ML17229A560

Replacement

Project equipment

removal

and welding

activities were being conducted in accordance

with approved

plans

and

procedures.

(Section Ml.6)

The licensee

continued to maintain

a well-organized

program for

monitoring flow accelerated

corrosion.

(Section H1.7)

The scope of the In Service Inspection

and planned preservice

inspections

were appropriate.

(Section M1.8)

Enclosure

2

The inspector concluded that the transfer of Incore Instrument

remnants

from the Unit 1 reactor vessel to the spent fuel pool was carefully and

thoroughly planned

and completed with low radiation dose

expended.

(Section M1.9)

Welding procedures

for the Steam Generator

Replacement

Project were

complete

and appropriately qualified in accordance with required welding

standards.

(Section M3.1)

Replacement

Project welder training and qualification

activities were being conducted in full compliance with ASME Section

IX

requirements.

(Section

M5. 1)

The licensee's

Nuclear Assur ance surveillance activities provided

a

comprehensive

review of'he contractor 's welding and welding inspection

activities.

(Section

M7. 1)

En ineerin

The inspectors

concluded that the preparation of engineering

and heavy

load lifting of the original and replacement

steam generators

was

acceptable

per the design

drawings

and was adequate

to provide the

stabilization of the steam generators

for removal.

(Sections

El. 1,

E1.2)

One violation was identified for the absence

of travel limit markings

on

the steam generator

temporary lifting device.

(Sections

E1.3)

~

Overall. the removal of the original steam generators

and the

installation of the replacement

steam generators

was completed without

incident.

(Section

E1.3)

~

The full core offload safety evaluation

was well presented

and clearly

documented

the lack of any unreviewed safety questions.

The evaluation

was properly translated into the applicable procedures

to ensure that

the evaluation

was valid.

(Section

E2. 1)

Plant

Su

ort

The Health Physics Project Overview documents

developed to instruct and

establish

radiological controls for unique Steam Generator

Replacement

Project

(SGRP) tasks

were an excellent planning resource.

(Section Rl. 1)

The inspectors

confirmed that As Low As Reasonably

Achievable

and

Radiation Protection concerns

were factored into the

SGRP planning.

Section Rl. 1)

With the exception of the pressurizer

heater

replacement

project, the

licensee

was effectively estimating

and tracking collective doses

for

Enclosure

2

planned tasks.

(Section R1.1)

Collective dose for the pressurizer

heater project was significantly

underestimated.

(Section Rl. 1)

Good radiation protection control measures

were in place inside the

licensee's

Radiation Control Area and overall licensee

exposure controls

were effective.

(Section R1.1)

Good use of remote radiation monitoring technology to monitor work in

radiation

and high radiation areas to save collective dose

was observed.

(Section R1.1)

Licensee contamination controls were effective.

(Section Rl. 1)

Licensee radiation protection controls for the construction

hatch were

appropriate

and effective.

(Section

R1. 1)

Inadequate

radiation worker awareness

of Radiation

Work Permit

(RWP)

requi rements

were identified as violations of the licensee's

radiation

protection procedures

and licensee's

Technical Specifications

(TSs).

(Section R1.2)

Inadequate written procedures

for the issuance of tele-dosimetry

and

setting dosimeter

setpoints

in agreement with the

RWP requi rements

was

identified as violation of licensee's

TSs.

(Section R1.2)

A Non Cited Violation was identified for failure to follow procedures

for securing

access to a Very High Radiation Area.

(Section R1.3)

The licensee

established

excellent Radiation Protection support

facilities for the

(Section

2. 1)

The licensee established

good Radiation Protection controls for the

removal

and movement of the Original Steam Generators

to the Interim

Storage Facility.

The licensee

was well prepared to temporarily store

and ship the Steam Generators

to a disposal facility.

(Section

R2. 1)

Radiation Protection staffing levels were sufficient to provide good

radiation protection support for the planned outage activities.

(Section R5.1)

Training activities for radiation workers

and Health Physics Technicians

concerning

Steam Generation

Replacement

Project activities were

appropriate.

(Section

R5. 1)

The inspector concluded that the licensee's

fitness for duty program was

being implemented in accordance

with 10 CFR 26.

(Section S1.3)

The protected

area barriers were in good condition, the isolation zones

Enclosure

2

i

well lit, and the appropriate

compensatory

guard postings in place.

(Section

S2. 1)

~

The licensee's

planned

compensatory

measures,

removal of vital area

barriers.

and access

control of containment during the steam generator

replacement

project were appropriate

and met the requirements

specified

in the Plant Security Plan.

(Section

S8. 1)

Enclosure

2

Re ort Details

Summar

of Plant Status

Unit

1 operated

at essentially full power until October 20,

when the licensee

shut

down the unit for the Steam Generator

Replacement

Outage.

The plant

remained shut

down for the remainder of the report period.

Unit 2 operated at essentially full power throughout the entire report period.

IIOI ti

01

01.1

Conduct of Operations

General

Comments

71707

Using Inspection

Procedure

71707, the inspectors

conducted

frequent

reviews of'ngoing plant operations.

In general.

the conduct of opera-

tions was professional

and safety-conscious;

specific events

and

noteworthy observations

are detailed

in the sections

below.

Unit 1 Shutdown for Steam Generator

Re lacement

Outa

e

71707

Inspection

Scope

At approximately

12:10

am on October

20, the licensee

removed Unit

1

from the grid in preparation for the Steam Generator

(SG) replacement

and refueling outage.

The inspector

observed the pre-evolution

briefings, turbine shutdown,

reactor

shutdown

and Hain Steam Isolation

Valve (HSIV) stroking.

Observations

and Findings

On the evening of October

19, the licensee started the Unit 1 shutdown

in preparation f'r the

SG replacement

outage.

The Assistant

Nuclear

Plant Supervisor

(ANPS) conducted

a detailed briefing for the evolution

shortly after 7:00

pm.

The brief was attended

by all affected

Operations

personnel,

Reactor

Engineering,

Chemistry,

and Hanagement.

Overall. the inspector

found the brief to be well organized

and

generally informative.

The inspector

noted that the crew'

participation was good and noted the crew made several

excellent

suggestions

to help the shutdown

go more smoothly.

At approximately 8:00

pm, Operations

began lowering turbine load in

accordance

with Procedure

NOP-1-0030125,

Revision 4, "Turbine Shutdown-

Full Load to Zero Load."

The operators

handled the down power

conscientiously

and professionally.

The inspector

noted good

coordination

between the operators,

their supervision,

and Reactor

Engineering.

The ANPS and Nuclear

Plant Supervisor

(NPS) maintained the

extraneous activity level in the control

room to a minimum.

The output

breakers for the main generator

were opened at 12: 10

am on October 20.

Enclosure

2

02

02.1

Operations

maintained the unit around

8 percent reactor

power for a half

hour to perform Steam

Bypass Control System

(SBCS) testing.

This test

assured

the licensee that the

SBCS would operate

as required to allow a

rrormal cooldown of the plant.

The system worked as expected.

After

completion of the test,

the operators

commenced

a reactor

shutdown

and

cooldown in accordance

with Procedures

NOP-1-0030128,

Revision 0,

"Reactor Shutdown,"

and NOP-1-0030127,

Revision 7, "Reactor Plant

Cooldown

- Hot Standby to Cold Shutdown."

The plant entered

Hode

2 at

12:48

am and

Hode 3 at 1: 15 am.

One issue in particular presented

a minor problem to the Operations

crew.

Several

months

ago, the licensee

adjusted the packing

on the

1A

HSIV.

This required the valve to be fully stroked

and timed as

a

retest.

This was not preplanned for the night and the Operating

crew

had to adjust thei r plan for the shift.

The inspector

observed

several

discussions

between the ANPS, the

NPS, the Nuclear

Watch Engineer

(NWE),

the Shift Technical Advisor (STA), and the board operators

about the

subject.

They determined

an appropriate

course of action that

procedures

encompassed.

The inspector then observed the

ANPS hold

"mini-briefs" with one or two individuals to discuss this plan.

At that

point, the inspector

believed that

a full crew brief would have

been

more efficient and beneficial.

About one half hour after disseminating

the plan, the

ANPS did perform

a satisfactory full crew brief.

The inspector

noted only one other

minor delay.

The licensee

knew about

two Control

Element Assemblies

(CEAs) in particular that had been

known

to drop when moved.

The licensee

had resolved this problem in the past

by installing temporary control cards.

As the operator

approached

the

first group with one of these

CEAs, Operations

had difficulty contacting

18C to get the card installed.

CEA insertion

was delayed approximately

25 minutes while waiting for the card to be installed.

The shutdown

continued without further incident.

The secondary

system

was aligned

for the A HSIV test shortly after 4:00

am and the valve was stroked

satisfactorily.

Conclusions

The licensee

performance during the Unit 1 shutdown

was professional

and

in accordance

with site procedures.

The inspector noted two minor

problems

caused

by inadequate

planning, but Operations

successfully

worked through them.

Operational

Status of Facilities and Equipment

En ineered Safet

Feature

S stem Walkdowns

71707

The inspectors

used Inspection

Procedure

71707 to walk down accessible

portions of the following Engineered

Safety Feature

systems within the

Unit 1 containment:

Enclosure

2

04

04.1

05

~

Safety Injection Tanks

~

Low Pressure

Safety Injection System

~

High Pressure

Safety Injection System

Equipment operability, material condition,

and housekeeping

were

acceptable

in all cases:

Several

minor discrepancies

were brought to

the licensee's

attention

and were corrected.

The inspectors identified

no substantive

concerns

as

a result of'hese

walkdowns.

Operator

Knowledge and Performance

Unit

1 Primar

Sam le Observation

71707

Inspection

Scope

On October

17, the inspector

observed

a Chemistry Technician

draw and

analyze

a primary sample

on Unit 1.

The inspector verified procedural

compliance,

confirmed good laboratory technique,

and surveyed the

technician's

general

knowledge.

Observations

and Findings

The inspector

observed

a Chemistry Technician

draw

a Unit

1 primary

sample in accordance

with Procedure

1-COP-65.21,

Revision 4, "Unit 1

Primary Systems

Sampling."

The inspector

noted that the technician

was

thoroughly familiar with the sampling procedure.

A current revision of

the procedure

was available at the sample sink,

and the technician

routinely referred to it throughout the sampling process.

The inspector

was satisfied that the sample

was drawn properly.

The inspector

then observed

the technician perform the analysis of the

sample.

The inspector

asked several

questions relating to the use of

the analytical

equipment,

the timing of samples,

and the expected

results.

All questions

were answered

by the technician to the

inspectors satisf'action.

The inspector

noted that the technician's

laboratory technique

was very good, minimizing any potential f'r

inadvertently contaminating

equipment

and ensuring that the sample did

not become accidentally adulterated.

The inspector verified that all results

observed

were within the

prescribed

Technical Specification limits.

No discrepancies

were noted.

Conclusions

The inspector

concluded that the primary sample

was performed in

accordance

with procedures,

and the Chemistry Technician

was

knowledgeable

about the evolution.

Operator Training and Qualification

Enclosure

2

05.1

a.

4

Licensed

0 erator

Re uglification Pro ram

71001

Inspection

Scope

The

NRC conducted

a routine.

announced

inspection of the licensed

operator Requalification program during the period of November 17-21,

1997.

The inspector

reviewed

and observed

annual Requalification

examinations

conducted

by the licensee

and conducted

inspection

activities to determine

compliance with 10 CFR 55.59, "Requalification,"

using Inspection

Procedure

71001.

Activities reviewed included

examination

development

and administration,

evaluator performance,

simulator scenario

and Job Performance

Measure

(JPMs) evaluations.

Observations

and Findings

Written Examination

The inspectors

reviewed the sample plan developed for the examination

which covered the last two year cycle.

The overall sample plan

construction

adequately

covered the material

presented for the

Requalification cycle.

The examinations

were developed with the intent

to prevent overlap between the diff'erent sections of the annual

examination.

This prevented

excessive topic or subject overlap.

The inspector

reviewed the Senior

Reactor Operator

(SRO) written weekly

quizzes administered

November

13,

and

November

14,

1997.

The quizzes

were administered

as

"open reference"

type exams, with references

limited to Control

Room material.

The "A" quiz was administered to 10

operators.

and the "B" quiz to 13 operators.

The quizzes

covered the

same week's instructional material,

and consisted of 20 questions

each'f

which 10 questions

were

common to both tests.

The inspector

discussed

several

questions with the exam author concerning question

stem development,

distractor

improvement,

and level of difficulty.

Approximately half the questions

on each quiz would have required

some

changes to be fully acceptable.

Most of the changes

involved making one

or more of the distractors credible.

The questions,

in most instances,

requi red an appropriate

amount of analysis

and synthesis of the provided

information to correctly answer

the questions.

However, the extremely

high scores

indicate the overall discrimination level of the quizzes

may

have been too low.

The results also indicate that individual questions

may have been too simplistic or contained construction deficiencies

which allowed

a high rate of correct answers.

The licensee's

exam

administration policies requi re an evaluation of questions

having

a 40

percent or more error rate.

but does not require evaluating questions

with a

100 percent correct

answer rate.

This tends to bias

an exam bank

toward the more "successful"

questions.

However, the 100 percent

questions

do not provide meaningful

feedback to the program.

In effect,

there is no discrimination value for a question which is answered

correctly 100 percent of the time.

The sample size of 10 and

13

students

is too small to provide an absolute determination of

Enclosure

2

5

discrimination level based

on success

rates,

but questions

receiving

100

percent correct answers

should

be evaluated

as aggressively

as questions

receiving too low a correct

answer

rate.

The "A" quiz results

were: All 10 students

answered

14 of 20

questions correctly.

