency Diesel

Generator

Periodic

Test

and General

Operating Instructions"

~

OP 2-0700022;

Rev 39, "Auxiliary Feedwater - Normal Operation,"

Appendix A,

2C Auxiliary Feed

Pump Governor Response

Test

b.

Observations

and Findin

s

Emergency Diesel

Generator

1B

The inspector witnessed

portions of the

24 hour2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months test run for EDG

1B being

on June 6.

The test

was being performed per

OP 1-

2200050B.

The

1B

EDG full load conditions

was reached

at 5:30

a.m.

on June

6.

During a walkdown inspection at 9:00 a.m.,

the

inspector

noted that the cooling water outlet temperature

indicator TI-59-015B for EDG

16 cylinder engine

1Bl was inoperable

ahd that the operators

were not taking temperature

readings

from

the redundant

thermometer.

This was discussed

with the system

engineer

and Operations.

At 10:30 a.m.,

the operators

began

recording the outlet temperature

reading

each half hour.

Step 8. 1.28, of OP 1-2200050B,

required the cooling water outlet

temperatures

be

recorded

every 30 minutes after the diesel

generator

reached full load conditions.

Technical Specification 6.8. l.a requires that written procedures

be established,

implemented,

and maintained covering the activities

recommended

in

Appendix A of Regulatory

Guide 1.33,

Rev 2, February,

1978.

Appendix A, paragraph

1.d includes administrative

procedures for

procedural

adherence.

gI 5-PR/PSL-I,

Rev 68, "Preparation,

Revision,

Review/Approval of Procedures,"

Section 5. 13. 1, stated

12

that all procedures

shall

be strictly adhered to.

The failure of

the licensee

to record cooling water outlet temperatures

every 30

minutes

once full load conditions were reached constituted

a

violation (VIO 50-335/96-08-06,

"Failure to Follow Procedure

During

EDG Testing" ).

During the walkdown of the

EDG

1B engines,

the inspector

noted

that electric driven fuel oil priming pump

1B2 had

been

removed

from the

12 cylinder engine for repairs.

The licensee

informed

the inspector that this motor was not required to be operable to

perform the surveillance test but the priming pump was required to

be installed

and operable prior to restoring

EDG 18 to operable

status.

~

Auxiliary Feed

Pump

2C

On June

6, the Unit 2 reactor

was manually tripped.

Auxiliary

Feedwater

(AFW) pump

2C started automatically following the trip,

as designed,

but tripped

on overspeed

after running for

approximately ten minutes.

To evaluate

the cause of this trip,

CR

96-1300

was issued

and

an event response

team

was formed to review

the events

associated

with this trip, determine

the cause,

and

identify the corrective actions required to prevent recurrence.

One of the team's

recommendations

was to test the

pump

and attempt

to duplicate the events

which caused

the trip.

Appendix A to

OP

2-0700022

was issued to perform the test.

The inspector

attended

the pre-test brief and witnessed

the performance of the test.

The

pre-test briefing was thorough.

Operations

performed the test

and

the

pump performance

was satisfactory.

The previous failure was

not reproduced

by the test.

Following the test,

engineering

evaluated

the test results

and the

design of the

pump and steam

pump driver.

This review identified

the long term collection of water in a low points of the piping

upstream of the steam supply valve to AFW pump turbine as the most

probable

cause of the turbine trip.

PC/H 96-099

was issued to

provide water removal at the low spot

on the upstream of the steam

supply valves to AFW pump

2C.

Work on this

PC/H was in process

at

the

end of this inspection.

c.

Conclusion

Surveillance test activities were properly conducted for the above

tests,

except that failure to perform half hour readings

on the cooling

water outlet temperature

for the

EDG 1B,

as required in the procedure

was identified as

a violation.

The engineering

group provided

responsive

support to operations

and maintenance

following the trip of

AFW puIAp 2C.

13

Ml.3

Emer enc

Diesel

Generator Reliabilit

62703

a.

Ins ection

Sco

e

The inspector

reviewed the program for recording

and maintaining the

reliability data for the

EDGs at St. Lucie.

b.

Observatio

s and Findin

s

TS Table 4.8-1,

which mandated

increased

frequency of diesel

surveillance testing

due to excessive failures,

had

been

removed

from

the TSs.

The reliability program for the station's

EDG was controlled

by AP 0010022,

"Emergency Diesel

Generator Reliability Program."

This

procedure

implemented

FPL's commitment to

NUMARC Initiative SA to

maintain the station's

EDGs at

a reliability level of 97.5 percent.

The

inspector

reviewed the System engineering

data

on tests

performed

on the

station's

EDGs.

The quarterly test

summary data,

dated

February

21,

1996,

was

as follows:

Last

20 Demands

Last

50 Demands

Last

100 Demands

EDG

1A

EDG 18

EDG 2A

0

2

1

4

1

EDG 28

The trigger values to maintain

a reliability target at 97.5 percent

were

failures of three or less for the last

20 demands,

four or less for last

50 demands

and five or less for the last

100 demands.

The reliability

of the St.

Lucie

EDGs were within. the acceptable

range.

The last failure of EDG

1A was in July 1991 due to

a failure of the

engine governor.

Recent failures of EDG 18 included electrical

breaker

relay failure on May 2,

1996,

a diesel

fuel leak on October 5,

1995,

broken engine valve on August 31,

1995,

a governor problem

on May 17,

1995

and

a voltage regulator problem in October

28,

1994.

Following the

October

1995 failure, weekly operability tests

were performed

on

EDGs

1A

and

18 until

a total of seven consecutive failure-free start

and load

run tests

were achieved

on

EDG 18.

The inspector requested

copies of recent quarterly reliability reports

for the

EDG required

by AP 0010022.

These

records

were not readily

available for review.

The records

were not classified or stored

as

"guality" records.

