ML17354A767

pump

discharge

check valves.

As

a result, after completion of routine

pump downs.

a false leak rate was annunciated

when water

drained

back into the

sump (section El.l).

The licensee

has

been thorough in their investigation into normal

start failures associated

with the Unit 4 emergency diesels.

The

safety related function was not effected (section

E2. 1).

The licensee appropriately

responded

in a timely manner to a

generic reactor fuel issue related to burnable

absorber

rods

and

the ability to meet cladding oxidation criteria (section E2.2).

A self-initiative to review plant aging issues

was sound

and

proactive (section E2.3).

An isolation valve modification on the intake cooling water system

was well planned

and executed,

and the minor changes

noted in the

system flow rate were negligible (section E2.4).

The Plant Review Board process for modification prioritization was

effective,

and demonstrated

strong

management

oversight of the

site's

long range planning activities (section

E6. 1).

Honthly operating reports submitted to the

NRC were timely,

complete,

and accurate

(section

E8. 1).

An open item regarding charging

pump actions

on

a safety injection

was closed

based

on the licensee's

plans to modify both units

(section E8.2).

.

Plant

Su

ort

Personnel

contamination

events during the fall 1997 Unit 4

refueling outage were abnormally high.

The licensee appropriately

documented

these

events,

followed up with specific condition

reports,

and assigned

skin and/or internal

doses

(section Rl.l).

Enclosure

2

Emergency

Response Facilities were well designed

and equipped.

and

were generally maintained at an adequate

level of operational

readiness.

However, the as-found condition of the designated

alternate

Operational

Support Center

was unacceptable

for its

intended

use,

and the material condition of'he stock of silver

zeolite cartridges

represented

a weakness

in the licensee's

surveillance

program f'r emergency

equipment

and supplies

(section P2.1).

Radiological

Emergency

Plan Revisions

30 and

31 were made in

accordance

with 10 CFR 50.54(q),

but

a violation for decreasing

the effectiveness

of the

REP was identified in Revision 32.

Emergency declarations

on March 4 and April 6.

1997 were

made in

accordance

with applicable procedures

(section

P3. 1).

Radiological

Emergency

Plan implementing procedures

were

determined to be generally thorough in terms of detail

needed to

implement the various requi rements

and commitments in the Plan

(section P3.2).

An observed quarterly emergency

planning drill was well planned

and conducted,

met the drill objectives.

and was

a good training

exercise

(section P5.1).

No degradation

had occurred in the organization

or management

of

the emergency

preparedness

program.

Emergency

preparedness

appeared

to be receiving solid management

support at Turkey Point

~

but maintenance of strong

management

oversight wi 11

be an area of

challenge

(Section

P6. 1).

The 1996-1997

Emergency

Preparedness

program audits fully

satisfied the

10 CFR 50.54(t) requirement

for an annual

independent

audit of the

EP program.

Additional self-assessments

in EP were commendable efforts by the licensee's

Quality Assurance

group (section P7.1).

Enclosure

2

0

TABLE OF CONTENTS

Summary of Plant Status

I.

Operations

II.

Maintenance

III.

Engineering

22

IV.

Plant Support

26

V.

Management

Meetings

Partial List of Persons

Contacted.

List of Items Opened.

Closed

and Discussed

Items

List of Inspection

Procedures

Used.

List of Acronyms and Abbreviations

..34

..35

.36

REPORT DETAILS

Summary of Plant Status

Unit 3

At the beginning of this reporting period. Unit 3 was operating at or

near full reactor

power and had been

on line since August 14,

1997.

The

unit was reduced to 40K reactor

power on November 17.

1997 to conduct

secondary plant testing

and to perform maintenance.

The unit returned

to full power

on November

19.

1997;

and operated

the remainder of the

period.

Unit 4

At the beginning of this reporting period. Unit 4 was operating at or

near full reactor

power and had been

on line since October

14 '997.

The unit operated at power during the period.

01

Conduct of Operations

I. ~Otal

01.1

Unit 4 Secondar

Plant Osci llations

71707

During the inspection period. Unit 4 experienced

minor secondary

or

balance of plant

(BOP) osci llations and swings.

These were accompanied

by turbine-generator

output swings of 4-5 megawatts electric

(HWe),

heater drain tank

(HDT) level

and

HD pump flow variations,

several

steam

generator

feedwater

pump

(SGFP)

low suction pressure

alarms.

feedwater

heater

level alarms.

and

No.

2 turbine control valve

(CV) position

swings of several

percent.

The licensee

responded to these

abnormal

indications

by starting

a third condensate

pump to assure

adequate

reactor protection system

suction pressure,

tuned the feedwater heater level control valves.

adjusted the

HDT flow control valves, throttled the extraction

steam

input to the feedwater

heaters to better assure

HDT input flow from the

moisture separator

reheaters

(HSRs),

and performed secondary plant

walkdowns by engineering

and maintenance

personnel.

On November

21

'997,

the

HD pump flow control valve (CV-4-1510A) was repaired

using

a

developed

temporary procedure

(TP) to control unit operations.

Unit 4

power

was reduced to 95K as

a precaution.

CR No. 97-1965

and

a problem

status

summary were written to address

these

issues,

and several

meetings

were held

among operations.

engineering,

maintenance,

and other

site groups.

The inspector

reviewed this issue

by walking down the secondary plant,

observing

system operations locally and from the control

room,

discussing

these

issues with operators

and engineers,

observing

maintenance

repair and tuning activities,

and reviewing procedural

Enclosure

2

01.2

01.3

controls,

including the TP.

The inspector

noted good coordination

and

communication

among operations,

engi neering.

and maintenance

personnel.

Simulator scenarios

were run by varying the failures in the secondary

plant to assure

continued unit operation,

and to minimize overall impact

on safe operation.

The licensee

was successful

in controlling,

coordinating

and minimizi ng the effect of these

secondary plant

perturbations.

Unit 3 Power Reduction

For Maintenance

and Testin

71707

61726

62707

The licensee

reduced

power on Unit 3 to 40K on November

17,

1997, to

perform secondary plant turbine valve testings

and to conduct routine

maintenance.

The unit was returned to full power on November 19,

1997.

Every three months the licensee

conducts turbine valve testing

by

cycling each stop, control, intercept.

and reheater

valve through

a full

travel operation.

In conjunction with this testing,

periodic secondary

plant maintenance activities were conducted.

Operators

used general

plant operating

procedures

(GOPs) for the power changes.

Extra person-

nel were scheduled to support operational activities

and to implement

system clearances.

Engineering

and maintenance

personnel

and superviso-

ry support were also scheduled

around-the-clock.

Operations

management

provided oversight during the power reduction.

A detailed

schedule

was

provided by the work control group,

and the Work Control Center

(WCC)

provided the operations

interface with the maintenance

groups.

The inspector

observed portions of the operations

and maintenance

activities,

reviewed the schedule.

and discussed

the plan with licensee

management.

The inspector

concluded that the planned Unit 3 load

reduction,

operations

conduct,

work control

and schedule

planning,

maintenance

implementation of work activities,

and engineering

and

management

oversight were noteworthy.

Control

Room Shift Turnover Meetin

Ins ection Sco

e

71707

The inspector attended

the control

room shift turnover meeting at

various times during the reporting period.

The inspection included back

shift and deep

back shift observations.

In addition, the inspector

interviewed licensee

management

to obtain

an understanding

of the

requirements of the meeting.

Licensee

procedures

were reviewed which

included

O-ADM-202, Shift Relief and Turnover,

and

O-ADM-200, Conduct Of

Operations.

Observations

and Findin s

There were three control

room shift turnover meetings

held every day.

The day shift meeting

was held at 7:35 a.m.. the peak shift meeting

was

held at 3:35 p.m.,

and the midnight shift meeting

was held at 11:35 p.m.

Enclosure

2

Operations

ran the meeting

and the complete on-coming Operations

crew

attended.

In addition, there

was

one representative

from each support

group,

such

as

Hechanical

Haintenance,

Instrumentation

and Control.

Electrical Haintenance,

Health Physics,

and Chemistry.

Also, depending

on unit activity. other groups were present,

such

as Reactor

Engineering.

Typically, the support groups

had already completed thei r

own turnover meeting prior to attending the control

room meeting.

The

Assistant

Nuclear Plant Supervisors

(ANPS) started the meetings

by

summarizing the status of thei r Units.

Hajor ongoing or planned

evolutions,

action statements,

out of service equipment,

and significant

activities that will occur during the shift or having occurred during

the previous shift were summarized.

Later, the Reactor Operators

gave

a

more detailed description of their unit status:

The Watch Engineer

assigned

the fire team leader

and members f'r the shift,

and summarized

safety briefs.

In addition, the operators

for the Auxiliary Building,

Turbine,

and Water Plant also summarized the activity in their area.

Lastly, night orders,

safety briefs, training information,

and

administrative information was communicated to the Operations

crew.

The level of detai

1 during the briefs was commensurat'e

with safety

significance of the activity. both,

personnel

and operational.

The

briefs included the work of the day and activity associated

with any

major planned evolutions.

For example,

load threat activities,

surveillance,

plant work orders

and plant modifications requi ring

coordination with various disciplines,

and equipment tagging

and

clearances

were reviewed.

The inspector

noted that there

was good

interaction

and discussions

between operations

and the support groups.

There was typically no new di rection given at these meetings.

However,

the inspector

noted that on several

occasions

based

on the discussion

during the meetings,

Operations

made requests

for additional support.

and provided or obtained clarifications on support group activities.

Operations

maintained the meeting with good focus

on unit operational

activity and safety.

and the inspector

noted that the

ANPS exhibited

a

good questioning attitude

and good ownership of thei r Units.

