ML17228B354

12 cylinder engine

developed

a fuel oil leak at

a piping connection

in the

FO

return line to the diesel

fuel oil day tank.

The operator

.

rapidly shut

down the

EDG to reduce fuel oil spray.

The engine

was declared

out of service

and

a section of the piping was

replaced.

The

EDG was satisfactorily retested

and returned to

service

on October 8.

Engineering laboratory analysis of the

failed piping by the licensee

determined that the failure was

the result of high cycle fatigue.

This crack evolved over

a

long period of time.

The licensee

also found that the piping

configuration

on the remaining engines

was of a different

design configuration

and that the failure that occurred

on

1B

EDG was not applicable to the other

The inspector did

a walkdown inspection of the failure when it

occurred.

He also did

a walkdown of the repairs after they

were completed

and verified that

a

PHT was conducted

by

a

CR

log review.

He inspected

the

FO piping system

on the remaining

EDGs, discussed

the failure and repairs

in detail with the

system engineer,

and observed

the engine in operation during

a

succeeding

week's surveillance.

Overall, this repair was

handled

in

a timely and effective manner.

Unit

1 Restart.

The Unit

1 reactor

was restarted

on October

12 after

a 73 day

outage.

The inspector

reviewed the control

room logs including

the

OOS, J/LL, Deficiency Log,

and the

OWA log prior to Unit

restart.

No deficiencies that would affect .the unit's safe

return to power were identified.

The inspector

conducted

a

plant walkdown and verified safety

system alignments

and

0

~e

'

12

availability.

Discussions

were also held with plant management

and on-shift operations

personnel

to verify that

no

deficiencies

existed

which could impact

a safe unit restart.

The inspector

observed restart activities over

a period of

several

hours

from the control

room.

Several

delays,

due to

CEA problems,

resulted

in delaying reactor startup.

Two CEA

timing modules

were replaced

and reactor startup

proceeded

in

an orderly and controlled fashion.

The reactor entered

Mode

2

at 12:03

and achieved criticality at 12:55.

Maintenance

work

on

a hydrogen

seal oil pump

and secondary

chemistry cleanup

delayed restart of the secondary

plant until October

13.

The

turbine was placed

on line at 3:00 p.m.

on October

13,

1995.

The overall startup

went well. It was well controlled

and

methodical with adequate

management

and supervisory oversight.

Some Refueling outage activities were delayed

on Unit 2 since

priority was placed

on Unit

1 restart.

6)

Unit 2

RFO

a)

Unit Shutdown/Cooldown

Unit 2 was

shutdown

on October 9,

and entered

a planned

refueling outage of 49 days.

ESF Safeguards

Testing

(paragraph 4.b.)

was conducted

during initial plant

shutdown.

A reactor containment building and system

walkdown by the

licensee

at operating

temperature

and pressure

found boric

acid buildup around

a third of the circumference of a

B hotleg nozzle for a Steam Generator differential

pressure

detector.

No active leakage

was observed

but the

boron buildup indicated past leakage.

Isotopic analysis

of the nozzle

boron residue

revealed

Cobalt-60

and

an

absence

of Cobalt-58.

This indicated that

no recent

leakage

had occurred.

Since the unit was already shut

down and preparing to enter

a refueling outage,

the

TS

required

shutdown

was not applicable.

Engineering

analyses

of this item determined that the

leakage resulted

from

PWSCC of the Alloy 600 material

used

in these

nozzles.

This'is

a well known industry problem.

Units

1 and

2 have several

nozzles that are susceptible

to

this problem.

These include:

pressurizer

nozzles,

hot and cold leg instrument nozzles,

pressurizer

heater

sleeves,

SG leakoff and

CEDMs.

The pressurizer

steam

space

nozzles

were replaced

on Unit

2 during the last refueling outage

and the

3 pressurizer

water space

nozzles

are scheduled

for replacement

during

the current outage.

Based

on the identification of this

13

problem,

the licensee

procured

the services

and materials

needed

to also replace

the

9

RCS Hot Leg Nozzles during

the current Unit 2 outage.

This work after integration

into the outage

schedule

appeared

to have minimal impact

on the planned

outage duration.

After discovery of the above,

ESF Safeguards

testing

continued until

a design

problem (paragraph

4.b.) resulted

in delaying test completion until later in the outage.

The unit was then cooled

down without any significant

'roblem

hnd entered

mode

6 on October

18.

Overall, the

unit shutdown

and cooldown

was handled well.

It was noted

that since operations

had gone to verbatim procedural

compliance,

a large

number of the procedures

used during

plant shutdown

and cooldown required temporary procedure

changes.

RPV Disassembly

and Defueling

Unit 2 was cooled

down to 200'

on October ll and work

was started

on removal of support

components

to permit

reactor disassembly.

The reactor vessel

head

was

detensioned

on October

19.

CEA's were unlatched

on

October

20, the

UGS was lifted on October

21

and core

offload commenced

on October 22.

All of the

above

evolutions went well without any significant problems.

During flooding of the lower refueling cavity on October

17, routine job distractions

and inattention to this

activity resulted

in overfilling the lower cavity into the

upper refueling cavity.

This resulted

in leaking

approximately

100 gallons of water into the containment

sump.

A TC/PCR to

OP 2-1600024

was developed

and

implemented to require that

an operator

be stationed

in

containment to follow this evolution in the future.

The

inspector followed all the above evolutions

and conducted

inspections

as

a part of routine daily plant tours.

Core offload initially incurred problems with the

adjustment

and calibration .of the refueling machine load

cell.

The load cell

was replaced

October

23 and offload

continued without any significant equipment

problems

and

was completed

on October 24.

The inspector

observed

the

offload activities from the control

room, containment

and

the refueling machine.

The activity met the

TS required

staffing.

Overall the offload went exceptionally well.

The inspector

was

impressed

with the strict procedural

compliance

and good repeat

back communications

used during

this evolution.

The licensee

practice of having contract

equipment specialists

available to provide for assistance

on equipment repairs

appeared

to assist

on rapid

0

(y

14

resolution of the minor equipment

problems encountered.

No deficiencies

were identified.

c.

Plant Housekeeping

(71707)

Storage of material

and components,

and cleanliness

conditions of

various

areas

throughout the facility were observed

to determine

whether safety and/or fire hazards

existed.

Overall plant

cleanliness

and equipment

storage

was

deemed satisfactory.

No violations or deviations

were identified.

d.

Clearances

(71707)

During this inspection period,

the inspectors

reviewed the following

tagouts

(clearances):

~

1-95-10-047

- This tagout isolated

FCV-25-2 isolation valve

(penetration

P-11) for HSV Containment

Purge Supply.

The

inspector verified that the

4 tags associated

with this

clearance

were

on the correct

components,

in the specified

position/condition

and that applicable

00S

Log entry was

made.

~

2-95-10-228

- This tagout isolated

SB14530/SB14528.

The

inspector

reviewed the Clearance

Order only and noted that the

2

CCW drain valves,

V14173

and V14455,

on lines

58 and

59 were

positioned

Open at 0550 hours0.00637 days 0.153 hours 9.093915e-4 weeks 2.09275e-4 months

on October

23 and not initialed

by the posltioner.

However,

an Independent Verification was

completed

on these

2 valves.

This discrepancy

was brought to

the attention of the work clearance

center

SRO For correction.

e.

2-95-10-245

- This tagout

was issued for configuration control.

The inspector verified that both valves

were in the closed

position

and properly tagged

and that the applicable

OOS

Log

entry was made.

~

2-95-10-246

- This tagout

secured

HVA/ACC-3A Air Handling Unit

for the Unit 2 Control

Room Air Supply due to the

CCW OOS.