Subsequently,

the licensee

located the record data

and provided copies of records

dated

June

5,

1995,

December

15,

1995,

February

21,

1996,

and June

5,

1996.

To improve the ability to retrieve these

records

in the future,

AP

0010022

was being revised to require these

records to be classified

as

"guality Assurance

Records."

The procedure is also being enhanced

to

14

address

other items covered

by the Maintenance

Rule (10

CFR 50.65).

This was to be tracked

by PMAI Correction Action Nos.

PH96-06-124

and

PH96-06-125.

c.

Conclusion

The reliability of the

EDGs at St. Lucie was

above the target level of

97.5 percent.

At the beginning of this inspection period, records

were

not available to demonstrate

that this requirement

was being met.

However, this information was subsequently

provided to the inspector.

The licensee

was responsive

to the identified weaknesses

in the storage

and the ability to retrieve the diesel reliability records.

Appropriate

action

was taken to revise

AP 0010022 to improve the maintenance

and

ability to retrieve records to demonstrate

that

EDGs met the reliability

and unavailability requirements

of the

NRC Maintenance

and, Station

Blackout Rules.

Hl.4

a'nte

ance

Backlo

62703

a.

Ins ection

Sco

e

The inspector

reviewed the licensee's

program for the identification,

tracking

and resolution of the backlog of work orders, i.e. work orders

that

had

been

issued for six months or longer.

b.

Findin

s and Observations

The inspector evaluated

work orders which were originated prior to

December

1,

1995.

These work orders

were categorized

as follows:

MAINTENANCE WORK REQUEST

ISSUED

PRIOR TO DECEMBER 1,

1995

ITEM

COMMON

UNIT 1

UNIT 2

TOTAL

1995 Outa

e

1996 Outa

e

315

27

315

1997 Outa

e

Work in Process

Packa

e Ready for Work

.

Hold for Technical

In ut

gC Review

Disa

roved

Minor Work

Totals

14

29

26

74

33

28

79

16

483

92

125

23

65

12

32

39

319

876

154

262

15

The oldest work order for components

common to both units

was written

Hay 5,

1995; for Unit 1,

two work orders

were originated in 1993

and

44

were originated in 1994;

and for Unit 2, two work orders

were originated

in 1992

and six were originated in 1994.

The 27 items scheduled

to be completed during the previous Unit 2 1995

refueling outage

were reviewed to determine

why these

items

had not been

accomplished.

At the inspector's

request,

the licensee

reviewed these

items

and found that the work could be satisfactorily deferred until

a

later date without affecting the safety or operability of the plant.

Several

of these

items could

be performed with the unit on line but had

not yet been rescheduled.

The inspector verified that the rescheduling

of these

27 items

was in process.

The inspector reviewed'work order nos.

940283601,

9501215401,

9501317801,

and

9501597801

and verified that the work on these

items

could

be accomplished

with the unit online.

These

items

had originally

been

scheduled for the

1995 Unit 2 refueling outage.

The 315 items (greater

than six month. old) on the Unit

1 1996'refueling

outage work schedule

are scheduled

to be completed this outage.

The

list indicated

33 Unit

1 work orders

were to be performed during the

1997 outage.

The inspector requested

information from the licensee

as

to why these

items were not to be performed during the current

1996

refueling outage.

Appropriate justification was provided by the

licensee for the proposed

schedule.

Several

items were low priority and

high cost

items which did not affect the safety or operability of the

unit and

had

been deferred for financial reasons.

A number of items

were preventative

maintenance

tasks

on the plant's "five year plan"

which had

been included

on the work list for the next outage.

The work

package for one item had not been completed in time to be performed

during the

1996 outage.

The inspector

reviewed Unit

1 work orders

9402890101,

9402965301,

9402970101,

943047901,

and 9502498901

and

verified that the work on these

items could

be deferred.

Work order 9502883301

was to replace

the seal

in RCP 181.

The seal

was previously

replaced

in November

1994.

The replacement

frequency

was listed

as

once

every

72 months.

Work order 9502639501

was

an inspection

and overhaul

of HPSI

pump 18.

The last overhaul/inspection

of this

pump was.Harch

1990.

The scheduled

frequency

was once every

90 months.

The Unit

1

items

on the

1997 refueling outage

schedule

appeared

to be appropriate.

In Harch

1996,

the licensee

began

a number of initiatives to identify,

track and assign

appropriate

action to complete the required work on

work orders

in

a timely manner.

Several

objectives,

goals

and

performance

indicators

were established

to evaluate

the performance

in

meeting these initiatives.

Normally, when the plant was not in an

outage,

the status of these

goals

and objectives were'reviewed

each

day

as part of a management

oversight meeting.

The status

on these

items

were reviewed weekly when the plant was in an outage.

During this inspection,

the plant was in an outage

and weekly management

status

reviews of the work order'nitiatives, were being performed.

The

0

16

inspector

attended

the meeting in which the weekly review of the status

of the work order initiates

was performed.

The inspector noted that

as

of June

4 the status of the initiatives were

as follows:

Un't

1 0 ta

e Work Orders

Initiated 2176

Completed

1015

Goal

(Complete all by the end of outage)

Work Orders in Non-Outa

e Hold for Technical

Assistance

tc.

Total

231

Goal

150

~

Work Orders

Read

to Work and Workin

Total

523

Goal

340

S stem

Leaka

e

Dri

Pockets

Unit

Outage

Repair

Non-Outage

Repair

1

9

5

2

18

9

27

14

~

Control

Room Control

Board Deficiencies

Totals

14

27

41

Total Outage

Non-outage

Goal for Non-outage

5

~

Work Orders Initiated Over

12 Months

Com onent

Re uired

Corrective Maintenance

or was

De raded

but 0 erable

Total

28

Goal

0

c,

Conclusions

A backlog existed for incomplete work orders.