Also, the

inspector

noted that the Reactor Operators

maintained continuous

monitoring of their units.

Overall, the meeting served

as

a good

communications tool for the on-coming Operations

and support crews.

The inspector noted,

however, that the meetings

lacked certain

accountability

and consistencies.

For example:

~

Occasionally,

attendance

from all the support groups

was not

complete, i.e., support group representative

walked in after the

start of the meeting,

or left before the end of the meeting,

or

did not attend at all without having notified or briefed the

control

room,

Enclosure

2

~

Heeting was delayed

due to waiting for someone to ar rive.

~

Operations

provided their briefs first, at other times the support

groups provided their briefs first and would not necessarily

stay

to the end of the meeting,

~

Upon noticing that

someone

was missing,

Operations

would call or

page support group representative

to obtain status just prior to

starting the meeting,

~

Calls would come into the control

room during the meeting

informing the

NPS that someone couldn't attend,

and

~

Information provide by

a representative

(who had called

and could

not attend)

was not always communicated

at the meetings.

The inspector

found that recently the Operations

Supervisor

had

requested,

via

a night order. that the control

room not conduct the

meeting unless all parties

were represented.

That request

was

a result

of the inspectors earlier finding that one of the support groups

had not

attended

two consecutive

control

room shift turnover meetings, i.e.. the

day shift and peak shift meeting.

In additions

the inspector

found that

the control

room had not been briefed or notified of thei r unableness

to

attend the meeting.

The inspector

found that there existed

no documentation

describing the

control

room shift turnover meeting

as it was being conducted.

For

example,

there were no procedures.

instructions,

guidelines,

or

documented

management

expectations.

Further,

throughout the interviews.

the inspector

noted that management

indicated they strongly supported

the meeting

and emphasized

the importance of this meeting

and described

"management

expectations" of the meeting.

Expectations for support

group meeting attendance

varied during the weekend

due to differences

in

plant coverage.

However,

no documentation

could be provided to the

inspector describing the meeting or the differences in management

expectations

of the meeting during the weekend.

c.

Conclusions

The control

room shift turnover meetings

provided

a good envi ronment for

Operations

and support groups to obtain

and review overall plant

activity for the day.

There were good briefings, discussions

and

opportunities to resolve unclear items.

Management strongly emphasized

the importance of the meeting.

However, the meetings

lacked consistency

and it was evident that no formal written requirements

or guidance,

or

documented

management

expectations

had been provided describing the

conduct of the meeting.

Control

Room Annunciator and Alarm Status

71707

and 62707

During the period, the inspector

reviewed the status of the Unit 3 and

4

Control

Room alarms.

The annunciator

and alarmed conditions were

tracked in the daily Plan-of-the-Day

(POD) document.

Conditions in

alarm and lit annunciators

were given high visibility by operations

and

plant management.

The maintenance

disciplines worked with operations to

address all lit annunciators

either

due to false alarms or due to

existing equipment deficiencies.

On several

occasions

during the

period. the units were able to achieve

a "blackboard" condition where no

alarms were annunciated.

On November

24 and 28,

1997, the inspector

noted that both units simultaneously

had achieved

a "blackboard"

condition.

The inspector

concluded that licensee efforts to achieve

and maintain

a

condition in the Control

Room where no alarms

were annunciated

(eg.,

"blackboard" ) were noteworthy.

Unit 3

Ea le 21

S stem

Power Failure

71707

On November 28,

1997, at 7:52 p.m., operators

received

numerous control

room alarms associated

with channel

three of the Unit 3 Eagle

21

protection system.

Operators

immediately responded

per alarm response

procedures

(ARPs)

and off normal operating

procedures

(ONOPs).

They

confirmed that

a power supply had failed on the system

and notified

Instrument

and Control

( I&C) maintenance

personnel.

TS actions for the

and safety injection logic were entered.

and

the related bistables

were tripped.

The Eagle

21 system supplies the

reactor coolant loop temperatures

and pressurizer

level.

A failed

Input/Output card was replaced,

the system

was calibrated

and tested.

and the Eagle

21 channel

logic was returned to normal

on November

29.

1997, at about

12:30 p.m.

The inspector

reviewed this failure and the related actions the

following day.

The inspector verified that the ARP.

ONOP,

TS,

and

maintenance

actions

were appropriate.

The inspector noted that the

operator training program has

a related simulator scenario failure.

and

that operators

were well prepared to deal with this issue.

Operator

response

was evaluated

as timely and proper.

Maintenance

support

was

also very good.

The inspector

concluded that the licensee's

overall

response to this Unit 3 Eagle

21 channel

three failure was noteworthy.

Root cause evaluations

for the card failure are in progress,

and the

inspector

intends to review this in

a future inspection.

Enclosure

2

02

02.1

Operational

Status of Facilities and Equipment

Antici ated Transient Without a Scram

ATWS Niti ation

S stem Actuation

Ci rcuitr

AMSAC

Wa 1 kdown

71707

The inspector

walked down the Unit 3 and

4 AMSAC systems

and reviewed

related documentation.

AMSAC is

a backup to the reactor protection

system

(RPS)

and is designed to mitigate

a possible

ATWS event.

ANSAC

is not safety-related

and will not actuate

on

a loss of power

.

The

energize-to-actuate

ANSAC logic has

redundant

micro-processors

that use

signals

independent of the

RPS.

AMSAC actuates

on low steam generator

(SG) level

(2 of 3 SGs) if the unit is greater than

40K power by turbine

first stage pressure.

ANSAC provides output signals to trip the

turbine. initiate the

AFW system.

and to trip the rod drive motor

generator

set output breakers.

The inspector

reviewed system description

No. 63, the

RPS design basis

document,

Updated Final Safety Analysis Report

(UFSAR) section 7.2.4,

operating

and surveillance

procedures,

electrical drawings'nd other

The inspector walked down the system,

examined the

control panel in the cable spreading

room, observed control

room

indications'iscussed

the system with the system engineer

and

operators,

and verified that periodic testing

was current.

The

inspector verified that the system appropriately actuated

during the

July 30,

1997. Unit 3 trip (reference

NRC Inspection Report

No. 50-

250.251/97-08).

The inspector, noted that operations

personnel

were knowledgeable,

that

system engineer

demonstrated

ownership

and technical

competence.

and

that the Unit 3 and Unit 4 ANSAC systems

were appropriately aligned for

standby operation.

02.2

Instrument Air

IA

S stem Walk Oown

71707

and 37551

The Instrument Air System

does not serve

any safety function,

and

'therefore, it is classified

as

a non-safety related

system.

However,

the Instrument Air system supports

operation of various safety related

components,

such as,

main steam isolation valves

and power operated

relief valves.

Failure of the Instrument Air system

can cause the plant-

to trip.

Consequently,

the licensee

has classified

Instrument Air

System

as risk significant and included it in the maintenance

rule.

The inspector

reviewed the system

P8IDs

and system descriptions,

and

independently

performed

a system walk down of the Unit 4 Instrument Air

System.

Additionally, the inspector verified that selected

portions of

the system were appropriately lined-up,

and reviewed status of selected

outstanding

Plant

Work Orders.

Aaterial condition and housekeeping

were

adequate

and no issues

were identified.

In addition, the inspector

reviewed the Unit 3 and Unit 4 Instrument Air systems with the system

Enclosure

2

03

03.1

b.

engineer.

The system engineer

was

new at Turkey Point.

However, other

system engineers

familiar with the Instrument Air system were on site

and could provide assistance

if'equired.

System level

and component

level operation were reviewed,

questions

relating to Generic Letter 88-

14

( Instrument Air Supply System

Problems Affecting Safety Related

Equipment),

and the modification history of the Instrument Air System at

Turkey Point were discussed.

All items were appropriately addressed

by

the system engineer.

The inspector concluded that the Instrument Air

System

was appropriately maintained

and that the system engineer

showed

good ownership

and was well versed with the system.

Operations

Procedures

and Documentation

Cold Le

Recirculation

Ins ection Sco

e

71707

and

37551

A recent

10 CFR 50.72 report

( Immediate Notification Requirements

For

Operating Nuclear

Power Reactors)

from Florida Power

8 Light's St. Lucie

Power Plant,

provided information that the bistable set points for the

recirculation

actuation signal

were found to be incorrect,

and in the

non-conservative

di rection.

The inspector

reviewed Turkey Point's

requi rements to switch over to recirculation to assess

whether the

same

issue existed.

Observations

and Findin s

The inspector

reviewed the applicable sections of the

UFSAR and

Emergen-

cy Operating

Procedures

3/4-EOP-ES-1.3

which described

Turkey Point's

switch over to the containment sump,recirculation.

At Turkey Point the

switch over to the recirculation phase

was not an automatic actuation,

as

was the case at St. Lucie. rather, it was

a manual operation.

To

ensure

adequate

r'eci rculation

sump level. two verifications were

requi red by procedure

EOP-ES-1.3,

Transfer

To Cold Leg Recirculation.

First, the Refueling Water Storage

Tank

(RWST) volume was verified to be

greater than 60,000 gallons.

and secondly.

the operator

needed to verify

that the containment recirculation

sump level

was greater

than 427

inches.

If the

RWST volume was not greater than 60,00 gallons

and the

recirculation

sump level was less than 427 inches,

then the procedure

would take the operator to

EOP 3/4-ECA-1. 1,

Loss of Emergency Coolant

Recirculation.

The inspector

reviewed the

EOP requirements

with a Reactor

Operator

and

with a Assistant Nuclear

Power Supervisor'nd

found that the operators

were well versed with the

EOP requirements

relating to the switch over

to recirculation phase.

The inspector noted that the

EOPs were recently

revised

based

on training and operations

feedback.