The

inspector verified that the breaker

was off and properly tagged

and that the applicable

OOS

Log entry was made.

No other deficiencies

were identified.

Technical Specification

Compliance

(71707)

Licensee

compliance with selected

TS

LCOs was verified; This

included the review of selected

surveillance test results.

These

verifications were accomplished

by direct observation of monitoring

instrumentation,

valve positions,

and switch positions,

and

by

review of completed

logs

and records.

Instrumentation

and recorder

traces

were observed for abnormalities.

The licensee's

compliance

with LCO action statements

was reviewed

on selected

occurrences

as

0

~

15

they happened.

The inspectors verified that related plant

procedures

in use were adequate,

complete,

and included the most

recent revisions.

f.

Effectiveness

of Licensee

Controls in Identifying, Resolving,

and

Preventing

Problems

(40500)

Facility Review Group Meetings

The inspector

attended

the

FRG meeting

on October

10 where

a

proposed

license

amendment

to permit operation with a

pressurizer

pressure

minimum limit of 2115

PSI if needed

due to

leaking safety valves

was reviewed.

This amendment

was

supported

by engineering

evaluation

JPN-PSL-SEFJ-95-039,

Rev 1,

After a presentation

by engineering

on this item, several

questions

were raised

by operations.

All questions

were

satisfactorily answered.

The licensee

intends to submit this

request for NRR review if equipment fixes do not resolve the

leaking pressurizer

safety valves.

This

FRG meeting

was the first meeting the inspector

had

attended

since the licensee

revised the

FRG Procedure

ADM-

0010520,

Rev 29, in September

and the Preparation,

Revision,

Revision/Approval of Procedure

gI 5-PR/PSL-1

Rev 64 in October

to use

a subcommittee

review of minor procedural

changes.

In

conjunction with the

above

changes,

the

PGM has delegated

the

Chairmanship of the

FRG to the Manager of Licensing or other

designated

managers

as

needed.

The above meeting

was chaired

by the Manager of Licensing.

The meeting

had the required

quorum and business

was conducted

in accordance

with the above

procedures,

and the meeting

issues

were covered well.

The inspector discussed

the changes

that have occurred in

FRG

Chairmanship with the

PGM.

The

PGM has indicated that

he will

approve all

FRG actions

and will periodically chair these

meetings

and will actually participate

in

FRG issues

with major

safety significance.

This appears

to be appropriate.

2)

Licensee Self Assessment

a)

The inspector

reviewed

gA Audit Report gSL-OPS-95-19,

Training and gualification Functional

Area Audit and gSL-

OPS-95-17

gA Performance

Monitoring Audit reports for the

months of August

and September

1995.

The Training and

gualification Audit appeared

to be adequately

detailed

and

contained

one finding involving the retention of training

records

in the

gA vault.

Action is being taken to address

this item.

gA Performance

Monitoring was conducted

on the following

items:

RCP lAl and

1A2 seal

replacements,

HVE-21A fan

motor replacement,

Local

Leak Rate Testing

on the

RCB

0

16

Maintenance

and

Equipment

and Personnel

Air Locks, Unit

1

PORV repairs

and testing,

Health Physics activities during

the

PSL-1 Short Notice Outage,

Operation of the

new

vehicle barrier gates,

freeze

seal activities

and the

closure

and statusing of STARs required for a mode change.

Two findings were identified in this report;

one

identified problems

associated

with the status of STARs

prior to mode change

and the second

item found that

a work

activity was started

by Construction Services prior to

obtaining formal approval of the Nuclear Plant Supervisor.

It was noted that

STARs were written on each identified

deficiency.

Overall the monitoring activities appeared

to

be adequately

detailed

and focused

on safety significant

activities.

The result of the inspections

were well

documented

and provided good recommendations

for

improvement.

b)

The inspector

met with guality Assurance

on October

19,

for a quarterly update.

Items covered

in this meeting

included:

~

Planned organizational

staffing and responsibility

changes

~

Summary of recent audits

and inspections

~

Planned

4th quarter

and plant outage

inspection

plans

~

Increased

operations

oversight

~ 'ew controls for contractor work

~

Recent

independent

technical

reviews

~

NPWO reviews

~

Engineering

and vendor audit results

~

Nuclear fuels

gA

l

Presentations

were provided

by group supervisors

for each

of the above items/area.

The meeting provided the

inspector with a good understanding

of current

gA and

gC

issues

from the licensee's

perspective.

The inspector

found the presentations

were beneficial

and the

discussions

open

and frank.

The licensee

appears

to be

aware

and taking appropriate corrective actions of

deficiencies that were discu'ssed.

(

17

4.

Maintenance

and Survei1

1 ance

a.

Maintenance

Observations

(62703)

Station maintenance activities involving selected

safety-related

systems

and components

were observed/reviewed

to ascertain

that they

were conducted

in accordance

with requirements.

The following items

were considered

during this review:

LCOs were met; activities were

accomplished

using approved

procedures;

functional tests

and/or

calibrations

were performed prior to returning components

or systems

to service; quality control records

were maintained; activities were

accomplished

by qualified personnel;

parts

and materials

used

were

properly certified;

and radiological controls were

implemented

as

required.

Work requests

were reviewed to determine

the status of

outstanding

jobs

and to ensure that priority was assigned

to safety-

Portions of the following maintenance

activities

were observed:

1)

Maintenance

Rework during Short Notice Outage.

In IR 95-15, the inspector identified that several

of the

components

that required work during the

SNO had also

been

worked

on during the previous Unit

1 refueling outage that

ended

in December

1994.

The inspector questioned

the licensee

on this item and they agreed

to review the issue.

The

licensee's

review found that 1,029 total

components

were worked

in the Unit

1

1994

RFO.

Sixty-four of these

same

items were

also worked on during this

SNO.

The licensee classified

32 of

these

as definite rework.

The other items were classified

as

long standing

known problems that frequently require

maintenance

and the remainder

were considered

as possible

rework.

Maintenance

issued

a

STAR on each

rework item to

identify root cause

and

needed corrective action.

The

inspector

noted that the number of items worked

on in this

refueling

and

SNO was 6.2 percent,

It was also noted that

several

of the items

had

a history of repetitive maintenance

and that

some of these

maintenance

items were major

contributors to this extension of the

SNO.

2)

Unit

1

EDG Load Oscillations.

In late August, the inspector questioned

an entry in the Unit

1

control

room log which identified

a load oscillation during the

monthly surveillance,

1-22000508,

on

EDG 1B.

Since there

was

no additional entries

involving this item and

any effect on

component operability, the inspector discussed

i,t with the

DG

system engineer.

The

SE stated that the oscillation resulted

from MVAR swings

on the grid.

On September

5, during the post maintenance

and surveillance

run on

EDG 1B,

some load oscillations

were again observed

and

logged.

Some adjustments

were

made in the governor control

0

('

18

circuitry and the swings were again credited to grid

oscillations.

On September

6, during

a surveillance

run of EDG

lA, the governor response

was identified as being slow and

non

linear when load adjustments

were

made

by the operator.

Electrical maintenance,

under the direction of the

SE again

made

adjustments

in the governor control circuitry.

During

a

followup test,

500 to 1000

KW load swings occurred

and

a ground

was found in the wiring harness

between

the

DG control cubicle

and the governor

on

EDG 1A2.

PWO 95026057-02

and 95024478-01

were issued

and repairs

were

made to the control wiring.

