ML17228B324

casing driven by an auxiliary impeller affixed to the

pump

shaft).

Seal

Failure-

On August 2, while performing

a Unit

1 heatup following

Hurricane Erin, operators

noted that the middle seal cavity of

the

1A2

RCP indicated

a pressure

which approximated

RCS

pressure,

indicating

a failure of the lower seal of the

package.

Operators

subsequently

entered

ONOP 1-0120034,

Rev 34,

"Reactor Coolant

Pump," which required,

upon

identification of a failed seal,

that seal

parameter

data

be

recorded

every 30 minutes to ensure that additional

seal

stages

were not degrading.

Throughout the day,

the licensee

considered

the option of

"restaging" the seal

package.

The process

involved opening

vents associated

with each

seal cavity in an effort to increase

the differential pressure

across

each

seal

stage

which, in

principle, would force moving and stationary

seal

faces

together

more tightly, thus reestablishing

the seal.

The

evolution was describeg

in

OP 1-0120020,

Rev 72, "Filling and

Venting the

RCS," Appendix

E, "Restaging

Pump

Seals."

According to various personnel

in the licensee's

Operations

organization,

the process

had

been successfully

applied several

times in the past.

The licensee

opted to perform the

procedure,

and informed the inspector of their intentions.

The

inspector

was not familiar with the process;

however,

in

discussions

with the licensee,

the inspector

was informed that

the process

had

been

performed satisfactorily in the past, that

a procedure

existed for the process,

and that experienced

ANPSs,

who had performed

the procedure

in the past,

were being

assigned

to the task.

At 5: 17 p.m.

on the

same

day,

the licensee

be'gan

the restaging

process.

Plant conditions at the time were

Node 3,

1450 psia,

370'F, with RCPs in operation. 'er the governing procedure,

the controlled bleedoff cavity was vented,

followed by the

upper

and middle cavities.

At this point, flow out the vents

was expected

to decrease

as the lower seal

stage

restaged;

however,

flow did not diminish and, after approximately I

minute, black material

was noted to be in suspension

in the

vented reactor coolant

from the middle cavity.

Additionally,

the water temperature

was noted to increase

rapidly.

Operators

closed the middle cavity vent valve

and noted that,

almost

immediately,

black, hot, water issued

from the upper seal

cavity vent, indicating

a middle seal failure.

Operators

immediately closed the vent valves associated

with the upper

seal cavity and the controlled bleedoff cavity.

At 5:50 p.m., control

room differential pressure

indications

were received

which confirmed that both the lower and middle

seal

stages

had failed.

Controlled bleedoff flow iricreased to

greater

than 3.5 gpm.,

which indicated degradation

of the upper

seal.

At 6: 10 p.m.,

a cooldown

and depressurization

of the

unit commenced.

At 6:40 p.m.,

the

1A2

RCP was secured

and

lower seal cavity temperatures

were noted to increase

to 300'F

due to the increased

leak rate through the seal

package

and the

lack of auxiliary impeller-driven cooling

(as

a result of

securing the pump).

A.

NSIS Actuation

As the cooldown proceeded,

SG pressure

decreased

and,

at

approximately

700 psig,

annunciators

9-18 and g-20,

"HSIS

Actuation Channels

A/B Block Permissive,"

illuminated.

These

were expected

alarms,

as cooldowns naturally result

in

SG pressure

decreases

below the HSIS setpoint.

HSIS

block keys were provided for this eventuality to prevent

NSIS actuations

under non-accident

related conditi'ons of

low SG pressure.

The desk

RCO,

who was performing cooldown-related

duties

at the subject

area of the control panels,

acknowledged

the annunciators

and later reported

observing that the

MSIVs and NFIVs were in their post-NSIS positions

as

a

function of the cooldown.

Consequently,

the

RCO elected

not to insert the

MSIS block and returned to

VCT degassing

operations.

The

RCO was then questioned

by an

STA as to

the failure to block the MSIS.

The

RCO responded

that,

as

the NSIVs and

MFIVs were in their post-trip positions,

the

actuation

would not present

a problem.

The board

RCO (the

second of the two

RCOs performing the cooldown)

became

involved and directed that the

NSIS be blocked.

Before

the keys could

be inserted

to block the signals,

SG

pressure fell below the actuation setpoint

and

an HSIS was

received.

The signal

was later blocked

and reset.

The inspector

reviewed

HPES '95-07,

Rev 2, the licensee's

review of the event.

In it, the licensee

determined that,

in "Summary of Factors that Influenced

Human Performance,"

the event

was the result of a lack of knowledge

on the

part of the desk

RCO that

an HSIS was reportable

to the

NRC whether or not components

changed

state.

Under

'"Summary of Causes,"

the licensee cited the following

causal

factors:

~

Training/gualification:

The licensee

determined that training had not

educated

operators

as to the reportable

nature of ESF

actuations,

whether or not components

changed state.

~

Supervisory

Hethods - Progress/Status

of Task not

Adequately Tracked:

The licensee

determined that the

ANPS and

NPS were

too involved in the diagnosis of the

RCP seal

failures

and were not observing the overall

cooldown

in progress

at the time.

~

Work Practices

- Pertinent

Information not

Transmitted:

The licensee

determined that the desk

RCO did not

announce

to the rest of the control

room that the

annunciators

had

been received;

thus,

ANPS/NPS

involvement to establish

the

NSIS block was not

obtained.

~

Work Practices - Document

Use Practices

Documents

not Followed Correctly:

The licensee

determined that

OP 1-0030127,

Rev 68,

"Reactor

Plant

Cooldown

Hot Standby to Cold

Shutdown," contained

a step requiring the operator to

block the

MSIS when the permissive

was received;

however,

the step

was contained further into the

procedure

than the operator

had proceeded.

Additionally, the licensee

determined that the

operator

had failed to refer to the annunciator

response

procedure,

which directed that the block

keys

be inserted.

The licensee's

proposed

corrective actions for this event

included:

~

Re'vising operator training to include "the necessity

to block

ESFAS

and other reportable, actuations

when

they alarm...The plant's operating

philosophy of

keeping

Licensee

Event Reports to

a minimum should

also

be included

and stressed."

10

~

Including the event in Licensed Operator

Requalification Training.

~

Emphasizing that control

room management

should

maintain

a "big picture" view of plant evolutions,

that formal crew communications

should

be employed,

and that procedures

are followed.

The inspector

concluded that the licensee's

investigation

was weak in that:

~

The operator's

knowledge of procedural

requirements

prior to the event

was not reported (i.e. did the

operator

know that the

OP 1-0030127 required that the

HSIS

be blocked?).

~

The conclusion that the operator's

lack of knowledge

of the reportability of the HSIS actuation

was

a

principle contributor to his actions

appeared

to

place

more importance

on avoiding

an administrative

burden

and the visibility of reporting actuations

to

the

NRC, than it did on knowledge of,

and adherence

to, procedural

requirements.

The inspector discussed

the subject report with the

licensee.

Operations

management

stated that the operator

in question

reported

being confused

at the time and that

it was their expectation that,

under

such circumstances,

operators

would refer to the annunciator

response

procedures

provided for each annunciator

panel.

Management further stated that it was not their

expectation that

RCOs would be familiar with NRC reporting

requirements

(reportability knowledge

was said to be the

responsibility of ANPS/NPSs

and

STAs)

and that operator

actions

should

be based

upon procedure

requirements,

as

opposed

to reportability.

The inspector

reviewed

OP 1-0030127

and found that step

8.21 directed that "At 700 psia

S/G pressure,

Annunciators

g-18 and g-20,

HSIS Actuation Channels

A/B Block

Permissive, will alarm.

Block HSIS by placing HSIS block .

key switch to

BLOCK position."

Additionally,

ONOP 1-

0030131,

Rev 60, "Plant Annunciator Summary," specified

that,

upon valid receipt of annunciators

g-18 and g-20,

operators

were to immediately block MSIS channels

A and

B,

respectively.

The inspector

concluded that the failure of

the

Desk

RCO to perform step 8,21 of OP 1-0030127 is

a

violation (VIO 335/95-15-01,

"Failure to Follow Procedures

and Block MSIS Actuation".

Following the HSIS, the cooldown

was temporarily suspended.

At

approximately 8: 18 p'.m.,

an annunciator

was received indicating

11

that reactor cavity leakage

exceeded

1 gpm.