Enclosure

2

Net Positive Suction

Head

(NPSH) requirements

were reviewed with

engineering.

Engineering described

and summarized

the results of the

recent

re-verification of the calculations relating to NPSH.

The

purpose of the re-verifications

was to prepare

a reply to

NRC Generic Letter 97-04.

Based

on the discussions,

there did not appear to be any

issues

in this area.

However, engineering

indicated that the official

Turkey Point position would be provided in the licensee's

reply to

Generic Letter 97-04 which was scheduled to be submitted in January

1998.

Conclusions

Switch over to containment

sump recirculation

was

a manual operation at

Turkey Point and there did not appear to be any issues with level

heights relating to NPSH.

Good support

by training and operations

feedback to enhance the

EOPs

was noted.

OfA'cial licensee position on

NPSH would be provided in the reply to Generic Letter 97-04.

04

Operator

Knowledge and Performance

04.1 Auxiliar

Feedwater

AFW Initiation Lo ic

Ins ection

Sco

e

71707

90712

and 92700

The inspector

reviewed the circumstances

surrounding the licensee's

identification on November

14,

1997. that the Unit 3 AFW initiation

logic for the steam generator

(SG) feedwater

pump

(SGFP) breaker trips

per Technical Specification (TS) 3.3.2,

Table 3.3-2 Item 6e,

was not

operable for the

3B SGFP.

The required

TS action statement

(TSAS) was

therefore not followed.

The issue

was identified by a control

room

licensed reactor control operator

(RCO) during routine log readings

on

the control board walkdowns while performing an operations

surveillance

procedure

(OSP).

The condition had existed since July 31,

1997.

Observations

and Findin s

At 6:00 p.m.

on November

14,

1997. the Unit 3

RCO was performing

surveillance

procedure

3-OSP-201. 1.

RCO Daily Logs Hinimum Instrument

and Equipment List.

The

RCO questioned

the status of the 3B SGFP

control

room console control switch.

The

SGFP was running,

and the

switch was mid-positioned with the red indicating light on;

however, the

switch window or "flag" was indicating green.

Normally,

a red "flag"

would be matched to the red running light for operating

equipment.

An

information tag on the 3B SGFP was obscuring the control switch "flag"

indication.

The

OSP requi res the

RCO to check that the

TS required trip

of all

SGFP breakers

was operable.

This is one of the logic initiation

signals for the

AFW system.

The ANPS and

NPS reviewed the issue,

and

discussed this item with the Operations

Supervisor.

After reviewing the

logic diagrams

and the Tss, the licensee

concluded that the

3B SGFP

Enclosure

2

control switch green "flag" condition would inhibit a portion of the

auto start circuitry.

The licensee therefore entered the

TSAS which was

to take action in one hour or

be in hot standby within the next six

hours (eg., enter

Node 3).

The operators

momentarily placed the 3B SGFP control switch in the start

position and then returned the switch to the mid-position.

This

resulted in obtaining the red "flag."

The affected

AFW auto start

circuitry was

made up,

and the licensee exited the TSAS in 20 minutes.

The licensee initiated an investigation

per Condition Report

(CR) No..

97-1974.

The inspector

was informed of this issue the following working

day.

The licensee

evaluated this issue to be reportable

under

10 CFR 50.73.

Therefore,

an

LER was required to be written.

TS 3.3.2 addresses

Engineered

Safeguards

Features

(ESF) Actuation System

Instrumentation.

TS Table 3.3-2 Items

6a through

6e includes

AFW auto

start signals

and instruments

requi red to be operable in Modes

1 and 2.

Electrical schematic

drawings 5613-E-26 sheets

1A2.

12B

~ and

12C depict

the

AFW initiation logic.

AFW auto start initiation signals

occur on

any one of the following signals:

Safety Injection (SI) signal,

or

Low Steam Generator

(SG) level

3A (2 of 3 devices),

or

Low SG level

3B, or

Low SG level

3C, or

Vital bus stripping

(sequencer

operation)

on low or degraded

voltage, or

Loss of the last running

SGFP (eg..

breaker trips).

The loss of the last running

SGFP initiation logic is an anticipatory

AFW start signal prior to reaching the low SG level

AFW auto start

signal.

The logic actuates

when both

SGFP breakers

are open ("b"

contact closed)

and when either

SGFP control switch is in both the

start/after start

(red "flag") position and the mid-position.

Thus, the

as-found condition for the

3B SGFP would not have satisfied the

TS

required auto start logic associated

with loss of the last running

This was due to the switch being in a green "flag" condition.

The licensee's

review concluded that the

3B SGFP was locally started

per

procedure

3-0P-74,

SGFP Operation,

at 4:34 p.m.

on July 30,

1997.

This

was after

a Unit 3 automatic reactor trip when the 3B MSIV unexpectedly

went closed.

Apparently, the control

room switch was not matched with

the existing condition or red "flagged" as required.

Unit 3 was

restarted

at 4: 13 a.m.

on July 31,

1997,

and entered

Mode

1 later that

day.

The second

(3A) was also started later on July 31,

1997.

Enclosure

2

10

With a trip of both running

SGFPs

or the 3A SGFP, the logic would have

started the

AFW system.

However, if the

3B SGFP were the only running

ump and tripped,

the

AFW system would not auto start until low SG

evel occurred.

The anticipatory ci rcuit would not have functioned

as

it would not have seen

a trip of the last running

The inspectors

confirmed this logic by reviewing the electrical

schematics

and by

observing simulator scenario

runs.

The licensee

operated

Unit 3 from July 31 to November

14,

1997, with

this condition.

and therefore

was in noncompliance with TS 3.3.2,

Table

3.3-2 Item 6e.

Further, the

TSAS was not followed and three

mode

changes

were affected without the

AFW logic operable.

The two periods

were on July 31 and August 14-15.

1997.

During these periods,

the 38

SGFP was the only running pump.

and therefore

AFW would not actuate

until low SG levels occurred: July 31,

1997 for 14 hours1.62037e-4 days 0.00389 hours 2.314815e-5 weeks 5.327e-6 months after the auto

trip and subsequent

restart;

and August 14-15,

1997 for 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

when

the unit was taken offline for an oil leak.

The licensee's

review included

a detailed time-line, barrier

analysis,

root cause determination,

related causal

factors,

and corrective

actions.

The licensee

concluded that the root cause

was inadequate

procedure

guidance for local starts of an

Procedure

3-OP-74 was

revised

on August 25.

1997 to include the specific steps

and signatures

for local starting of a

and control switch matching (eg..

red

"flagging").

This was after the local start conducted

on July 30 '997.

The inspector verified that the revised

OP (steps

13

a and b) adequately

addressed

these

issues.

The reason for performing local starts

was

corrective actions

from an inadvertent

AFW start while in Node 3 when

the first SGFP was started

and immediately tripped (Reference

LER 97-

04).

The logic saw this condition as

a trip of the last running

factors included training and knowledge deficiencies of a

number of licensed operators for the

SGFP switch and flag relationships

for the

AFW start logic.

Apparently.

some operators

had recognized the

green "flag," but had not questioned it thoroughly.

In addition,

an

information tag was obscuring the control switch "flag" indication for

the

3B SGFP.

This tag was placed

on the switch after the spring

1997

outage

due to pump casing leaks.

The tag instructed operators to

minimize the

pump start

and stop cycles

due to the

pump casing condition

and to reduce the potential for further leaks.

The leaks were

temporarily repaired

and permanent

repairs

are scheduled

for the next

refueling outage.

(Reference

NRC Inspection Report

No. 50-250.251/97-07,

section E1.2).

In addition, the

GOP switch alignment checklist

implemented prior to mode changes

did not include the

SGFP switches or

"flag" indications.

Enclosure

2

11

Quality Assurance

(QA) also performed

a review of this event

and

concluded that the cause

was inadequate

procedures.

LER 97-09

was

written and submitted to the

NRC.

The

LER presented

the

CR findings,

causes,

significance,

and corrective actions.

These corrective actions

included the following:

Enhanced

procedures

3/4-OP-74 to include independent verification

of'GFP switch positioning when performing local

SGFP starts.

Conducted

crew briefings for each shift on the ci rcumstances

of'he

event,

and

stressed

management's

expectations

for a

questioning

attitude,

Developed

a training brief (No. 703) discussing'the

AFW initiation

logic,

Plans to modified operator initial and continuing training to

cover

AFW logic and in particular the

SGFP switch relationship,

Conducted root cause

assessment.

LER submittal,

and independent

QA

reviews,

Conducted simulator scenario

runs with various

SGFP combinations

and the as-found condition.

Wrote an operations

night order book entry addressing

these

issues,

Performed

a Control

Room walkdown and did not identify any other

switch or "flag" or tag obscuring

issues

on either unit,

Revised the

GOPs to include

SGFP switch and "flag" positions.

Plans to incorporate other switch "flag" indications in the

GOPs

and

other operating

and surveillance

procedures,

Relocated the tag on the 3B,SGFP switch as not to obscure the

"flag"

indication,

and

Plans to review the tagging procedure for enhancements

in tag

style and positioning.

The licensee

assessed

the significance of this issue

and

TS

noncompliance

as of minimal safety significance.

The corporate risk

assessment

group provided

a probabi listic safety assessment

(PSA) and

calculated the as-found condition to be negligible to overall risk.

The

PSA group considered that the risk dominant scenarios

requi ring AFW are

associated

with low SG level initiations.

Further, the safety analysis

Enclosure

2

12

takes credit for the low SG level start for AFW initiation.

The loss of

the last running

SGFP initiation logic is only an anticipatory signal.

The inspector

reviewed the

UFSAR sections

9. 11 and 14. 1. 11 'nd the

design basis

document

No. 5610-075-DB-001.

The auto start signals

described

were consistent with the TSs.