As

a result of the

above

problems

and to place

more experience

on the

EDGs, the licensee

assigned

a new system engineer with

extensive

past

EDG experience

on the Unit

1 and Unit 2

On September

8, during surveillance testing,

KW oscillation was

again

noted

on

EDG A and additional

adjustments

and tuning took

place

on the governor control circuits.

On September

20,

1B experienced

400

KW load spikes during

a

surveillance

run.

During the troubleshooting effort a ground

alarm started

coming in each

time the governor

speed controls

were manipulated.

Troubleshooting

located

and repaired

frayed

wiring in the wiring harness

between

the local control

panel

and the governor.

This was the

same wiring where

a problem had

been identified and repaired

on

1A on September

6.

The

repairs

were performed

under

PWO 95026002-1A.

The above repair

on both engines

was accomplished

on back

shiFt.

The inspector retrieved

and reviewed the

PWO

documentation

and found that the repair was

made using

Raychem

under

an approved

engineering repair method for damaged

cable

insulation

600 volt and below.

The details for this repair

were contained

on drawing 8770-8-328,

Sheet

19H for PCH 336-

192.

The inspector

reviewed the

PWOs

and discussed

the repairs

with maintenance,

engineering,

and the system engineer.

Based

on this information and

a successful

post maintenance test,

the

repairs

were

deemed

to be acceptable.

An engineering

assessment

of the

above

DC ground

was that the

plant

DC System is designed

as

a floating, ungrounded

system

and

a single ground

on either the positive or negative

bus

would not affect operability of the

bus or the

EDG governor

system.

The inspector

reviewed this issue

and the governor

control wiring circuit with the frayed wires with the system

engineer

and agreed with that conclusions

On September

21,

18 again experienced

load oscillations

during

a surveillance test.

This occurred

when the operator

attempted

to make load adjustments.

On September

22,

VAR and

KW swings again occurred

on

EDG 1A.

1A was declared

OOS by

operations

and

a meeting

was held with Operations,

Engineering,

19

System Engineering,

and Plant Management

to discuss this issue

and overall

EOG performance

and reliability.

As

a result of

this meeting

an

EOG maintenance

vendor

and governor

manufacturer

services

were obtained to analyze

and propose

short term and long term corrective actions

on these units.

The short term corrective action resulted

in initiation of PWOs

65-1328

on

EOG IB and 65-1326

on

EDG 1A.

These

PWOs led to the

replacement

of the motor operated

potentiometer,

the speed

load

sensor,

and amplifier modules

on

EOG

1A and the motor operated

potentiometer

and

speed

sensor

module

on

EDG 1B.

The

electronic control units were readjusted

and tuned in

accordance

with the vendor technical

manual

and with direct

assistance

provided

by the governor

and engine vendor

representatives.

The

DGs were taken out of service

one at

a

time and worked under

LCO controls.

Repairs

were complete

on

September

24.

Post maintenance

testing

on both units

demonstrated

considerably

improved operator control during load

changes.

It was also noted that the frequency

and magnitude of

previously identified oscillations

had decreased.

The inspector

observed

several

of the

above

EOG runs

and

attended

the meeting held

on these

issues.

He also

had

frequent interface with the system engineer,

maintenance

and

vendor personnel

who worked

on the

EDGs,

The licensee

decided to place the Unit

1

EDGs

on

an increased

surveillance of every seven

days until they gained confidence

that the above repairs

had addressed

the previous problems.

The system engineer

and maintenance

management

have stated that

they are reviewing the overall maintenance

program

on the

EOG.

They have

asked for inputs from the engine

and governor vendors

and intend to upgrade

the overall maintenance

of these vital

components.

They have also stated that they are considering

upgrading

the governor control

system to

a newer model that has

improved reliability and more readily available

spare parts.

The licensee's

efforts

on the

EDGs have resulted

in improved

performances

However, it was noted that this did not occur

until after several

failures

and significant questioning

by the

NRC.

This item is identified as

a weakness

in diesel

generator

maintenance

and the lack of adequate

equipment

performance

standards

by operations.

(Closed)

URI 389/95-05-03,

" Incore Instrument Wiring Errors"

IR 95-05 documented

apparent wiring discrepancies

in Unit 2

ICIs.

The discrepancies

were associated

with ICI flange

8 and

resulted

in erroneous

ICI spatial

input to the plant computer.

During the current Unit 2 outage,

the licensee

performed

an

inspection of ICI flange

8 wiring prior to de-terminating

the

wiring for vessel

head

removal.

20

The subject inspection

was performed

under

PWO 64/4529

and

included checks of wiring from the refueling disconnect

panel

to the top of the reactor

head.

The licensee

found that

4 of 6

ICI strings

were improperly wired.

The results

were recorded

for inclusion in detector

burnup calculations.

As stated

in IR 95-05,

18C Procedure

1400023,

"Incore

Instrumentation

(ICI) Outage Tasks,"

Appendix K, "ICI Flange

Assembly," required

two separate

reverifications of proper

wiring once flange connections

were

made.

The failure of the

licensee

to perform adequate

verifications of the wiring of ICI

flange

8 following reconnection

during the

1994 Unit 2

refueling outage constitutes

a violation,

This licensee-

identified and corrected violation is being treated

as

a Non-

Cited Violation, consistent

with Section VII of the

NRC

Enforcement Policy,

and will be identified as

NCV 389/95-18-04,

"Inadequate Verification of ICI Wiring Connections After

Reassembly."

b.

Surveillance Observations

(61726)

Various plant operations

were verified to comply with selected

TS

requirements.

Typical of these

were confirmation of TS compliance

for reactor coolant chemistry,

RWT conditions,

containment

pressure,

control

room ventilation,

and

AC and

DC electrical

sources.

The

inspectors verified that testing

was performed in accordance

with

adequate

procedures,

test instrumentation

was calibrated,

LCOs were

met,

removal

and restoration of the affected

components

were

accomplished

properly, test results

met requirements

and were

reviewed

by personnel

other than the individual directing the test,

and that

any deficiencies identified during the testing were

properly reviewed

and resolved

by appropriate

management

personnel.

The following surveillance test(s)

were observed:

1)

OP 1-2200050A,

1A

EDG Periodic Test

On October 5, the inspector

observed

the licensee

perform the

monthly surveillance

on the "1A" EDG using

OP No.

1-2200050A,

Rev 22.

A local start

was performed

per step 8. 1. 18 of the

procedure.

After performing the normal

engine

checks at 375 to

475

RPM (idle), the operator placed the Idle Start

Mode

Selector

Switch in AUTO and verified that the diesel

increased

speed

to 900

RPM.

At this time, the Local

and

RTGB

STOP/AUTO/START Switch were to have both the green

and red

lights illuminated per the

NOTE in the procedure.

The operator

at the local station notified the control

room that the red

light was not illuminated.

The System Engineer,

who was

present for the test,

issued

a

PWO identifier tag

872844 for a

faulty lamp socket.

Several

indicator lamps

on this local

panel

had

been

worked

and closed out on September

25 under

a

minor

PWO (Work Request 895015426 identified intermittent

amber

lights).

The inspector's

followup with the Electrical

Planning

21

Department

showed that the bulbs

had

been replaced).

The

System Engineer released

the diesel for test

and initiated Work Request 895016229 to correct the faulty lamp socket.

The

diesel

was loaded to approximately

3500

KW for its

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months run.

The inspector

reviewed the strip chart for load

and

saw no

fluctuations or spiking.

Following successful

completion of

the surveillance

the

EDG was returned to it's standby status.

OP 2-0400050 Periodic Test of the Engineered

Safety Features

Background

Engineered

Safety Features

(ESF)

are designed

to mitigate the

consequences

of postulated

DBA.