9 of 10 students

received

scores of 90

percent

or greater,

lowest score

was

85 percent.

The "B" quiz results were:

All 13 students

answered

10 of 20

questions correctly.

'12 of 13 students

receive scores of 90

percent or greater,

lowest score

was

85 percent.

The written exam deficiencies

are similar to those previously identified

during an

NRC inspection of the licensee's

Requalification program and

detailed in Inspection

Report 50-335,389/96-20.

Simulator Scenario Construction

The inspector

reviewed the dynamic simulator scenarios

administered

during the inspection

week.

The inspector also witnessed

two scenarios

presented

to

a single crew.

The dynamic scenarios

were considered

appropriately challenging

and were an excellent

assessment

tool.

The

scenarios

provided opportunities to evaluate the competency of operators

in all pertinent areas.

Simulator

and In-Plant Job Performance

Measures

JPMs

Evaluators effectively queried the operators

using follow-up questions

based

upon operator

performance.

This allowed the evaluators to

determine generic or individual areas

needing

improvement.

There were

no JPM failures observed.

JPMs were considered to be of very good quality and were appropriately

discriminating.

A less-than-qualified

individual would not be expected

to successfully

complete the JPMs.

This evaluation

area

should provide

good feedback to the Requalification Training program.

0 erator/Evaluator

Performance

The inspector

observed

a single crew's performance

during two simulator

scenarios.

The inspector's

evaluation of the crew's performance

differed significantly from that of the licensee.

The crew being

evaluated tripped the reactor

unnecessarily

based

on

a single failed

indicator, erroneously

declared

a Site Area Emergency

(which resulted in

an unnecessary

Site Evacuation).

and failed to consider the effects of a

faulted emergency

power supply on safeguards

equipment.

In addition,

the crew neglected to attend

numerous

alarms

and annunciators.

Despite

these errors,

the evaluators

passed

the crew overall without

remediation.

The crew was

a staff crew that had not had experience

working together.

However, their overall performance

was not considered

Enclosure

2

satisfactory

by the inspector.

The inspector

attended

the evaluators'valuation

and debriefing of the

crew.

The evaluators correctly identified the technical errors

by the

crew, but appeared tolerant of the mistakes.

In fact.

one evaluator

offered explanations

and excuses f'r some of the errors to the

inspector.

The inspector

concluded that the evaluators

used

good

techniques

and were observant of most of the crew'. errors,

but were not

sufficiently aggressive

and demanding in their conclusions.

The errors

would have resulted in a crew failure during an NRC-administered

examination.

As

a minimum, several

areas of remediation should

have

been stipulated

by the evaluators.

This appears to be an instance of

negative training or feedback to the individual crew members.

0 erator

Performance

During the simulator scenarios,

operators

on numerous

occasions

did not

respond to alarms,

missed

some alarms completely,

and were not

conscientious

in attending,

acknowledging,

or responding to alarms.

The

inspector

noted

a single exception to the general

lack of response

to

alarms.

A back, auxiliary alarm panel

always received

prompt attention

from the operators.

This particular

panel

was not unique in the safety

significance of the items monitored.

but instead

had

an audible alarm

that was irritating in nature

and did not time out in three seconds.

The inspector

concluded that the present

design of the audible portion

of the general

alarm system is conducive to inappropriate

operator

response to those alarms.

The facility appears to be

an outlier in

regards to audible alarms timing out within three seconds.

This issue

was discussed

in detail with licensee

management.

During the

inspection,

licensee

management

agreed to evaluate the alarm system

design.

During simulator

JPMs,

operators

frequently placed

books

and procedure

manuals

on the control panel.

In one instance.

an operator

propped

an

open book against the rod position (in-hold-out) switch when he moved

away from the panel.

The book was

a light, Accopress

binder

which

probably would not have

been

heavy enough to move the rod control

switch.

The inspector

noted that there are no provisions for operators

to put their books

and manuals

down for easy reference

other than the

control board or a relatively inaccessible

table or desk behind them.

This makes attending the control board while referring to procedures

extremely difficult.

As

a consequence,

operators

have introduced

an

unintended work-around in the manner in which they place reference

material

on the control board.

When questioned

about why they tolerated

such

a poor design.

several

operators

said that past requests

to have

a

shelf placed

on the panel

were not accepted.

The operators

were not

able to provide any information on formal requests.

corrective action

initiatives, or any other corroborating evidence that the issue

was

aggressively

pursued.

The inspector

concluded that operators

have

been

aware of an unacceptable

condition,

made limited efforts to effect

a

Enclosure

2

change,

but eventually accepted

the condition without taking

a strong

stand.

During performance of JPM 0821082,

Realigning

a CEA, three of four

operators

interpreted

a procedural

caution to "maintain reactor

power

constant"

during the

CEA realignment

as requiring boron changes

during

the rod movement.

The realignment involved minor reactivity changes

from the

CEA (12 inches total travel,

rods near the,top of the core),

and could have been accomplished relatively easily without boration.

Because of thei r sensitivity to maintaining reactor

power constant,

those operators

who elected to change

boron concentrations

took much

longer to restore the

CEA and in fact caused

more power changes

because

of the lagging effect of boron changes

on reactor

power (over- and

under-shoot).

Since the recovery procedure is not prescriptive in the

methodology of holding power constant or in what constant

means,

one

operator simply pulled the

CEA and accepted

the relative minor reactor

power

change.

All operators

were evaluated

as "satisfactory" in how

they performed this JPM.

The inspector concluded that the procedure

should

be reviewed for enhancement,

especially in defining whether

"constant" should

be defined

as

some acceptable

range.

The procedure

could also provide guidance

on

a rough calculation of the total

reactivity associated

with a realignment

and better guidance

on whether

the total change

should

be accompanied

by

a boration change.

The

inspector also noted that the operator

was required to make

a total of

four phone calls to operations

management

and to Reactor

Engineering

prior to and after the

CEA realignment.

If this procedure is considered

critical enough for this level of'pproval or notification, direct

assistance

from those contacted

may be indicated.

Otherwise,

simply

making notification provides

no real support to the operators.

In addition to the boron changes

described

above,

the lack of

consistency

on defining "constant" also caused

operators to consult

additional

power level indicators while making reactivity changes

for

the

CEA Realignment

JPM.

A digital readout indicator

on the safeguards

panel behind the operators

was frequently checked while making boron

changes

and manipulating rods.

This required all four operators to turn

around to view this instrumentation.

The inspector

asked the operators

after the

JPM performance

why they were watching the back panel

indicators rather

than the power level indicators directly in front of

them at the rod control panel.

The operators

indicated that the back

anel indicators were "real-time" while the rod control panel indicators

ad

a considerable

lag time due to computer updating.

and that the

digital readouts

on the back panel

were superior in their display of

reactor

power to two decimal

places.

Therefore,

they were better for

complying with the requi rement to hold power "constant."

The inspector

considers this condition to constitute

a work-around.

Either the

indicators

on the rod control panel

are perfectly acceptable for such

reactivity maneuvers

or appropriate indicators should

be provided at the

panel.

If operators

are misinterpreting the requirement to keep power

constant,

appropriate training should

be provided.

The inspector

Enclosure

2

08

08.1

informed the licensee that this issue should

be evaluated

and resolved.

Turning away from the control panel

during reactivity manipulations

should only occur when absolutely required,

not as routinely as observed

during this JPM.

Operators

did not use the Alarm Response

Procedures

(ARPs) in a

consistent

manner.

The ARPs in use

on the simulator are very sketchy

and provide minimal information to the operators.

When questioned,

both

evaluators

and staff told the inspector that one unit has already

upgraded the ARPs,

and. the other unit's

ARPs are being upgraded.

Pro

ram Feedback

The inspector

reviewed records

and followup documentation of student

and

management

observation

feedback to the Requalification

Program.

The

training staff treated

feedback in a thoroughly professional

manner.

Feedback

was afforded the right level of respect

and skepticism where

warranted.

Suggestions

and complaints were handled

and pursued in an

appropriate

manner.

Conclusions

The Requalification program met all regulatory standards

and

requi rements

during this training cycle.

The written weekly quizzes

were considered

minimally discriminating and provided little effective

feedback to the program.

Simulator

scenarios

and

JPMs were

appropriately discriminating

and were well organized.

Operators

were

knowledgeable of the plant and systems,

but did not display good

corroboration

and verification techniques.

Operators

were frequently

inattentive to the control panels

and alarms.

Evaluators did not

aggressively

implement management

standards

in the area of'onduct of

Operations.

Evaluators

were tolerant of both minor mistakes

and major

errors. to the point of providing negative

feedback

on thei r

acceptability.

Operators

were tolerant of unacceptable

conditions,

and

were not aggressive

in ensuring their resolution.

Procedural

weaknesses,

control

room human factor deficiencies,

and work-arounds

were not identified and aggressively

pursued

by operators

or evaluators.

Miscellaneous

Operations

Issues

Control Element Assembl

Lifted Durin

U

er

Guide Structure

Removal

71707

93702

Inspection

Scope

Whi'le lifting the upper guide structure

(UGS), from the Unit I reactor

pressure

vessel

(RPV), the licensee

noted

a Control Element Assembly

(CEA). lodged in the

UGS and fully withdrawn from the core.

The

inspector monitored the activities associated

with the retrieval of the

CEA as well as the procedure

changes

and evaluations that were necessary

Enclosure

2

to accomplish the task.

b.

Observations

and Findings

On October 27. the licensee lifted the

UGS in preparation for defuelling

the reactor.

Once lifted, an underwater

inspection of the bottom side

of the

UGS was performed, to determine if there were any interferences

with other

reactor internal

components.

During the. inspection,

the

licensee identified a single

CEA protruding from the lower end of the

UGS.

The

CEA had apparently

lodged in the

UGS and was lifted from the

reactor core.

Upon identification, the licensee

immediately halted

further

UGS movement.

At the time of the event.

the containment

equipment

and personnel

hatches

were open to facilitate access

in preparation for replacing the

steam generators.

The licensee

subsequently

secured

those penetrations

and reestablished

containment integrity.

The licensee

revised the reactor disassembly

procedure

being used at the

time, General

Maintenance

Procedure

No 1-M-0015, Revision 36,

"Reactor

Vessel

Maintenance

- Sequence of Operations," to account for the

additional height the

UGS would have to be lifted for the

CEA to clear

the

RPV wall.

In addition, cautions

were added to account for the

expected

increase

in dose rates

as the

UGS was raised.

Shielding was

provided for the crane operator

as well as others

necessary

to complete

the task.

As the

UGS was moved,

a containment isolation occurred,

as expected,

due

to the increased

radi ation levels.

The

UGS was successfully

moved to

the equipment storage

area adjacent to the

RPV.

The entire

move was

videotaped with the aid of a submersible

"submarine"

camera.

However.

during the move, the tether attached to the submersible

became entangled

in the rodlets of the CEA.

The licensee

used the tether to free the

CEA

f'rom the

UGS and it fell, approximately

one foot, to the floor of the

storage

area.

The

CEA was then

moved to the fuel handling building for

inspection.

A high level of management

attention

was afforded this activity.

Hours

of work were reviewed to ensure that the job would be completed

by

personnel

that were rested

and alert.

Continuous inspection of the

activity via the submersible

proved to be

a tremendous

aid to ensure the

move route for the

UGS was acceptable.

The inspector attended

the Facility Review Group meeting which approved

the revision to the reactor disassembly

procedure,

and noted that the

review was methodical

and well thought out.

Contingencies

were

discussed

and preparations

made as

a result.

In addition, the inspector

witnessed the

UGS move.

The job was very well controlled,

both from an

ALARA perspective

as well as from a heavy lift perspective.

The total

dose received during the move was below 200

mR with the highest single

Enclosure

2

dose being 42 mR.

10

The inspector

reviewed the procedure the licensee

used while unlatching

the CEA's,

OP 1-0110022,

Revision 20. "Coupling and Uncoupling of CEA

Extension Shafts",

and concluded that it appeared

adequate

to properly

unlatch the CEAs.

Video tape of the

CEA and the extension shafts

were

reviewed but no conclusions

could be drawn

as to the ultimate cause of

the

CEA becoming

lodged.

Although the investigation into the root cause

of this event

was not complete,

the licensee

does plan to replace

both

the

CEA and the

CEA extension shaft prior to restart.

Conclusions

The inspector concluded that the licensee's

response to the lodged

CEA

was extremely well planned

and coordinated.

Examples of excellent

communication

and team work were observed

during the

UGS move,

as

evidenced

by the low dose received

by the personnel

performing the work.

His ra

led Fuel

Assembl

Durin

Unit 1 Core Offload

71707

Inspection

Scope

The inspectors

witnessed portions of the Unit

1 core offload during this

report period.

In addition, the inspector witnessed activities

associated

with a misgrappled fuel assembly.

Observations

and Findings

The inspectors

witnessed the licensee

remove fuel from the reactor

and

transfer it to the spent fuel pool, at various times during the offload.

The actual fuel movement

was performed by contractors with oversight

provided by the licensee.

The inspectors

observed the amount of

oversight provided to be adequate.

At 4:00

pm,

on October 29,

a refueling machine

over load condition was

observed

when the licensee

was attempting to remove fuel assembly

R33

from core location E-5.

Visual inspection of'he assembly

using

a

remote

camera

revealed that the refueling machine

had grappled

a fuel

assembly corner

post instead of the center post.

This misgrappling

misaligned the assembly,

such that it could not be withdrawn into the

hoist box,

and resulted in the overload condition when the assembly

was

attempted to be raised.

Appendix J of licensee

Pre-Operational

Procedure

3200090,

Revision 26,

"Refueling Operation" provided guidance

on diagnosing

and resolving

overload problems.