The licensee

had also

identified this issue

and initiated action to reduced

the backlog.

The

licensee's

program to identify and reduce

the backlog

was identified as

a positive feature.

The actual

numbers for the above items exceeded

the

plant's goals.

The licensee

acknowledged this status

and management

attention

was being directed toward meeting the goals.

17

Haintenance

and Haterial Condition of Facilities

and Equipment

Ladders

and Scaffoldin

71707

During walkdowns,

the inspectors

noted

a high number of

ladders/scaffolds

placed

on or near equipment in the Unit 2 (operating

unit)

RAB,

and in the Unit 2 turbine areas.

Inspections

revealed that

five out of approximately fourteen ladders/scaffolds

checked

had yellow

scaffold tags indicating that they were installed in December

1995

and

intended to last only for the duration of the Unit 2 outage.

Although

the outage

had

ended in early January,

the ladders

remained in place

four months later.

The inspectors

found approximately five additional

ladders/scaffolds

which were not removed following other dates

and

expected

durations

ind'icated

on attached

tags.

The inspectors

found

only one ladder/scaffold

which had

a green

usage

tag denoting that the

ladder/scaffold fully met all guidelines for assembly.

All other

ladders/scaffolds

(approximately thirteen)

had yellow caution tags

denoting that the ladder/scaffold

was usable

but deficient in some item.

The inspectors

reviewed

AP 0010724,

Rev 8,

"Use of Scaffolds,

Ladder s,

Boatswain's

Chair and Hanbaskets,"

and found that procedural

requirements

were met.

However, the inspectors

concluded that

ladders/scaffolds

were not being promptly removed from operating unit

areas

following work and that ladders/scaffolds

were routinely used with

minor deficiencies requiring the posting of yellow caution tags.

RWT Bottom Ins ection

62703

In July,

1993,

the licensee identified pitting which resulted

in leaks

in the bottom of the Unit

1

RWT.

A relief request

was approved at the

time for a non-code repair of the tank bottom, which was attempted

during the

1994 Unit

1 refueling outage

(see

IR 94-24).

The original

non-code repair could not be

made during the

1994 outage

due to severe

e~.".ernal pitting in the tank bottom.

Consequently,

the licensee

received

NRC approval for a non-code repair which involved the

installation of a vinyl ester,

fiberglass-reinforced,

bottom in the

tank.

During the current Unit

1 outage,

the licensee

performed

an inspection

of the non-code repair to verify the integrity of the tank bottom.

On

Hay 18, the licensee

entered

the tank and inspected

the liner.

The

liner was inspected for a number of attributes,

including hardness,

delamination,

adhesion,

peeling, flaking, blistering, cracking,

and the

existence of pinholes.

The inspection

was documented

in an attachment

to JPN-PSL-SECP-96-053.

One anomaly

was identified in the inspection,

involving a small hole of

approximately

1/32 inch diameter.

The hole was excavated

to determine

depth.

The depth

was recorded

as less

than 1/16 inch deep

and did not

penetrate

the fiberglass roving.

The hole was then repaired to return

full liner thickness to the affected area.

The licensee

determined

the

condition to be

an installation defect.

In addition to this anomaly,

the licensee

also identified an area

on the

RWT wall where duct tape

had

18

been left and covered

by liner topcoat.

The topcoat

was cut away and

the tape

removed.

The inspector

concluded that the licensee

had satisfied their

commitments relat>ve to this inspection.

M2.3

Post Maintenance Testin

of the IA EDG

62703

On May 17, the inspector

observed

a portion of the

PM testing of the

1A

EDG conducted

per

MP 1-0950188,

"Operation of the

1A Emergency Diesel

Generator for Maintenance

and Governor Set Up."

This procedure

provided

instructions for the set

up and testing of the lA EDG engines'overnor

actuators

following their replacement.

The inspector did not attend the infrequent evolution briefing.

However,

a subsequent

discussion

and review of the topics covered with

the management

designee

lead the inspector to conclude that the brief

was thorough,

Prior to commencing

the test,

the inspector

reviewed post modification

test requirements,

journeyman

PC/M packages

at the worksite and

performed

a walkdown of the lA EDG.

As

a result,

the inspector

made the

following observations

and findings:

'a ~

The journeyman

PC/M ¹177-195

package

contained

MP 0930063,

Rev

14

"Installation of Cable Terminal

Lugs and Miscellaneous

Control

Wire Termination Instructions," which were not verified as

a

current revision.

The inspector brought this discrepancy

to the

attention

oF both the journeyman

and test specialist.

The test

specialist

confirmed via telephone that this was the latest

revision

and verified the procedure.

A similar finding was

made

on May 8 and was documented

in IR 96-06

(NCV 335/96-06-02).

The inspector discussed

this issue with the Maintenance

Manager,

who stated that,

since the initial identification of this problem

area,

stand

down meetings

had

commenced

to reinforce the

requirement that procedures

be verified prior to use.

It was

explained that these activities were still underway

and that,

due

to the short time which had passed

between

the two observations,

corrective actions

had not had

a chance to take full affect.

The

inspector

noted that signs reminding workers of these

requirements

were being posted

and that the licensee

had not yet closed the

CR

documenting

the origina) finding.

As appropriate

procedural

controls

had

been in place prior to these findings (indicating no

programmatic

issue)

and

as the most recent finding indicated that

the correct revision was,

in fact, in the field, the inspector

determined that this constituted

a violation of minor safety

significance

and is being treated

as

a non-cited violation

consistent with section

IV of the

NRC Enforcement Policy

(NCV

335/96-08-02,

"Failure to Verify Maintenance

Procedure

Used at

Worksite" ).

19

The inspector identified a deficiency tag

(WR ¹96003002)

on TI-59-

003A during the walkdown using the test procedure.,

This

temperature

indicator was

used to record engine oil temperature

in

step 9. 1.20 for the

16 cylinder

EDG engine.