The

ESF function is to limit,

contain,

control

and terminate

an accidental

release

of

radioactive fission products, particularly as

a result of

accidents

that could release

large

amounts of energy within the

containment structure.

ESF systems

keep exposure levels to the

public and plant personnel

below applicable limits.

St.

Lucie Unit 2 utilizes the following ESF systems:

1.

2.

3.

4.

5.

6.

7.

Containment Structure

Containment

Spray

System

Containment

Cooling System

Shield Building Ventilation System

Containment Isolation System

Combustible

Gas Control

System

Safety Injection System

Unit 2 Technical Specifications identify the

LCOs and

associated

surveillance

requirements.

The surveillance

requirements

specify tests

and the frequency requirements

to

demonstrate

operability of systems

important to safety.

Operating

Procedure

No. 2-0400050,

Rev 16, "Periodic Test of

the Engineered

Safety Features,"

satisfies

a large

number of

ESF surveillance

requirements.

This

OP verifies

ESF system

actuations

with plant systems

configured

as closely

as possible

to those

found in the normal operating

procedures.

The

OP is organized

into

12 blocks of test instructions

and

15

Appendices.

Hultiple TS requirements

are verified by this test

procedure.

The

NRC inspector selected this

OP for observation

due to the

first use

on Unit 2 following procedural

revision.

Past

surveillance

problems

included:

~

IR 92-14 identified

a procedural

violation for the Failure

to Adequately Test the

C Intake Cooling Water

Pump.

This

was

based

on

a failure to test the trip and restart of the

22

C

ICW Pump

on the energized

emergency

bus following a

~

IR 94-12 identified

a violation for inadequate

corrective

actions involving the surveillance testing of the

C

ICW

Pump,

This involved

a failure to verify C train

ICW and

CCW pump load shed

and sequencing

functions

when powered

from their alternate

power supply busses.

~

IR 94-22 identified

a violation involving inadequate

corrective action to

a

NRC violation regarding

operability.

This violation identified an electrical

alignment of the

1C

ICW pump to the

IA3 bus while relying

on operability of the IA EDG.

Load shed testing of the

1C

ICW Pump,

when aligned to this bus,

had not been

performed

as required

by TS for

EDG operability.

Test Observation

On October

12, the inspector

attended

the pretest briefing

conducted

by the operations

manager

and found it to be thorough

and detailed.

All test personnel

were verified in attendance.

Items covered

included;

Precautions

and Limitations

Past

experiences

and lessons

learned

Pro<"" iral control

Use of effective communications

Contingencies

and test termination criteria/

It was also stressed

that the operating

crew retained

responsibility for safe plant operation.

On October

12, the inspector

observed

the performance of the

following test procedure

steps:

Step 8.4

~

Verifies initial system alignments

~

Secures

SDC

a'nd realigns

SDC system,

ESFAS logic and

ICW

system for test

~

Initiates

a

LOOP by simultaneously

opening the Startup

Transformer

feeds to the 4. 16

KV buses

2A2 and

2B2

~

Simultaneously initiates

a SIAS,

CIAS, NSIS and

CSAS using

the trip test pushbuttons

~

Verifies proper system

response

~

Resets

and restores

systems

to pretest

alignments

During the realignment of the

ICW system for test,

the manually

operated

ICW pump discharge

valves were throttled to 10 turns

open

from their normally full open position. 'his

was done to

minimize potential

equipment

damage

due to water

hammer

when

'

23

starting the

ICW pumps

under

no flow conditions.

The

ANPO

assigned

to this test

area

looked

ahead

in the procedure

and

requested

permission to throttle the

2C

ICW Pump discharge

valve before

SDC was secured.

This was proposed

to minimize

the time required to realign the

ICW system after

SDC was

secured.

The Test Director agreed

since the

2C

ICW would be in

a P-T-L position for the test.

The

ANPO reported that the

valve locking device

(a padlocked

chain) could not be removed

and that

he was unable to insert the key into the padlock due

to corrosion.

After removing the chain with boltcutters,

the

ANPO was unable to reposition the valve without excessive

force, i.e. the operator

appeared

to be frozen.

The Test

Director determined that leaving this valve in the full open

position would not impact the test or create

a potential for

equipment

damage.

As followup to this problem,

however,

the

Test Director briefed other test personnel

that if a similar

problem was encountered

in repositioning the

2A or 28

ICW

discharge

valves,

SDC would be restored

and the test

temporarily secured.

The inspector

was

impressed

by the ANPO's

initiative in looking ahead

in the procedure

and identifying

this impediment to testing.

This problem recognition

and

resolution minimized the period of time that

SDC was secured

and which could have interrupted the test.

Shutdown cooling was secured

at 2:26 p.m.

and the final 'system

realignments

performed.

RCS temperature

was 120'.

At 2:40

p.m.,

the

LOOP was initiated by simultaneously

opening the

Startup Transformer

feeds to the 4.16

KV buses

2A2 and 282.

One

second later the SIAS,

CIAS, HSIS and

CSAS trip test

pushbuttons

were depressed

inserting the

ESFAS Signals.

All

ESFAS actuations

occurred

as expected.

SDC was restored

at

1505 hours0.0174 days 0.418 hours 0.00249 weeks 5.726525e-4 months .

During the 39 minutes

SDC was secured

the

STA

calculated that the

HUR was approximately 66',

however

temperature

increased

to only 160'

due to partial core

cooling from the operating

ECCS pumps.

An unexpected

EDG 28 Local Alarm (A-26 annunciator)

was

received

when the

LOOP was initiated.

This was caused

by the

failure of the

EDG 28 electrical

fuel

pump.

The attached

fuel

pump allowed for continued operation.

This alarm later cleared

and

a

PWO was written to correct this problem.

Also, test

personnel

reported

problems with the

EDG 2A test recorder.

A

cross-check

with installed instrumentation locally and in the

control

room as well as

a hand held calibrated voltmeter,

isolated

the problem to an apparent drift of the null point

(bias)

on the test recorder

channels

selected.

At 3:42 p.m.,

a loud noise

was heard

from the

H&V toom adjacent

to the control

room.

The operating

HVAC/ACC 3-A was secured

and the noise stopped.

The licensee

suspected

a freon release

caused

by inadequate

ICW flow to the

CCW Heat Exchangers.

24

HVAC/ACC 3-B was placed in service,

however,

a failure alarm

was received

on that train also.

This placed Unit 2 in AS b.

of TS 3.7.7 which with both control

room emergency air cleanup

systems

inoperable,

required the suspension

of all operations

involving core alterations

or positive reactivity changes.

The

access

door from the control

room to the

H&V room was blocked

with explicit instructions given by the Operations

Manager to

the

NPS that entry for safety

and maintenance

personnel

would

be through the access

door inside the

RCA and not the control

room.

This would ensure

continued control

room habitability.

A technician

from the safety department

reported to the control

room,

and

due to poor communications,

entered

the

H&V room

through the blocked access

door.

The technician

entered

the

H&V room alone using

a handheld

oxygen meter sampling at neck

level.

The Operations

Manager ordered

the technician

out the

H&V room and posted

a sign

on the access

door stating,

"No

entrance without prior NPS approval".

A followup survey of the

H&V atmosphere

using

a freon detector

confirmed that freon

levels were within an acceptable

range.

Maintenance

reported

that the 3-C freon safety valve had apparently lifted based

on

low system pressure

and that both the 3-A and 3-B units were

available.

Unit 2 then exited

TS 3.7.7.

A followup discussion

by the inspector with the Operations

Manager confirmed that the

safety department

technician's

actions

were inconsistent with

plant procedures

and that the technician

had

been

counseled

on

this item.