For unanticipated

circumstances.

this procedure

provided considerable

latitude to the Refueling Supervisor for

development

and execution of corrective actions.

Licensee

personnel

outlined

a sequence

of actions to return the misgrappled

assembly to its

original core location,

release

the grapple,

and then to regrapple over

Enclosure

2

the center post.

11

After briefing personnel

on the planned

sequence

of events.

the

refueling machine

was manually moved to coordinates

calculated to be

close to the assembly's

original location.

The licensee

used the video

camera to monitor the movement of the assembly

and verify that the lower

end fitting was properly aligned with the core support plate alignment

pins.

The assembly

was then lowered manually,

and the grapple released

at 8:55

pm, October 29.

The assembly

was observed to be bowed

approximately

3 inches east;

and 0.5 inches north.

The video camera

was

used to monitor the grapple position as the refueling machine

was

repositioned to properly grapple the assembly.

The assembly

was then

moved to the upender

and on to the spent fuel pool.

Conclusions

The inspectors

concluded that the core offload was completed in a safe

and deliberate

manner.

It was noted that the amount of licensee

oversight

was adequate.

Inspectors

noted that activities associated

with a misgrappled fuel bundle were completed in a deliberate

and

safety-conscious.

manner.

Closed

LER 50-335/96-006-00

" Inadvertent

Loss of Containment Audible

Count Rate"

92901

This

LER was the result of the Unit 1 wide range audible neutron count

rate indication in containment

being temporarily rendered

inoperable

during refueling operations.

The audible count rate is required

by TS

while in Mode 6 whenever core alterations

or positive reactivity changes

are in progress.

The loss of the audible count rate was the result of

the electrical

bus being deenergized

to support maintenance

on the bus.

Power was restored to the bus

and the audible count rate restored in

approximately five minutes.

The inspector

reviewed the licensee's

investigation of this event

and

the corrective actions identified in the

LER.

The cause of the event

was determined to be procedural

inadequacy

which did not identify the

audible count rate

as equipment that would be deenergized

when the bus

was

removed from service.

The inspector

reviewed the revised procedure

and found the guidance

adequate to identify the loads

powered from the

bus.

Additionally, the plant breaker list was revised to add detail of

the audible count rate for the specific breaker

and bus.

The inspector

reviewed this breaker list revision and other corrective actions

identified in the

LER and determined that they were satisfactory.

II. Maintenance

Conduct of Maintenance

General

Comments

62707

61726

Enclosure

2

a.

Inspection

Scope

12

The inspector

observed all or portions of the following maintenance

during the report period:

97015173

97002981

97017387

97031237

97017387

97024676

96032335

01 lA Low Pressure

Safety Injection pump routine

preventative

maintenance

01 Unit 1 Main Steam Safety Valve removal

01 Unit 1 High Pressure

Safety Injection preventative

maintenance

Ol 1A Component Cooling Water Heat

Exchanger

cleaning

01

1A High Pressure

Safety Injection pump routine

preventative

maintenance

01 Power Operated Relief Valve indication troubleshooting

01 Boric Acid Makeup Tank

1A Outlet For

Emergency

Boration

Also, the inspectors

observed

the following survei llances

and post

maintenance

tests:

OP 2-1400059 Reactor Protection

System

- Periodic Logic Matrix

Test

OP 1-0410024 Full flow testing of the Unit 1 Safety Injection

Tanks

b.

Observation

and Findings

The inspectors

found the work performed to be professional

and thorough.

All work observed

was with the work package

present

and in active use.

Technicians

were experienced

and knowledgeable of their assigned

tasks.

The inspectors

frequently observed

supervisors

and system engineers

monitoring job progress,

and quality control personnel

were present

whenever

requi red by procedure.

When applicable,

appropriate radiation

control measures

and Foreign Material Exclusion

(FME) controls were in

place.

The inspectors

considered

the work associated

with WO 96032335

01. to be

a particularly good example of a well planned

and executed

maintenance

activity.

The work area

was extremely clean with the tools laid out and

arranged for easy

use.

The system openings

were covered

and identified

by large signs

as

an

FME boundary.

The work package

was well written

and properly completed

up to the appropriate

step.

In addition,

see the additional discussions

of maintenance

observed

under M1.2, M1.3, M1.4,

and M1.5 below.

M1.2

Ins ection and Maintenance of lA Emer enc

Diesel Generator

62707

a.

Inspection

Scope

Enclosure

2

13

During the week of November 2, the inspector

reviewed the

1A Emergency

Diesel Generator

(EDG) inspection

and preventative

maintenance

activities.

The inspection included

a review of planned inspections,

. observation of inspections

in progress,

and observation of FHE controls.

Observations

and Findings

The licensee

had

a vendor

perform

a routine inspection

and corrective

maintenance of the

EDG.

The inspector

observed portions of the cylinder

inspections,

connecting

rod inspections,

bearing inspections.

and

fastener torque checks.

The inspections

found no problems with the

diesel.

The inspector also reviewed the applicable work orders

and

noted that the documentation of the findings was good.

One item of note,

was that the licensee treated the area

as

a level

2

FHE area.

According to thei r Procedure

QI 13-PR/PSL-2,

Revision 34,

"Foreign Material Control Housekeeping

and Cleanliness

Control Methods,"

an area

2 would be appropriate for systems

and components

where

configurations

and circumstances

allow foreign material to be

immediately retrievable

and

a final cleanliness

inspection to be

erformed.

The inspector

reviewed the requi rements

and found that the

icensee fully complied with the procedure.

Generic Letter 96-06 Thermal Pressurization

Relief Valve Installation

62707

Inspection

Scope

NRC Generic Letter identified

a potential

problem with thermally induced

overpressurization

of isolated water filled piping sections

in

containment jeopardi zing the ability of accident mitigating systems to

perform their safety related functions.

Florida Power

8 Light (FPKL)

identified three susceptible

piping penetrations

in Unit 1 that required

modification to prevent this potential

problem.

The inspectors

reviewed

the modification work packages

and observed portions of the modification

installation.

Observations

and Findings

The inspectors

reviewed the modification package,

PC/H 97032,

which

proposed to add

a thermal relief valve on each of three containment

penetrations.

The three penetrations

were in the non-safety related

containment

spray function.

They were P-46 and P-47, refueling cavity

pool purification supply and return lines,

and P-42, reactor cavity sump

pumps'ischarge

line.

The report adequately

documented

the design

change

and the justification that no unreviewed safety question existed.

On November

7, the licensee

informed the residents that the welders

who

would be performing this job had developed

a unique technique to weld

the

new valve bosses

onto the pipe while ensuring that

FHE was

Enclosure

2

14

maintained.

This technique

used

a leather 0-ring to seal

the prepared

pipe opening

from the inside.

They attached this to a clamping device

with an extra long bolt to allow retrieval if it fell into the pipe.

This clamping device held the boss in place until the root weld was

completed.

The leather provided adequate

strength to keep extraneous

material outside the pipe, but was flexible enough to insert in the

hole.

The valves were installed according to

PWO 61/2650 (P-42),

PWO 61/2652

(P-47),

and

PWO 61/2653 (P-46).

The inspector

observed the tack welding

and root welding for the valve on P-46.

The welders performed the

welding exactly as

seen in the shop

on November

7.

Also. the inspector

,verified that the welders were following the procedure

as written.

All

OC signatures

were noted to be obtained

.as required before continuing

the job.

En ineered Safet

Feature

Run of 1A Emer enc

Diesel

Generator

61726

Inspection

Scope

On November

12. the licensee

performed

a portion of Procedure

OP 1-

0400050,

Revision 46, "Periodic Test of the Engineered

Safety Features

ESF)."

The licensee

chose to perform

a fast start of the

1A EDG to

satisfy the post maintenance testing

and Technical Specifications 4.8. 1. 1.2.e.4

and 4.8. 1. 1.2.e.6 that required that the diesel

be started

each refueling by an

ESF test signal

and that the diesel

be run for 24

continuous

hours

each refueling.

The inspector

observed

the preparation

and start of the test.

Observations

and Findings

For the retest for the lA EDG, the licensee

performed part of the

ESF

Actuation System testing.

They had run the diesel that day as part of

the post maintenance test from the

EDG routine work just completed.

The

inspector

observed the pre test brief given by the Test Director and the

Operations

Supervisor.

The conduct of the brief included all applicable

precautions

and limitations.

The inspector

noted good participation

from the crew member s,

and noted that they raised several

valid

questions

during the session.

However, the brief was less than formal,

with several

conversations,

unrelated to the brief, taking place.

Two hours after the brief, conditions were established

to start the

test.

A question

was raised in the control

room about the need to roll

the engine before the test.

All the operators

knew that the diesel

did

not need to be rolled prior to this start since it had just been secured

four hours prior.

However,

none of the operators

could find where this

was permissible

by procedure.

The Assistant Nuclear Plant Supervisor

eventually found the note allowing this to occur in Appendix A of

Procedure

OP 1-2200050A.

Revision 35,

"1A Emergency

Diesel Generator

Periodic Test

and Operating Instructions."

Enclosure

2

't

15

The Test Director positioned her crew to perform the test.

Although

a

long period had expired between the brief and the beginning of the test.

the Test Director nor the

ANPS required another brief.

I&C personnel

input the Safety Injection signal

and the

EDG started

as expected.

The

inspector noted

good procedural

compliance

by the control

room personnel

during the start

and while loading the diesel.

The next day the load

run was successfully

completed

and the diesel

was secured.

Conclusions to Conduct of Maintenance

Maintenance activities were generally completed thoroughly and

professionally.

FHE control

was adequate

in all instances.

In one

instance.

the inspectors

found the installation of the thermal relief

valve in response

to Generic Letter 96-06 concerns

was completed

as

planned.

The inspector noted good procedural

compliance.

Also. the

inspector

found the technique

developed

by the we1ders to maintain

FME

control to be innovative.

A portion of the

ESF Actuation System testing

was successfully

completed in spite of a less than formal brief by the

Test Director.

Re lacement

Pro ect

50001

Inspection

Scope

The inspectors

conducted walk-through inspections of the containment to

review preparations

for the

They also observed

clad-welding

activities involving the replacement

steam generators.

Obser vations

and Findings

The inspectors

observed

the following activities for the preparation of

removal of the existing steam generators:

~

Cleaning

and painting of the surfaces of the steam generators

to

encapsulate

contaminants.

Installing wedges in supports

and cables

around piping to minimize

movement of the main loop piping.

~

Preparations

for, and the final cutting and removal of the

containment construction

access

cover.

The activities observed

were being conducted in accordance

with

appropriate

work plans

and procedures.

During preparation

inspections of the steam generators,

the licensee

determined that the stainless

steel

cladding

on the primary nozzles

was

not thick enough.

The inspectors

observed

automatic

gas tungsten

arc

weld buildup activities on the cladding inside the primary inlet and

outlet nozzles.

These welding activities were found to be well

Enclosure

2

16

controlled, with the welders

and welding operators

aware of, and

following, appropriate

procedures.

Conclusions

Replacement

Project,

equipment

removal

and welding

activities were being conducted in accordance

with approved

plans

and

procedures.

Flow Accelerated

Corrosion

FAC

49001

The inspectors

reviewed the scope

and

a part of the inspection results

of the licensee's

program for monitoring

FAC in the steam,

condensate,

and feedwater

systems of St. Lucie Unit 1.

The scope of the inspection

included samples

selected

because of reported industry experiences

as

well as the samples

selected

from the licensee's

predictive program.

There were no major corrosion problems discovered

during these

inspections.

Based

on the sample

reviewed,

the licensee

continued to

maintain

a well-organized

program for monitoring flow accelerated

corrosion.

Inservice

Ins ections

ISI

73753

The inspector

discussed

the scope of inservice

and preservice

inspections

scheduled for the Unit 1 steam generator

replacement

outage.

During thi s report peri od, the

1 icensee

IS I inspectors

had spent the

majority of their effort doing wall-thickness

measurements

of piping in

support of the

FAC program,

and were just starting the scheduled

ISI

inspections.

The scope of the ISI and planned preservice

inspections

were appropriate.

Transfer of Unit 1 Incore Instrument

Remnants

62707

Inspection

Scope

Inspectors

reviewed the licensee's

planning for transferring

Incore

Instrumentation

(ICI) remnants

from the Unit 1 refueling pool to the

spent fuel pool.

Observations

and Findings

The licensee

removed several

ICIs from the reactor in preparation for

installation of new detectors.

The licensee cut the rhodium detector

segments off each ICI, and placed those pieces

in a disposal

container.

The remaining ICI segments,

approximately

12 feet long, were tied off to

the side of the refueling pool.

Measured

dose rates

on these

segments

were found to be 300 to 2500

mR.

To transfer the ICI remnants to the spent fuel pool, the licensee

constructed

a shielded transfer tube from the refueling pool through the

Enclosure

2

17

containment

emergency airlock.

An inspector

examined the transfer

tube,

and discussed

plans for the ICI transfer with licensee

personnel.

The

licensee

conducted briefings consistent with requirements

for

imfrequently performed evolutions.

including discussion of contingencies

for addressing

unexpected

conditions.

The inspector

concluded that the

activity was carefully and thoroughly planned.

The ICI remnant transf'er

was performed shortly after completion of the

core offload.

The activity proceeded

smoothly, with very low dose

absorbed

by workers.

Conclusions

The inspector

concluded that the transfer of ICI remnants

from the

reactor vessel

to the spent fuel pool was carefully and thoroughly

planned

and completed with low radiation dose

expended.

Maintenance

Procedures

and Documentation

SGRP Weldin

Procedures

50001

Inspection

Scope

The inspector

reviewed the welding procedure specifications

(WPS)

and

the supporting procedure qualification records

(PQR) for the St. Lucie

Unit 1 SGRP.