Precaution

4.6

contained instructions

based

on this recorded

temperature.

The

inspector questioned

what the nature of the identified deficiency

was

and whether it would affect this test.

The operations

representative

said that the TI read

low and that it would not

affect the test.

The inspector questioned

how low.

Operations

reviewed the deficiency log and found no information related to

that question.

Prior to beginning the test,

a contact pyrometer

was acquired to monitor engine oil temperature.

The inspector

concluded that the failure to identify this

deficiency

shows

a weakness

in the test program.

The licensee

should incorporate either

a procedural

step or perform

a field

walkdown to ensure that there

are

no outstanding

maintenance

items

which could affect testing.

The inspector reviewed

HP 1-0950188,

Rev 0, "Operation of the

1A

Emergency Diesel

Generator for Haintenance

and Governor Setup,"

and

had the following observations:

~

Step 9.1.22.L used the IV process to identify relay "IRA"

prior to removal for the test.

Step 9. 1.22.H removed the

relay with no IV required.

This appeared

inconsistent with

the use of the IV process.

The inspector brought this

observation

to the attention of the management

designee.

In

a followup discussion

with system engineer responsible for

the test,

the inspector learned that the

IV in the removal

step

was shifted to

a column in the procedure

which did not

print.

~

Step 9.2.21 contained

step-by-step

instructions for switch

and tag removal.

At the end of the instruction was

a

signoff by a journeyman

and

a table with IV signoffs.

The

inspector questioned

the system engineer

as to the

appropriateness

of the .journeyman signoff since all of the

step-by-step

instructions

were signed off with IVs in the

table.

Since this procedure

had

a

S ecial Conditions

Note and Allowances

that permitted minor procedural

changes

during testing with post

testing

FRG approval prior to returning the

1A

EDG to an operable

status,

the inspector identified the above

as observations

only.

During the test the inspector

observed electricians lift the

governor actuator

leads

and install

an in-line switch per step

9. l. 11.

This step contained five step-by-step

instructions,

four

of which required

IV.

The inspector

observed

steps

9. 1. 11.A

through 9. 1. 11.C before attending

a briefing for operators

held

outside the

1A EDG building.

The inspector

made the following

20

observations:

~

Step 9. 1. 11.A identified terminals 3(-)(wire 220)

and

4(+)(wire 221) located

on the Woodward amplifier inside

one

of the

1A EDG control cabinets.

The inspector

observed

the

electrician

kneel

and perform the initial verification.

When the independent verifier approached

the cabinet,

he

looked in the upper portion.

The initial verifier pointed

to the lower portion of the cabinet with a brief verbal

exchange,

The system engineer

counseled

both electricians

to observe

the

IV requirements.

Step

9. 1. 11.C installed

a double pole on/off switch between

wire 220 and terminal

3 and (2) wire 221

and terminal 4.

The inspector

observed

the electrician installing the

switch.

There were two other electricians

present,

one of

whom would be required to IV this step.

Both had

moved to

either side of the cabinet

and were observing the

installation.

The inspector told the system engineer

before

leaving the area that if either electrician

performed the

IV, they needed

to back out of the cabinet.

The inspector discussed

these

events with the Haintenance

Hanager

and

system engineer.

The system engineer stated that he was procedurally

required to independently verify the switch installation following the

IV described

above.

In doing so, it was identified that the switch had

been installed

(and IV'd) incorrectly.

The inspector

reviewed the completed

procedure

and noted that the system

engineer did perform the final IV of the switch installation.

However,

the inspector

noted that

no evidence of a misinstalled switch existed in

signoffs.

The system engineer stated that,

upon identification, the

switch was

removed

and reinstalled properly.

Again,

no evidence of

repeated

steps

existed.

Inspection

Report 96-04 (paragraph

01.3) identified

a similar case of

steps

which were repeated

due to difficulties involved in performing

a

procedure,

which were not documented.

As additional

information is

required to determine whether this practice constitutes

a violation of

NRC requirements,

this issue will be tracked

as

an unresolved

item (URI

50-335,389/96-08-03,

"Adequacy of Documentation for Repeated

Procedural

Steps" ).

The inspector

concluded that the observation

documented

in (b), above,

failed to demonstrate

the "independence"

required

by AP 17.06,

"Independent Verification."

This may have

been

a contributor to the

fact that

a switch was installed

and verified in error.

However,

the

inspector

noted that the checks

performed

by the licensee's

maintenance

procedure

were sufficiently rigorous to identify the problem.

Additionally, the inspector

noted that the

IVs discussed

above did not

impact

EDG operability,

and thus lacked

immediate safety significance.

Consequently,

this is

a violation of minor safety significance

and is

21

M2.4

being treated

as

a non-cited violation, consistent with Section

IV of

the

NRC Enforcement Policy

(NCV 50-335/96-08-04,

"Failure to Follow

Procedure

When Performing'V").

CEA Reliabilit

Issues

62703

On May 24,

CEA 12 dropped during troubleshooting of a blown fuse for CEA

10.

The licensee initiated

a team to address

the increasing

numbers of

CEA problems the licensee

has experienced.

The team included

members

from Engineering,

Operations,

Maintenance,

and the vendor

(ABB/CE).

The

team's initial assessment

pointed out that Unit 2 CEAs had

been highly

reliable, with only one dropped

CEA since

1993.

Unit

1 was found to

have experienced

5

CEA drop events

since

1993.

The team's efforts were

to be completed within 60 days.

On June 4, Unit 2 operators

received

annunciators

indicating that at

least

one of four.undervoltage

relays

on the

CEDM bus

had changed state.

These relays provided

a turbine trip function following reactor trip in

a two-out-of-four coincidence.

When

18C personnel

responded

to the

CEDMCS cabinets,

they noted that

CEA 36 had

a continuous

high gripper

voltage alarm in.