The licensee

is evaluating

a procedural

enhancement

~

which will either fully open the

ICW discharge

valves

when flow

is reestablished

during the test or increase

the number of

turns throttled

open to preclude

recurrence

of this problem.

A list of equipment

problems identified during steps

8. 1

through 8.4

and their associated

PWOs,

where applicable,

include:

a.

b.

C.

d.

e.

HCV-09-1A, A MFW isolation valve, valve was slow to open,

PWO 5424/64

MV-09-10,

2C

AFW Pump discharge,

Unable to throttle,

PWO

1451/66

V09136,

2B AFW Pump Supply isolation valve,

Valve leaking

by,

PWO 5072/62

V09158,

2C

AFW Pump Supply isolation valve to

SG

2B

FW

inlet, Valve leaking by,

PWO 5092/66

MV-09-13, Cross-tie

between

AFW pump

2A and

2B discharge,

Valve leaking by,

PWO 5074/62

MV-09-14, Cross-tie

between

AFW pump

2A and

2B discharge,

Valve leaking by,

PWO 5075/62

25

g.

FCV-25-35, Shield building vent

8 purge control to vent

stack,

OL would not reset,

PWO 1458/62

h.

2B2

EDG,

DC

FO

Pump binding,

PWO 5098/62

i'UPS,

SUPS lost in

LOOP test,

PWO 1447/66

j.

'VE-6A, The overload tripped when the

A train Shield

Building Ventilation Fan

was stopped

and then restarted.

This was due to

a high rad signal

being present

when the

radiation monitor lost power during the

This signal

was reset

and the overload for HVE-6A was also reset.

HVE-6A was

OP tested

SAT.

k.

2A2

RCP OIL LIFT PUMP, This

pump restarted

when the

SIAS

signal

was reset.

The licensee will review the applicable

CWDs and determine if a

PWO is required.

l.

RM-23's, Approximately 1/2 of the

RM-23 monitors were lost

during the

The licensee

generated

a

STAR to address

this problem.

m.

FCV-25-32/33,

HVE-6A/6B inlet control valves,

These

two

valves closed

upon reset of the

CIAS signal.

This was

due

to the high rad signal

being present

when the radiation

monitor lost power during the

When the signal

was

reset,

the valves functioned normally.

Items j. and

m.

above will be incorporated

as

a procedural

enhancement

to recognize

the failed high rad monitor signal

during the

Step 8.5

Aligns the

2AB bus to the

A Electrical Side

Initiates

a load rejection with a concurrent

LOOP/Swing

Pump

SIAS Signal

using

a Group

9A SIAS Signal

Realigns

the

2AB bus to the

B Electrical

Side

Initiates

a load rejection with a concurrent

LOOP/Swing

Pump

SIAS Signal

using

a Group

9B SIAS Signal

Testing of the

A Electrical

Side was satisfactorily completed

prior to shift turnover.

When testing

resumed

on the

B

Electrical Side,

the

2C Charging

Pump failed to start

when the

Group

9B SIAS Signal

was inserted.

This was

due to

a

procedural

deficiency, i.e.,

channel

MB Containment

Pressure

SIAS 127,

BA 101,

301

bypass

key was in the bypass position.

The test

was exited prior to completing step 8.5

and

resumed

at

step 8.6.

Step 8.6

26

Aligns both

full load

Initiates

a

Initiates

a

Initiates

a

Initiates

a

Initiates

a

Initiates

a

2A and

2B

EDGs with offsite power at or near

Channel

A CIAS then resets,

Channel

B CIAS then resets

Channel

A SIAS then resets

Channel

B SIAS then resets

Channel

A CSAS then resets

Channel

B CSAS then resets

After each

ESFAS Channel

is actuated

individual component

actuations

are verified.

This particular step of the procedure

had

been revised.

The

Revision inserted

a SIAS Signal prior to the

CIAS Signal.

This did not allow for separate

verification of

the

CIAS Signal actuations

since the

SIAS also generated

a CIAS

signal

by design.

The licensee

believed that changing the

order would enhance

the procedure

and provide more detailed

ESFAS Signal verifications.

After the Channel

A CIAS Signal

was inserted

and the component

actuations verified, Channel

A CIAS was reset.

At this time

the

2A

EDG tripped

on reverse

power.

The test

was secured

and

the

2A

EOG declared

inoperable.

An investigation

by the licensee

determined that during the

performance of Section 8.6 of OP 2-0400050,

EDG 2A was running

parallel to the grid and loaded to >3600

KW.

CIAS-A was

manually initiated in accordance

with step

12 of the test

procedure.

Actuation of CIAS caused

the

EDG A governor circuit

to change

from the droop

mode (i.e. follows the grid frequency)

to an isochronous

mode (i.e. reverts to preset

frequency

and

does

not follow the grid frequency).

The

EOG

2A preset

frequency

was lower than that of the grid.

This resulted

in

reducing fuel to slow the

EOG down, leading to reverse

power

flow causing

the generator to act

as

a motor (or synchronous

capacitor).

The reverse

power relay actuated;

however,

due to

the presence

of the CIAS-A signal,

the relay trip function was

blocked.

Upon resetting of the CIAS-A signal,

the reverse

power relay trip block was

removed

and the

EOG tripped,

Total

time of EOG operating

under reverse

power was approximately

45

seconds.

A review of the

ERDADS printout of Bus

2A3 voltage

and current

and

EDG current confirmed

a sudden

change

at the approximate

time CIAS was initiated.

The current

drawn by the

EDG 2A

generator

during the reverse

power incident was approximately

330

amps.

From this the licensee

determined that the

2A EDG

output current of 477.54

amps reversed

to 330.38

amps for a net

change of 807.84

amps which was sufficient to actuate

the

reverse

power relay.

Concurrent with this,

Bus

2A3 voltage

changed

from 4331.7 volts to 4360.2

as

a result of the

27

generator

producing additional

HVARs, i.e., acting

as

a

synchronous

capacitor with a high power factor.

This value is

well within the

660

amp continuous

rated capacity of the

generator

windings.

Based

on the above,

System

and

Component

Engineering

determined that

EOG

2A had not been

damaged

by the

incident.

The

2A

EDG voltage regulator

was visually inspected

with satisfactory results

and the

2A EDG was started

and loaded

successfully

as

an operability check.

Further,

performance of

the regular

18-month preventative

maintenance

(Haintenance

Procedures

2-2200062

and 2-H-00180),

included

a thorough

inspection

on

EDG 2A and did not identify any damage

as

a

result of this event.

An engineering

review of the

EDG control circuits found that

the

EDG starts

on SIAS,

CSAS or CIAS and that these

signals

cause

the

EOG to change

from droop

mode to isochronous

mode

(Ref.

CWDs 957

& 958

and Vendor Hanual

2998-7434).

Opening the

Bus 2A2-2A3 tie breaker will also

change

the

EDG from droop to

isochronous

modes.

In the case of SIAS and

CSAS

(CSAS will

only occur with SIAS), the

EOG circuit breaker will trip if

closed,

permitting the

EOG to run separate

from the offsite

power source.

However,

CIAS without SIAS does not trip the

breaker,

resulting in the

EDG operating

in isochronous

mode

while still connected

to offsite power. This condition is not

expected

during normal operation or any design basis

event

requiring the

STAR 8951391

was written to identify this design deficiency

on

the Unit 2

EDG 2B has not been tested with a manual

CIAS actuation,

therefore its operability was not affected.

The Unit

1

EDGs governor control design is different from the

Unit 2

The Unit

1

EDGs have

been successfully

tested

using

an essentially identical

ESFAS test procedure.