Operators verified

that control

room instruments

indicated

an increased

leak rate

from approximately

.25

gpm to approximately

2 gpm.

The leakage

was identified as being related to the

1A2

RCP vapor barrier.

Operators

entered

ONOP 1-0120031,

Rev 23,

"Excessive

Reactor

Coolant

System

Leakage,"

at 8:24 p.m.

At 8:44 p.m., safety

function status

checks

were completed satisfactorily.

At 9:25

p.m., the licensee

declared

an Unusual

Event based

upon

occurrences

that warrant increased

awareness,

specifically,

due

to concerns

over further

RCP seal

degradation.

At 6:30 a.m.

on

August 3, the Unusual

Event was terminated

based

upon the

reduction in

RCS leakage

through the

1A2

RCP seal

(due to

depressurization)

and

on stability of plant conditions.

The licensee

performed

a cooldown/depressurization

of Unit

1

and replaced

the subject

seal

package.

The failed package

was

then disassembled

in an attempt to determine

the root cause for

=the failures.

At the close of the inspection period,

the

licensee

had not concluded its root cause investigation..

The

inspector

discussed

the effort with the licensee,

The most

probable root causes

for the noted conditions

were described

as

follows:

~

The most probable root cause for the indicated failure of

the lower seal

was destaging.

Upon restaging,

the carbon

face of the lower seal

was believed to have

been forced,

rapidly, against its mating seal

face, resulting in

fracture.

The most probable

cause for the middle seal failure and

degradation

of the remaining seals

was stated to be

a

reduction in cooling

and lubricating flow though the seal

as

a result of the venting of the seal cavities.

The

subsequent

torque,

imposed

due to pump rotation without

lubrication, fractured the middle seal rotating face.

Following the failure of the

1A2

RCP seal

package,

the

PGM

initiated

STAR 950849 to perform

a self-assessment

of the

decision

making process

that led to the restaging of the seal.

The conclusions

reached

in the self-assessment

were that the

one-on-one

nature of the decision

making process

precluded

a

"synergistic environment."

The study went

on to state that,

while several

individuals expressed

concern

over the prospects

for success,

no specific technical

issue

was raised.

The

licensee

determined that the existing Nuclear Policy 105

process,

which required multidisciplinary review of proposed

abnormal activities,

should

be expanded

such that it is

employed

when questions

of procedure applicability are raised.

The insp'ector

reviewed available

information regarding

seals

and restaging.

The following was noted:

12

~

OP 1-0120020,

Rev 72, "Filling and Venting the

RCS,"

contained,

in the

base

procedure,

precaution

4.2 which

stated

"Do not attempt to vent if the

RCS temperature

is

above 200'F."

Initial conditions specified in the

base'rocedure

were consistent

with the Cold Shutdown

mode of

operation.

~

OP 1-0120020,

Rev 72, "Filling and Venting the

RCS,"

Appendix E, "Restaging

Pump Seals,"

included only two statements

that could

be construed

as'nitial

conditions or'recautions.

One

was in the form of

a note

and the other in the form of a caution.

The note

stated

"Ensure

seal

injection is aligned

and in service."

The caution stated

"If RCS is greater

than 200'F,

Then

use

caution

when venting."

~

FSAR section 5.5.5.2 stated

that the vapor seal

was

designed

to withstand

RCS operating

pressure

when the

RCPs

were idle.

~

The restaging

process

described

in Appendix

E of OP 1-

0120020

was substantially

the

same

as the seal

package

venting procedure

described

in the vendor technical

manual

for the

RCP.

However,

the venting procedure

in the

technical

manual directed that the venting

be performed at

approximately

200 psi with an idle pump.

Safety Evaluation JPN-PSL-SENJ-93-001,

Rev 1, "Deletion of

RCP Seal Injection," included,

by reference,

FPL letter L-

81-107 to the

NRC reporting test results for RCP seals

in

postulated

station blackout conditions.

The results of

the tests

were that,

under simulated

Hot Standby

conditions,

a maximum of 16, 1 gph was recorded after 50

hours without cooling water flow to the seal

package.

~

The vendor

recommended

a maximum seal

package

temperature

of 250'F based

upon the rubber components

in the seal

package.

Safety evaluation

JPN-PSL-SENJ-93-001

provided

analyses

to increase

the temperature limit to 300'F.

~

The licensee

produced

a Byron-Jackson letter,

dated

November

16,

1990,

which reported

a review of St. Lucie's

proposed

restaging

process.

The letter stated that the

proposed

process

was acceptable.

The letter also stated

that application of the process

sh'ould consider initial

seal

condition

and

age in determining whether to apply the

process.

The inspector

concluded that the licensee

had reason

to believe

that restaging

the

1A2

RCP seal

package

would correct the

identified condition.

Vendor information and

knowledge of

previous successful

restagings

tended to support the evolution.

13

However, 'the inspector

found that the procedure

appendix which

directed

the evolution did not require initial conditions

sufficient to ensure that seal

package

temperature

limitations

would be observed.

In fact, the "Caution" statement

of the

Appendix (advising caution if RCS temperature

exceeded

200'F)

ran counter to precaution

4.2 of the base

procedure

(precluding

venting if RCS temperature

exceeded

200'F).

Absent

any

modifying information in Appendix

E, the inspector concluded

that the initial conditions specified in the base

procedure

applied to the procedure

and its appendices.

Consequently,

the

failure of the licensee

to adhere to the initial conditions

specified in

OP 1-0120020 is the first example of a violation

of failure to follow procedure

during

RCP Seal

restaging

(VIO

335/95-15-02,

"Failure to Follow Procedures

during

RCP Seal

restaging").

The inspector

noted that control

room logs did not reflect 'the

alignment of seal injection, while the note of Appendix

E of OP

1-0120020 required

seal

injection.

When questioned,

the

licensee

stated that seal

injection was not aligned

due to

concerns

for the affect it might have

on the

RCP shaft.

When

asked

why a

TC had not been

made to the Appendix, the licensee

had

no explanation.

The licensee's. failure to align seal

injection to the

1A2

RCP prior to restaging

the pump's

seal

is

the

second

example of a violation of failure to follow

procedure

during

RCP Seal

restaging

(VIO 335/95-15-02,

"Failure to Follow Procedures

during

RCP Seal restaging").

The inspector

reviewed

ONOP 1-0120034,

Rev 34,

"Reactor Coolant

Pump,"

and found that, while actions

were described for the

failure of one

RCP seal

(30 minute readings

to ensure

degradation

is not'ccurring - step 7.2.8.C),

and more than

one

RCP seal

(unit shutdown,

secure

RCP when

TCBs open

step

7.2.8.0),

no actions

were specified for the instance

when

3

seals,had

failed.

As stated

above,

the fourth, vapor,

seal

was

only designed

to contain

system pressure

when

an

RCP is idle.

The failure of ONOP 1-0120034 to direct the securing of an

when

3 seals

have failed was found to be in contradiction to

the design

parameters

of the

RCP.

The inspector

brought this

to the attention of the licensee.

The licensee

reviewed the

issue

and stated that

PCRs would be prepared for the

RCP off-

normal

procedures

for each unit, adding

a requirement

to trip

the unit and secure

the affected

RCP should third stage

seal

failure occur.

In conclusion,

the inspector

found that the activities relating

to the failure of the lower seal of the

lA2 RCP were poorly

considered

in that the restaging

process

was 'applied in

inappropriate plant conditions.

The failure to establish

proper initial conditions 'for the restaging

was found to

exacerbate

the seal's

already

degraded

condition.

The

inspector further concluded that two examples of procedural

14

noncompliance

were associated

with the seal

restaging effort

and that one example of procedural

noncompliance

was associated

with the HSIS actuation.

The licensee's

evaluation of the HSIS

actuation

was found to be inappropriately

focused

on event

reportability,

as

opposed

to procedure

compliance.

The

licensee's

self-assessment

of the decision

making process

that

led to the restaging of the

1A2

RCP was found to be

commendable.

OP 1-0120034

was found to include inconsistencies

between

the base

procedure limitations and those

found in

Appendix

E of the

same

procedure.

A'weakness

was identified in

ONOP 1-0120034,

in that design limits of the

RCP seal

package

vapor seal

were not properly incorporated

into the procedure.

4)

Reduced

Inventory for RCP Seal

Replacements

On August 5, Unit

1 entered

a reduced

RCS inventory condition

to support

RCP seal

replacement

work.