Observations

and Findings

The inspectors

reviewed fifteen WPSs which had been prepared

specifically for the St. Lucie

1 SGRP.

Thirteen of the procedures

were

qualified in accordance

with the requi rements of ASME Section

IX and

were supported

by PQRs;

two of the procedures

were prequalified

AWS

procedures

which did not require

PQRs.

For twelve of the

ASHE WPSs, the weld assemblies

represented

by the

PQRs

were welded

and tested in 1997, specifically for the St Lucie SGRP.

The

review by the inspectors

showed that all required "essential"

and

"supplementary essential"

elements

were properly documented in the

PQRs

and the

WPSs.

The remaining

ASHE

WPS (GT/8.43-1 SL) was

a gas tungsten

arc welding

procedure for welding stainless

steel to Inconel; the

PQR supporting

this

WPS

(PQR GTM/8.43-Ql, Rev.0)

was completed in February

1992.

and

reported the tests that were conducted in July 1985.

While the test

weld data

were in excess of 10 years old, the

PQR met all procedure

qualification requirements of the current

ASME Section

IX, in that, all

"essential"

and "nonessential"

welding variables

were provided by the

PQR.

Enclosure

2

M5

M5.1

18

The inspectors

did note that f'r two of the

WPSs

a nonessential

element

was not completed in two cases.

The procedures

for welding Inconel

(P43) to Carbon Steel

(Pl) and Inconel

(P43) to Stainless

Steel

(P8)

contained

"none" or "N/A" in the spot reserved for the weld filler

material

"A-number designation"

even though the materials

were fully

identified by brand

name in another part of the

WPS.

(In that the

ASME

has not assigned

an "A-number designation" for the Inconel welding

material

used,

accepted

protocol would have been to: list the filler

material

brand

name in the "A-number designation"

space of the

WPS,

rather than list it in another location.

The "A-number designation" is

listed as

a "nonessential

element"

by ASME Section

IX. and is required

to be included in the procedure.).

When this was pointed out. the

licensee/contractor

agreed to revise the two procedures

to show the

filler material

brand

name in the proper location in the

WPSs.

The inspectors

also questioned

the

PQRs for welding of "impact tested"

Pl materials.

The test assembly

base materials in the

PQR were listed

as "Pl,

Gp

1

& 2" to "Pl,

Gp

1

& 2" despite the tact that

a change

from

one group number to another would require requalification of the welding

procedure.

(As specified

by ASME Section

IX, to fully qualify with one

test plate, the assembly

would have to consist of Group

1 material

welded to Group

2 material.)

When this was questioned.

the

licensee/contractor

was able to produce

a material certification for the

test plates,

showing that the

ASME SA516,

Grade

60, test plate material

met all of the chemical

and physical

requi rements for ASME SA516,

Grade

70,

and therefore qualified as Pl, Group

1 and Pl, Group 2.

Conclusions

The welding procedures

for the Steam Generator

Replacement

Project were

complete

and appropriately qualified in accordance

with required welding

standards.

Maintenance Staff Training and Qualification

SGRP Welder

uglification

50001

Inspection

Scope

The inspector

reviewed welder qualification facilities and activities

related to preparations

for the

Observations

and Findings

The

SGRP welder training and qualification facility was

a converted

maintenance

building, outside the security area,

on the north side of

the St Lucie site; the facility was referred to as "the boathouse."

The inspector

reviewed the procedures

for security of welder

qualification test assemblies

through

a walk-through inspection with the

Enclosure

2

19

test

super visor

.

The inspector

was

shown

how welder identification was

verified; how test assemblies

were permanently identified;

and

how the

assemblies

were secured

in a locked

room when

a test weld took longer

than one shift to complete.

The supervisor

also demonstrated

how- the

test assembly identification was transferred to each

bend specimen

taken

from the assembly.

Conclusions

Replacement

Project welder training and qualification

activities were being conducted in full compliance with ASME Section

IX

requirements.

Quality Assurance in Maintenance Activities

ualit

Re orts and Surveillances

50001

Inspection

Scope

The inspector

reviewed quality and nonconformance

reports related to

welding activities.

Observations

and Findings

Quality reports

are generated

by the

FP8L Nuclear Assurance

Group to

document survei llances of licensee

and contractor

SGRP activities.

Since

Hay 1997, there

have

been in excess of 30 Nuclear Assurance

survei llances of the contractor's

welding related acti vities.

Twelve of

these surveillances

identified potential

problems with the

implementation of the welding program.

The inspector

reviewed the

12 surveillance reports that identified

unsatisfactory

audit findings.

The majority of the surveillance

findings were minor findings which were corrected at the time of

discovery

and reported in the surveillance reports

as

"VIS"

(unsatisfactory,

immediately satisfactory)

or were quickly corrected

after the surveillance

report was issued.

The results of these

surveillances

indicated that the welding program was functioning in a

satisfactory

manner, with only minor problems.

The major exceptions to this impression

were the findings of Quality

Reports

97-6186,

dated October

28,

1997,

and 97-6215.

dated October

30,

1997, which documented

problems with undersized

welds which had been

accepted

by the contractor's

QC inspectors.

The corrective actions for

these survei llances

involved 100 percent reinspection of welds accepted

by the

QC inspectors identified in the surveillance reports,

along with

a sample of welds accepted

by other

QC inspectors.

After the ultimate

disqualification of one

QC inspector,

the licensee

and contractor

concluded that they had determined the extent of the problem,

and had

corrected it.

The inspectors

agreed that the most serious

aspect of the

Enclosure

2

20

problem had been

addressed

by fully investigating the

QC inspector

involvement,

and that the corrective action was appropriate.

The one

question that did not seem to be addressed

was the welder and welder

supervisors'nvolvement

in undersized

welds that were turned over to

QC

for inspection.

Conclusions

The licensee's

Nuclear Assurance surveillance activities provided

a

comprehensive

review of the contractor's

welding and welding inspection

activities.

III. En ineerin

Conduct of Engineering

Review and Walkdown on

SGRP Liftin

and Trans ort Pre aration for Unit 1

~50001

Inspection

Scope

The inspectors

examined the Steam Generator

Replacement

Project

(SGRP)

lifting equipment which was erected

inside

and outside the Unit

1

Containment Building.

Additionally, the inspectors

reviewed the

adequacy of the

SGRP lifting and transport

programs,

procedures,

work

packages

(WPs)

and load test records, to assure that they were prepared

and tested in accordance

with regulatory requirements,

appropriate

industrial codes,

and standards.

Observations

and Findings

The licensee contracted

the entire

SGRP to the Steam Generator

Team

(SGT) which was formed by a collaboration

between

Duke Power Engineering

(DPE) and Morrison Knudson Corporation

(MKC).

Duke Power Engineering

provided the engineering expertise

and

MKC provided the construction

'xpertise

to the project.

The

SGT subcontracted

the heavy lift

engineering

and operation of the

SGRP to Mammoet Transport Engineering,

Netherland.

The licensee listed American National Standard Institute (ANSI) codes

as

references

in the

SGRP Lifting Program.

As specified in ANSI N45.2. 15,

"Hoisting, Rigging.

and Transporting of Items for Nuclear

Power Plants,"

1981. the licensee

performed

110 percent

load tests for the erected

Temporary Lifting Devices

(TLD) inside the containment,

Outside Lifting

System

(OLS) outside the containment,

and transporters

which transferred

the steam generators

to or from the temporary storage

area.

A Horizontal Transfer System

(HTS) was installed inside the containment

and extended outside the containment

and provided the transfer

connection

between the TLD and the

OLS.

Enclosure

2

21

The licensee established

procedures

and

WPs, drawings.

and calculations

for removing, transporting,

and installing the original and replacement

SGs.

The inspectors

randomly selected

and partially reviewed the

following WPs, calculations,

and drawings for the heavy load lifting and

transport preparation:

WP 1039,

"Erection of TLD Mock-Up and Load Test of TLD and Gantry

Crane," Revision

0

Calculation

PSL-1MHC-95-014.

"Foundation Design for Temporary

Gantry and Horizontal Transfer

System for SGRP," Revisions

2 and

6

'FPL Dwg. SGR-DP-5.3-014,

"Handling

SG with TLD Inside

Containment,"

Revision

0

FPL Dwg. SGR-DP-5.3-016,

"Handling

SG Inside Containment-

Downending Process,"

Revision

0

FPL Dwg. SGR-DP-5.2-002,

"Handling Steam Generator Outside,"

Revision

1

The licensee successfully

performed the required load tests

in

preparation for the

as recorded

on

WP 1039.

The design loadings of

the foundations

were obtained

from addendum to this calculation,

and

included dead, live, and wind loads applied to the structures

and

foundations.

Three drawings detailed the

SG lifting, downending,

and

moving processes.

The inspectors

walked down and inspected

the lifting equipment stored in

the yard area,

the TLD erected

inside the containment,

the

OLS erected

outside the reactor building,

and the on-site fabrication facility for

performing final preparation of the steam generators.

The inspectors

considered that the erected lifting systems,

the on-site fabrication

facility, and the lifting equipment storage

area

were adequate

and could

achieve the intended function for the

A11 the temporary lifting

devices

and equipment will be removed from the site after the completion

of the

Conclusions

The inspectors

concluded that the required lifting plan. path,

calculations,

and analyses

generated

and performed for the safe lifting

and transfer operations

for the original and replacement

SGs were

adequate.

Review and Walkdown on

En ineerin

Pre aration for Unit 1

50001

Inspection

Scope

The inspectors

reviewed the installation of temporary pipe restraints;

Enclosure

2

22

modification of the existing restraints:

removal of snubbers,

beams.

instrument lines;

and pipe cuts in order to verify that the engineering

preparation for the removal of SGs

was in accordance with the applicable

WPs and drawings for the

b.

Observations

and Findings

The inspectors

discussed with the licensee's

engineers

the restraint

systems to be installed or modified for removal

and installation of the

SGs.

The licensee's

engineers,

based

on their research,

indicated that

there was

no evidence that any pipes

or

SGs would shift during or after

cutting.

However, the licensee

took precautions

and either installed

temporary restraints

or modified existing restraints to become rigid

restraints

in order to provide additional stability and prevent the

shifting of pipes during the cutting process.

This was done for the

SGs,

main steam lines,

hot and cross leg pipes,

feed water pipes.

and

auxiliary feed water

pipes.

The inspectors

reviewed several

WPs and drawings for installation,

modification,

or

removal of the restraints

and pipes

and considered

them

to be acceptable.

The inspectors

inspected

the preparations

for

removing the

SGs

and compared the work performed to the drawings.

The

inspected

elements

included pipe cuts, installation of the temporary

restraints,

modification of the existing restraints,

and removal of the

interferences

such

as

beams,

snubbers,

instruments,

and electrical

cables.

etc.

The drawings

used for the walkdown inspection were:

~

SGR-DP-6. 1.1-001 to 007,

Reactor Cooling System

- 1A side

~

SGR-DP-6.2. 1-001

and 002,

Main Steam Spring Hanger

MSH-79 and

Rupture Restraint

RE-MS-17 for SG

1A

~

SGR-DP-6.3.1,

Feed

Water Spring Hanger

BFH-81 and Rupture

Restraint

RE-BF-10 for SG

1A

~

SGR-151-193-001 to 006,

SG

1A Piping Demolitions

The inspectors

found some minor discrepancies

during the walkdown.

These minor discrepancies

were discussed

with the appropriate

licensee

personnel.

The inspectors

considered that the engineering

preparation

for the removal of the

SGs was adequate.

c.

Conclusions

The inspectors

concluded that the licensee

performed adequate

engineering

preparations

for the removal, installation, modification of

piping, restraints

~

and interferences

for the removal

and installation

of the SGs.

Enclosure

2

23

El.3 Observation of SG Liftin

and Trans ortin

for Unit 1

50001

a.

Inspection

Scope

The inspectors

observed the lifting of the

SGs to and from the

containment

area

and transporting of the equipment to and from the

temporary storage

area to verify that those activities were performed in

accordance

with the established

procedures

or WPs.

.

Observations

and Findings

The

WPs used for the lifting and .transporting the original and

replacement

SGs were:

~

WP 2570A,

"Removal of Original Steam Generator

1A," Revision

1

~

WP 25708,

"Removal of Original Steam Generator

18," Revision

1

~

WP 3040A. "Installation of Replacement

1A,"

Revision

1

The inspectors partially observed

the licensee's

removal of two OSGs

from the containment

area

and transporting

them to the temporary storage

area.

The lifting and transporting

steps for the

SGs included:

checking

the clearances f'r removal; lifting and rotating the

SGs from the rest

pad to the center of the containment;

lowering the

SGs for sealing

(or

welding) the hot and cross

leg nozzles with cover plates;

downending the

SGs with the TLD and

a skid unit; pushing the

SGs outside containment;

lifting the

SGs to the transporter

by using the OLS: and transporting

the

SGs to the temporary storage

area.

For

a

RSG to be moved into the

containment,

the process

was reversed.

On November

15, the licensee

began lifting the

1A SG from its cubicle.

The lift was halted after the

SG was lifted approximately

2 feet,

so

that the remaining water could be removed from the channel

head.

It was

then raised

up to the refueling floor where covers were welded over the

hot and cold leg nozzles.

The

SG was then

moved outside of containment,

lowered to the mobile transporter,

and on November

18, transported to

the temporary storage location outside of the protected

area.

The 18 SG, which followed the same sequence

of events,

was lifted on

November

17 and transported to the temporary storage location on

November

19.

The inspectors

observed

a large portion of each aspect of the

SG move.