Therefore,

there is no operability concern

from the Unit

1

Based

on the above,

the

EDGs were considered

operable.

The, inspector

reviewed the above

assessment

and noted that

while actuation of the

CIAS relay without SIAS is not expected

during normal operation,

both Unit 2

EDGs are tested

monthly

and operated

a minimum of

1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months paralleled to the offsite

power source.

Actuation of CIAS under these test conditions

could have resulted

in damage to the

EOG.

The inspector

was concerned

by several

aspects

related to the

design deficiency identified during testing:

(4

kj'

28

I.

Integrated

Safeguards

testing over the, past

2 years

had

received

a high level of management

and technical

support

attention

due to the licensee's

misinterpretation of

testing requirements

particularly related to swing bus

components.

The current test procedure revision changed

the test

sequence

for initiating CIAS/SIAS/CSAS Signals in

step 8.6

as

a procedural

enhancement.

Although this

same

test

was successfully

performed earlier

on Unit I and

satisfactorily tested

on the simulator, it was not

reviewed in sufficient detail to assess

the impact

upon

equipment or system operation

on Unit 2.

2.

This condition has existed

since initial construction.

There

was

no licensee identification of this failure mode,

i.e. receiving

a CIAS Signal while paralleled to an

offsite power source.

3.

The

2A

EDG was operated for approximately

45 seconds

with

a reverse

power trip blocked,

A review of the

CWDs

determined that

a local reverse

power alarm occurred

which

the licens'ee

believes

also generated

a control

room alarm.

Since operators

were either

unaware or did not question

these

alarms,

the inspector

concluded that it was doubtful

whether operator actions

would have prevented

damage if

the

CIAS had not been reset

unblocking the reverse

power

trip.

The licensee

has

placed

a temporary hold on 2A/B EDG testing

pending resolution of their STAR.

On October

23, the licensee

issued

JPN-PSL-SEES-95-034,

Rev.

0

Safety Evaluation for the provisions to trip emergency diesel

generator

output breaker

on CIAS in plant modes

5 and 6.

This

short term plant temporary modification (plant mode

5 and

6

only) involves wiring any convenient

"deenergize

to close"

CIAS

spare

contact in the

ESFAS cabinet

(A or B,

as required) to

trip the

EDG output breaker

upon receiving

an actual

or

spurious

CIAS while operating

the diesel

generator paralleled

to an offsite power source.

The inspector

reviewed the Safety

Evaluation

and found the approach

acceptable

and consistent

with existing licensing requirements.

The above short term plant temporary modification was not

implemented.

Rev I to the above Engineering

Report

was issued

on October 27.

The licensee's

long term corrective action

involved deletion of the automatic

EDG start

on CIAS and

CSAS

~

since it removed the adverse

conditions,

was relatively easy to

implement

and test,

and

can

be installed

under

10CFR50.59.

This modification will also

be impl'emented

on Unit I at the

earliest

convenience

for consistency

between units

and to

ensure

that spurious signals

would not bypass

the non-safety

trips if the

EDG was connected

to offsite power.

The inspector

29

reviewed

and evaluated

the revised

Engineering

Report

and found

it to be acceptable.

10 CFR 50 Appendix

B guality Assurance Criteria for Nuclear

Power Plants

and

Fuel

Processing

Plants requires,

in part:

a.

that

"Measures

shall

be established

to assure

that

applicable regulatory requirements

and the design basis,

as defined in g 50.2

and

as specified in the license

application, for those

systems,

structures

and components

to which this appendix applies

are correctly translated

into specifications,

drawings,

procedures,

and

instructions...

The design control measures

shall provide

for verifying or checking the

adequacy of design,

such

as

by the performance of design reviews,

by the use of

alternate

or simplified calculational

methods,

or by the

performance of a suitable testing program."

[CRITERION

III, DESIGN CONTROL]

b.

that

"A test

program shall

be established

to assure that

all testing required to demonstrate

that structures,

systems,

and

components will perform satisfactorily in

service is identified and performed ..."

[CRITERION XI]

The licensee's

failure to identify this design deficiency

during initial design

and testing

and adequately

review the

revised

Safeguards

Test procedure for performance

on Unit 2 is

considered

a violation,

VIO 389/95-18-03,

"Failure to

Adequately Design

and Test the

Emergency

Diesel

Generator

2 A/B

Engineered

Safety Feature

Control Logic."

This licensee

identified and corrected violation was considered for treatment

as

a Non-Cited Violation, consistent with Section VII of the

NRC Enforcement Policy.

This violation is being cited due to

the lack of questioning attitude

and

a weakness

in the depth of

review during the changing,

updating,

and correcting of the

applicable

EDG test procedure.

3)

Hissed

CEA Position Surveillance

On October 20, the licensee identified that operations

had

missed

the Unit

1

TS 4. 1.3.3 surveillance

which verifies

CEA

position indication difference

between

reed switch position

transmitters

and pulse counting channels

to be less

than 4.5

inches.

TS requires this surveillance

once every

12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months

and

the licensee

accomplishes

this surveillance

once

each shift in

accordance

with AP 1-0010125,

Rev 102,

"Schedule of Periodic

Test,

Checks,

and Calibrations,"

Check Sheet

1, step

16.

This

surveillance

was missed

on the day and peak shifts

on

October

19.

An investigation

by the licensee

found that the last

surveillance

was performed

between

Midnight and 2:00

AH on

0

30

October

19.

The readings

were recorded

on the Control

Room Log

sheet for CEA positions.

The operator

also signed off

completion of the surveillance

on AP 1-0010125

Check Sheet

1.

The midshift ANPS reviewed the log and check sheet,

but

inadvertently placed the

CEA position log sheet

in the

licensing review file rather than returning it to the

RCO.

The

oncoming

RCO did not identify that the log sheet

was missing

and therefore

he did not perform the surveillance.

Since the

RCOs were standing

12 hour1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months shifts during the refueling of a

unit,

he was responsible

for completing the day and peak shift

surveillance.

Prior to turnover to the next

RCO,

he signed off

the

AP 1-0010125

check sheet indicating that the

CEA position

indicator surveillance

had

been

completed.

The next midshift ANPS, during his documentation

review on

October

20, discovered that the surveillance

had

been

missed

for the day and peak shift.

The readings

were then taken at

approximately

1:00

AM on October 20.

The total time between

surveillances

was approximately

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

the

allowable interval including

a 25 percent

extension

period of

15 hours1.736111e-4 days 0.00417 hours 2.480159e-5 weeks 5.7075e-6 months .

Since the pulse counting channels

and

CEA reed switch positions

were both operable

and alarms

were available to indicate

any

significant

CEA misalignment, this item had minimal safety

significance.

It has

been

noted that the licensee's

current practices

permit

operators

to complete surveillances

such

as this

and later sign

off the check sheet

near the

end of their shift.

Had the check

sheet

been required to be signed off when the surveillance

was

actually done vice the

end of the shift, then this event would

not have occurred.

This licensee identified and corrected violation is being

treated

as

a Non-Cited Violation, consistent

with Section VII

of the

NRC Enforcement Policy,

and will be identified as

335/95-18-05,

"Missed Surveillance

on

CEA Position Indication."

Hissed Surveillance

on

RCS Born Sample

Unit 2 Technical Specification 3. 1.2.9 requires that boron

'oncentration

shall

be verified consistent with Shutdown Margin

in Mode 6 by sampling the

RCS at

a frequency determined

by the

number of operable

charging

pumps.