The following items were

observed

during this evolution:

~

Containment

Closure Capability

Containment

was

established

and maintained during the evolution.

The

equipment

hatch

had

been

open prior to draindown,

but it

was replaced,

and the personnel

hatch closed,

once

equipment required for the

RCP maintenance

was in

containment,

RCS Temperature

Indication - Normal

mode

1

CETs were

available for indication,

I

RCS Level Indication

-. Independent

RCS level indications

were available.

A Tygon tube level indicating standpipe,

in the containment

was

manned during the draindown

and

was

displayed,

via closed-circuit televisi'on,

in the control

room.

The inspector walked

down the tygon standpipe

and

verified it to be correctly aligned

and free of obvious

kinks which would adversely affect its operation.

Additionally,

a wide range pressurizer

level transmitter

provided level

and trend indications

in the control

room.

RCS Level Perturbations

- When

RCS level

was altered,

additional operational

controls were invoked,

At plant

daily meetings,

operations

took actions to ensure that

maintenance

did not consider performing work that might

effect

RCS level or shut

down cooling.

RCS Inventory Volume Addition Capability

Three charging

pumps

and

a HPSI

pump were availqble for RCS addition.

RCS Nozzle

Dams - Due to the type of outage,

the nozzle

dams

were not installed this time.

15

Vital Electrical

Bus Availability Operations

would not

release

busses

or alternate

power sources

for work during

this evolution.

Both

EDGs were operable,

as were all

offsite power sources.

I

Pressurizer

Vent Path

The manway atop the pressurizer

has

been

removed to provide

a vent path.

The inspector

observed

control

room activities during the

RCS

draindown to reduced

inventory conditions.

The'volution was

performed in accordance

with OP 1-0410022,

Rev 21,

"Shutdown

Cooling," Appendix A,

" Instructions for Operation at Reduced

Inventory or Hid-Loop Conditions,"

and

OP 1-0120021,

Rev 38,

"Draining the Reactor Coolant System."

The inspector verified

that specified conditions

were met prior to the evolution.

The

inspector

found that operators

controlled the evolution well,

that appropriate

cross

checking

between level indications were

performed,

and that procedural

requirements

for waiting periods

between draining stages

were met.

The licensee

exited reduced

inventory conditions following the

RCP seal

replacements

on

August 7.

5)

Containment

Spraydown

A.

Background

The St.

Lucie Unit

1

and

CS systems

are

shown in

Figure

1.

The two systems

are interrelated

in that they

share

the

SDC heat exchangers.

In an accident

mode,

the

SDC heat

exchangers

serve to cool water drawn from the

containment

sump prior to delivery to the containment

environment via the containment

spray headers.

Referring

to Figure

1, the accident

mode flowpath for CS, train A,

involves water traveling into the

A CS

pump,

through the

SDC heat exchanger,

and to the

A CS header in'ontainment.

In a

SDC mode,

the

SDC heat exchangers,

in conjunction

with the

LPSI pumps,

serve to remove heat

from reactor

coolant.

The flowpath in this

mode (again, for the

A

train) involves water flowing from the

RCS hot leg and

through the

A LPSI

pump.

The fluid flow is then split at

FCV-3306, with some water passed

through the valve

and the

balance diverted through the

SDC heat exchangers,

through

NV-3456 and/or HV-3457,

and returned to the

LPSI system

for delivery to the

RCS cold legs.

During power operations,

the two systems. are isolated

from

one another

and

each is aligned to perform its safety

function.

In the case of the

CS system,'his

alignment

involves

an

open flowpath from the

RWT, through. the

pumps,

and

up to FCV-07-1A and

FCV-07-1B, normally closed

AOVs which receive

open signals

in response

to

a

CSAS.

'

0

16

LPS'I System Venting

In February,

the licensee

experienced

a waterhammer

event

in the Unit

1

LPSI system while placing

SDC in service

(see

IR 95-04),

The licensee

determined

that

one of the

potential contributors to the event

was air, trapped

in

system piping.

At approximately the

same,

the licensee

identified

a Unit

2 LPSI

pump in an air bo'und condition

during

a surveillance

run of the

pump.

In response

to

these

events,

the licensee

developed

aggressive

venting

programs for the systems.

As

a part of the effort,

OP 1-

0420060,

"Venting of the

Emergency

Core Cooling and

Containment

Spray Systems,"

was developed.

The procedure

required,

in part, that venting

be performed following SDC

system operation.

The procedure

was approved

on August

13.

As

a part of the venting procedure,

the licensee

pressurized

the lines leading to the

SDC heat

exchanger

via the

pumps

and systematically

di.rected flow to the

RWT in an effort to sweep air from the system.

The

boundary of this venting process

included the

CS lines

up

to the

CS header isolation valves.

FCV-07-1A Inoperability

On August

11,

CS flow control valve FCV-07-IA failed

a

stroke time test

and

was declared

OOS.

As shown

on Figure

1, the valve isolated

the

A CS header

from the

CS system

outside containment.

The valve was designed

to open

on

a

CSAS

and

was

a fail-open

AOV.

The valve was required

by

AP 1-0010125A,

Rev 39, "Surveillance

Data Sheets,"

Data

Sheet

8A, "Valve Cycle Test

Non-Check Valves," to stroke

in less

than

8 seconds.

In the failed test,

the stroke"

was recorded

as 20.3 seconds.

As

a result of the failed surveillance test,

STAR 950869

was generated.

The stroke time failure was documented

and

the

STAR was assigned

to Engineering for disposition.

Engineering

proposed

placing the valve in its safeguards

position

(open)

and prepared

SE JPN-PSL-SENS-95-016,

Rev

0, "Alternative Valve Position for Spray Header Isolation

Valve 1-FCV-07-1A."

The inspector

reviewed the subject

SE.

The purpose of the

valve

and its relationship to containment isolation

and

containment

boundary integrity were found to be

appropriately considered.

The

SE concluded that

no

unreviewed safety question

was introduced

by placing the

valve in an open position.

The

SE went

on to provide

3

"required/recommended"

actions:

0

17,

~

Administrative controls,

consisting of caution tags

and the installation of plastic covers

over switches,

were required to be implemented locally and at the

RTGB for CS

pump

1A to prevent inadvertent

operation

of the

pump.

~

Operators

were to be informed of the

new valve

alignment with emphasis

given to

pump

surveillances

and

A SDC train operation.

~

Procedures

were to be reviewed for impact.

The

SE

stated that,

in lieu of procedure

changes,

administrative controls

may

be used while the valve

was open.

The

SE was

approved

by the

FRG on August

12.

Upon

completion of the evaluation,

the

STAR was turned over to

Mechanical

Maintenance with a required action of restoring

the valve to original design

and to perform

a root cause

investigation into the failure.

The inspector

noted that

the subject

STAR included

no indication that the required

actions listed

above

had

been

completed prior to

Engineering releasing

the

STAR to Mechanical

Maintenance

and prior to Operations

repositioning

FCV-07-1A.

The

inspector questioned

the

STAR coordinator

as to who was

responsible

for ensuring that the SE's required actions

were complete

and

was informed that Engineering,

as the

organization

responsible

for the resolution,

was

responsible.

The

same question

was

posed to the

Engineering Chief Site Engineer,

who stated that the

responsibility for completing the action belonged to

.Operations.

The inspector

reviewed

OI 16-.PR/PSL-2,

Rev 1,

"St. Lucie Action Report

(STAR) Program,"

and found that

the pr'ocedure

was unclear

as to who was responsible for

ensuring

the activities were completed.

As

a result the

inspector

concluded that

a weakness

existed

in the

STAR

program with regard to ensuring that required corrective

actions

were documented

and completed.

On August 15,

a Night Order was issued

which informed

operators

that the unit would be operated

with FCV-07-1A

open.

The Night Order went on to state

"See attached

Engineering evaluation

which includes actions to be taken

to avoid

an accidental

spraydown of containment."

The

SE

limited its consideration for the potential of inadvertent

spraydown to inadvertent

pump starts,

except

as

provided in the

second

required action

summarized

above.

On August

16, caution tags

were

hung

and the valve was

taken to

an

open position.

Containment

Spraydown

J

0

18

On August

18, venting of the

A train was

commenced

per

OP 1-0420060,

Rev 0, "Venting of the

Emergency

Core

Cooling and Containment

Spray Systems."