On November

16, the inspector

reviewed the procedure

being used to lift

the

1A Steam Generators

Work Package

2570 A, Revision 1.

"Removal Of

Original Steam Generator

1A", and noted that several

steps

had not been

signed

as complete,

although the work had been performed.

The steps

not

signed were for the

SG to be hoisted

upward and then rotated

around

Enclosure

2

24

containment to align it with the equipment

hatch.

At the time the

unsigned

steps

were identified, the

SG was stationary with the

RCS

nozzle plugs being welded into place.

The inspector

brought this to the

attention of the

FP8L shift manager,

who had the procedure

updated.

In

addition, the inspector discussed this issue with both

FP8L management

and Steam Generating

Team

(SGT) management

to determine

what the

expectation

was with regard to signing off procedural

steps after they

are completed.

Although both groups indicated that. it was their

expectation that procedure

steps

be signed

as

soon

as possible after

they were complete,

SGT

QC offered several

explanations

why these

articular steps

were not signed.

One explanation

was that it would not

e safe for the Person

In Charge .(PIC) to divert his attention to

signing

a procedure

when the

SG was being moved.

Another explanation

was that the PIC was directing other important activities.

The

inspector took exception to these explanations

based

on the lack of

activity which was in progress

when the unsigned

steps

were identified.

Later inspections

did not identify additional

examples.

Overall, the inspectors

considered that the licensee

handled the removal

of the

OSGs very well.

During the welding process,

the inspectors

observed that the licensee

issued hot work permits

and stationed fire

watches with extinguishers

near the welding area f'r the control of

combustible materials

as required

by WPs.

The inspectors

also partially observed transporting

a

RSG from the

temporary storage

area

and lifting it into containment

and noted

no

discrepancies.

Shortly after lifting the first

OSG from its rest position, the

inspectors

went to the top of the TLD main girders

and f'ound that there

were no markings

on the top of the main girders to indicate the

hydrajack near side

and far side travel limits.

There were near side

and far side travel limit markings

on one side of one main girder and

there

was

a near side travel limit marking on the bottom of both main

gi rders.

Step 38, Sheet

14 of 17, of WP 1038,

"Erection of the

Temporary Lifting Device (TLD) inside the Containment." stated:

"Apply. or verify, markings (e.g.

~ tape line) on the top and

bottom of one of the main girders to show the travel limits from

the centerpost

centerline.

Note:

Ensure the locations of the

markings are visible to the hydrajack operator

and to the PIC on

the floor."

The inspectors

conducted

several

discussions

with a day shift PIC and

hydr ajack operator to verify they could see the

mar kings.

The

inspectors

also verified by di rect observations

the location of existing

main gi rder markings

and questioned if they could clearly be observed

for various main girder positions.

The inspectors

concluded that the

existing markings did not meet the

HP requirements

and they could not be

observed

from all main girder positions.

The licensee

marked the main

Enclosure

2

E2

E2.1

a.

25

girder as required

by the procedure

before the inspectors

concluded

their inspection in this area.

The lack of'arkings

on the top and bottom of one of the main girders,

such that the hydrajack travel limits were visible to the hydrajack

operator

and to the PIC on the floor, constitutes

a violation of 10 CFR 50 Appendix B, Criterion V. and the licensee's

accepted

Quality

Assurance

Program Section 5.0.

They collectively require that

activities affecting quality shall

be accomplished

in accordance

with

documented

instructions or procedures.

This was identified to the

licensee

as Violation 50-335/97-13-01,

"No Travel Limit Markings on the

.

Top and Bottom of One of the Main gi rders of the Temporary Lifting

Device."

Conclusions

Overall, the inspectors

concluded that the licensee

performed adequate

operations for the lifting and transporting of two OSGs from the

containment building to the temporary storage

area.

A violation was

identified for not marking the top and bottom of one of the main

girders. to indicate the travel limits of the hydrajack.

Engineering Support of Facilities and Equipment

Full Core Offload Safet

Anal sis

37551

Inspection

Scope

The inspector

reviewed the Engineering safety evaluation

PSL-ENG-SENS-

97-0050,

Revision 0, "Routine Performance of Full Core Fuel Offloads,"

to check technical

adequacy

and to ensure that all recommendations

had

been properly translated into procedures.

Observations

and Findings

Safety evaluation

PSL-ENG-SENS-97-050,

Revision 0,

was issued

by the

licensee

on August 19.

The purpose of the evaluation

was to develop the

conditions

under. which Unit 1 may fully offload the core for all future

refueling outages.

It also addressed

the temporary storage of the

reactor internals within the vessel

and the head

on the vessel

after all

fuel was transferred to the spent fuel pool.

The inspector

found the

evaluation well presented.

It clearly documented that no unreviewed

safety questions

existed.

Also, it laid the basis for future full core

offloads

as the routine.

The inspector

noted that

a

FSAR change

request

was included with the evaluation to agree that full core offload is the

normal

method of defueling.

Section 5.0 of the evaluation listed eleven conditions with which the

plant must comply in order

for the evaluation to be valid.

The

inspector verified that all of the restrictions

had been incorporated

Enclosure

2

E2.2

26

into the appropriate

procedures.

One item of interest that the

inspector

noted was that the procedure

revisions were not issued until

a

few days prior to the beginning of the outage.

The licensee

stated that

this occurred

due to the large workload for the Procedures

group.

The

inspector did observe that Operations

had

a dedicated

SRO reviewing the

procedures

as they became available to verify that the procedures

were

accurate.

Conclusions

The full core offload safety evaluation

was well presented

and clearly

documented

the lack of any unreviewed safety questions.

The evaluation

was properly translated into the applicable procedures to ensure that

the evaluation

was valid.

Flow Test of the Unit 2 to Unit

1 Condensate

Stora

e Tank Cross-tie

37551

61726

Inspection

Scope

The inspector witnessed the performance of LOI-0-85, Revision 0,

"Flow

Test of the Unit 2 to Unit 1 Condensate

Storage

Tank Cross-tie."

The

procedure

was

an "approved for use" copy of Revision 0.

Observations

and Findings

A cross-tie line between the Unit 2 Condensate

Storage

Tank (CST),

and

the Unit

1 CST,

was established

as part of a licensing commitment for

Unit 1.

The cross-tie

and dedicated

water supply in the Unit 2 CST were

provided for use in the event that

a vertical tornado missile disabled

the Unit 1 CST.

Inspector Followup Item 50-335/96-201-06,

was identified during an

NRC

design inspection.

documenting that although the cross-tie

had been

established, it had never

been flow tested.

In response,

to that

finding, the licensee

developed the aforementioned

procedure to operate

the Unit 1 Auxiliary Feedwater

(AFW) pumps through the cross-tie

from

the Unit 2 CST.

The purpose of the procedure

was to verify that the Unit

1 AFW accident flow rate plus the recirculation flow, could be passed

through the cross-tie.

Prior to performing the test,

the licensee

held

a pre-job brief.

The

inspector witnessed the brief and thought it to generally

be thorough.

It was attended

by the appropriate

personnel,

with the exception of the

non-licensed field operator.

The ANPS stated that he would be stationed

with the field operator

and would ensure

he received

an appropriate

brief, as needed.

During the briefing, it was identified that the

procedure

required

AFW flow to reach

460 gpm, but the range of the

control

room indicator

was only 400 gpm.

The licensee

reviewed the

engineering

analysis

and verified that operating the

pump at 400

gpm

Enclosure

2

E8

E8. 1

27

would be adequate to verify proper operation.

The procedure

was revised

and

FRG reviewed.

The inspector

reviewed the analysis

and concluded the

licensee's

conclusions

were sound.

The inspector witnessed portions of the pre-test

valve alignment

and

noted the operators verified each valve tag prior to manipulating the

valves.

Additionally, the inspector

noted that the oil level for the

1A

pump was below the normal level designated

on

a placard attached to the

pump skid.

The licensee

was informed and concluded that it was adequate

for operation of the pump.

The 1A pump was started, test data

was taken

and all the test criteria

were satisfactorily

met.

IFI 50-335/96-201-06, will remain open pending

an engineering

review of the test data.

Conclusions

The AFW cross-tie flow test

was satisfactorily completed.

The inspector

considered

the failure to identify the range of the flow meter to be

inadequate for the test,

a weakness

in the technical

review of the

procedure.

Hiscellaneous

Engineering Issues

Evaluation of Ino erable Unit 2 Containment

Fan Cooler

37551

Inspection

Scope

The inspectors

reviewed

an evaluation

performed

by the vendor,

Asea

Brown-Boveri Combustion Engineering Nuclear Operations

(ABB CENO), which

analyzed the significance of operating with an inoperable containment

cooling fan.

This evaluation

was performed in response to the licensee

discovering

one of the Unit 2 containment

fan coolers rotated in the

reverse direction when operated

in the emergency

mode.

The inspector's

review was performed to verify that the accident analysis

data

used in

the evaluation

was bounded

by that used in the

FSAR analysis.

The

details of this event were discussed

in Inspection Report 97-15.

Observations

and Findings

As discussed

in IR 97-15, the licensee

requested

that

ABB CENO evaluate

the safety significance of power operations with an inoperable

containment

fan cooler.

This evaluation

was

documented

in an ABB CENO

letter dated October

14,

1997.

ABB CENO concluded that peak containment

pressure for the limiting LOCA would increase

by no more than 0.5 psi,

and would not exceed

containment

pressure

design limits.

Inspectors

reviewed the ABB CENO letter,

FSAR Section 6.2,

and the

containment

fan cooler technical specification bases.

The limiting LOCA

for containment

pressure

is

a double-ended

suction leg slot

(DESLS)

Enclosure

2

28

break with minimum safety injection flow.

The event analysis

described

in the

FSAR was performed in 1993 as part of a licensee effort to

improve documentation of design basis information.

This case provided

the baseline

used for. the ABB CENO evaluation of the effect of an

inoperable

containment

fan cooler.

After the

FSAR analysis

was updated in 1993, the licensee

asked

ABB CENO

to evaluate the effect of'

longer containment

spray delay time.

The

FSAR analysis is based

on the

TS delay time of 25.65 seconds,

which

represents

the time to start the containment

spray

pumps.

The licensee

calculated

a delay time of 45.5 seconds for flow to reach the spray

nozzles,

with full flow attained .at 58.5 seconds.

ABB CENO determined

that there

was sufficient margin in the calculation to accommodate

the

increased

delay time, so the peak pressure

reported in the

FSAR remained

valid.

ABB CENO subsequently

identified additional

conservatisms

in the

FSAR

analysis,

and

recommended that

an updated

containment

response to a

LOCA

be performed.

However, the conservatisms

identified by ABB CENO will

improve containment

pressure

margin for this event.

Therefore,

the

LOCA

results given in the

FSAR remain bounding.

Conclusions

The inspectors

concluded that the evaluation

performed in response to

the discovery of an inoperable Unit 2 containment

fan cooler,

was

adequate

in that the accident analysis

data

used

was bounded

by the data

used in the

FSAR.

Additional discussion

and review of the inoperable

fan cooler was performed in

NRC Inspection Report 97-15 with EA number

97-501.

Closed

LER 50-335/96-014-00

"Invalid ESF Actuation of CI Oue to

Failed Rela

"

92903

This

LER documented

an invalid actuation of several

containment

isolation system

(CIS) components.

These actuations

resulted

from a

failed engineered

safety features

(ESF) actuation relay on October 27,

1996, for Unit 1.

There was

no adverse affect on plant operation.

The

relay was replaced

and the

ESF components

restored to their normal

operating configuration.

The inspector

reviewed the licensee's

investigation

and corrective

actions.

In addition to relay replacement

and system restoration,

additional corrective action included failure analysis of the relay and

a review of industry and plant data.

An adverse failure trend was not

identified for this relay.

Failure analysis identified the failure was

due to aging of the relay.

The inspector

found the licensee's

investigation thorough

and corrective action appropriate.

This

LER is

closed.

Enclosure

2

E8.3

E8.4

29

Closed

VIO 50-335/96-17-04

"Failure to

U date the Plant

Ph sics

Book"

~92702

This violation involved the failure to update reactor physics

data for

the Unit

1 Plant Physics

Curve Book.

Following completion of full

length control element'ssembly

(FLCEA) testing,

Shutdown Margin

Verifications were performed

on October

31 and November

1,

1996.

Procedure

OP 1-0110055,

Revision 16, "Surveillance

Requirements

for

Shutdown Margin,

Modes

1 and

2 (Critical)," required operators to obtain

reactivity information provided in Figures A.6, B.3 and B.4 of the Unit

1 Plant Physics

Curve Book.

This Operator

Aid, as defined in Step 3.4.6

of Procedure

AP 0010140,

Revision 9, "Control of Operator Aids," is

"generated

and updated

by the Reactor Engineering department tor use by

Control

Room operators

in the operation of the plant."

The inspector

noted that the Unit 1 Plant Physics

Curve Book showed B.3 Reactivity

Deviation Log (Updated Monthly).

The last entry on Figure B.3 was dated

September

18.

The inspector brought this to the attention of the

ANPS who contacted

Reactor Engineering.

RE verified that Operating Surveillance

Procedure

64.01.

Revision

16,

"Reactor Engineering Periodic Tests,

Checks

and

Calibrations," Appendix 7, "Reactivity Deviation From Design,"

was

performed

on October

8 and not entered in the Unit 1 Plant Physics

Curve

Book Figure B.3 Reactivity Deviation Log.

Condition Report

No. 96-2751

was written to address this issue.

Procedure

QI 5-PR/PSL-l,

Revision 73, "Preparation,

Revision,

Review/Approval of Procedures,"

in Step 5. 14. 1 stated

"A strict

adherence to procedure/guideline

requirements

- Verbatim Compliance

- is

the policy expected

and required of all St. Lucie Plant personnel."