The

AS requires that all

operations

involving core alterations

or positive reactivity

changes

be suspended if the

TS requirement

is not met.

At.approximately 6:00

AM on October

20 the Shift Technical

Advisor identified that two charging

pumps were operable

and

that the

RCO was logging the Boronometer readings

hourly to

verify Born concentration.

After review, it was determined

31

that sampling vice using the boronometer

was required

and that

with

2 charging

pumps operable the'ampling

frequency

was

95

minutes.

Further review by the operators

found that this

TS

had

been

met by using the boronometer

since entering

Mode

6 at

4:30

AM on October

18.

During this time span Chemistry

had

been taking

RCS samples

every

72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months

as required

by TS

4. 1.9.2.

Upon identification of this item the

NPS directed

that

2C Charging

pump

be disabled

and Chemistry to begin taking

samples

every

220 minutes

as required with I Charging

pump

available.

During the

above time span

when samples

were not

taken,

the boronometer

'readings

showed that

RCS boron

concentration

was consistent with the shutdown margin

requirements,

and

no core alterations

or positive reactivity

changes

had occurred.

The inspector verified this action

had

been

taken

and the readings

were current

by log reviews.

The licensee's

above corrective actions

were adequate

to

prevent recurrence

of the event.

However,

the inspector

noted

that the licensee's initial evaluation of the event

found that

the licensee's

method of scheduling

and tracking this

surveillance,

AP 2-0010125,

Rev 55,

"Schedule of Periodic Test,

Checks

and Calibration," check sheet

I item ll was poorly

worded

and possibly misleading to the operator.

The inspector,

on conducting

an evaluation of the licensee

action to correct

this procedural

deficiency, visited the control

room on October

26

and found that

a procedure

TCN had not been

issued to clear

up the procedural

questions

and the operators

on watch did not

understand

this problem

and the correct

TS interpretation or

the operator actions that should

be taken.

Based

on the above,

the inspector

met with the Operations

Supervisor

who stated

that the task of correcting the procedure

had

been

assigned

to

a night shift NPS.

A procedure

change

was

implemented

on

October

26, to address

this issue.

It was noted that since the

boronometer

was in service

and

used during this time span

and

since the correct

boron concentration

was maintained, this item

has little safety significance.

The licensee identified and

corrected violation is being treated

as

a non-cited violation,

consistent with Section VII of the

NRC Enforcement Policy and

will be identified as

NCV 389/95-l8-06,

"Hissed

RCS Boron

Concentration

surveillance during Mode 6."

5.

Engineering

Support

(37551)

a.

Review of adequacy of Spent

Fuel

Pool Cooling Design

assuming

single

failure.

The inspector

reviewed the both unit's

FSARs

and

spoke with Reactor

Engineering

regarding

the Spent

Fuel

Pool Cooling Design issue

addressed

in the Region II Director of Reactor Projects

memo to all

Region II SRIs.

This issue

questioned:

32

1)

Is the Spent

Fuel

Pool

heat

removal capability based

on the

assumption

that only 1/3 of the core would be off-loaded,

rather

than the full core

as

has

become

the standard

practice

at

some sites

and,

2)

Is the Spent

Fuel

Pool heat

removal capability adequate

in this

case

assuming

single failure.

a)

Unit

1 was designed

to maintain

a storage

capacity of no

more than

1706 fuel assemblies

(7 2/3 cores of spent fuel

assemblies,

control element

assemblies,

new fuel during

initial core loading

and the spent fuel shipping cask).

Two thermal

loading analyses

have

been performed;

the

Normal. Batch Discharge

and the Full Core Discharge.

In

the case of the Normal

Batch Discharge,

the analysis

assumes

that

18 batches

of 80 assemblies

each

have

been

discharged

from the core in

18 month intervals,'

refueling batch of 80 assemblies

was

added

150 hours0.00174 days 0.0417 hours 2.480159e-4 weeks 5.7075e-5 months after

reactor

shutdown.

This analysis

showed

a maximum pool

bulk temperature

of 133.3 degrees

F with the fuel pool

cooling system in service.

For the Full Core Discharge,

assuming that

73 of the assemblies

have

90 days of

irradiation,

72 have

21 months of irradiation

and the

remaining

72 assemblies

have

39 months of irradiation (217

assemblies total), the analysis

showed

a maximum pool bulk

temperature

of 150.8 degrees

with the fuel pool cooling

system in service.

Unit

1 has

2 fuel pool cooling

pumps supplying flow

through

a single spent fuel pool heat exchanger.

The Unit

1

FSAR requires

2 fuel pool

pumps

and the heat

exchanger

in service for an abnormal,

or full core offload.

FSAR

section

9. 1.3.4.3 states

" In the event of a complete loss

of cooling capability, there is sufficient time to provide

an alternate

means of cooling".

The inspector

has

requested

a clarification of this section

from the

licensee.

b)

There were currently 973 spent fuel assemblies

and

16

miscellaneous

assemblies

in the Unit

1 Spent

Fuel

Pool.

Existing space

allows for operation until the year 2007.

Unit 2 was designed

to maintain

a storage

capacity of no

more than

1076 fuel assemblies

(approximately

5 full cores

and the fuel handling tools).

Two thermal

loading analyses

have

been

performed;

the

Normal

and the Accident Case

Assumptions.

The Nor'mal

Case

assumes;

1.

11 batches

(each

1/3 core) discharged

33

2.

Host recent

batch cooling for five days after

shutdown

3.

Adiabatic heat

up of the pool

The analysis

showed

a maximum pool bulk temperature

of 131

degrees

F with the fuel pool cooling system in service.

The Accident Case

assumes;

1.

11 batches

plus

one full core discharged

2.

One (1) core cools for 7 days

3.

Host recent

1/3 core batch cools for 90 days

This analysis

shows

a maximum pool bulk temperature

of 148

degrees

F with the fuel pool cooling system in service.

Unit 2 has

redundant trains of spent fuel pool

pumps

and

heat exchangers.

Under accident conditions, i.e. loss of

1 train,

pool temperatures

are expected

to rise to

approximately

155-160

F.

This exceeds

the

SRP Subsection

9.1.3 recommendations,

however,

the licensee

considers

this to be acceptable.

There are currently 544 spent fuel assemblies,

84 new fuel

assemblies

and

5 miscellaneous

assemblies

in the Unit 2

Spent

Fuel

Pool.

Existing space

allows for operation

until the year 2002.

6.

Plant Support

(71750)

a.

Fire Protection

During the course of their normal tours,

the inspectors

routinely

examined

facets of the Fire Protection

Program.

The inspectors

reviewed transient fire loads,

flammable materials

storage,

housekeeping,

control

hazardous

chemicals,

ignition source/fire risk

reduction efforts, fire protection training, fire protection

system

surveillance

program, fire barriers, fire brigade qualifications,

and

gA reviews of the program.

No deficiencies

were identified.

'.

Physical

Protection

During this inspection,

the inspector toured the protected

area

and

noted that the perimeter

fence

was intact

and not compromised

by

erosion or disrepair.

The fence fabric was secured

and barbed wire

was angled

as required

by the licensee's

Physical

Security Plan

(PSP).

Isolation zones

were maintained

on both sides of the barrier

and were free of objects

which could shield or conceal

an

individual.

34

The inspector

observed

personnel

and packages

entering the protected

area

were searched

either

by special

purpose detectors

or by a

physical

patdown for firearms,

explosives

and contraband.

The

processing

and escorting of visitors was observed.

Vehicles were

searched,

escorted,

and secured

as described

in the

PSP.

Lighting

of the perimeter

and of the protected

area

met the 0.2 foot-candle

criteria.