The inspector confirmed that

low SG level auto start signal

and SI are the assumed

AFW initiation

signals in the accident analysis.

This is for LOOP and

LOCA events.

The inspector noted that the

UFSAR stated that

AFW was required to

deliver

AFW flow to the

SGs within three minutes.

However,

based

on

thermal

power uprate analyses,

the time required

was shortened

as

follows:

95 seconds for a loss of offsite power event,

and two minutes

for a loss of a main feedwater event.

The licensee stated that they had

also identified this

UFSAR issue

and that it would be corrected in the

1998 revision.

The inspector verified this by reviewing

a licensing

UFSAR revision form..

The inspector

reviewed the

CR, the

LER. the

PSA analysis.

the

QA report.

selected

drawings

and schematics.

and other related documentation.

The

inspector also independently verified selected corrective actions.

The

inspector

concluded that

a violation of TS 3.3.2.

Table 3.3-2 Item 6e

and action

23 existed for about three

and one-hali months (July 31 to

November

14,

1997).

Violation (VIO) 50-250/97-12-03.

Failure to Meet

the AFW,Initiation Logic for

SGFP Trip, was licensee identified;

however

~ the condition was not considered

for

a non-cited violation

based

on length of time and missed opportunities.

The TSAS required

action to be taken in one hour,

or to achieve hot standby

(Mode 3) in

the next six hours,

and then to achieve hot shutdown

(Mode 4) in the

following six hours,

and finally to achieve cold shutdown

(Mode 5) in

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

Further,

TS 3.0.4 prohibited

mode changes

without the

AFW logic being operable

per

TS 3.3.2.

This condition was

not met on three occasions:

on July 31,

1997,

when the unit went from

Mode 3 to Mode 2,

and then to Mode 1; and.

on August 15.

1997,

when the

unit went from Mode 2 to Mode 1.

Failure to follow TS 3.0.4 was

a

second

example of the violation.

c. Conclusions

Failure to meet

TS 3.3.2,

Table 3.3-2 Item 6e and

TS 3.0.4 for the 38

SGFP trip ci rcuit for AFW auto initiation logic was

a violation.

Licensee root cause,

independent

reviews,

LER reporting,

and corrective

actions

were good.

Safety significance

was minor based

on the

availability of the other

(3A) trip logic, the time spent in single

(3B) operati'ons

(eg., twice for about

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

respectively), negligible risk significance,

safety analysis

assumptions,

and the availability of the low SG level

and

AMSAC signals

to auto start the

AFW system.

The decision to issue

a cited violation

was

based

on the time involved (more than three

and one-half months),

and the prior opportunities for discovery of the condition.

Based

on

Enclosure

2

'05

05.1

07

07.1

b.

13

the ade'quacy of the Unit 3 LER No. 97-09 and corrective actions to

prevent recurrence,

no response to the violation is necessary.

Oper ator Training and Qualification

Control

Room Simulator

Su

ort for 0 erators

and Unit Issues

71707

The inspector

noted excellent training support for operations

and, in

particular, strong real time review and assessment

of unit operating

issues

by the training department.

Examples included the observed Unit

4 secondary

plant swings (section 01. 1), the Unit 4 Eagle

21 protection

system failure (section H1.5),

and the Unit 3 SGFP switch issue (section

04. 1).

In each instance.

training was able to duplicate the observed

condition in the plant or develop specific scenarios

to evaluate the

plant issue.

This information was then fed back into the plant

organizations

for training or evaluation

purposes.

The inspector

observed

these simulator exercises

and discussed

them with

training and operations

personnel.

The inspector

concluded that

training and simulator support for the plant was excellent.

Quality Assurance in Operations

Refuelin

Outa

e Criti ues

Ins ection Sco

e

40500

and

71700

The inspector

reviewed the licensee's

post refueling outage critique and

self-assessment

processes.

Findin s and Observation

The licensee

conducted critiques

and outage reports for the Unit 3

spring

1997

and Unit 4 fall 1997 refueling outages.

The Unit 3 outage

met all the goals except schedule

(44 days versus

35 days).

The Unit 4

outage also did not meet schedule

(35 days versus

28 days);

however, the

radiation exposure

goal

(251

Rem actual

versus

165

Rem goal)

and

personnel

contamination related goal were also not met.

The critique process

assessed

the impact of delays

and lost time issues.

Strengths

and opportunities for improvement for each site discipline

were addressed

during each discipline related

meetings.

Final outage

reports were issued with corrective actions

and tracking denoted.

The inspector

reviewed the process,

attended

selected discipline

meetings,

reviewed the outage reports,

and discussed

the process with

licensee

management.

The inspector

noted that process

was very self-

critical, with a mix of positive and negative findings.

The areas for

improvements

were well identified.

Although schedular

goals

have not

Enclosure

2

14

been recently met', nuclear

and personnel

safety related goals were

achieved for both units'997 refueling outages.

c.

Conclusion

The inspector concluded that the licensee

demonstrated

excellent self-

assessment

in the area of refueling outage critiques.

0

07.2

Licensee

Self-Assessment

40500

The inspector

reviewed the licensee's

self-assessment

process

as related

to

a self-evaluation

completed during the inspection period.

A team of

ten licensee

employees

from various site disciplines conducted

an

assessment

of plant performance

by reviewing recent

and historical

issues.

The review was initiated by plant and site management.

The team concluded that there were

some areas

where actions

should

be

taken to improve overall plant performance.

These

areas

included the

following:

- Self-assessment

process.

- Efficiency of the work force,

- Radiological

issues,

- Aging of components,

- Housekeeping.

- Employee morale,

and

- Personnel attrition.

The inspector

reviewed the final report and proposed actions,

attended

the team debrief of management,

and discussed

the issues with

management.

The inspector

concluded that the licensee

conducted

a

thorough self-assessment

and demonstrated

a willingness to be self-

critical

.

II.

Maintenance

M1

Conduct of Maintenance

Ml.1

General

Comments

a.

Ins ection Sco

e

61726 and 62707

Maintenance

and surveillance test activities were witnessed or reviewed.

The inspector witnessed

or reviewed portions of the following mainte-

nance activities in progress:

Unit 3 secondary plant and

BOP maintenance

(section 01.2)

Enclosure

2

15

Unit 4 secondary plant oscillations

and related

BOP maintenance

(section 01.1)

Auxiliary Feedwater

System maintenance

and modification work

(secti on Ml.5)

Unit 4 Reactor Protection

System

(RPS) relay replacement

(WO 97026523)

(section

M1.6)

The inspectors

witnessed

or reviewed portions of the following test

activities:

Unit 3 residual

heat

removal

pump testing (section

M1.2)

Unit 4 safeguards

logic testing (section

M1.4)

Unit 3

RPS train

B per 3-OSP-049.

1 (section M1.6)

b.

Observations

and Findin s

For those maintenance

and surveillance activities observed or reviewed,

the inspectors

determined that the activities were conducted in a

sa;isfactory

manner

and that the work was properly performed in accor-

dance with approved maintenance

work orders.

The inspectors

also determined that the above testing activities were

performed in a satisfactory

manner

and met the requirements of the

technical specifications.

c.

Conclusions

Observed

maintenance

and surveillance activities were well performed.

M1.2

Residual

Heat

Removal

Inservice Test

IST

a.

Ins ection Sco

e

62707

and 61726

The inspector

observed

and reviewed the test results for the monthly

Inservice Test for the Unit 3 residual 'heat

removal

(RHR) pumps.

b.

Observations

and Findin s

The inspector

observed

the

IST surveillance

on the

3B RHR pump and

portions of the 3A RHR pump.

The tests

were performed

by

a nuclear

watch engineer

and

a senior reactor operator

(SRO) that was in training

for a watch engineer position.

In addition, the systems

engineer

was

present

during the testing of the

3B pump.

The inspector noted that the

watch engineer

reviewed in detail

each portion of the procedure with the

SRO prior to executing the procedure steps.

Enclosure

2

16

During the

pump operation,

the -inspector verified that there were no

leaks,

and that the flow rate

and differential pressure

measurements

were within the required

normal

range.

The surveillance results of the

two tests

were satisfactory.

However,

two vibration measurements

fell

within the alert range.

The 3A pump's axial position upper motor

bearing vibration response

measured

.34 inches/second.

The alert level

for this position was between

.20 and

.325 inches/second.

The 3B pump.

north side lower motor bearing vibration response

measured

2.0

mi ls

(.001 inches).

The alert range for this position was between

1.7 and

4.08 mils.

The inspector

noted that the watch engineer

appropriately.

informed the Nuclear Plant Supervisor

and the systems

engineer

each time

upon finding that

a vibration measurement

had fallen in the alert range.

The inspector verified the

pump reference

values

used in the procedures

for the 3A and the

3B

RHR pumps.

There

was some:discussions

with the

IST coordinator regarding the justifications for the reference

values

used

on the

3B pump.

Namely, the inspector questioned

the use of the

1994 reference vibration values (in June the

3B pump had been

removed

and refurbished).

The IST coordinator described

and justified the

reasons for not changing to

a new alert reference

value.

The decision

to keep the old alert vibration reference

value was conservative

because

the

new normal vibration value was actually greater than the old value.

However, after further review of the data

by the IST coordinator

and the

system engineer,

the licensee later informed the inspector that the

decision to keep the 1994 alert reference

value had been too conserva-

tive.

Inspection of the data trend (since the

3B pump refurbishment in

June)

indicated that the

new normal vibration value at the north side

lower motor bearing position was too close to the old alert value and

did not provide enough margin before entering into the alert range

as

allowed by the code.

In addition, the licensee

also noted

a slight

positive slope

on the trend data.

These

two items were the cause for

falling into the alert range.