When the

A train

was pressurized

through the

SDC heat exchangers,

the open

flow path created

to the

A CS header

through FCV-07-IA

allowed water to be drawn from the

RWT and

passed

into the

containment

atmosphere

via the spray header.

Operators

were alerted to the event

by an annunciator

indicating high reactor cavity inleakage. 'ndicated

flow

into the cavity was increasing rapidly and operators

entered

ONOP 1-0120031,

Rev 23,

"Excessive

System

Leakage."

Approximately one minute after the

'nnunciator

was received,

operators

identified the

flowpath leading to the

spraydown

and secured

the

A LPSI

pump.

The spraydown resulted

in

a slight decrease

in

containment

temperature

and pressure.

The licensee

noted

that

90 percent of containment

smoke detectors

alarmed or

faulted

and

an electrical

ground developed

in the lA2 SIT

sample valve

as

a result of the event.

Impact

on Unit

1

The licensee

determined that approximately

10,000 gallons

of water from the

RWT was transferred

to containment

during the event.

The water

was borated

at approximately

2200

ppm.

The spray resulted

in an increase

in

contamination fevels inside containment,

with levels

exceeding

Ix10

dpm/100

cm

in many areas.

Following the event,

the licensee

placed

a hold on all

work on Unit 1.

The unit was maintained

stable in Mode

3

and

management

announced

that it would conduct

a series of

meetings with all plant personnel

to discuss

the recent

events

on Unit

1

and to reiterate

management 'expectations

for worker performance.

Meetings

were held

on August

18

in which the Division President,

the Site Vice President,

and the Plant General

Manager stressed

the

need for worker

vigilance, procedural

compliance,

and

a questioning

attitude

on the part of all plant personnel.

Additionally, plant management

made plans to cool

down

Unit

1 to allow for a decontamination

of containment,

a

repair of FCV-07-1A,

and

a number of other work items

prior to returning the unit to service.

The licensee's initial plans for containment

cleanup did

not bring the contamination levels to pre-event

conditions.

After discussions

with management,

a decision

was

made to expand

the

scope of this cleanup

and

decontamination

to reduce

the

need for additional

cleanup

during the next refueling outage.

0

19

The inspector toured the containment

on August

19.

HP

briefings prior to entry indicated that the majority of

the contamination

was in

a smearable

form.

Containment

cleanup

had

begun,

and guidelines

had

been

developed

and

promulgated

under

LOI-HP-23, "Oecontamination

Following

Inadvertent

Spraydown of the Unit

1 RCB."

The inspector

noted that the

62 ft. elevation of containment

had

been

separated

into quadrants

for initial decontamination.

While light water spotting

was noted

on the outer surfaces

of some equipment,

no obvious

boron deposits

were

identified.

Water was observed

to be puddled in upturned

I-beams supporting floor grating,

but floor surfaces

were

dry.

The licensee

evaluated

the event in Engineering

Evaluation

JPN-PSL-SENS-95-017,

"Assessment

of Inadvertent

Containment

Spray Event."

Items considered

in the

evaluation

included:

~

Boric acid corrosion of carbon steel

components,

potential effects

on

EQ and

non-EQ instrumentation

and electrical

equipment.

~

Potential effects

on cranes

and supports

~

Potential effects

on snubbers

~

Potential

effects

on containment

coatings

Corrective actions resulting

from the evaluation

included

a comprehensive

inspection of components

inside

containment.

Included were visual inspections

of all

snubbers

inside containment

following containment

washdown

for decontamination.

The inspection list compiled by

engineering

included

items to be inspected

by tag number,

the type of inspection to be performed,

acceptance

criteria,'and

actions to be performed if acceptance

criteria was not met.

In all, approximately

1000

individual inspections

were performed.

Of the items

inspected,

only minor deficiencies

were identified.

Evaluation of the Licensee's Activities

The inspectors

concluded that the root cause of the

containment

spraydown

event

was

a failure of OP 1-0430060,

Rev 0, "Venting of the

Emergency

Core Cooling and

Containment

Spray Systems,"

to require

a verification of

initial conditions.

Specifically, the procedure failed to

verify that the

CS system

was in an alignment which was

appropriate for the evolution being conducted.

The

procedure

was revised to remove the subject portion,

leaving only static venting,

on September

1.

The licensee

20,

reached

a similar conclusion

in LER 335/95-007,

and

added

that contributing factors included operators failing to

realize that plant conditions at the time of the evolution

would result in the event.

Additionally, the licensee

identified that the decision to defer the repair of FCV-

07-1A contributed to the event.

The failure to include

appropriate initial conditions in OP 1-0430060 constitutes

a violation (VIO 335/95-15-08,

"Inadequate

Procedural

Initial Conditions" ).

The inspectors

reviewed the licensee's

corrective actions

as they related to containment

inspections

following the

event.

The inspectors

found that the licensee's

evaluation of the event

and the inspection

scope resulting

.from the evaluation

was in agreement

with the

NRC position

on the subject

(as described

in the

NRR DST Safety

Evaluation

on the subject,

transmitted to regional offices

via letter from T.E. Murley on March 13,

1991).

The

licensee's

inspection

was determined

to be comprehensive

in scope

and detail

and adequate

to ensure future

component reliability.

6)

Primary Water Storage

Tank Overfill

On August 19, at approximately 5:30 p.m., the Unit

1

RCO

directed the

SNPO

and

ANPO to fill the

PWST.

At approximately

7:45 p.m., the "Primary Water Tank Level High/Low" alarm

annunciated

in the control

room.

The

RCO directed the

SNPO to

have the

ANPO secure

the fill valve to the

PWST while making

his rounds.

The decision to delay securing

the valve was based

on the

RCO using

a tank strapping table in the control

room

which. showed

a margin of approximately

1.5 feet, from the high

level alarm to tank overflow.

At 8:30 p.m.,

a call

was

received

from the Unit

1 containment

ramp that the

PWST was

overflowing.

At that time the

ANPO and

SNPO were directed to

immediately secure

from filling the

PWST.

The fill valves were

then closed.

It was estimated

that about eleven

thousand

gallons overflowed form the tank.

Chemistry

samples

found that

no release

limit's were exceeded

as

a result this event.

The cause of this event

appeared

to be inappropriate

and

untimely operator

response

to an alarm coupled with an existing

operator work around

on the level control

system for the

PWST.

The

PWST level control valve LCV15-6 had

a history of

unreliability.

Because of this unreliability, the operator

had

been manipulating

V15106 or V15105 which are in series with

LCV15-,6. If this condition had

been correcte'd,

the system

would have

been able to automatically maintain

PWST level.

7)

2A Heater Drain

Pump Trip

21

At 8:20 a.m.,

on August 23, the

"LP Heater

2-4A Level Hi/Lo"

annunciator

alarmed

in Unit 2 control

room.

The operator

observed that

2A condenser

back pressure

had increased

from 4.5

to 4.9 inches

Hg.

Immediately thereafter,

the

2A heater drain

pump tripped.

The control

room operator

immediately entered

ONOP 2-0610031,

Rev

13,

Loss of Condenser

Vacuum,

and

began

reducing

power to maintain condenser

back pressure

to less

than

4,0 in Hg.

Power

was reduced

and the unit was stabilized at 82

percent.

The inspector

responded

to the control

room and

observed this power reduction.

An investigation of the event

by the licensee

found that relay

63X-4A (a

GE

HGA relay),

common to both the

4A alternate

and

5A

normal heater drain valves

had failed.

This failure caused

the

4A alternate

drain valve solenoid to de-energize

and the val've

to fail open.

It also caused

the

5A normal drain valve to fail

closed.

These failures resulted

in a rapid decrease

in level

in the

4A heater

and tripped the

4A heater drain

pump.

The inspector

found that operators

response

to the event

was

timely and correct.

The failed relay was subsequently

replaced.

An investigation

by the licensee

determined that the

relay failure was

due to aging.

A review of other applicable

uses of this type relay by the licensee

found and replaced

several

other

HGA relays in the heater drain system.

The inspector

noted that at least eight other heater drain

pump

trips had occurred

over the past

two years.

None of these

trips were the result of a

HGA relay failure.

The

licensees'eview

of this

and other recent

HDP trips led them to install

a

PC/N in the heater drain

pump protection cir cuiting during this

outage that should result in

a reduction of these

and similar

HDP trips.

The inspector

found that the licensee's

corrective action for

this event

was detailed

and thorough.