The CEA,'nd its associated

subgroup

CEAs, were

transferred

to the hold bus.

IKC determined that the cause for the

observed

conditions

was increased

temperature

in the room containing the

cabinets.

Electrical maintenance

personnel

determined that one (of two)

CEDMCS

room air conditioners

(2-TAC-1) had one compressor trip due to high

discharge

pressure.

The second air conditioner

(2-TAC-2) had

been out

'f service.

The trip was reset

and the air conditioner

began to bring

about

a reduction in room temperature.

IKC then proceeded

to

troubleshoot

and repair the subject conditions.

H3

Maintenance

Procedures

and Documentation

M3.1

Observation of Inservice

Ins ection Work Activities Unit

1

73753

a 0

Ins ection

Sco

e

b.

On May 13, the inspector returned to the St.

Lucie facility to observe

inservice inspection activities

and to determine if these activities

were conducted

in accordance

with applicable procedures,

regulatory

requirements,

and licensee

commitments.

The inspector's

objective

was

to continue the review of the licensee's

steam generator

examination

and

evaluation activities

and the 10-year ultrasonic examination of the

reactor vessel.

The initial portion of the review was documented

in IR

50-335,389/96-06.

Findin

s and Observations

On May 13,

14,

and

16, the inspector

observed portions of the licensee's

eddy current data acquisition activities.

These activities were

22

conducted

in accordance

with approved

procedures

delineated

in IR 50-

335,389/96-06

and the

FPL Steam Generator

Eddy Current Examination Plan.

On May 15, the inspector went to FPL's

NDE Center in West

Palm Beach,

Florida, to examine

FPL's eddy current analyses activities.

These

activities were also conducted

in accordance

with approved

procedures

and industry guidelines delineated

in IR 50-335,389/96-06.

During this

portion of the inspection,

the licensee

had identified numerous

rejectable

indications.

However,

some of the rejectable

indications

were found in areas

where they were not expected.

These

areas

included

two tubes

which exhibited circumferential

cracking at the top of the

tube sheet

in the

A Steam Generator

Cold Leg.

This will require the

cold leg side of both steam generators

to be examined

100 percent with a

motor rotating pancake coil.

In addition,

an axial indicatioh was found

in the free span

area

between

support plates

7

& 8.

This is an area of

concern that will require expansion

examinations

because

there is no

inherent condition which should cause

crack initiation in this area.

As

a result of the present

expansion

examinations,

the licensee

has

added

approximately

one week to the steam generator

eddy current

and plugging

activities.

The inspector also reviewed qualification and certification records for

all eddy current personnel.

In addition,

equipment calibration records

were verified.

During the inspection period,

the inspector

was also

a party to NRC's

Office of Nuclear Reactor Regulations

(NRR) telephone calls with the

licensee.

These calls dealt with FPL's

steam generator

tube inspection

plans,

tube expansion

plans, in-situ pressure

testing plans

and tube

plugging plans.

The licensee

was pro-active in keeping

NRR informed of

their inspection findings and correction action plans

and all actions

taken

by the licensee

at this point appeared

to be conservative.

During the next refueling outage

(Cycle 14), the licensee

intends to

replace the steam generator

tube bundles in both Unit I steam

generators.

The inspector

observed

the work activities associated

with the 10-Year

Inservice Inspection of the Unit I Reactor

Pressure

Vessel.

As

a result of slippage in the defueling schedule,

the ultrasonic

examinations

of reactor vessel

were not conducted

during this inspection

period.

However,

as partially reported

in IR 50-335,389/96-06,

the

inspector did review the applicable nondestructive

examination

procedures,

visited the Electric Power Research 'Institute

(EPRI) in

Charlotte,

N.C. to review EPRI's methods of testing for one sided

access

examinations,

reviewed analyst

performance

demonstration qualification

records,

verified ultrasonic

equipment calibration records,

and verified

the setup of the ultrasonic

system both in the plant

and in the remote

acquisition

and analysis station.

During the inspector's

May 10 visit to the

EPRI

NDE Center

(as

documented

in IR 50-335,389/96-06)

the inspector

noted that the

F

-

0

23

qualification examinations

given for one sided weld access

examinations

were conducted

on test

samples

which did not have

a weld joint in them.

The inspector

was concerned that the demonstration test did not

accurately depict plant conditions

because

of the acoustical

differences

between

the weld metal

and the base material,

which should

have

some

limiting effects

on the examination.

In addition, the differences

in

the lay of defect indications

on the far side of the welds

had not been

addressed

by EPRI even in an analytical

manner.

EPRI's position was

that, in their opinion, the missing weld would not make

a significant

difference in the detection

and sizing of indications in the carbon

steel reactor vessel.

Although not disagreeing

with EPRI, the inspector

felt that the difference should

be defined

and factored into the

difficultlyof the single side weld access

performance

demonstration

test,

and actual reactor vessel

examinations if necessary.

On Hay 13,

when the inspector returned to the St. Lucie plant, the above

issue

was discussed

with FPL licensing

and

NDE personnel.

The licensee

contended

that

a weld was not necessary

in carbon steel

vessel

material

because this is

a completely isotropic medium which has minimal

influence

on the passage

of ultrasonic waves.

The licensee

stated

they

intended to prove this by the following:

~

As

a member of the Performance

Demonstration Initiative (PDI),

FPL

has initiated action at the

EPRI

NDE Center to address

the issue.

The

PDI program

was

used to conduct the demonstration,

therefore

it is incumbent

on them to defend their position.

The licensee

expected

them to produce empirical data from a previous study or a

demonstration

to show that the presence

of a weld in vessel

material is insignificant.

OR/

~

The examination contractor

(Southwest

Research

Institute) will

look at producing similar empirical data from their studies.

If

necessary,

SwRI will measure

ultrasonic

beam attenuation

in

similar material with and without a weld.