The licensee

indicated they now had

enough data to justify a change to a new reference criteria.

The data

obtained in June would now be the new reference

data for the

3B pump.

As for the trend data

on the

3A pump, the data did not reveal

any

trends.

Engineering indicated that the next scheduled

RHR IST survei 1-

lance

on the 3A and

3B pumps would include

a spectral

analysis

and that

the vibration data that had fallen into the alert range would be closely

monitored

on future tests.

The inspector

independently verified the calibration of

the plant

uninstalled

gages

and the

H&TE gages

used in the surveillance

and found

that all the records

were complete

and that the gages

were calibrated.

c.

Conclusions

The IST surveillance

was well performed

and the inspector concluded that

both Unit 3

RHR pump IST results

were satisfactory.

The licensee

appropriately

addressed

the data that had fallen into the alert range.

Enclosure

2

17

Auxiliar

Feedwater

S stem Testin

Ins ection Sco

e

61726

The licensee identified that

an

AFW system train

1 test

was not per-

formed within the TS surveillance

requi rement for Unit 3.

The inspector

reviewed this issue.

Observations

and Findin s

On October

12,

1997, the Unit 3 ANPS was reviewing

AFW testing

requirements

and discovered the train

1

AFW test for the

C AFW pump was

last tested

on August 29.

1997 (eg.

~ 42 days).

TS 4.7. 1.2. la requires

that each

AFW pump be tested

every

31 days.

Allowing a

25K grace period

(e.g.,

7 days), the

AFW test

was not performed within the 38 day TS

requirement.

The licensee

immediately declared the

C AFW pump inoperable,

entered the

required

30 day action statement

per

TS 3.7. 1.2.'3, satisfactorily

performed the surveillance test,

declared the

C AFW pump operable

and

exited the TSAS.

CR No. 97-1829 was written and

a root cause

review was

performed.

The

C AFW pump is normally aligned to train 2; however,

the

C AFW pump

was realigned to train

1 on July 30.

1997 when the A AFW pump tripped on

overspeed

during

a Unit 3 reactor trip.

The

B AFW pump remained aligned

to train 2.

Because of the realignment,

the computerized tracking

system

was not updated to ensure the

C AFW pump was tested

on train l.

The licensee's

review concluded that failure to update the computerized

surveillance tracking sheets

was the root cause.

factors

included the decision to leave the

C AFW pump aligned to train

1 for an

extended

period of time (e.g..

3 months)..and

the increase to weekly

testing

and focus

on the A AFW pump.

Corrective actions included testing the

C AFW pump with satisfactory

results,

modifying the tracking sheets,

adding

an administrative

tracking action statement of 30 days during future

AFW pump realign-

ments,

and personnel

counsel, ling.

The

C AFW was subsequently

realigned

back to train 2.

The inspector

reviewed the

CR, logs, surveillance

procedures,

and

discussed this issue with operators

and surveillance

personnel.

The

inspector

confirmed that the related Unit 4 testing

had been performed.

Since the time between survei llances did not exceed the surveillance

interval plus the action statement

(e.g..

60 days), this issue

was not

reportable to the

NRC.

However, failure to meet

TS 4.7. 1.2. la testing

frequency is

a non-repetitive,

licensee identified and corrected

violation,

and is being treated

as

a non-cited violation per section

Enclosure

2

18

VII.B.l of the

NRC Enforcement Policy.

NCV 50-250/97-12-01,

Failure to

Test

AFW Pump.

was closed.

Conclusion

The fai lure to test the

C AFW pump on Unit 3 as required

by technical

specifications

was

a licensee identified and corrected non-cited

violation.

Licensee

response,

root cause,

and corrective actions

were

timely and appropriate.

Unit 4 Safe uards

Lo ic Testin

61726

On November 26,

1997, during procedure

4-OSP-063. 1, Safeguards

Logic

Actuation Test,

licensed operators

performing the test

on train A did

not receive the expected

results.

The control

room shift personnel

were

immediately notified,

and the

OSP implementation

was stopped.

System

engineering

was contacted for assistance.

The TS allows one train of

the logic to be out-of-service for up to eight hours for testing.

Operators

checked the similar Unit 3 OSP and noted what appeared to be

a

typographical error in the Unit 4 procedure.

These two OSPs

had

recently been revised

and upgraded into the current procedure

format.

The Unit 4

OSP was changed

using the on-the-spot-change

(OTSC) process,

and the test

was

recommenced

and completed satisfactorily.

A revision

to the

OSP is planned.

CR No. 97-2007

was also written to document the

problem and to address

corrective actions.

The ihspector

was in the control

room when the test

was being conducted

and observed the above issues.

The inspector verified TS compliance.

reviewed the

OSPs

and

OSTC No. 97-0841.

and discussed

these

issues with

operators

and the system engineer.

The inspector concluded that the

operators

acted correctly and conservatively in stopping the test

when

unexpected

results occurred.

Procedure

compliance

was noted to be

strong.

Test oversight

by the on shift ANPS was good.

Auxiliar

Feedwater

S stem maintenance

and Modification Work

61726 and

62707

The licensee

removed

one

AFW pump at

a time to perform corrective

and

preventive maintenance

work, and to implement two modifications

(PC/M

96-86 and 97-33).

A detailed schedule

was assembled

which included

system realignment verifications, surveillance testing,

PC/M package

closeout

and post modification testing,

system engineer oversight.

and

operations'learances.

A 30 day TS action statement

was entered after

realignment of the

C AFW pump.

This allowed both units to maintain two

independent

pumps

and trains operable.

The work scope

was scheduled

around-the-clock for three days.

Designated

maintenance

and engineering

individuals provided oversight

and continuity.

Enclosure

2

19

The inspector

reviewed the work scope.

PC/M packages

including the

safety evaluations,

the

AFW system clearances,

related operating

and

surveillance

procedures,

and other related work documents.

The

inspector

independently

walked down the realignments

in the field. and

discussed

the work with appropriate parties.

The inspector

noted that

the licensee

removed the

AFW Terry turbine electrical

overspeed trip

units.

The reason for removal

was to- enhance

pump performance,

and to

improve system reliability.

Turbine spurious trips due to induced noise

have occurred in the recent past

(See

NRC Inspection Report

No. 50-

250,251/97-08)..

The licensee's

evaluation

documented

the basis for

removal

as the electrical

overspeed

device was not needed

as the turbine

governor

and the mechanical

overspeed trip device provided the necessary

protection.

Apparently. other plants

have also removed this function or

have never

had it installed.

The inspector

concluded that the licensee

conducted these

maintenance

outages

for the

AFW system with excellent planning.

Excellent teamwork

among operations,

engineering.

and maintenance

personnel

was noted.

Strong oversight in the field was noting during all aspects

of the work.

Reactor

Protection

S stem

RPS

Observations

61726 and 62707

The inspector

observed

portions of'he operations

conduct of RPS

periodic testing

on the Unit 3 train

B in accordance

procedure

3-OSP-

049. l.

RPS Logic Test.

on December

2,

1997.

The inspector verified OSP

and

TS 3.3. 1 compliance relative to the reactor trip bypass

breakers.

Operator

performance

was well coordinated

among the control

room, the

trip breaker

panel,

and the

RPS logic rack locations.

Communications

were formal and procedure

compliance

was strong.

Supervisory oversight

was also very good:

On the

same

day. the inspector observed

a relay replacement activity

associated

with the A train of the Unit 4 RPS.

On December l. 1997.

I8C

maintenance

personnel

were performing surveillance testing

(SMI) on the

B reactor coolant system

(RCS) loop temperatures.

An abnormality was

noted by operators

in that

an annunciator

alarmed unexpectedly in the

control

room.

The test

was stopped

and the licensee verified RPS

operability.

The problem was traced to relay

(TC 42281)

alarm function

for the Overpower Delta Temperature

input.

One of the relay contacts

was observed to be malfunctioning.

Root cause

assessment

is pending.

The licensee

entered

TS actions for a single train of RPS and closed the

train A reactor trip bypass

breaker.

This was

a short duration action

statement of only six hours.

I8C personnel

performed the relay

replacement

per

WO 97026523.

The post maintenance testing

(PMT) and

surveillance operability testing

was completed satisfactorily,

and the

licensee exited the action statement

in two hours

and 35 minutes.

The

inspector witnessed the activities,

and independently verified TS,

procedure,

and

WO compliance.

Strong field oversight

and supervisory

involvement were observed.

The inspector

concluded that licensee

. performance

was outstanding.

Enclosure

2

M2. 1

20

Maintenance

and Material Condition of Facilities

and Equipment

Pressurizer

Level Transmitter

LT

Drift

62707

During the period, Unit 4 pressurizer

level device LT-4-461 drifted

above the allowed maximum

7X tolerance

between

redundant

channels.

This

required the licensee to declare the protection channel out-of-service

(OOS),

make containment entries to fill the reference

leg,

and address

protection

and control actions

required

by TSs

and procedures.

LT-4-461

is one of three pressurizer

level inputs to the

RPS.

When the device's

reference

leg was filled, shared

instruments

(on the

same level taps)

were also effected.

This includes

PT-4-457 (protection channel),

PT-4-

445 and 444 (control channels),

and LT-4-462 (cold calibration pressur-

izer level).

The other two pressurizer

instrument taps

were not

affected.

The licensee

believes that the LT-4-461 condensing

pot may be

differently designed

or affected.

CR No. 95-1126 was previously written

to address

the Unit 3 LT-3-461 device due to reoccurring drift issues.

The licensee

has historically seen

LT-3/4-461 drift issues after

a

refueling outage.

Apparently non condensing

gases inhibit the ability

of the reference

leg condensing

chamber.