However, taking into

consideration

the previous

number of HDP trips that

had

occurred

and the licensee's

knowledge of this problem

and the

needed

changes

clearly indicate that corrective action

on this

item was not timely.

This item is identified as

a weakness

in

corrective action.

Control

Room Logs

On August 24, during

a review of the Unit 2 control

room

RCO

log, the inspector

noted

an entry which stated that

28

EDG had

erratic load swings during the performance of the monthly

surveillance tests.

Further review of the lo'g indicated that

the

EDG was taken out of service to replace

an air start

solenoid valve

and then tested

and returned to service.

The

RCO,

on the shift after this item occurred,

was questioned

on

the entry involving the erratic load swings

and

was not aware

0

22

of the cause

or any corrective action taken

on this potential

deficiency.

This item was discussed

in detail with the system

engineer

who was able to satisfactorily address

this item.

AP 0010120,

Rev 74,

"Conduct of Operations,"

section 2.A.3,

requires that problems

associated

with major equipment

be

logged,

The inspector

noted that the control

room log should

have contained

adequate

information to allow the operator

on

a

succeeding shift to clearly understand

this potential

problem

and

know if it had

been

adequately

addressed

to ensure

operability of this

ESF component.

In addition to the above,

on September

1,

a review of the Unit

1 00S log found that containment

purge valve FCV-25-4 had

PWOs

95013857

and

95004327

and

STAR 94110479

issued

against it.

The

valve had

been

placed in the failed closed position but had not

been

entered

in the

OOS log.

OP 0010129,

Rev 24,

"Equipment

Out of Service," section 3.2, required that inoperable

TS

equipment that is out of service

be logged.

Upon

identification by the inspector this item was entered

in the

00S log.

On September

2, the inspector

noted that clearance

1-95-009-011

had

been

issued to deenergize

1B

EDG fuel oil transfer

pump to

permit work on

a local switch.

A review of the

OOS log and

control

room log also found that this had not been entered

in

either

as required

by the clearance

procedure

OP 0010122 step

5.6.5.

A discussion

with the

RCO revealed that

he did not

think this entry was necessary

since the

EDG was out of service

for other maintenance

activities.

This item was discussed

with

the

ANPS who directed that the appropriate

log entries

be made.

The inspector

noted that all of the

above

items were in a safe

condition

and did not affect system operability.

These

items

do indicate

a weakness

in logkeeping that could result in

operating

the plant with equipment out of service that could be

required for that operational

mode.

This item is identified as

a weakness

in logkeeping

and

a failure to follow procedures.

The licensee

response

to this item has led to significant

improvements

in the

amount of detail provided in control

room

logs.

They also plan to implement computerized

control

room

logs.

Since this item has minimal safety

importance

and

corrective action is underway to prevent recurrence

and the

licensee efforts meet the criteria specified in section VII of

the

NRC Enforcement Policy, it will not be cited.

It will be

identified as

a Non-Cited Violation (NCV 335/95-15-08 "Failure

to Follow Logkeeping

Procedures" ).

Operation of 1B LPSI

Pump with the Suction'Valve

Closed

On August 29, Unit

1 was in mode

5 with both trains of SDC in

operation.

At 2:20 p.m., the

B train of SDC was placed in

23

standby to allow a

SDC hot leg suction valve leak test to be

performed

as specified

in data

sheet

25 of AP 1-0010125A.

Step

6.5.4.B of this test left one hot leg suction valve

V3651 open

and the'ther

hot leg injection valve closed at the completion

of the test.

The

SDC normal operating

procedure

OP 1-0410022,

section 8.3,

was then

used to return the

B train of SDC to

service.

Instead of using the procedure,

the

RCO transposed

the procedural

steps of section 8.3 to

a separate

piece of

paper

and

used this to perform the procedural

steps.

Using

this guidance

he failed to open

and lock open

B hot leg suction

valve V3652 as required

by procedure

step 8.3.7.

The

1B LPSI

pump was then started

by the board

RCO who noted

the starting

surge

on the

pump ammeter

and that the

amperes

had

subsequently

declined

and steadied

out at about

15 amperes.

The

ANPS opened

the

LPSI discharge

valve at the

CRAG panel

to

re-establish

flow in the

B LPSI loop,

The board

RCO did not

recognize that

pump

B amperes

were lower than anticipated.

The board

RCO then went to the

CRAC panel

to initiate flow to

B

SDC HX.

At about 4:45 p.m., the

NPS identified that

pump amperes

were lower than anticipated.

At the

same time the desk

RCO

found that the hot leg suction valve V3652 was shut.

The

1B

LPSI was secured

and the

1B

SDC train was returned to the

standby lineup.

A subsequent

inspection of the

pump determined

that

no apparent

damage

had occurred during the short period of

pump operation.

After an inspection

and evaluation the

pump

was returned to'service

and all parameters

were normal.

An

ASNE Section

XI test

was subsequently

performed satisfactorily.

The failure of the operator to follow OP 1-0410022 is

a

violation (VIO 335/95-15-04,

"Failure to Follow Procedures

during Alignment of Shutdown Cooling System" ).

This failure

could have resulted

in the failure of the

1B LPSI

pump

and

subsequent

loss of one loop of SDC.

1B Emergency

Diesel

Generator

Failure

On August 31, the

1B

EDG tripped due to high crankcase

pressure

in the

12 cylinder engine during the performance of the monthly

surveillance test,

OP 1-2200050B,

"1B

EDG Periodic Test

and

General

Operating Instructions."

Licensee

personnel

found that

the engine coolant expansion

tank had drained

and the engine

oil

sump level

had increased

approximately eight inches

above

normal.

Inspection

by licensee

personnel

revealed that the number nine

power pack crown

and cylinder head

had sustained

severe

damage,

apparently

due to separation

of the northeast

exhaust

valve

head

from its stem.

The failed valve head

became

loose within

the combustion

chamber

and during numerous

strokes

punctured

24

the piston crown

and cylinder,

The engine coolant then'eaked

through the cylinder head

and piston into the oil and entered

the engine

sump,

The source of the high crankcase

pressure

trip was

a combination of intake air and exhaust

gases

escaping

through the failed piston into the crankcase.

The licensee

developed

a root cause

investigation

team

composed

oF personnel

from mechanical

maintenance,

technical staff, site

and corporate

engineering,

and

an engine

vendor representative.

This team performed

a detailed investigation

over several

days

which concluded that the most probable root cause

was:

Cylinder number

9 lash adjuster lock nut loosened.

The

lash adjuster

screw

was then able to back out of position

due to normal operational

vibration.

As the lash adjuster

screw loosened,

the hydraulic lifters

initially compensated

for the increased

height of the

valve bridge assembly.

Eventually the increased

height of

the valve bridge resulted

in impact loading at the locking

ring in the lower spring seat.

The locking ring is

normally unloaded

during operation.

The impact loading eventually

caused

the bridge guide to

fail.

This allowed further bridge movement

and loss of

"zero lash" in the valve train.

The increased

clearances

resulted

in impact loads

being transmitted to the valves

themselves.

The bridge guide failure also increased

wear

on the guide's

lower spring seat.

The impact loading caused

the lock grooves of both east

valve spring

stems to deform due to fretting wear from the

valve spring seat .locks.

The northeast

val've spring seat

eventually failed due to hoop stresses

induced

by the

wedging action of the seat locks.

The failed spring seat

was retained

by the helical spring

coil which initially prevented 'valve stem detachment.

The

additional

clearances

provided

by the failed spring seat

allowed the seat

locks to progressively fail due to

wedging

and point loads until they finally released

the

valve and allowed it to drop into the engine cylinder.

The valve head

separated

from the

stem due to impact

loading

by the piston.

The separated

valve head

was then

loose in the cylinder and punctured

the piston crown and

the cylinder head

when the piston rose.

Engine tripped

on high crankcase

pressure

due to flow of

turbocharged inlet air and exhaust

gases

through the

piston into crankcase.

Water from broken cylinder head

water passages

flowed through the piston into the

25

crankcase

to drain the expansion

tank.

Smaller particles

from the piston

and cylinder head

were blown into the

exhaust ducting.

The inspector

conducted daily meetings with the manager of'the

root cause

team

and discussed

the status of their investigation

and findings.

He also observed

numerous

facets of the licensee

investigation,

inspections,

and repairs to the affected diesel

engine.

The initial plans called for replacement

of the number

9 power

pack (cylinder and piston)

and inspection of all shaft

bearings.