Procedure

OSP 64.01,

Revision 16,

"Reactor

Engineering Periodic

Tests'hecks

and Calibrations," Appendix 7, "Reactivity Deviation From

Design," Step 4. 15 stated

"Document the results in Plant Physics

Curve

B.3. Reactivity Deviation Log, in the Control

Room (applicable Unit) and

Reactor

Engineering Plant Physics

Curve Book."

The inspector

reviewed the root cause

and corrective actions identified

for this violation.

A verification checklist

was developed for updating

the Plant Physics

Curve book,

and the Reactor

Engineering

Schedule of

Periodic Tests

and Reports

AP-0010127

was revised to require

a weekly

review of the Plant Physics

Curve book.

The inspector

reviewed these

revisions

and found them adequate to correct the causes

of the

violation.

This violation is closed.

Closed

VIO 50-335/EA-96-457/03023

"Failure to Initiate

a Condition

Re ort for Labelin

on Safet

Related Detectors"

92702

This violation involved the fai lure of the I

8

C maintenance

personnel

involved in the replacement of the No.

6 Channel

B linear range detector

for the Nuclear Instrumentation to initiate a Condition Report

(CR) when

Enclosure

2

30

cables for the replacement

detector

were labeled differently than the

existing ones.

The inspector

reviewed the licensee's

cause determination

and corrective

actions for this violation.

The cause of the violation was determined

to be personnel

error

due to an informal approach

being used to resolve

the discrepant

condition instead of the requi red

CR process.

Personnel

were counseled

on the

CR process

and this violation.

The inspector

reviewed the

PHAI corrective action forms which identified the training

and the participants for this corrective action.

Additional corrective

action included documentation

provided by the vendor to clarify cable

designations.

The inspector

found these corrective actions

adequate

and

this violation is closed.

IV. Plant

Su

ort

Radiological Protection

and Chemistry Controls

SG

Re lacement

Ins ection

50001

and Occu ational

Radiation

Ex osure

83750

Inspection

Scope

The purpose of this inspection effort was to verify that Radiation

Protection

(RP) activities for the Unit 1 Refueling Outage

(RFO) and the

Replacement

Project

(SGRP) were performed 'safely and met

applicable regulatory

and licensee

requirements.

The

RP program planning, preparation,

and implemented controls were

reviewed in the following program areas:

As Low As Reasonably

Achievable

(ALARA) planning:

Dose estimates

and dose tracking;

Exposure Controls

and temporary shielding;

Contamination controls;

Radiological

work plans

and controls;

storage

and disposal

and

Staffing and training plans.

The inspection included reviews of'ecords

and procedures,

interviews

with licensee

personnel

and observations

of work activities in progress.

The inspectors

made observations

in the Unit 1 Reactor

Containment

Building (RCB). Reactor Auxiliary Buildings

(RABs), Original Steam

Generator

(OSG) Interim Storage

Faci lity ( ISF),

and yard areas within

the Radiation Control Area

(RCA).

Observations

and Findings

Radiolo ical Work Plans

and

ALARA

Enclosure

2

31

The

RP staff'egan

preparing for the

SGRP in 1996.

Approximately six

months prior to the start of the'outage

the licensee obtained the

services of radiation protection personnel

having experience

in recent

SGRPs to develop the specific ALARA work plans for the project.

The licensee

developed

a series of documents titled Health Physics

Project Overviews

(HPPOs) which provided Health Physics

(HPs)

an

overview of'he specific

SGRP and pressurizer

heater

replacement

tasks.

The

HPPOs described

the process

employed in the infrequently encountered

SGRP tasks

such

as pipe end 'decontamination

and Reactor Coolant Systems

(RCS) pipe severance.

The documents

also outlined the application of

radiation protection measures

to be applied to processes

such

as the use

of containments

or High Efficiency Particulate Air-filters.

The

informative documents

served

as basic radiation protection plans for the

tasks.

The inspectors

reviewed radiological protection activities associated

with several

SGRP tasks during the inspection

and generally observed

the

application of sound radiation protection control measures.

The inspectors

reviewed the licensee's

dose goals for 1997

and the

to assess

thei r performance in obtaining those objectives.

The licensee

modified the various collective dose goals during the year.

The

original dose goals for 1997, the revised goals,

and actual

person-rem

accumulated

are

shown in the table below.

1997 SITE COLLECTIVE DOSE

GOALS AND ACTUAL EXPOSURE

(PERSON-REM)

Original

Goal

Routine Operations

25.0

Unit 2 RFO (Spring 97)

150.0

Unit 1

RFO (Fall 97)

205.0

Unit

1

240.0

Unit 1 Pressurizer

30.0

Plant Manager

Reserve

25.0

TOTALS

675.0

Revised

Goal

22.5

171.5

191.0

247.0

43.0

0.0

675.0

Actual*

Exposure

25.0

169.5

88.5

83.5

65.9

0.0

432.5

Through day 29 (November

17,

1997) of the 75 day Unit

1

RFO and

The inspectors

reviewed the licensee's

processes

for estimating task

dose projections

and the licensee's

dose tracking system.

The licensee

was continuously

and effectively tracking and trending outage

and non

outage

doses to evaluate

dose reduction efforts on nearly 200 Radiation

Work Permits

(RWPs).

The total dose goal for all Unit 1 outage work was

481 person-rem.

Through

November

17,

1997 the actual

dose

was 238.0

person-rem

which was slightly above the projected

dose of 235.8 person-

rem.

The collective doses

were:

Enclosure

2

32

RFO ...........89.5

person-rem

vs projected

108.4 person-rem;

SGRP ..........82.5

person-'.rem

vs projected

100.4 person-rem;

and

Pressurizer

...65.9 person-rem

vs projected

27.0 person-rem.

With the exception of the pressurizer

heater

replacement

project the

licensee

was generally below the projected

dose estimates

for most

tasks.

In most of those,

the number of hours estimated for the tasks

turned out to be too low.

The licensee

underestimated

the time to cut

the heater

tubes which was one of the reasons

the pressurizer collective

doses

were so much higher than projected.

The inspectors

reviewed the results of the licensee's

shutdown

RCS

cleanup procedures

for the Unit

1 RFO.

The licensee

implemented

licensee

Procedure

COP-05.03,

Revision

1, "Refueling Shutdown/Startup

Guidelines."

The licensee

provided sufficient time in the outage

schedule for the cleanup

phase of the procedure.

The licensee

also

considered

the impact the crud burst would have

on various systems

and

delayed work in those areas until the clean

up processes

were completed

for ALARA purposes.

The

RCS clean

up process

worked as planned but did

not result in as great

a crud burst

as the licensee

expected.

However,

the licensee

reported the process

had reduced contamination levels in

the

RCS.

Ex osure Controls

and

Tem orar

Shieldin

On tours within the

RCA, the inspectors

made independent

radiation

surveys,

examined the adequacy of the licensee's

radiation protection

boundaries

and radiological postings,

examined labeling of containers,

verified radiation monitoring equipment in use

was calibrated

and

receiving periodic source

checks.

The inspectors

also checked the

security of high radiation areas,

housekeeping,

radiation worker

compliance with radiation protection controls,

observed

Health Physics

Technicians

(HPT) performing radiation surveys.

and inter viewed

radiation workers.

Overall,

RP controls were good.

The inspectors

found the licensee

made good use of remote monitoring

equipment including communication,

video and tele-dosimetry to reduce

collective dose.

The licensee

also utilized shielding when practical.

The licensee

reported using nearly twice as

much lead in the

SGRP outage

than used in previous outages.

Contamination Controls

Unusually large quantities of contaminated

materials,

tools and

equipment were utilized during the

The licensee

had prepared for

the handling of the materials.

The inspectors

observed

movement of tools and equipment out of the

licensee's

equipment

hatch throughout the inspection to verify proper

radiological controls were implemented for materials exiting the

Enclosure

2

33

Containment Building.

The licensee

had

a contaminated

area

boundary

that extended

outside the Containment Building approximately

30 feet.

The inspectors

found

a

HPT posted at the hatch at all times.

The

inspectors

noted the area

was not covered

and was exposed to the

elements.

The inspectors

inqui red about contamination controls

when

raining.

The floor of the contaminated

area

was covered with thick

plastic sheets

which sloped

down into a trough.

Licensee

representatives

reported during periods of rain, water

flowed into the

trough and was absorbed with mop heads.

The inspectors

asked

HPTs about

the ability to conduct contamination

surveys in the rain.

The HPTs

reported that release activities were halted during rain storms.

The

inspectors

observed

and reviewed area contamination

surveys

made at the

equipment hatch.

Contamination levels inside the contaminated

area

were

low and checked several

times each shift.

The

HPTs also surveyed the

clean side of the contaminated

boundary several

times

a shift.

No

violations of regulatory or licensee

procedures

were identified during

the review.

The licensee

opened the construction

hatch to permit the removal

and

replacement of the SGs.

The licensee

decontaminated

portions of the

RCB

and an area directly in front of the construction hatch.

The licensee

built a deck to support the track the

SGs travel

on in and out of the

RCB.

The licensee stationed

Health Physics

(HP) personnel

in the area

to control work activities there.

The area

was monitored for

contamination during the inspection.

The inspectors

also reviewed personnel

contamination reports

completed

in 1997.

The licensee

documented all personnel

contamination

events

when contamination levels greater

than

100 counts per minute/100

cm'ere

found on personal

clothing or body.

The inspectors

noted

many of

the contaminations

were the result of radiation workers adjusting face

shields or communication headsets.

No concerns with personnel

contamination

events identified.

During the review, the inspectors

observed radiation workers that were

entering contaminated

areas with protective clothing that was not fully

donned or sealed.

Workers were failing to zip coveralls

up fully or

close hoods.

When it was observed.

the inspectors

informed individual

workers or HPTs in the work area

and proper corrections

were promptly

made.

During the inspection,

the inspectors

noted

improved worker

performance

and increased

HP efforts to address

the observed

poor work

practices.

c.

Conclusions

The

HPPOs developed to instruct and establish

radiological controls for

unique

SGRP task were an excellent planning resource.

The inspectors

confirmed that

ALARA and

RP concerns

were factored into the

planning.

Collective dose for the pressurizer

heater project was

significantly underestimated.

With the exception of the pressurizer

Enclosure

2

R1.2

heater

replacement project, the licensee

was effectively estimating

and

tracking collective doses for planned tasks.

Good

RP control measures

were in place inside the licensee's

RCA and overall licensee

exposure

controls were effective.

Good use of'emote radiation monitoring

technology to monitor work in radiation

and high radiation areas

and to

save collective dose

was observed.

Licensee contamination controls were

effective.

Licensee

RP controls for temporary containment

openings

were

appropriate

and effective.

Radiation

Work Permits

50001

83750

Inspection

Scope

The

RP controls

as di rected

by

RWPs were reviewed to evaluate the

adequacy of the controls.

Radiation worker awareness

of those controls

was also reviewed.

Observations

and Findings

Licensee

RWPs provided instructions for radiation workers performing

task within the licensee's

RCAs.

As described

in section 12.5.3.4 of

the licensee's

Final Safety Analysis Report,

RWPs define allowable

exposures;

stay times; anti-contamination clothing; respiratory

protection:

survey requi rements;

and special

precautions

or instructions

for the work to be performed safely, efficiently, and within the ALARA

commitment.

Radiation

Worker Performance

Each worker entering the

RCA was required

by licensee

procedures

to

determine the proper

RWP f'r the work activity planned

and location

where the work was to be performed.

The licensee's

automated

Access

Control System

(ACS) was used

by RP staff to control access

into and out

of RCA areas.

Personnel

entering the

RCA were requi red to have

a

RWP,

a

thermoluminescent

dosimeter,

and

a Digital Alarming Dosimeter

(DAD).

The ACS terminal required the worker to provide the

RWP number

and. to

confi rm they had reviewed the

RWP requi rements.

If the

RWP requi red

a

pre-job briefing, the system would check to see if the worker had

attended

an applicable pre-job briefing and verify the radiation

worker's remaining allowable dose

was sufficient for the limits

specified

on the

Each

RWP had

a dose limit per entry and

a dose

rate limit for the radiation worker.

The

DAD was set to alarm at those

values.

The

ACS monitor provided the

RWP user with the dose limit per

entry, the maximum dose rate field the worker was permitted to enter,

and the radiation worker's personal

remaining allowable dose limit.

During the review

NRC inspectors

observed radiation worker awareness

of

RWP requirements

was inadequate.

Technical Specification (TS) 6.8. l.a required written procedures

be

Enclosure

2

35

established,

implemented,

and maintained covering the activities

recommended

in Appendix A, Regulatory Guide 1.33, Quality Assurance

Program Requirements

(Operation),

Revision 2, February

1978.

Appendix A

paragraph

7.e required,

in part, the licensee establish

procedures

for

(1) Access Control to Radiation Areas Including

a Radiation

Work Permit

System

and (7) Personnel

Monitoring.

Section 3.5.2 of the licensee's

Health Physics

Procedure

(HPP)-2,

Revision

10. "Florida Power and Light Health Physics Hanual," requi red,

in part, prior to using

a

RWP. workers should read

and understand

the

RWP requirements,

document that they have read

and understood

the

RWP,

and agree to comply with their requirements.

Personnel

were not

permitted to deviate

from the requirements

of the

Section 5.9 of HPP-1.

Revision

10, "Radiation Work Permits," required,

in part,

a job specific

RWP for entry into the

RCB.