Corrective actions

have

included insulation repairs,

leak repai rs.

and post-refueling

reference

leg filling.

Longer term reviews are still in progress.

M2.2

The inspector

observed

implementation of procedure

0-GMI-047. 1. Filling

Reference

Leg for LT-461.

Appropriate precautions

and actions

were

taken for the containment entry for tripping the

RPS bistables

and for

manual control of pressure

devices.

An operator

was stationed to

monitor and control the charging

pumps

and pressurizer

level, to control

. the pressurizer

heaters

and spray valves.

and to control the one

affected

PORV.

The inspector

concluded that the licensee

has adequately

addressed

this issue in the past,

and noted that longer term actions

planned were appropriate.

Plant Housekee in

Material Condition

and Cleanliness

62707

During the period, the inspectors

reviewed the licensee's

actions

and

progress to improve the plants'ppearance

and material condition.

Actions to cleanup

and paint several

plant areas

were completed.

This

included the spent fuel pool areas.

Unit 3 auxiliary building rooms,

and

specific areas in the turbine building.

Marked improvements in these

areas

were observed.

Overall plant housekeeping

has also improved;

however, the inspector

did note several

ar eas in the auxiliary building

that were in need of attention.

This included three instances

where

water was left on floor areas

and Unit 4 equipment

rooms.

The licensee

immediately addressed

the water issues

and the areas

were not

contaminated.

Further, the licensee

has plans to address

these other

areas

when high background radiation levels decrease.

Enclosure

2

H7.1

M8

H8.1

21

The inspector concluded that the licensee

has

a plan in progress to

improve the overall

appearance

and material condition of the units.

Progress

to date

as

been

good.

Quality Assur ance in Maintenance Activities

Maintenance

Performance

Assessment

62707

The licensee initiated

a third party assessment

of maintenance

per for-

mance.

The review includes work scope,

back log, resource allocations,

costs,

planning,

scheduling,

work execution,

and other related

reviews.

The assessment

was conducted during November and December

1997.

and the

final .report is due in late December

1997 or in early January

1998.

The review included process

reviews,

personnel

interview,

benchmark

comparisons,

and recommendations

and improvements,

and

a workshop

conducted onsite..

The results of the review were pending at the

conclusion of the inspection period.

The inspector

reviewed the process

and discussed it with licensee

management

and maintenance

personnel.

The inspector

concluded that the

independent

assessment

process

was sound,

and demonstrated

the

licensee's

openness

for third party assessments.

The inspector

intends

to review the final results in future inspections.

Miscellaneous

Haintenance

Issues

Closed

LER 97-08

Emer enc

Core Coolin

S stems

Containment

Sumo Screen

Issues

62707

90712

and 92700

The licensee identified deficiencies

in three of the four

ECCS contain-

ment

sump screens.

10 CFR 50.72 and 50.73 reports

were made for a

condition outside the design basis.

LER 97-08 was issued

on October 8,

1997.

NRC Inspection Report

No. 50-250,251/97-10,

section H2.5,

previously reviewed this issue.

Corrective actions

and root cause

analysis,

and

NRC inspection of the repairs

were documented

in that

NRC

report.

The

LER concluded that causal

factors included inadequate

procedural

guidance

and personnel

error.

The inspector

reviewed the

corrective actions

as stated in the

LER, and independently verified

selected

items.

The licensee

addressed

safety impact and concluded that

the as-found condition of the

ECCS screens

did not represent

a signifi-

cant impact to the operation of components

required for accident

mitigation.

The inspector noted that the decision to inspect the Unit 4 screens

at

the beginning of the September

1997 refueling outage

was based

on

findings at the St. Lucie plant.

Further,

once deficiencies

were

identified on the shutdown Unit 4, the operating Unit 3's screens

were

immediately

inspected.

One Unit 3 screen

required repairs,

and the

work was performed immediately on-the-spot.

The inspector concluded

Enclosure

2

E1

El. 1

E2

E2.1

22

that the corrective actions.

root cause

assessment.

and

LER were

appropriate.

The failure to have

an adequate

ECCS sump screen

inspection procedure

was

a non-repetitive.

licensee identified and

corrected violation, and is being treated

as

a non-cited violation (NCV)

per section VII.B.1 of the

NRC Enforcement Policy.

NCV 50-250 '51/97-

12-02,

Inadequate

Sump Screen

Inspection Procedure,

and

LER 97-08

were closed.

III.

~E

Conduct of Engineering

Unit 4 Containment

Sum

Pum s

37551

After restart

from the fall 1997 Unit 4 Cycle

17 refueling,

abnormal

containment

sump indications were noted following a normal

pump

down evolution.

PC/M 97-12 drilled holes in the sump

pump discharge

check valves,

4-4692A/B, in response

to

NRC GL 96-06. Overpressurization

Protection of Isolated Piping.

Drilling the disc in the check valve was

not considered

as

a significant change to system response.

However.

after

a

pump down evolution, approximately

65 gallons of water

drained from the line through the drilled hole and back into the sump.

This resulted in control

room annunciator

alarm

G 5/3,

"Containment

Level Increasing >1.0 GPM." for about

30 minutes.

The licensee initiated

CR No. 97-1814 to address

root cause

and correc-

tive actions.

Root cause

was determined to be engineering oversight of

the drain-back

phenomena

during the

PC/M review and approval

phases.

Immediate corrective actions

included Training Brief No. 701,

"Unit 4

Containment

Sump Drain-Back," and revisions to the

ARP

G 5/3 and to the

RCS leak rate procedure.

Longer term actions

included

PC/M changes

for

the upcoming Unit 3 fall 1998 outage

and for Unit 4 at the next

opportunity.

The inspector

noted

a weakness

in the

PC/M process

due to engineering

oversight that overlooked this actual

response to the sump.

Once

identified, licensee

response

was aggressive

and thorough.

Corrective

actions

appeared

to be appropriate.

Engineering Support of Facilities and Equipment

Unit 4 Emer enc

Diesel Generator

Normal Start Failures

61726 and

~62707

The inspector

reviewed the licensee's

efforts to identity the root cause

for three Unit 4

EDG normal start fai lures during monthly surveillance

testing.

The start failures did not effect rapid or emergency start

mode of the

EDGs.

(The normal start switch and logic is bypassed.)

This

was confirmed by reviewing the

UFSAR and related electrica't

schematics.

The previous failure was reviewed in

NRC Inspection Report

No. 50-

Enclosure

2

23

250,251/97-08.

Initially. the licensee

had noted corrosion deposits of

silver sulfide on the switch contacts.

However,

recent

reviews per

CR

No. 97-1856 concluded that the normal start switch was satisfactory,

but

the normal start relay had three

open contacts

caused

by foreign

material deposition.

Similar relays

(Square

D type 8501

XUDO 1200

series)

used in the

EDG logic and elsewhere

in the plant were checked,

and no other problems were noted.

Root cause

assessments

by the

licensee's

metallurgical laboratory

and by the vendor

are continuing.

The inspector verified corrective actions

as stated in the CRs.

The

.

inspector also observed

selected testing

and maintenance activities

associated

with the Unit 4 EDGs.

The inspector verified that the Unit 3

EDGs were not effected

as they are older and have different electrical

controls.

The inspector

concluded that the licensee

has

been thorough

in their investigation of these

issues.

The inspector intends to follow

the continuing efforts by the licensee

and the vendor.

Westin house

Fuel

Issues

37551

On October 29.

1997. the licensee

reported

a condition (for information

only) to the

NRC regarding Westinghouse

high power. high burn up

Integral

Fuel Burnable Absorber

(IFBA) fuel rods.

A recent generic

analysis

noted the potential for exceeding

the

10 CFR 50.46

maximum

cladding oxidation criteria of 17K.

The analysis

concluded that for IFBA fuel. internal

rod pressure

(from

the absorber

reaction)

may exceed the pellet-to-clad

gap opening

criteria.

This in turn could cause the

17K criteria to be exceeded.

The generic analysis

was for 17x17 fuel with a 1.5 IFBA coating.

Turkey

Point uses

15x15 fuel with a 1.0

IFBA coating.

A generic justification

for continued operation

(JCO) was provided.

On November

13.

1997,

Westinghouse

submitted

a letter to the

NRC that based

on preliminary

information Turkey Point Units 3 and

4 were not effected.

The licensee initiated

a

CR and performed their operability and

reportabi lity determinations.

This issue is being tracked

by NRR on

a

plant specific basis.

The inspector

and

NRR intend to follow licensee

actions in this area.

The inspector

concluded that the licensee

appropriately

responded to this fuel issue.

E ui ment

A in

Team

37551

Based

on recent aging related

equipment failures, the licensee's

engineering

group developed

a team approach to review Turkey Point's

electronic equipment

and aging impact on the plant.

The team included

representation

from engineering,

operations,

maintenance,

and procure-

ment.

The team addressed

issues

including susceptible

equipment,

prioritization, scope

and existing measures.

planned

replacements,

and

recommendations

to management.

The team was recently organized.

and

meetings

and reviews are ongoing.

Three sample

systems

(heater drain,

Enclosure

2

E2.4

condensate,

and rod control) are scheduled

as pilot systems to be

completed

by January

31,

1998.

The inspector

reviewed the team's charter

and procedure,

compositions

scope,

and preliminary work.

The inspector also discussed this item

with licensee

personnel.

The initiative appears

to be sound

and

proactive.

The inspector intends to follow the licensee's

progress

in

future inspections.

Intake Coolin

Water

ICW

S stem Modification

Ins ection Sco

e

62707

and 37551

The inspector

reviewed the engineering

and maintenance activities on an

ICW system modification.

Observations

and Findin s

On November 5, at 4:45 AN. the

3C component cooling water

(CCW) heat

exchanger

was declared

out of service to install

a modif'ication on the

intake cooling water system.