After inspections

found several

metal parts

from the

damaged

number. 9 cylinder in the exhaust

ports of other

cylinders

and

on the engine

exhaust

turbocharger

intake

screens,

the engine inspection

was

expanded

to include all

cylinders,

exhaust

headers,

and bearings.

This inspection

found

some rust in number

12 cylinder and led to replacing that

power pack also.

The inspection of the remaining cylinders

also led to replacing

number

3

and

4 cylinder heads

due to

leaking

valves.'fter

the above repairs

and bearing

inspect'ions,

the engine

was

reassembled

and flushed with new lubricating oil and all

filters were replaced.

As

a result of the root cause

investigation

the lash adjuster locking nuts were torqued to

a

50 ft-lbf value given by the

EDG service

company (this value

had not been previously specified in the vendor manual

or

licensee

maintenance

procedures).

This torquing

was

accomplished

on all cylinders for both the

1A and

1B Unit

1

diesel

engines.

After a series of maintenance

runs

and

adjustments

on September

5 and 6, the

1B

EDG successfully

completed its surveillance test

and

was declared

operable

on

September

6.

The inspector

found the root causes

investigation

team to be

composed of well-qualified individuals.

They pursued

the

issues

associated

with the failure in

a diligent manner

and

worked well with the personnel

performing engine repairs.

The

inspector noted that the licensee's

service

vendor plans to

also perform

a root cause

investigation of this failure.

The inspector

was very impressed

with the teams that worked the

engine repairs

around

the clock.

Their detailed investigation

resulted

in expanding

the scope of inspection

and repair to

cover the entire engine.

The overall repair effort was

strongly supported

by site

and corporate

engineering

and

resulted

in timely completion of the

repairs.'nit

2 Hain Generator

Hydrogen Overpressurization

26

On September

7, at approximately I:30 a.m.,

a

NPO noted that

the hydrogen

pressure

on Unit

2 generator

was at

58 psig.

This

pressure

is normally maintained

at

57 to 60 psig,

The

contact'ed

the

RCO and notified him that

he would be bringing

the pressure

up to approximately

60 psig,

When the hydrogen

supply header

was aligned to the generator,

control

room

annunciator

"H2 Nanf Sply Press

Hi/Lo" alarmed

as expected

due

to low header

pressure

and remained illuminated.

The

NPO left the area to continue his rounds.

At approximately

2:00 a.m.,

the control

room requested

the

NPO come to the

control

room and assist

in a digital electro hydraulic loss of

load test.

This test

was completed

at about 2:24 a.m.

The

then completed his round

and returned

to his office area.

At about 3:20 a.m.,

the

ANPS noticed that the

"H2 Hanf Sply

Press

Hi/Lo" annunciator

was illuminated.

The

RCO checked

the

hydrogen pressure

and found it to be 80 psig.

The

RCO then

directed the

NPO to secure

the hydrogen

and reduce

the

generator

gas pressure

to 60 psig.

Licensee investigation of this event determined that the

and control

room operators

did not apply sufficient detail to

the progress

of this evolution.

The

NPO allowed himself to be

assigned

to another

task

and lost control of the status of the

evolution.

The generator

hydrogen filling evolution was not

adequately

tracked

by the

RCO and

ANPS.

They also permitted

the

"H2 Hanf Sply Press

Hi/Lo" annunciator

to stay illuminated

for about two hours

when the filling evolution should

have

taken approximately

30 minutes.

The licensee

also found that

a

generator

high gas pressure

alarm should

have

sounded

and

actuated

an annunciator

in the control

room.

The local alarms

were found to be inoperable with existing

PWOs that required

work.

This event pointed out

a failure of the

NPO and

RCO to maintain

status while adding hydrogen to the main generator

and the

failure to reset

a control

room alarm.

It also

showed that

an

operator

must stay

aware of the status of alarms

on equipment

and take compensatory

actions if normal

annunciators

are not

available.

This item is identified as

a weakness.

A subsequent

inspection

and evaluation

by the equipment

vendor

determined that the generator

had not been

damaged

as

a result

of this event.

Plant Housekeeping

(71707)

Storage of material

and components,

and cleanliness

conditions of

various

areas

throughout

the facility were observed

and

no safety

and/or fire hazards

were identified.

I

J

0

27

d.

Clearances

(71707)

During this inspection period,

the inspectors

reviewed the following

tagouts

(clearances):

~

1-95-009-011 - on

EDG

1B fuel oil transfer

pump.

The inspector

found the clearance

tag in place

and the breaker

in the off

position

as required.

~

2-95-09-002

control valve V-3661 for SIT outlet drain valve

to

RDT.

The inspector

found the valve in the closed position

with fuses

removed

from RTGB-206.

No deficiencies

were identified.

e.

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

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)

1)

Licensee Self Assessment

The inspector

reviewed

a special

gC assessment

of decisions

'hat

led to the inadvertent

spraydown of Unit

1 containment.

This assessment

was requested

by the

FPL Nuclear Division Vice

President

and focused

on the plant's decision to operate

Unit

1

with FCV 07-1A in the open position

and the development

and

execution of new procedure

OP 1-0420060,

"Venting of Emergency

.

Core Cooling and Containment

Spray System."

This review found

that operating

the

CS system in an abnormal

lineup

and

executing

a new procedure

under this condition,

coupled with

operator error resulted

in spraydown of Unit

1 containment.

The assessment

also noted that schedule

pressure

may have

prevented timely repair of. the

CS valve

FCV 07-1A.

The

inspector

noted that the assessment

was detailed

and provided

some

recommendations

for improvement.

The inspector

also noted that the assessment

identified that

the quarterly surveillance test directed that

FCV 07-lA be

lubricated

immediately prior to the performance of its

scheduled

surveillance.

The inspector questioned this practice

0

28

since prelubricating the valve prior to performance of the

surveillance test would not result in testing the valve's

ability to provide the required

response

time during

an

actuation.

The licensee

agreed with this

and changed .the

procedure

to delete

the prelubrication

under

TCN 2-95-177

on

September

7,

1995.

The inspector also questioned

why

QA had not documented this

deficiency under the

STAR program

as required

by QI 16-PR/PSL-

2,

Rev

1, "St. Lucie Action Report

(STAR) Program," Section

5. 1, "Initiation of a

STAR Form."

As

a result of the question,

a

STAR was generated

on September

6.

The failure to document

the subject finding via the

STAR process

is

a violation (VIO

335/95-15-05,

"Failure to Follow Procedure

and

Document

a

deficiency

on Containment

Spray Valve Surveillance

Test

Procedure" ).

g.

Unit

1 Restart Activities

The inspector

accompanied

maintenance

QC on

a walkdown of the Unit

1

containment prior to unit restart.

This inspection

by

QC was

conducted after departmental. heads

had completed their final

inspection,

as specified in AP 0010728.

It was noted that these

department

tours

had

been

completed

and signed off (with a few

exceptions

for items that would be

as

a part of unit restart).

The

inspector

and

QC identified approximately

40 deficiencies that

needed

to be corrected prior to unit restart.

These

included:

Burned out lights

Hissing covers

on electrical outlets

and components

Electrical

box and panel

covers that

had not been tightened

Areas that needed

additional cleaning

Some small trash

and debris

on top of components

A scaffold that

had not been

removed

Hissing screws

and bolts in various

components

Hissing conduit covers

The inspector

noted that the majority of the deficiencies

were the

responsibility of Electrical Haintenance.

A meeting

was

hei.d with

the Haintenance

Hanager to discuss

the items after the inspection

was complete..

He indicated that these

items would be corrected

prior to restart and,that

responsible

managers

would be counseled

on

this item.

The inspector

found that the

QC walkdown was very thorough.

Discussions

with

QC found that

QC had conducted

several

inspections

prior to this final closeout

inspection to .verify that containment

was being prepared for closeout.

IR 94-24 noted that at the

completion of the Unit

1 refueling outage

in November

1994 the

NRC

also

accompanied

QC on the final closeout

inspection

and identified

similar conditions to that found in this inspection.

That

IR also

identified that heavy management

reliance

was placed

on

QC to verify

\\

0

29

the readiness

of containment

closure.

Although containment

was

returned to

a final satisfactory condition it appears

tliat licensee

management

is employing

gC in a line function rather than quality

verification role.

This item is identified as

a management

weakness.

4.