In conclusion,

selected

functions

and equipment of the security

program were inspected

and found to comply with the

PSP

requirements.

c.

Radiological Protection

Program

Radiation protection control activities were observed to verify that

these activities were in conformance with the facility policies

and

procedures,

and in compliance with regulatory requirements.

These

observations

included:

Entry to and exit from contaminated

areas,

including step-off

pad conditions

and disposal

of contaminated

clothing;

Area postings

and controls;

Work activity within radiation,

high radiation,

and

contaminated

areas;

Radiation Control Area

(RCA) exiting practices;

and,

Proper wearing of personnel

monitoring equipment,

protective

clothing,

and respiratory equipment.

7.

Other Areas

Susan Clark,

Chairman of the Florida Public Service

Commission visited

the plant

on September

22.

She

was provided

an overview and tour of both

units.

The SRI attended

a working lunch, question

and

answer session,

with the Chairman

and her staff assistant,

Mr,

W. Berg,

and the licensee.

8.

Exit Interview

The inspection

scope

and findings were

summarized

on November

1,

1995,

with those

persons

indicated in paragraph

1 above.

The inspector

described

the areas

inspected

and discussed

in detail the inspection

results listed below.

The licensee

questioned

violations 389/95-18-02,

"Failure to Follow Clearance

Procedures,"

and 389/95-18-03,

"Failure to

adequately

Design

and Test

Emergency Diesel

Generator

2A/B Engineered

Safety Feature

Control Logic."

They stated that since the first item was

identified and corrected

by the licensee it should

be

a non-cited

violation.

The inspector

acknowledged

that the item could have

been

non-

cited but since this item was

one of the

many examples of procedural

noncompliance

identified in the past several

months,

the licensee's

corrective actions for these

previous violations should

have reinforced

the need for procedural

compliance

and prevented this violation.

35

The second

item involved the inadequate

design of EDG

2 A/B ESF control

logic, the licensee

stated that this item was the result of an error in

the initial design which had

been detected

by a recently

improved

integrated

safeguards

test procedure.

Therefore,

they felt that this

item'hould also

be non-cited.

The inspector

noted that even

though it

was

an old design

issue,

the licensee,

in the past

18 months

had done

extensive

research

into these

design features

while upgrading the

ESF

test procedure

in response

to two violations in this area.

Since this

afforded the licensee

ample opportunity to identify this error, the

NRC

did not exercise discretion

on this item.

Proprietary material is not

contained

in this report.

~T

e

Item Number

Status

50-335/95-18-01

Open

50-335/95-18-02

Open

50-389/95-18-03

Open

Descri tion

"Failure to Follow Procedures

and

Maintain Current

and Valid Log

Entries in the

Rack Key Log and

Valve Switch Deviation Log,"

paragraph

3.a,

"Failure to follow clearance

procedures,"

paragraph

3.c.

"Failure to Adequately Design

and

Test the

Emergency

Diesel

Generator'

A/B Engineered

Safety

Feature

Control Logic," paragraph

4.b.

50-389/95-18-04

Closed

50-335/95-18-05

Closed

50-389/95-18-06

Closed

URI

50-389/95-05-03

Closed

" Inadequate Verification of ICI

Wiring Connections After

Reassembly,"

paragraph

4.a.

"Hissed Surveillance

on

CEA

Position Indication," paragraph

4.b.

"Hissed

RCS Boron Concentration

surveillance during Mode 6,"

paragraph

4.b.

" Incore Instrument Wiring

Errors," paragraph

4.a

~

9.

Abbreviations,

Acronyms,

and Initialisms

AB

ACC

ADM

AEOD

AFAS

Auxiliary Building

Heating Ventilation and Air Conditioning

Administrative Procedure

Analysis

and Evaluation of Operational

Data, Office for (NRC)

Auxiliary Feedwater

Actuation System

V

36

AFW

ANPO

ANPS

ATTN

CFR

CIAS

CR

CWD

dpm

F

FR

FRG

gpm

HUR

HVA

HVAC

HVE

IAW

ICI

ICW

IR

J/LL

JPN

KW

Auxi1 iary Feedwater

(system)

Auxiliary Nuclear Plant [unlicensed]

Operat

Assistant

Nuclear Plant Supervisor

Administrative Procedure

Attention

Cubic Centimeter

Component

Cooling Water

Control

Element Assembly

Control

Element Drive Mechanism

Cubic Feet per Minute

Code of Federal

Regulations

Containment Isolation Actuation Signal

Control

Room

Containment

Spray Actuation System

Circulating Water

Control Wiring Diagram

Circulating Water

Pump

Design Basis Accident

Diesel

Generator

Disintegration

Per Minute

Demonstration

Power Reactor

(A type of oper

Emergency

Core Cooling System

Emergency

Diesel

Generator

Executive Director for Operations,

Office o

Emergency

Response

Data Acquisition Display

Engineered

Safety Feature

Engineered

Safety Feature Actuation System

Fahrenheit

Flow Control Valve

Fuel Oil

The Florida Power

& Light Company

Federal

Regulation

Facility Review Group

Final Safety Analysis Report

Feedwater

Gallon(s)

Per Minute (flow rate)

Hydraulic Control Valve

High-Efficiency Particulate Air

Health Physics

High Pressure

Safety Injection (system)

High Radiation Area

Heatup

Rate

Heating Ventilation and Air Conditioning

Heating

and Ventilating Exhaust

(fan, syste

In Accordance

With

Incore Instrument

Intake Cooling Water

[NRC] Inspection

Report

Jumper/Lifted

Lead

(Juno

Beach)

Nuclear Engineering

KiloWatt(s)

or

ating license)

f the

(NRC)

System

m, etc.)

LCO,

HSIS

MWe

No.

NOT

NPF

NPS

NPWO

NRC

NWE

ONOP

OP

PCH

PGM

PHT

PORV

psi

psia

PSL

PSP

PWO

PWSCC

gA

gC

gSL

RAS

RCB

RCO

RCP

Rev

RFO

RI I

RH

RPV

RTGB

RWT

37

TS Limiting Condition for Operation

Loss of Offsite Power

Low Pressure

Safety Injection (system)

Hain Feed

Water

Hain Steam Isolation Signal

Motorized Valve

Reactive

Load

Megawatt(s),

Electrical

[Energy from the Electrical Generator]

NonCited Violation (of NRC requirements)

Number

Normal Operating

Pressure

Normal Operating

Temperature

Nuclear Production Facility (a type of operating license)

Nuclear Plant Supervisor

Nuclear Plant Work Order

Nuclear Regulatory

Commission

NRC Office of Nuclear Reactor Regulation

Nuclear Watch Engineer

Overload

Off Normal Operating

Procedure,

Out Of Service

Operating

Procedure

Operations

Operator

Work Around

PerCent Milli (0.00001)

Procedure

Change

Request

NRC Public Document

Room

Plant General

Manager

Post Maintenance

Test

Power Operated Relief Valve

Pounds

Per Square

Inch

Pounds

per square

inch (absolute)

Plant St.

Lucie

Physical Security Plan

Plant Work Order

Primary Water Stress

Corrosion Cracking

guality Assurance

guality Control

guality Instruction

guality Surveillance Letter

Recirculation Actuation Signal

Reactor

Containment Building

Reactor Control Operator

Reactor Coolant

Pump

Reactor Coolant

System

Revision

Refueling Outage

Region II - Atlanta, Georgia

(NRC)

Radiation Monitor

Reactor

Pressure

Vessel

Reactor Turbine Generator

Board

Refueling Water Tank

SNPO

St.

TCN

TS

UGS

URI

VAR