The purpose of'he modification was to

install

a new isolation valve at the discharge

side of the

CCW heat

exchanger,

and to abandon in place valve 3-50-360. that was serving the

isolation function.

This valve is cycled when the heat exchangers

are

cleaned

and during the

ICW inservice tests.

The problem with the valve

was that it had

become too difficult to actuate, i.e., the torque

required to move the hand wheel

was very high.

Prior to planning this modification, engineering

and maintenance

had

made several

attempts to resolve the high torque issue.

Inspection

efforts included visual

and borescopic

inspections,

and adjustment to

the gearbox actuator.

The root cause for the high torque could not be

determined.

Due to the location of this valve on the

ICW system.

replacing the valve would requi re taking the

ICW system out of service

and this would subsequently

make the

CCW system inoperable

as well.

The

CCW system at Turkey Point is the most risk significant, therefore.

the

licensee appropriately classified this modification as safety related.

The licensee

decided to remove

a previously abandoned

continuous-tube

cleaning strainer

and replace it with a butterfly valve.

However, the

isolation valve that was presently installed

was not removed from the

system.

The valve was fully opened,

the handle wheel

was

removed,

and

the valve was subsequently

abandoned.

In performing this modification, the licensee

declared the

3C

CCW heat

exchanger

out-of-service

(OOS)

and entered

a 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months administrative

limited condition of operation

(LCO).

Unit 3 has three

CCW heat

exchangers.

However, Technical Specifications

only requi re two operable

CCW heat exchangers.

The licensee controlled the

OOS time on the thi rd

heat

exchanger

by procedurally limiting the

OOS time.

On November 11,

Enclosure

2

25

at 4:35

PH, the

3C

CCW heat

exchanger

was returned to service, within

the 72 hour8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months administrative

LCO.

The inspector

observed portions of the modification maintenance

work,

which included removal of strainer,

welding of the modified pipe

support,

and installation of the new butterfly valve.

Safe work

practices

were noted

and good use of procedures

was noteworthy.

The

inspector noted continuous

maintenance

supervision at the job site,

and

noted that Quality Assurance

was present at the job site and was

performing

a field surveillance

on this modification.

In addition, the

inspector verified the appropriate

system line ups

and flow rates

on the

inservice

3A and

3B

CCW heat exchangers.

Also, the inspector verified

the post maintenance

flow testing

had been completed

and that,appropri-

ate justification had been provided by engineering for the change in

flow rate.

The post maintenance

flow rate increased

by 100

GPM compared

to the as found flow rate (prior to installing the modification).

Engineering

reviewed the increase in flow rate

and provided the techni-

cal justification for the acceptance.

The inspector

reviewed the

control

room logs and verified LCO compliance.

In addition, the

inspector

reviewed the implementation turnover

package

and found it

contained the required

documentation

and appropriate

approvals.

Conclusions

The inspector

concluded that the modification was well planed

and

executed.

Good maintenance

supervision

and work practices

were

noteworthy.

The minor increase

in flow rate was negligible and did not

degrade the

CCW system heat transfer

requirements.

E6

E6.1

Engineering Organization

and Administration

Pl ant Revi ew Board

PRB

Process

37551

The

PRB process

provides for management

review, prioritization. and

approval of proposed site modifications on th Top 20 (outage)

and Top 30

(non-outage) lists.

Procedures

0-ADM-510. Request

For Engineering

Assistance

(REA) and QI 3-PTN-l. Design Control, delineate the plant

change/modification

(PC/M) processes

and

PRB process

functions.

The inspector attended

several

PRB meetings,

reviewed the Top 20/30

lists,

reviewed the procedures,

discussed

the process with engineering

and plant management

and reviewed selected

PRB meeting

agenda

and

summaries.

The inspector

noted good representation

at the meetings

and

a positive interaction

among

PRB members.

Regulatory required

PC/Hs

performance

enhancements

and budget restrictions

were all considered

during

PRB discussions.

The inspector

concluded that the licensee's

process for modification

prioritization and approval

using the

PRB was effective.

Enclosure

2

E8

E8.1

26

Miscellaneous

Engineering

Issues

Honthl

0 eratin

Re ort

92713

E8.2

Rl.l

The inspectors

reviewed the September

and October

1997 monthly operating

reports

and determined

them to be complete

and accurate.

Closed

Ins 'ector Follow Item

IFI

50-250 251/96-04-01.

Char in

Pum

Res

onse Durin

Safet

In ection

SI

92903

During a SI, the charging

pumps trip and are locked out for two minutes.

These

pumps (three

per unit) are not part of the

ECCS.

The

EOPs direct

the SI signal to be reset,

at which time the operators

can restart the

charging

pumps.

The HHSI pumps are part of the

ECCS;

however. they are

1600 psig discharge

pressure

pumps.

Therefore, if reactor pressure

remains

highs it is important for the operators to restore charging

pump

flow to the reactor.

The licensee

reviewed this issue

under

REA No. 96-

018,

and concluded

a

PC/H would be developed.

The

PC/M is scheduled

for

the Unit 3 fall 1998 and the Unit 4 spring

1999 refueling outages.

The

inspector verified this by reviewing the outage work lists and

PRB

approvals.

Based

on these reviews'he

IFI was closed.

The inspector

intends to track the completion of the

PC/M through the outage

modification lists.

IP.

~P1

P

I

Radiological Protection

and Chemistry

(RP&C) Controls

Unit 4 Personnel

Contaminations

Events

PCEs

Ins ection

Sco

e

71750

The inspector

reviewed the licensee's

actions relative to the number

of'CEs

that occurred during the fall 1997 Unit 4 cycle 17 refueling

outage.

Observation

and Findin s

. During the Unit 4 cycle 17 refueling outage

(September

8 to October

13,

1997), the licensee

experienced

an unusually high number of PCEs.

Some

of these

events

resulted in assignment of skin doses

and

some resulted

in small uptakes of radioactivity.

As

a result, the licensee did not

achieve their outage goals.

In each instance

where

a

PCE occurred,

a condition report

(CR) was

initiated.

as well as

a radiological event report,

a personnel

contamination report,

a whole body count.

and

a dose assignment

record.

All of the external

contaminations

were successfully

decontaminated.

In

a number of instances

skin doses

were assigned.

Also. there were

a

Enclosure

2

P2

P2.1

27

number of instances

where small uptakes

occurred

when individuals

received facial contamination.

The inspector

reviewed

an event that occurred

on October

1,

1997, in the

Unit 4 reactor, cavity.

Three mechanical

maintenance

workers were

involved in cleaning the reactor

stud holes.

Apparently. all three

workers received facial contaminations of levels from 3.000 to 22.000

dpm.

Whole body counts were taken after successful

decontamination.

The three workers all had levels of Cobalt-58

(45 to 113 nanoCuries).

The licensee

performed

dose

assessment,

and assigned

doses of one to two

milli-Roentgen Equivalent

Man

(mRem) committed effective dose equivalent

(CEDE),

and three to ll mRem committed dose equivalent

(CDE) over the

next 50 years.

The inspector

reviewed the documentation

associated

with

this instance,

and discussed

the event

and results with the licensee.

The inspector also reviewed procedure

O-ADM-600, Radiation Protection

Manual.

The inspector verified that the

CDE and

CEDE exposures

were

added to the individuals exposure histories.

The inspector also reviewed

CR No. 97-1748 which addressed

this event.

The licensee's

corrective actions included reviewing the need for a dust

mask when working in areas of potentially high contamination.

revising

including overall outage

radiological performance

and critique items

as longer term planned

actions,

updating exposure

records,

briefing individuals on work

practices

and contamination control,

and plans to perform

a post outage

review of all PCEs.

The inspector verified selective corrective

actions.

In addition, regional specialist

inspectors

intend to review

overall outage

and related radiological

performance

during regular

scheduled

inspections.

Conc 1 us ions

The inspector concluded that the licensee appropriately

documented

and

followed up on the Unit 4 related

PCEs,

including

CR No. 97-1748.

No

violations of NRC requirements

were identified.

However,

improvements

are necessary

in radiological outage

performance

as evidenced

by the

abnormally high number of PCEs

and exposure results

from the fall 1997

Unit 4 refueling outage.

Status of EP facilities, Equipment,

and Resources

Facilit

Ins ection

Ins ection Sco

e

82701

The inspectors

examined the licensee's

emergency

response facilities

(ERFs)

and equipment to'assess

thei r adequacy

and to determine

(1) whether they were maintained in a state of operational

readiness

as

specified in the Turkey Point Radiological

Emergency

Plan

(REP),

and

(2) whether

ERF changes

made since the last such inspection

(December

Enclosure

2

o

28

1995) were technically adequate

and in accordance

with NRC requirements

and licensee

commitments.

b.

Observations

and Findin s

.The inspectors

toured the Technical

Support- Center

(TSC) and Operational

Support Center

(OSC).

Various modifications

had been

made to both

facilities since the previously referenced

December

1995 inspection, all

of which appeared to represent

enhancements.

Changes to three

TSC

status

boards

were

made to enhance

human factors,

including conversion

of two to copy boards.

The inspectors

toured the Emergency Operations

Facility at the licensee's

General Office in Miami as part of the May

1997 emergency exercise evaluation.

and observed

enhancements

that had

been

made.

During the current .inspection,

changes

were reviewed with

licensee

management

and were determined to have improved the ability of

the

EOF to carry out its function,

based

on licensee

and

NRC

observations

during the May exercise.

As of August l. 1996, the plant

organization

assumed responsibility for EOF maintenance

and operational

procedures

from the corporate organization.

This change

was

appropriately reflected in surveillance procedures.