The licensee

also stated

they would assign

a licensing

number to this

item to insure that the issue is properly tracked

and that

a copy of the

result would be forwarded to the inspector.

The inspector considered

the licensee's

actions to be appropriate

and

adequate

to resolve this concern.

c.

Conclusions

The licensee's

inservice inspection activities for the steam generator

tube eddy current examination activities

and the 10-year reactor vessel

examinations

were well planned,

performed,

and managed

by very talented

and knowledgeable

NDE personnel.

No violation or adverse

trend

was

noted in any area

examined.

0

H8. 1

Miscellaneous

Maintenance

Issues

(92700,92902)

Closed

LER 50-335 95-002

"Hissed

Emer enc

Diesel

Generator

Surveillance

Oue to Procedural

Oeficienc

"

92700

H8.2

This itemwas discussed

in IR 50-335,389/95-10

and was identified as

50-335'/95-10-01.

The inspector reviewed the licensee's

correction

actions

and verified that these

actions

had

been completed.

TS Table 4.8-1 which mandated

increased

frequency of diesel

surveillance

testing

due to diesel

generator failures

has

been

removed from the St.

Lucie TSs.

Refer to paragraph

H1.4 for a discussion of the reliability

program for the station's

emergency diesel

generators

which was

controlled

by AP 0010022,

Rev 1,

"Emergency Diesel Reliability Program."

C osed

50-389 95-003

"Missed Techn'c l

S ec'f'cat'o

Sc

d

Surveillance

on Containment

Personnel

Airlock Door Oue to Procedu

e

Deficienc

"

92700

This item was discussed

in IR 50-335,389/95-09,

Section 4.b,

and

was

identified as

NCV 50-335/95-09-01.

The inspector

reviewed the

licensee's

correction actions

and verified that these

actions

had

been

completed.

III. En ineerin

E2

E2.1

Engineering Support of Facilities and Equipment

Unit

1 Steam Generator

Tube Ins ections

and Plu

in

37551

40500

a ~

Ins ection

Sco

e

b.

During the current refueling outage,

the licensee,

after discussions

with NRC/NRR, adopted

a more conservative

set of SG tube plugging

criteria than

had

been

used in the past.

As

a result, projections of SG

tube plugging predicted that the

25 percent/7

percent

asymmetry limit

for tube plugging assumed

in the accident analysis

would be exceeded

during the current outage.

Consequently,

the licensee

prepared

TS

amendments

which would be required to allow operation after the outage.

Findin s

and Observations

The

PLA package

was reviewed

by

FRG and the

CNRB on June

1, prior to

submittal to the

NRC.

The inspect'or attended

the

CNRB meeting,

which

considered

PLAs for reduced

RCS flow, changed

the reactor core thermal

margin safety limits, modified

RCS total

steam

and water volumes,

made

RPS low flow setpoint

changes,

and limited reactor thermal

power after

mid-cycle.

The inspector

found that the

CNRB responsibly

considered

the issues,

with members

asking, probing questions

regarding the technical merit

behind the

PLAs.

Most notably,

the

CNRB chairman questioned

the

~

~','t

25

licensee's

representatives

as to the issues

arising from the

FRG review

of the issues.

When informed of the scope of the changes

which would be

required to plant procedures

and operating practices

(which were

reviewed in principle in the

FRG and which involved, at the time,

59

identified actions

ranging from setpoint

changes

to simulator training),

the

CNRB elected to hold

a Hode

2

CNRB meeting to consider whether the

licensee

had adequately

incorporated

the changes

(prior to criticality).

c.

Conclusions

The inspector

concluded that the

CNRB had executed its responsibilities

in a probing

and competent

manner,

and that the decision to perform

a

Hode

2

CNRB was proactive

and appropriate.

IV. Plant

Su

ort

R4

Staff Knowledge

and Performance

in RPSC

R4. 1

Radiolo ical Protection Activities

71750

a.

Ins ection

Sco

e

b.

.During the 'period from Hay

14 - 16, the inspectors

reviewed radiological

protection activities during numerous tours through both

units'uxiliary

buildings

and the Unit

1 containment.

Findin

s and Observations

The inspectors

observed

personnel

dosimetry

and

PC usage,

radiation area

postings,

and

RCA cleanliness

and material conditions.

The inspectors

comoared practices

to

10

CFR 20 and various licensee

procedural

req 'irements

and practices.

The inspectors

did not identify any

activities which failed to meet regulatory requirements.

Cleanliness

and material conditions throughout the

RCA and the Unit

1 containment

were good.

However,

the inspectors

did note several

inconsistent

or

poor practices,

including:

Personnel

dosimetry positions were inconsistent

when

PCs were worn

by personnel,

The inspectors

observed

some

EDs and

TLDs worn

inside clothing,

some hanging outside clothing,

and others

inserted into clothing pockets.

Several

individuals were observed

completing the

PC dress

out

(closing zippers

and velcro straps)

after crossing into the

contamination control area at the containment entry.

Boundaries for a hot particle area

on the

SFP crane

were unclear

with regard to inclusion or exclusion of the crane control panel.

Switches

on the panel

were manipulated

at

some times using

an

extra set of gloves,

and at other times were manipulated without

an extra set of gloves.

Survey

maps indicated that the hot

26

particle area

was intende 'o include the crane mast.

~

The general

containment entry

RWP brief video showed

PC removal

practices

which were not the

same

as actual practices

in the

plant.

Specifically, the video showed

an individual removing all

parts of PCs at the step off pad, while the actual practice

was to

remove different parts of the

PCs at three sequential

points

when

exiting containment.

~

The frequency of SFP heat exchanger

and

pump area

surveys

was not

increased

during fuel offload.

The regular weekly survey, last

performed

on Hay 12,

was the most recent

survey available

when the

inspectors

checked

the survey results

on Hay 16.