Haintenance

and Surveillance

'a ~

Haintenance

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)

PWO 61/5570

and

PWO 61/5571

Remove

PORV

1402

and

1404 from

pressurizer,

bench test,

repair

as necessary

and reinstall.

The valves

had

been identified as inoperable

and the

above

PWOs

were generated

to remove the valves,

determine

the cause of

failure and correct.

The valves

were

removed

and worked using

HP 1-H-0037,

Rev 6,

"Power-Operated

Relief Valve Haintenance."

The inspector

observed

selected

portions of the valve

disassembly

and troubleshooting

to determine

the cause of

failure.

These efforts involved several

shifts over several

days.

This work was accomplished

in a contaminated

work area

in Unit 2 RAB.

The inspector

noted that

HP coverage

was

provided

and that

a vendor representative

assisted

maintenance

in this effort.

The inspector

also noted that continuous

supervisory oversight

and engineering

support

were present

in

the field to provide for a timely repair of these

components.

These

items were worked around the clock since they delayed

plant restart.

The inspector also noted that calibrated tools

were being

used

and that

gC provided coverage of this job.

The

inspector

found that work procedures

and

PWO were in the field

and being used.

At the completion of the

above work, the inspector

reviewed the

completed

work package

documentation

and

found that

TC had

been

implemented for requir'ed

procedure

changes,

repair parts,

and

work was correctly documented,

and other support documentation

was properly filled out.

30

Overall,'he

personnel

performing this task were adequately

qualified and

used the appropriate

procedures.

The overall

work effort resulted

in identifying, correcting the problem

and

returning the

PORVs to service.

Adequate supervisory,

engineering,

and vendor support

was provided to successfully

complete the task in

a timely manner.

See

IR 95-16 for a

detailed description of the root cause of the noted

PORV

inoperability.

PWO 1230/65 Perform

PCH 11-195

on

DG IA/1B,

The inspector,

while conducting routine plant inspections,

observed that work on this modification was in progress

on

DG

18.

Two electricians

were completing the work activities

associated

with installing new splice

boxes for the trip

solenoids

on the

12

and

16 cylinder engines for DG 1B.

The

inspector

reviewed the

PWO and procedure that the technicians

were using.

He noted that the work was nearly complete

on the

12 cylinder engine,

but only the first few steps of the

procedure

had

been

signed off.

He questioned

the electrician

as to what work had

been

completed

and the electrician stated

that

he had terminated

the wiring, torqued the connections,

and

applied several

layers of different types of tape in the

sequence

indicated

by the

PC/H.

Noting that only a few steps

of the

PC/H had

been

signed off, the inspector

asked specific

questions

as to the wiring identification, torquing

requirements,

and

sequence

and type of tapes

used.

The electrician

was unable to locate the guidance

provided for

wiring identification for correct termination

and admitted

that,

although

he

had torqued the connection

to the correct

value,

he did not'ocument this in the work package

when the

step

was accomplished.

He also stated that

he

had taken over

this job from another

individual

and

had only scanned

through

the work package

instructions

and details.

Further review of

his work activity and the work package

by the inspector

determined that the connections

had

been correctly made

and the

correct torque value

had

been

used.

The circuitry was tested

on the night of August

31

and

performed satisfactorily.

The inspector discussed

this item in

detail with the Maintenance

Manager

and noted that. not filling

out procedural

steps

as they are accomplished,

doing only

a

cursory review of a work package,

and not being knowledgeable

of all aspects

of the job can lead to serious errors or

mistakes

in the performance of maintenance activities.

The

Maintenance

Manager stated that

he agreed with the inspector's

observations

and that corrective action would be taken in this

concern.

ADM-08.02,

Rev 7,

"Conduct of Maintenance,"

Appendix 5, Step

5,

required that procedures

be present

during work and that

31,

individual steps

be initialed once performed.

The noted

failure of the electrician to initial procedural

steps

on an

as-completed

basis

is

a violation (VIO 335/95-15-06,

"Failure

to Initial Haintenance

Procedure

Steps

as work was completed" ).

A deficiency very similar to this

had

been identified by the

NRC to Maintenance

in IR 95-10,

3)

PWO 95-02-4066

Remove Cylinder Head

No, 9, Inspect for Damage.

This

PWO was later expanded

to perform repairs.

The inspector

conducted periodic inspections

of these activities

as they

occurred over

a period of approximately

one week.

Additional

details

and evaluation of this work is contained

in paragraph

3.b.11).

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

was observed:

1)

OP 1-220050A,

1A

EDG Periodic Test

and Operational

Inspection.

The inspector

observed this special

test that was done

as

a

result of identified oscillations in

EDG frequency

and voltage.

This test

was modified to permit operation

unloaded for one

hour followed by

a one hour full load test.

The unloaded test

was completed satisfactorily.

Near the

end of the

one hour

loaded run,

a ground

was identified in the

DG control

system.

The ground

was located in the wiring from the engine control

panel

to the governor

on the

16 cylinder engine.

This faulty

wire was replaced

and the engine retested

satisfactory.

The

system engineers

vigorous pursuit of the ground led to timely

identification and repair.

Overall the performance of this

test

was satisfactory.

ILC Training and Qualification (41500)

The purpose of this inspection

was to conduct

a review of the

qualifications

and training of IKC personnel.

This inspection

was

conducted

in accordance

with the requirements

of 10 CFR 50

F 120.

The

inspector

reviewed the scope

and content of IEC maintenance

training

under the guidance of Inspection

Procedure'.41500,

"Training and

32

gualification Effectiveness"

and

NUREG-1220, "Training Review

Criteria and Procedures."

The inspector

examined

the facility's procedures

and administrative

controls with respect

to

I&C training, the self evaluation report,

the Maintenance Training Instructional Materials

Upgrade Project

Report,

a selection of student

feedback

forms, the

ILC lesson

plans'tructure

and format,

and all of the

I&C examination results.

The

inspector

also interviewed personnel

regarding

the nuclear

I&C

training program for Journeymen

and Specialist.

I&C Technicians

were interviewed using the

Incumbent protocols in NUREG 1220,

Rev l.

The inspector identified no strengths

or weaknesses

in the training

and qualification arena.

However

a weakness

was identified in the administrative

procedures.

It was not clear to the inspector that proper job supervision

(as

directed

by ADH-08.02,

"Conduct of Maintenance"

and

AP 0010432,

"Nuclear Plant

Work Orders" ),

was being maintained during the

conduct of safety related

work by unqualified

I&C journeymen

(see

details

below).

This issue currently has

low safety si'gnificance

since the work that was performed

(see

PWO 93033900 description

below)

had

no adverse

affect

on safety related

equipment or the

health

and safety of the public.

The inspector

concluded that the

I&C training program incorporated

a Systems

Approach to Training.

The inspector identified no violations or deviations

in the area of

I&C training.

In February,

1994,

two

PSL Journeymen

were tasked

to calibrate Unit

2

RCS Pressurizer

Pressure

Loop Transmitter,

PT-1102D

(PWO

93033900).

The licensee

was unable to prove through documentation

that the two Journeymen

were qualified to do the task.

However,

one

of the two

PSL Journeymen

had

been previously

a qualified

I&C

supervisor

at Turkey Point.

That Journeyman

appeared

to be well

qualified to perform this calibration,

however

he had not completed.

the required

I&C training for basic qualifications at St Lucie.

The inspector

reviewed

how the licensee

addressed

maintenance

to be

performed

by

I&C Journeymen

that

had not completed

basic

I&C

qualifications at St Lucie.

Administrative Procedure

ADH-08.02,

Conduct of Maintenance,

which states

that

"If personnel

not

possessing

the required training or qualification are assigned

to

a

work activity, increased

instruction detail or "on the job"

supervision

is required."

Administrative Procedure

0010432,

Nuclear Plant Work Orders,

contains

a caution which states, if the assigned

i.ndividual is not

on the qualification list for that component,

the following

additional

steps

must

be taken:

1)

Must have additional

supervisory oversight or specific

procedural

guidance.

33

OR

2)

Must have greater detail in the

NPWO work description.

ADH-08.02 states

that the supervisor

must

be "on the job" which

implies continuous

supervision.

AP 0010432 states

that the

supervisor

must provide "supervisory oversight."

The facility

contends

that "supervisory oversight"

does

NOT insinuate

continuous

supervision.

The facility stated that additional oversight

was provided

by the

IKC supervisor.

The inspector

reviewed the work order

and

.interviewed the two journeymen

who conducted

the maintenance.