Additionally,

section

5. 10, required'n part.

any individual entering

an area

where

an

RWP is required should

be aware of special

instructions

and remarks

listed on the

The licensee's

RWPs list the entry radiation dose

limit and radiation dose rate limit in the Special

Instructions section

of the

The

ACS set the workers

DAD alarm setpoints

as specified

on

the

The inspectors

observed

a radiation worker in the

RCB that was asked

by

an

HP. controlling work in the area, to identify the specific

RWP the

worker was using.

The worker reported using

a 500 series

The

informed the worker that the 500 series

RWPs specifically excluded their

use in the

RCB.

The radiation worker was required to exit the

RCB.

The

worker had entered the

RCB on

a

RWP for the

RAB.

Licensee

RWP 97-1431,

Rev 0,

was written for pressurizer

heater

replacement

work in the Unit 1

RCB 18oot elevation

and pressurizer

platform area.

The

RWP set

an entry dose limit at 300 mrem and

a dose

rate alarm at 1,000 mrem/hr.

While observing

RP activities in the

RCB,

a

HPT providing

HP job

coverage of the pressurizer

heater

replacement activities asked

a

radiation worker about his radiation dose limits specified

on the

RWP

(97-1431) the worker

was using.

The technician wanted to know what dose

limit was specified

on the

RWP and shown on the

ACS terminal.

The

radiation worker reported that

he did not know what the

RWP dose limit

was.

The inspectors

brought the problem of radiation worker knowledge

and

awareness

to the attention of HP management.

Management's

response

was

timely.

An informal survey of a large population of radiation workers

in the

RCA and others entering the

RCA was

made by the licensee's

staff.

Host of the radiation workers could not answer correctly,

questions

concerning the

RWP requi rements they were requi red to review

and

know prior to work in the

RCA.

The

HP department

immediately

Enclosure

2

36

assigned

monitors at Containment Building and the Containment

Access

Building (CAB) to verify the radiation workers were using the correct

knew what their personal

remaining allowable dose was,

and

knew the

RWP specified

dose per entry and

maximum dose rate limits.

Monitors and

HP staff reported radiation worker performance

improved rapidly within

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

During following reviews, the inspectors

found that radiation

worker knowledge of individual remaining allowable dose,

dose per entry,

and maximum allowable dose

improved significantly and was later

satisfactory.

Failure of radiation workers to utilize the correct

RWP for entering the

RCB and failure of radiation workers to maintain awareness

of RWP

requirements

concerning specified

dose limits were identified as two

examples of a violation of licensee

RP procedures.

VIO 50-335.389/97-13-

02,

"Inadequate

Radiation Workers Awareness of RWP Requirements."

Pressurizer

Radiation Protection Job Covera

e

Licensee

TS 6.8. 1.a required that written procedures

be established.

implemented,

and maintained covering the activities

recommended

in

Appendix A, Regulatory Guide 1.33, Quality Assurance

Program

Requirements

(Operation),

Revision 2, February

1978.

Appendix A

paragraph

7.e requi red licensee establish

procedures

for (1) Access

Control to Radiation Areas Including

a Radiation

Work Permit System

and

(7) Personnel

Monitoring.

HPP-3, Section 7.2 listed responsibilities of HP personnel

covering work

in High Radiation Areas including, in part,

knowing the requirements of

the

RWP including any special

precautions that

may be necessary

for

entry into the area

and maintaining control of and authority over

workers in the area.

While observing work in progress,

the inspectors

spent

some time at the

pressurizer

heater

replacement

control point in lower containment.

The

HPT at the station

had just received

a turnover

and was observing the

radiation workers below the pressurizer with remote video and dosimetry

monitoring systems.

The workers

on the pressurizer

platform were

cutting the heater

tubes

and were wearing tele-dosimetry to permit

continuous

and remote monitoring of their individual radiation doses.

The tele-dosimetry monitor system displayed the radiation dose

information for each worker in the area

on top of the video.

The

workers were receiving dose at

a rate of several

hundred mrem/hr.

As

one worker 's dose

approached

300 mrem

a series of four blocks

began to

turn red one at

a time.

The inspectors

questioned

the

HPT about the

significance of each

red block.

The HPT knew the indicator

meant the

worker was approaching

a dose limit but could not explain the

significance of each

red block.

The

HPT had been told in a turnover

that the dose per entry had been raised

from 300 to 400 mrem per entry.

However, the

HPT did not have

a copy of the

RWP 97-1431 at the

checkpoint.

The blocks for one of the workers continued to turn red as

Enclosure

2

37

the worker 's dose neared

280

mrem of dose.

The

HPT made several calls

to confirm the dose limit had been raised

from 300 to 400 mrem.

When

the dose for one worker approached

290 mrem the

HPT pulled the workers

out of the work area.

The radiation doses

received

by the workers cutting and removing the

heater

coils were higher

than expected

and the radiation workers were

quickly approaching

the 300 mrem dose limit originally specified

on

RWP

97-1431.

To improve efficiency and increase

worker stay times

on the

pressurizer

platform a decision

was

made by the

HP staff to increase

the

entry dose from 300 mrem to 400 mrem/entry.

The

RWP was revised to

reflect the change.

The inspectors

learned the data

base for the

RWP system

and the tele-

dosimetry monitoring systems

were not connected.

When an

RWP dose limit

changed

and workers were issued tele-dosimetry it was necessary

for the

HPs changing the

RWP to communicate those

changes

to the

HPs issuing the

tele-dosimetry.

On November

4,

1997,

HP personnel

raised the entry dose

limit on

RWP 97-1431

from 300 mrem to 400 mrem without notifying the

persons

issuing tele-dosimetry.

As

a result,

workers having

an entry

limit of 400 mrem were assigned

dosimetry that was set to alarm at 300

mrem.

The radiation monitoring system

on the HPT's video monitor was

operating with the 300 mrem dose limit instead of the 400 mrem dose

limit specified

on revision

1 of RWP 97-1431.

That was the reason the

visual alarm indicator (series of four red blocks)

was peaking at

a dose

of about

290 mrem.

The

HPT acted conservatively

and pulled the radiation workers out of the

area

and no administrative

dose limits were exceeded.

However, if the

dose limits had been

lowered instead of raised

and the persons

issuing

the tele-dosimetry were unaware of those

changes

the alarm system

on the

dosimetry monitoring equipment would not have alerted the

HP to workers

approaching

or exceeding

a radiation dose limit.

The inspectors

concluded that the licensee's

RP procedures

were inadequate.

in that,

the procedures

did not describe the tele-dosimetry

issuance

procedures

and provide

a process to ensure

personnel

setting radiation monitoring

system setpoints

remained

knowledgeable of dose setpoints

modified when

RWPs were revised.

Failure of'he licensee to have written procedures

for the issuance of

tele-dosimetry that would ensure the dose limit setpoi nts applied i n

tele-dosimetry monitoring systems

were in agreement

with the limits

established

on the applicable

RWPs was identified as

a violation of the

licensee's

TS.

VIO 50-335.389/97-13-03.

"Failure To Have Adequate

Procedures

for Issuance of Tele-dosimetry."

Enclosure

2

-38

R1.3

Conclusions

Inadequate

radiation worker awareness

of RWP requirements

was

identified as violations of the licensee's

RP procedures

and licensee's

TS.

Inadequate written procedures

for the issuance of tele-dosimetry

and

setting dosimeter setpoints

in agreement with the

RWP requirements

was

identified as violation of licensee's

TS.

Control of Ver

Hi h Radiation Area

83750

Inspection

Scope

The purpose of this inspection effort was to review ci rcumstances

regarding failure to maintain positive

HP control of a posted

Very High

Radiation Area

(VHRA).

Observations

and Findings

Title 10 CFR Part 20 defines

a

VHRA as

an area,

accessible

to

individuals, in which radiation levels could result in an individual

receiving

an absorbed

dose in excess of 500 rads in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at

1 meter

from a radiation source or from any surface that the radiation

penetrates.

Title 10 CFR Part 20. 1602 prescribes

requi rements for access

to VHRA.

In addition to the requi rements in 20. 1601 the licensee shall institute

additional

measures

to ensure that

an individual is not able to gain

unauthorized

or inadvertent

access

to areas

in which radiation levels

could be encountered

at 500 rads or more in 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months at

1 meter

from a

radiation source or any surface through which the radiation penetrates.

Title 10 CFR Part 20. 1101 (a), requires

each licensee

develop,

document

and implement

a radiation protection program commensurate

with the scope

and extent of licensee activities and sufficient to ensure

compliance

with the provisions of this part.

Licensee

procedure

HPP-3,

Revision 3,

"High Radiation Areas", Appendix A

Definitions defines Positive Access Control

- f'r VHRA to include

locking with a lock and key unique to the area.

Health Physics

Procedure

HPP-24,

Revision 5,

"Containment Entries At

Power," described

requi rements

for securing

RCB hatches.

Form HPP-24. 1

Securing

From

RCB Entry required,

"Locking Devices

must be secured

such

that both locks (Security and Health Physics)

must be removed before

handwheels

can be operated."

The Security and

HP departments

each locked the handwheels to the

Enclosure

2

R2

R2.1

= 39

containment

hatches.

The licensee utilized one chain with both locks to

secure the hatch handwheels.

On October 8,

1997, licensee

personnel

found the

HP lock on the emergency

escape

hatch

on the Unit 2

Containment

Bui lding was not locked in such

a manner to prevent

access

to the Unit 2 Containment Building.

The

HP lock would not have

prevented

operation of the hatch handwheel.

Following the discovery the

HP lock was latched properly and the licensee initiated

a Condition

Report to cause

a review and corrective actions for, the identified

problem.

The licensee

chose to utilize two chains.

one for the security

and another for the

HP lock:

The corrective action should prevent

similar improper lock configuration.

While the improperly positioned

lock would not have prevented

access

into the equipment hatch.

the

equipment hatch

remained

secured with a lock controlled by the Security

department

at all times.

There was no evidence that anyone

had

improperly accessed

a

VHRA.

Access controls for VHRA are expected to be positively controlled as

access to such high radiation areas

(greater

than 500 rad/hr ) can be

life threatening.

This licensee identified and corrected violation is

being treated

as Non-Cited Violation,

NCV 50-335,389/97-13-04,

"Failure

to Follow Procedures

for Securing Access to a Very High Radiation Area."

Conclusion

A NCV was identified for failure to follow procedures

for securing

a

VHRA.

Status of Radiation Protection

and Chemistry Facilities and Equipment

SGRP Facilities and

E ui ment

50001

Inspection

Scope

To verify that

SG removal activities were performed in compliance with

regulatory

and licensee's

RP program requirements.

b. Observations

and Findings

To facilitate the processing of a large work force on site supporting

the

SGRP,

the licensee established

a

SGRP control point in temporary

facilities erected

on the north side of the site.

The facility included

an

HP checkpoint, briefing and video monitoring room,

HP office space,

a

dress-out facility, ACS,

and whole body personnel

contamination

monitors.

The inspectors

found the facility to be well equipped

and

performing the intended functions of a primary RCA control point and was

evidence of managements

support to the site

RP program.

Ori inal Steam Generator

Removal

Movement

Interim Stora

e and Dis osal

The inspectors

reviewed the licensee's

plans for removing the

OSG from

Enclosure

2

40

the

RCB,

movement of the

OSGs to the

ISF and plans for transporting

and

disposal of the

OSG.

The licensee

implemented effective measures

to remove water from the

OSGs,

seal

the

OSG ports,

and

remove

and seal

fixed contamination

on the

external

surfaces

of the

OSGs.

The licensee

established

effective

RCAs around the

OSGs

when they were

removed from the

RCB.

The movement of the

OSGs from the protected

area

to the

ISF was efficient, orderly,

and controlled to prevent unnecessary

radiation doses.

The radiological controls at the

ISF were well planned

and effective.

The inner and outer perimeters

were properly posted.

The inspectors

made independent

radiation surveys of general

areas within the OSG-ISF

and along the perimeters.

Radiation levels outside the inner radiation

perimeter were all less than

5 mrem/hour

and radiation levels outside

the outer

RCA perimeter

were all less than 0.2 mrem/hr.

The facility

was properly secured.

posted,

and controlled.

The licensee

planned to ship the

OSGs intact to a waste disposal

facility.

The licensee

had applied for exemption from the packaging

requi rements for a Surface Contaminated

Object

(SCO) required in

Department

Of Transportation

(DOT) regulation

49

CFR 173.427

and from

the

SCO limits in 49 CFR 173.403 in order to facilitate the one time

controlled shipment of two SGs from the St. Lucie site to Chem-Nuclear

Systems

Low Level Radioactive

Waste

Management Facility in Barnwell,

South Carolina.

The request

was dated

June

19,

1997.

The licensee

received the exception

from the

DOT in a memorandum

dated

October

2,

1997.

The exception permitted the licensee to classify the

SGs

as

SCO

and transport the

SGs un-packaged

under

a transportation

plan that was

to provide an equivalent level of safety to the packages

and procedures

specified in the

DOT regulations.

The SGs were prepared for transportation

by cutting the penetr ations at

the primary cooling water inlet and outlet nozzles,

the secondary

feedwater nozzles,

the secondary

steam exit nozzles,

and several

instrumentation lines.

The penetrations

were to be sealed with welded

closures that also provide

some shielding of the radioactive material

inside.

Inspection ports

and manways

were covered

by bolted closures

that were

a part of the original design.

The SGs were to be shipped

by barge to the Savannah

River Site and by

land with a heavy haul

motor vehicle to the disposal facility.

The

licensee

had developed

an approved shipping plan for the process

and

planned to ship the generators

in 1998.

c.

Conclusions

The licensee

established

excellent

RP support facilities for the

Enclosure

2

V

R5

41

and good

RP controls for the removal

and movement of the

OSGs to the

ISF.

The licensee

was well prepared to ship the

SG to a disposal

facility.