During the

intervening four days, refueling activities were continually

placing additional

spent fuel assemblies

into the

SFP.

Such

activities provided

a significant potential for increasing

radiation levels.

c.

Conclusions

Observations

of radiological worker practices

indicated inconsistent

application of standards.

F2

Status of Fire Protection Facilities

and Equipment

(64704)

a.

Ins ection

Sco

e

An evaluation

was performed of the licensee's

actions in the resolution

of fire protection discrepancies

identified during the Unit

1 1996

refueling outage.

b.

Findin

s and Observations

~

Fire Barrier Breaches

AP 1800022,

Rev 16, "Fire Protection Plan," Appendix A Section

6.0, required fire rated assemblies

and barriers,

including

penetration

seals,

to be operable

at all times.

The fire rated.

assemblies

were required to be verified operable at least

once per

18 months

by performing

a visual inspection of the exposed

surface

of each fire rated

assembly,

performing

a visual inspection of

each fire damper

and associated

hardware,

and by performing

a

visual inspection of at least

10 percent of each type of sealed

penetration.

If discrepancies

were identified in the seal

penetrations,

an additional

10 percent

sample

was required to be

taken.

This inspection

process

was required to continue until a

10 percent

sample with no discrepancies

was identified.

During the Unit

1 outage,

the surveillance

inspections identified

a number of fire barrier and fire barrier penetration

seal

discrepancies.

The inspectors

reviewed the results of the first

sample of 12 fire barrier penetration

seals

and noted that

27

discrepancies

had

been identified on two penetration

seals.

The

results of the second

sample

were reviewed

and the inspector

noted

that discrepancies

had

been identified on three of the

12 samples

which had

been inspected.

The licensee

had selected

a third

sample but these penetrations

had not been

inspected

at the

end of

the inspection period.

A total of approximately

36 fire barrier

and'fire barrier penetration

seal

discrepancies

had

been

identified.

The inspectors

toured Unit

1 to review the licensee

identified fire barrier

and penetration

seal discrepancies.

Host

of these discrepancies

consisted of small cracks which did not

appear to significantly degrade

the fire resistive rating of the

fire barrier.

The licensee

had initiated work requests

to correct

these deficiencies.

These

areas

had also

been

included

on the

list of degraded fire protection

components.

An hourly fire watch

was being provided for these

areas until these

degraded fire

barriers

were repaired.

The corrective action

and compensatory

measures

initiated for these

degraded fire barriers

were

appropriate.

~

Use of Combustible Scaffolding in Turbine Building

During routine tours of the Unit

1 turbine building, the inspector

noted that combustible

wood was being

used for scaffolding.

The

licensee's

procedures

only require non-combustible

or fire

retardant

wood scaffolding in safety related

areas.

This was

a

program weakness.

Normal nuclear industry practice is to use fire

retardant treated

wood or non-combustible materials for

scaffolding throughout the power plant, including turbine

buildings.

c.

Conclusions

The acceptance

criteria for degraded fire barrier walls and assemblies

was very restrictive.

Barriers with only minor discrepancies

were

considered

inoperable

by the licensee's

procedures.

This was

a positive

finding.

Combustible materials

were being used for scaffolding in the

turbine building.

These

were negative findings.

V. Hang ement Heetin

s and Other Areas

Xl

Review of UFSAR Commitments

A recent discovery of a licensee

operating their facility in a manner

contrary to the

UFSAR description highlighted the need for additional

verification that licensees

were complying with the

UFSAR commitments.

While performing the inspections

which are discussed

in this report the

inspectors

reviewed 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

parameters.

The following deficiencies

were identified during this period;

28

Unit 2 Table 7.5-3 for Window No. LA-9 and

LB-9 incorrectly showed

actuating device

as

LS-17-552A/553A and LS-17-552B/553B.

The

correct actuating devices

were LS-59-009A,

-014A and LS-59-021B,

028B.

~

Unit 2 Table 7.5-3

showed

LA-4 and LB-4 Lube Mater Supply

Strainers

High Differential Pressure

as safety-related.

This

system

was downgraded

to non-safety-related

by PC/M 268-292.

These

items form additional

examples of URI 96-04-09,

"Failure to Update

UFSAR."

X1.1

UFSAR Review Effort

40500

X2

In January,

the licensee's

engineering

organization identified the need

for a comprehensive

UFSAR review and update effort to ensure

accuracy of

the document.

Stated goals at the time included verification that plant

hardware

was correctly described

in the

UFSAR and that procedures

described

in the

UFSAR were correctly translated

into plant procedures.

The inspector

met with the licensee

during the inspection period to

discuss

the status of the effort.

The licensee

stated that

an initial

review had

been

completed

and that,

as

a result,

a methodology for a

more comprehensive

review was established.

The licensee

developed

ENG-

gI 6.7,

Rev 0,

"UFSAR Reviews," which described

the planned effort.

The

inspector reviewed the document

and found that it contained direction

for the conduct of the reviews, descriptions of types of findings

(delineating the difference

between typographical

errors

and more

substantial

errors),

requirements

for the initiation of 10

CFR 50.59

reviews

and operability assessments,

and directions invoking the

CR

process for identified deficiencies.

The licensee

stated that the

review schedule

would culminate in UFSAR submittals in September

(Unit

2)

and

December

(Unit 1),

1996.

The inspector

reviewed the lists of licensee identified UFSAR

deficiencies

compiled to date.

The deficiencies

included items for

further review and items

known to be incorrect

and the total

numbers of

items to date

were

73 for Unit

1 and

78 for Unit 2.

The inspector

concluded that further information and review would be required to

determine

whether violations of NRC requirements

were contained

in the

list.

Consequently,

this issue will be documented

as

an Unresolved

Item

(URI 50-335,389/96-08-05,

"Licensee-Identified

UFSAR Deficiencies" ).