The

journeymen

stated that additional oversight

(out of the ordinary)

was not provided.

Additional oversight

was neither requested

by the

facility nor identified by the inspector

on the work order,

The inspector's

review of the calibration data revealed that the

instrument

was in calibration

and

had received

supervisory review.

Therefore, this issue

had low safety significance

since the work

that

was performed

had

no adverse affect

on safety related

equipment

or the health

and safety of the public.

However,

a procedure

inconsistency

existed

in which the facility had committed to resolve

via Temporary

Change

Request

TC-95-213

and

a procedure

change

request

to

ADM 08.02.

The licensee

plans to change

ADM 08.02 to

reflect

AP 0010432 thus requiring additional supervisory oversight

in lieu of on the job supervision.

The inspector

concluded that the

statements

in both procedures

regarding

journeyman qualifications

were weak.

5.

Engineering

Support

(37551)

A concern involving the lack of prompt corrective action

on

a plant

generic

problem associated

with relief valves

was identified and will be

discussed

in IR 95-20.

A concern involving the assumptions

used in engineering

evaluation

JPN-

PSL-SEMP-95-101,

which evaluated

the impact of V3439 setpoint

and

blowdown on plant operations,

was identified,

The licensee

is currently

reviewing the issue.

Engineering

support of diesel

generator

repairs

and root cause

evaluation

of the diesel failure and pressurizer

power operated refief was found to

be effective.

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,

34.

b.

housekeeping,

control

hazardous

chemicals,

ignition source/fire risk

reduction'fforts, 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'hat

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.

Isolation zones

were maintained

on both sides of the barrier

and

were free of objects

which could shield or conceal

an individual.

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,

C.

In conclusion,

selected

functions

and equipment of the security

program were inspected

and found to comply with the

PSP

requirements.

Radiological

Protection

Program

Radiation protection control activities were observed

to verify that

these activities were in'onformance 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

The following plant organizational

changes

were

made during the report

period:

J. Scarola. was reassigned

from Manager of Operations

to Plant

General

Manager.

J.

West

was reassigned

from Manager of Site Services

to Manager of

Operations.

35

~

C. Burton was reassigned

form Plant General

Manager to Manager of

Site Services.

~

L. Rogers

was reassigned

from Instrument

and Control Maintenance

Supervisor to Manager of System

and

Component

Engineering.

~

P. Fulford was assigned

as Operations

Support

and Testing

Supervisor,

a new position in Operations

that will be responsible

for inservice,

surveillance,

predictive,

and post maintenance

testing.

~

R. Olson

was promoted to Instrument

and Control Maintenance

Supervisor.

8.

Exit =Interview

The inspection

scope

and findings were

summarized

on September

15 and

October

11,

1995, with those

persons

indicated in paragraph

1 above.

The

inspector described

the areas

inspected

and discussed

in detail the

inspection results listed below.

Proprietary material is not contained

in this report.

Dissenting

comments

were not received

from the licensee.

Plant

management

was

aware of the large

number of issues

that were being

discussed

at the exit and expanded

the normal

attendance

to include

a

large

number of supervisors,

operators,

maintenance,

and plant support

personnel.

They appeared

to desire that the exit information be

disseminated

to as

many plant personnel

as possible.

The exit appeared

to be well received

by plant management

and staff.

At the exit

conclusion,

the site vice president

and plant general

manager

commented

on:

Plant performance

not

up to past standards.

Need for improvement.

Need to set

new standards.

Personal

accountability.

Identifying and fixing problems.

~T

e

Item Number

50-335/95-15-01

Open

"Failure to Follow

Procedures

and Block MSIS

Actuation,"

paragraph

3.b.

50-335/95-15-02

Open

Two Examples of "Failure to

Follow Procedures

during

Seal

restaging,"

paragraph

3.b.

50-335/95-15-03

Open

"Failure to Follow Procedure

and

Document

abnormal

valve

36

position in the Valve Switch

Deviation Log,"

paragraph

3.b.

50-335/95-15-04

50-335/95-15-05

50-335/95-15-06

50-335/95-15-07

Open

"Failure to Follow

Procedures

during Alignment

of Shutdown Cooling System,"

paragraph

3.b.

"Failure to Follow Procedure

and

Document

a deficiency

on

Containment

Spray Valve

Surveillance

Test

Procedure,"

paragraph

3.b.

"Failure to Initial

Maintenance

Procedure

Steps

as work was completed,"

paragraph

3.b.

"Failure to Follow

Procedures

during venting of

ECCS

System resulted

in

Containment

Spraydown,"

paragraph

3,b.

NCV

50-335/95-15-08

Closed

"Failure to Follow

Logkeeping Procedures,"

paragraph

3b.

9.

Abbreviations,

Acronyms,

and Initialisms

ADM

Administrative Procedure

ANO

Arkansas

Nuclear

One

ANPO

,

Auxiliary Nuclear Plant [unlicensed]

Operator

ANPS

Assistant

Nuclear Plant Supervisor

AOV

Air Operated

Valve

AP

Administrative Procedure

ASME Code American Society of Mechanical

Engineers

Boiler and Pressure

Vessel

Code

CCW

Component

Cooling Water

CET

Core Exit Thermocouple

CFR

Code of Federal, Regulations

cm

Centimeter

CRAC

Control

Room Auxiliary Control

(panel)

Containment

Spray

(system)

CSAS

Containment

Spray Actuation System

CVCS

Chemical

8 Volume Control

System

DG

Diesel

Generator

dpm

Disintegration

Per Minute

DPR

Demonstration

Power Reactor

(A type of operating license)

DST

Division of Systems

Technology

EDT

ESDE

F

FI

FR

FRG

FSAR

GE

gph

gpm

HDP

Hg

HPES

HUT

IR

J/LL

JPN

lbf

LCO

LER

MFIV

MV

No.

NPF

Emergency Operations Facility

NPS

NPWO

NRC

NRR

NUREG 37

Emergency

Core Cooling System

Emergency

Diesel

Generator

Equipment Drain Tank

Engineering

Package

Environmentally Qualified

Excessive

Steam

Demand

Event

Engineered

Safety Feature

Engineered

Safety Feature Actuation System

Fahrenheit

Flow Control Valve

Flow Indicator

The Florida Power

5 Light Company

Federal

Regulation

Facility Review Group

Final Safety Analysis Report

General

Electric Company

Gallon(s)

Per Hour (flow rate)

Gallon(s)

Per Minute (flow rate)

Hydraulic Control Valve

Heater Drain

Pump

A GE relay designation

Mercury (element)

Health Physics

Human Performance

Enhancement

Systems

High Pressure

Safety Injection (system)

Holdup Tank

Heat

Exchanger

.

Instrumentation

and Control

[NRC] Inspection

Report

Jumper/Lifted

Lead

(Juno

Beach)

Nuclear Engineering

Pounds

Force

TS Limiting Condition for Operation

Level Control Valve

Licensee

Event Report

Loss of Coolant Accident

Letter of Instruction

Low Pressure

Safety Injection (system)

Main Feed Isolation Valve

Main Steam Isolation Signal

Main Steam Isolation Valve

Motorized Valve

Number

Nuclear Production Facility (a type of operating license)

Nuclear Plant Operator

Nuclear Plant Supervisor

Nuclear Plant

Work Order

Nuclear Regulatory

Commission

NRC Office of Nuclear Reactor Regulation

Nuclear Regulatory

(NRC Headquarters

Publication)

NWE

ONOP

OP

PC/M

PGM

ppm

psia

psld

pslg

PSL

PSP

PWO

PWST

QA

QC

QI

RAB

RCB

RCO

RCS

RDT

Rev

RII

SNPO

St.

TCB

TCN

TS

URI

VCT

VIA

38

Nuclear Watch Engineer

Off Normal Operating

Procedure

Out Of Service

Operating

Procedure

Operator

Work Around

Plant Change/Modification

PerCent Milli (0.00001)

Procedure

Change

Request

NRC Public Document

Room

Plant General

Manager

Power Operated Relief Valve

Part(s)

per Million

Pounds

per square

inch (absolute)

Pounds

per square

inch (differential)

Pounds

per square

inch (gage)

Plant St.

Lucie

Physical

Security Plan

Plant

Work Order

Primary Water Storage

Tank

Quality Assurance

Quality Control

Quality Instruction

.

Reactor Auxiliary Building

Reactor

Containment Building

Reactor Control Operator

Pump