Staff Training and gualification in Radiation Protection

and Chemistry

R5.1

S1

SGRP Staffin

and Trainin

50001

Inspection

Scope

Review adequacy of staffing and training for the

HP and radiation

workers for the

Observations

and Finding

The site had obtained

a sufficient number of HPT and support personnel

for the

On tours throughout the

RCA the inspectors

observed

good

HP presence

and

a sufficient number of HPTs to control work.

No

staffing concerns

were identified.

The licensee

developed specific training plans for radiation workers

and

HPls.

Radiation workers received training on the ALARA program relative

to the

SGRP which addressed

ALARA goals,

worker responsibilities

in

maintaining exposures

ALARA, site ALARA program processes,

general

dose

reduction guidance, site exposure tracking capabilities,

overview of

planned

dose reduction processes,

and site ALARA contacts.

Interviewed

radiation worker s were knowledgeable of maintenance

and modification

processes

employed during the

RFO and

The licensee

performed

mockup training on several

SGRP tasks to qualify

personnel.

The licensee

developed

approximately fifteen mockup training

modules for the

The licensee

addressed

RWP requirements for some

of the tasks

and students

were required to understand

the radiological

requirements

and conditions of the mockup activity.

Some staff personnel

participated in some mockup training for the

pressurizer

heater

replacement

project offsite.

However, licensee

personnel

reported that the mockup used

was not identical to the actual

plant configuration.

The licensee did not identify several

equipment

problems

and space restrictions

encountered

during the pressurizer

heater

removal at St. Lucie.

Conclusions

The

RP staffing levels were sufficient to provide good

RP support for

the planned outage activities.

Training activities for radiation

workers

and

HPTs working the

SGRP activities were appropriate.

Conduct of Security and Safeguards Activities

Enclosure

2

S1.3

Fitness for Out

Ins ection Sco

e

81502

42

S2

S2.1

The inspector

reviewed

random Fitness

for Duty (FFD) records

and reports

at St. Lucie and the Florida

Power and Light (FP8L) Corporate Office to

determine if the licensee

was in compliance with the provisions outlined

in 10 CFR 26.

Observations

and Findin s

The inspector

reviewed the following procedures

and selected

a random

number of records to review in conjunction to determine if the

licensee's

procedures

were being followed:

FFD-2, Revision 2. "Urinalysis Collection Instruction"

NP-400,

Revision 5, "Fitness for Duty"

FFD-5, Revision 3, "Processing

and Reporting Test Results"

DOC-2, Revision 1, "Protection of Confidential

Information/FFD Records Retention"

Conclusions

Through

a randomly selected

record review and discussions

with licensee

representatives,

the inspector determined the licensee

was following

their

FFD procedures,

which were in accordance

with 10 CFR 26.

Status of Security Facilities and Equipment

Status of Securit

Facilities

and

E ui ment

71750

Inspection

Scope

On October

19, the inspector walked down the protected

area barriers to

verify they were intact.

In addition, the posting of the requi red

NRC

forms was also verified.

Observations

and Findings

In performing these walkdowns, the inspector verified the fence fabric

had no unintentional

openings,

was not degraded,

and was not eroded at

the base;

isolation zones

were free of objects

and well illuminated;

and

compensatory

guard postings

were in place

as necessary.

The inspectors verified that all required

postings

were current.

Two

exceptions

were noted posted in break

rooms.

The licensee

determined

that these

were postings in excess of their procedures.

Subsequently,

the licensee

ensured that the postings

were hung in accordance

with

their procedure.

Enclosure

2

c.

Conclusions

43

The protected

area barriers

were in good condition, the isolation zones

well lit, and the appropriate

compensatory

guard postings in place.

S5

Security Safeguards Staff Training and Qualification

S5.1

General

Comments

81700

During the

NRC Chairman's visit to St. Lucie on November

17,

1997, it

was noted that security force personnel

were carrying weapons outside of

their cases.

The inspector noted that the licensee

had improved

Security Force Instruction 9, Revision 6, "Firing Range Operating

Procedure."

The licensee

now utilizes

weapon

gun cases to transport

one

or two weapons to the range.

If more than two weapons

are to be

transported.

they will be transported

in a security vehicle.

Additionally, the licensee

published

an Inter-Office Correspondence

-to

remind personnel

that long guns taken outside the protected

area

should

be cased at all times.

S8

Hiscellaneous

Security and Safeguards

Issues

S8.1

Re lacement

Ins ections

Ins ection Sco

e

50001

The inspector evaluated

the licensee's

implementation of compensatory

measures

in place during the steam generator

replacement

project.

Additionally, the inspector

reviewed access

control

and affected vital

area barriers during the course of the inspection to determine

compliance with the licensee's

Physical Security Plan

(PSP).

b.

Observations

and Findin s

The St. Lucie PSP,

Revision 49, dated

December

18,

1997, Section 3.3.6

~

states

in part that major equipment

assemblies

need not be searched.

Upon arrival

on Hay 7 and 8,

1997. the licensee

performed

a cour tesy

search of'elect portions of both steam generators.

The steam

generators

were placed in the protected

area to be stored.

During the

period of September

15-26.

1997. the licensee

performed

a limited search

of the generators

during the course of removing the sealed

packaging the

generators

arrived with.

Upon review of Security Information Reports

and discussions

with licensee

representatives,

the inspector

determined

that all searches

were conducted in accordance

with PSP commitments.

No discrepancies

were noted by the licensee with respect to the

integrity of the steam generators.

The inspector determined that

associated

vehicles

and .personnel

were appropriately searched.

The inspector

reviewed

and observed the licensee's

existing plan to

control access

during movement

and work on the steam generators

being

Enclosure

2

i

S8.2

X1

44

replaced.

The inspector identified that access

was appropriately

controlled to prevent unauthorized

personnel

and equipment

from entering

containment.

The inspector verified that vital area barriers that were removed

due to

replacement of the steam generators

were appropriately

compensated.

Other deficiencies in security systems,

such

as loss of Closed Circuit

Television

Cameras

(CCTV) due to blockage

by the steam generators.

were

also appropriately

compensated

according to the licensee's

PSP.

Conclusion

The licensee's

planned

compensatory

measures,

removal of vital area

barriers,

and access

control of'ontainment during the steam generator

replacement

project were appropriate

and met the requirements

specified

in the

NRC approved

PSP.

Action on Previous

Ins ection Findin s

92904

Closed

VIO 50-335 389/96-16-01

and 50-335 389/EA-96-458/01023

-Failure to Submit

a

Re ort Under

10 CFR 73.71"

The licensee initiated corrective action in response to a failure to

report

a tampering event (96-16-01)

and to a failure to report

an actual

entry of an unauthorized individual into the protected

area

(EA-96-458).

The inspector

reviewed Security Procedure

0006125,

Revision

10,

"Reporting of Safeguard

Events."

and determined the procedure

was

adequately

changed to clarify the definition of tampering

and the

associated

guidance to make

a clear determination if reportability was

necessary

during the course of similar events.

Additionally, Security

Event Response

Guideline,

Revision 0. dated October

10.

1996,

was

developed to provide for action in response

to an event that resulted

from, or was suspected

to have resulted

from deliberate or malicious

actions against the plant.

In conjunction with this guideline,

an Event

Review Team gathers

when such

an event is suspected,

to investigate

and

provide rapid response to determine the root cause of plant events or

conditions.

The prospect of malicious or deliberate

actions or

suspected

tampering are factored in to better guide the licensee

on

a

course of action

and reportabi lity matters.

The inspector

reviewed the

licensee's

responses

dated October

18,

1996,

and February

6,

1997.

respectively to determine if the proposed corrective actions

by the

licensee

were appropriate.

The corrective actions are considered

adequate to close these violations.

V. Mana ement Meetin s and Other

Areas

Exit Meeting Summary

The inspectors

presented

the inspection results to members of licensee

management

at the conclusion of the inspection

on November

24,

1997.

Interim

Enclosure

2

45

exit meetings

were held on November 6, 20,

and 21,

1997 to discuss

the

findings of Region based

inspection.

Proprietary information was reviewed,

but is not contained in the report.

The licensee

acknowledged

the findings

presented.

PARTIAL LIST OF

PERSONS

CONTACTED

Licensee

H. Allen. Training Manager

C. Bible, Site Engineering

Manager

W. Bladow, Site Quality Manager

G. Boissy, Materials

Manager

H. Buchanan,

Health Physics Supervisor

D. Fadden,

Services

Manager

R. Heroux,

Business

Manager

H. Johnson,

Operations

Manager

J.

Harchese,

Maintenance

Manager

C. Marple, Operations

Supervisor

J. Scarola,

St. Lucie Plant General

Manager

A. Stall, St. Lucie Plant Vice President

E.

Weinkam, Licensing Manager

W. White, Security Supervisor

Other licensee

employees

contacted

included office, operations.

engineering,

maintenance,

chemistry/radiations

and corporate

personnel.

INSPECTION

PROCEDURES

USED

IP 37551:

IP 49001,

IP 50001,

IP 61726:,

IP 62707:

IP 71001:

IP 71707:

IP 71750:

IP 73753,

IP 83750:

IP 92702:

IP 92901:

IP 92903:

~0ened

Onsite Engineering-

Inspection of Erosion/Corrosion Monitoring Programs

Replacement

Inspections

Surveillance

Observations

Maintenance

Observations

Licensed Operator Requalification

Program Evaluation

Plant Operations

Plant Support Activities

Inservice Inspection

Occupational

Radiation

Exposure

Followup on Corrective Action For Violations and Deviations

Followup - Plant Operations

Followup - Engineering

ITEMS OPENED.

CLOSED,

AND DISCUSSED

50-335/97-13-01

"No Travel Limit Markings on the Top and Bottom

of One of the Main gi rders of the Temporary

Lifting Device" (Section

E1.3)

Enclosure

2

50-335,389/97-13-02

50-335,389/97-13-03

50-335,389/97-13-04

Closed

50-335/96-006-00

50-335/96-014-00

50-335,389/96-16-01

46

"Inadequate

Radiation Worker Awareness of RWP

Requirements"

(Section R1.2)

"Failure to Have Adequate

Procedures

for

Issuance of Tele-Dosimetry" (Section Rl.2)

NCV

"Failure to Follow Procedures

for Securing

Access to a Very High Radiation Area

(VHRA)"

(Section R1.3)

LER

"Inadvertent

Loss of Containment Audible Count

Rate" (Section 08. 1)

LER

"Invalid ESF Actuation of CI Due to Failed

Relay" (Section E8.2)

"Failure to Report Event to NRC" (Section S8.2)

50-335/96-17-04

"Failure to Update the Plant Physics

Book"

(Section E8.3)

50-335/EA-96-457/03023

"Failure to Initiate

a Condition Report for

Labeling on Safety Related Detectors"

(Section

E8.4)

50-335,389/EA-96-458/

"Violations Assessed

a Civil Penalty Related

01023

To Security Access.

Failure to Hake

a

NRC

Notification Within One Hour

as Required

by 10 CFR Part 73" (Section S8.2)

Discussed

50-335/96-201-06

IFI

"Full Flow Testing of AFW Crosstie"

(Section

E2.2)

LIST OF ACRONYMS USED

ANPS

ASME Code

ATTN

CEA

CFR

As Low as Reasonably

Achievable (radiation exposure)

Auxiliary Feedwater

(system)

Assistant

Nuclear Plant Supervisor

Administrative Procedure

Annunciator Response

Procedure

American Society of Hechanical

Engineers

Boiler

and Pressure

Vessel

Code

Attention

Control

Element Assembly

Code of Federal

Regulations

Enclosure

2

CIS

CR

DWG

ENG

FLCEA

FPKL

FR

FRG

FSAR

Foreign Material Exclusion

HPP

HPPO

HPT

HRA

HTS

I8C

ICI

ISF

ISI

JPM

LER

mrem

No.

NPF

NRC

NWE

OLS

OP

OSG

PDR

PIC

PMAI

PQR

PSL

PWO

QC

-47

crating license)

rating license)

cation)

Enclosure

2

Containment Isolation System

Condition Report

Condensate

Storage

Tank

Demonstration

Power Reactor

(A type of op

Drawing

Enforcement Action

Emergency

Diesel Generator

Engineering

Engineered

Safety Feature

Flow Accelerated

Corrosion

Full Length Control Element Assembly

.

The Florida Power

8 Light Company

Federal

Regulation

Facility Review Group

Final Safety Analysis Report

Health Physics

Procedure

Health Physics Project Overviews

Health Physics Technician

High Radiation Area

Horizontal Transfer System

Instrumentation

and Control

Incore Instrumentation

Interim Storage Facility

InService Inspection

(program)

Job Performance

Measurement

Licensee

Event Report

milli rem

Main Steam Isolation Valve

Non Cited Violation (of NRC requirements)

Number

Normal Operating

Pressure

Notice of Violation

Nuclear Production Facility (a type of ope

Nuclear Plant Supervisor

Nuclear Regulatory Commission

NRC Office of Nuclear Reactor Regulation

Nuclear Regulatory

(NRC Headquarters

Publi

Nuclear Watch Engineer

Outside Lifting System

Operating

Procedure

Original Steam Generator

NRC Public Document

Room

Pressure

Indicator/Controller

Plant Management Action Item

Procedure Qualification Records

Plant St. Lucie

Plant Work Order

Quality Control

RCB

RII

SBCS

St.

TS

UGS

48

Quality Instruction

Reactor Auxiliary Building

'adiation

Control Area

Reactor

Containment Building

Reactor Coolant System

Refueling Outage

Region II - Atlanta, Georgia

(NRC)

Radiation Protection

Reactor

Pressure

Vessel

Replacement

Steam Generators

Radiation

Work Permit

Steam

Bypass Control System