Exit Meeting Summary

The inspectors

presented

the inspection results to members of licensee

management

at the conclusion of the inspection

on June

11.

The licensee

acknowledged

the findings presented.

29

PARTIAL LIST OF

PERSONS

CONTACTED

i icensee

Bladow, W., Site guality Manager

Buchanan,

H., Health Physics Supervisor

Burton, C., Site Services

Manager

Dawson,

R., Business

Manager

Denver,

D., Site Engineering

Manager

Fincher,

P., Training Manager

Frechette,

R., Chemistry Supervisor

Fulford, P., Operations

Support

and Testing Supervisor

Harple, C., Operations

Supervisor

Heffelfinger, K., Protection Services

Supervisor

Holt, J.,

Information Services

Supervisor

Johnson,

H., Operations

Manager

Kreinberg, T., Nuclear Material

Management

Superintendent

Harchese,

J.,

Maintenance

Manager

O'Farrel,

C., Reactor Engineering Supervisor

Olson, R., Instrument

and Control Maintenance

Supervisor

Pell, C., Outage

Manager

Scarola, J., St.

Lucie Plant General

Manager

Stahl A., Site Vice President

Weinkam, E., Licensing Manager

Wood, C.,

System

and

Component

Engineering

Manager

White, W., Security Supervisor

Other licensee

employees

contacted

included office, operations,

engineering,

maintenance,

chemistry/radiation,

and corporate

personnel.

IP 37551:

IP 40500:

IP 61726:

IP 62703:

IP 64704:

IP 71707:

IP 71750:

IP 73753:

IP 92700:

IP 92901:

IP 92902:

IP 93702:

30

INSPECTION

PROCEDURES

USED

Onsite Engineering

Effectiveness

of Licensee

Controls in Identifying, Resolving,

and

Preventing

Problems

Surveillance Observations

Maintenance

Observations

Fire Protection

Program

Plant Operations

Plant Support Activities

Inservice Inspection

Onsite Followup of Written Reports of Nonroutine Events at Power

Reactor Facilities

Followup Plant Operations

Followup - Maintenance

Prompt Onsite

Response

to Events at Operating

Power Reactors

31

~0ened

50-335/96-08-06

50-335,389/96-08-03

50-335,389/96-08-05

Closed

50-335/96-08-01

50-335/96-08-02

50-335/96-08-04

50-335/95-002

ITEHS OPENED,

CLOSED,

AND DISCUSSED

VIO

"Failure to Follow .Procedure

During

EDG Testing"

(Paragraph

Hl.2)

URI

"Adequacy of Documentation for Repeated

Procedural

Steps"

(Paragraph

H2.3)

URI

"Licensee-Identified

UFSAR Deficiencies"

(Paragraph

Xl.1)

"Failure to Haintain Oper ability of Two Wide

Range Nuclear

Instruments

During Fuel

Hovement"

(Paragraph

01.2)

"Failure to Verify Haintenance

Procedure

Used at

Worksite" (Paragraph

H2.3)

"Failure to Follow Procedure

When Performing IV"

(Paragraph

M2.3)

LER

"Hissed

Emergency Diesel

Generator Surveillance

Due to Procedural

Deficiency" (Paragraph

HB. 1)

50-389/95-001

50-389/95-002

50-389/95-003

LER

"Low Pressure

Safety Injection (LPSI)

Pump

Found

to be Inoperable

During ASME quarterly

Code

Run

Due to Air Binding" (Paragraph

08. 1)

e

"Automatic Reactor Trip on

Low Steam Generator

Water Level

due to

a Failed Level Transmitter"

(Paragraph

08.2)

"Hissed Technical Specification

Scheduled

Surveillance

on Containment

Personnel

Airlock

Door Due to Procedure

Deficiency" (Paragraph

H8.2)

50-335,389/96-01-03

Discussed

50-335,389/96-04-09

IFI

"Conformance with UFSAR Assumptions

on

Leakage"

(Paragraph

08.3)

URI

"Failure to Update

UFSAR." (Paragraph

X1.2)

AFWP

ASME Code

ATTN

CFR

CMM

CNRB

CR

CRN

CWD

DWG

FIS

FR

FRG

HPSI

ICW

IFI

IHE

ISI

IV

JPN

KV

LC

LCO

LER

LIS

Emergency Diesel Generator

LS

32

LIST OF

ACRONYMS USED

rs Boiler and Pressure

System

operating license)

ASEA Brown Boveri

(company)

Alternating Current

Auxiliary Feedwater Actuation System

Auxiliary Feedwater

(system)

Auxiliary Feedwater

Pump

Administrative Procedure

American Society of Mechanical

Enginee

Vessel

Code

Attention

Cubic Centimeter

Component

Cooling Water

Combustion

Engineering

(company)

Control

Element Assembly

Control

Element Drive Mechanism

Control

Element Drive Mechanism Control

Code of Federal

Regulations

Critical Maintenance

Management

Company Nuclear Review Board

Condition Report

Change

Request

Notice

Containment

Spray

(system)

Circulatory Water

Control Wiring Diagram

Design Basis Accident

Demonstration

Power Reactor

(A type of

Drawing

Emergency

Core Cooling System

Electronic Dosimeter

Emergency

Operating" Procedure

Electric Power Research

Institute

Engineered

Safety Feature

Flow Indicator/Switch

The Florida Power

& Light Company

Federal

Regulation

Facility Review Group

High Pressure

Safety Injection (system)

Intake Cooling Water

[NRC] Inspector

Followup Item

In-House-Event

Report

InService Inspection

(program)

Independent Verification

(Juno

Beach)

Nuclear Engineering

KiloVolt(s)

Load Center (electrical distribution)

TS Limiting Condition for Operation

Licensee

Event Report

Level Indicating Switch

Low Pressure

Safety Injection (system)

Level Switch

HSR