Section 2.4.5 of the

REP stated that the second floor of the

TSC

building was

an alternate

location for the

OSC if the primary OSC was

deemed

unhabitable for any reason.

The inspectors

toured this

designated

location and observed that

~ in the as-tound condition. the

facility was not suitable for use

as

an

OSC because of the large

uantity of furniture that was stored there,

leaving insufficient space

or personnel.

The licensee

promptly restored the designated

alternate

OSC location to an appropriate state of readiness

by moving the excess

furniture items out of the facility.

The licensee

planned to henceforth

conduct periodic survei llances (e.g.,

monthly) of this facility to

maintain it in an appropriate state of readiness.

Miscellaneous

instruments,

equipment

(including telephones

and other

communications

devices),

and supplies in the

ERFs were selectively

examined.

With some very minor exceptions

(e.g..

"low battery"

indication on one. survey meter). all tested

components

were found to be

in operable condition.

No significant discrepancies

in connection with

emergency supplies

were identified with the exception of some problems

with silver zeolite cartridges.

These cartridges

are used in

conjunction with an air sampler

as

a medium for detecting radioiodine in

the atmosphere

in the event of a radiological release.

The cartridges

were supplied

by the vendor in packages

of 10, sealed in heavy-duty

l0-mi 1 plastic sleeves.

This packaging

was intended to minimize the

degradation of the cartridges that would occur with exposure to the

atmosphere

and to thereby maximize shelf life (rated at

10 years).

The

inspectors

found that all 20 silver zeolite cartridges

stored in the TSC

and

20 of 50 stored in the

OSC were in unsealed original packages

(e.g.,

tom open at one end).

Information from the vendor (in a letter dated

February 6.

1997)

recommended that

an opened

package

should

be thermally

Enclosure

2

29

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

so as not to void the 10-year shelf life.

Furthermore,

of the total of seven

packages

of silver zeolite cartridges

stored in the

TSC and

OSC. only two carried

any indication of

manufacturing date or shelf-life expiration date.

The two dated

packages

were labeled

as manufactured

in 1986.

The inspectors

questioned

whether any of the licensee's

silver zeolite cartridges

were

within thei r rated 10-year shelf life.

As

a result of these findings.

the licensee

immediately arranged with the vendor to replace its entire

stock of 150 silver zeolite cartridges.

On the day following the

identification of this discrepancy,

the licensee

received

50 fresh

cartridges

from the vendor,

and expected to receive the remaining

100 by

mid-January

1998.

Although the applicable surveillance

procedure

(O-HPS-090,

"Inventory of Health Physics

Emergency

Equipment",

approved

August 9,

1996) did not specifically require any checks of the stock of

silver zeolite cartridges

beyond

an inventory of the quantity,

Section 3.2 of the procedure

assigned

responsibility for "Reporting any

Emergency

Equipment malfunction or damage to the

HP Instrument

Supervisor",

and Section 6.4 cautioned that -Any equipment that is

broken ... shall

be reported

immediately" to the appropriate

supervisor.

These general

di rectives should have been sufficient to prompt

identification of the subject

problems during the surveillance

process.

The inspectors

informed licensee

management

that the failure to identify

inadequacies

in the material condition (namely,

unsealed

packages

and

unknown age) of the stock of silver zeolite cartridges

represented

a

weakness

in the licensee's

surveillance

program for emergency

equipment

and supplies.

Records of survei llances of emergency

supplies

and equipment

as

conducted in accordance

with O-HPS-090,

-Inventory of Health Physics

Emergency

Equipment" were selectively inspected.

Survei llances

and

tests

as specified

by the subject procedure

were determined to have been

performed at the required frequencies.

Records of periodic

ERF

walkdowns conducted in accordance

with Administrative Procedure

EP AD-007,

"Emergency

Response Facilities

and Equipment Survei llances",

were also reviewed.

The documentation for both of these

procedures

indicated that those deficiencies

which were identified during these

survei llances

were expeditiously corrected.

Conclusions

ERFs were well designed

and equipped,

and were generally maintained at

an adequate

level of operational

readi ness.

However

. the as-found

condition of the designated

alternate

OSC was unacceptable

for its

intended

use.

and the material condition of the stock of silver zeolite

cartridges

represented

a weakness

in the licensee's

surveillance

program

for emergency

equipment

and supplies.

Enclosure

2

P3

P3.1

EP Procedures

and Documentation

Emer enc

Res

onse

Plan

Ins ection

Sco

e

82701

30

The inspectors

reviewed the licensee's

maintenance of the

REP and

selected

commitments therein,

and reviewed recent revisions to the

REP

to determine whether changes

were made in accordance

with 10 CFR 50.54(q).

Observations

and Findin s

The version of the

REP in effect at the time of the current inspection

was Revision 32. effective January

29,

1997.

Since the previously

referenced

December

1995 inspection,

the licensee

had promulgated four

revisions

(Revisions

29 through 32) of the Plan.

Revision

29 was

formally reviewed by Region II, with the results

conveyed to the

licensee in an

NRC licensing letter dated August 30,

1996.

During the

current inspection,

Revisions

30,

31 'nd 32 were selectively reviewed.

Many of the modifications in these revisions resulted

from plant and

corporate organizational

changes.

No changes

were identified as

decreasing

the effectiveness

of the

REP, with the exception of a change

in Section

7. 1.4. 1 of Revision 32.

In an effort to incorporate the 1996

"exercise rule" change,

which allowed licensees

to conduct full-scale

exercises

biennially instead of annually,

the licensee

revised its

REP

to require exercises

every two years

but failed to include

a requirement

for an "off-year" drill between exercises;

Section IV.F.2.b of

Appendix

E to 10 CFR Part 50 specifies that "the licensee shall take

actions

necessary

to ensure that adequate

emergency

response

capabilities

are maintained during the interval between biennial

exercises

by conducting drills. including at least

one drill involving a

combination of some of'he principal functional areas of the licensee's

onsite

emergency

response capabilities."

Although the licensee

had

commenced

a program of'uarterly drills beginning in December

1996 (any

one of which met the requirement for an off-year drill). the

REP did not

contain any requi rement or commitment to this program.

The inspectors

concluded that

a violation of 10 CFR 50.54(q) occurred in that

Revision 32 reduced the effectiveness

of the

REP without Commission

approval

.

(VIOLATION 50-250,

50-251/97-12-04:

Failure to follow 10 CFR 50.54(q)

requirement that revision of the Radiological

Emergency

Plan

must not reduce its effectiveness)

Since the December

1995 inspection,

the licensee

had

made two emergency

declarations

for the Turkey Point facility.

Each was classified

as

a

Notification of Unusual

Event

(NOUE).

On March 4,

1997.

a

NOUE was

declared

because of an electrical fire lasting more than

10 minutes in

the 4A control-rod-drive motor-generator

set.

On April 6,

1997,

a

NOUE

was declared

based

on the occurrence, of reactor coolant system pressure-

,

. boundary leakage.

The inspectors

examined licensee

documentation of

Enclosure

2

P3.2

P5.1

p6

31

these

events

and concluded that both were promptly and correctly

classified

based

on the licensee's

EALs, and that notifications to

cognizant offsite authorities

were

made in accordance

with requi rements

regarding timeliness

and content.

Conclusions

REP Revisions

30 and

31 were made in accordance

with 10 CFR 50.54(q),

but

a violation for decreasing

the effectiveness

of the

REP was

identified in Revision 32.

Emergency declarations

on March 4 and

April 6,

1997 were made in accordance

with applicable procedures.

Plant

Emer enc

Procedures

82701

The inspectors

reviewed the licensee's

administration of selected

REP

requirements

through evaluation of the adequacy of the implementing

details contained in the Emergency

Plan Implementing Procedures

(EPIPs).

Based

upon selective

review. the licensee's

EPIPs were determined to be

generally thorough in terms of detail

needed to implement the various

requirements

and commitments in the

REP.

No examples of REP commitments

without appropriate

EPIP implementing details

were identified by the

inspectors.

Selected

copies of the EPIPs which were available for use at the

TSC and

OSC were checked

and found to be current revisions.

Staff Training and Qualification in EP

uarterl

EP Dri 1 1

71750

On November 21,

1997, the licensee's

EP group conducted

a site evacua-

tion drill.

This include the activation of the onsite facilities

~

personnel

accountability, site evacuation,

and offsite assembly.

The

drill was successfully

performed

and critiqued.

The inspectors

observed portions of the drill from various onsite

EP

facilities.

The inspectors

conclude that the drill was well conducted,

met the drill objectives,

and was

a good training exercise.

EP Organization

and Administration

Ins ection Sco

e

82701

The inspectors

reviewed this area to determine if any changes

in

management

or personnel

had occurred which could adversely affect the

management

and implementation of the emergency

preparedness

program.

Enclosure

2

Observations

and Findin s

32

P7

P7.1

The organization

and management

of the emergency

preparedness

program

were reviewed

and discussed

with licensee

representatives.

Several

staff and management

personnel

changes

since the December

1995

inspection affected the emergency

planning function.

The principal

change in this area

was the addition

(as of November

1,

1997) of the

Security program to the duties of the Protection Services

Manager

(formerly Fire Protection/Safety

Supervisor),

who was also responsible

for supervising the licensee's

programs in fire protection. safety,

and

emergency

preparedness.

At the

same time.

a former Senior Nuclear Plant

Operator replaced the

EP Coordinator.

The inspectors

interviewed

various cognizant staff and management

personnel

in an effort to

ascertain

the effects of these

changes

on the

EP program at Turkey

Point.

No deleterious

effects were identified.

The new'P Coordinator

was knowledgeable

in emergency

preparedness

through his Operations

experience

as

a participant in many drills and .exercises.

The

Protection Services

Manager,

as

a former

EP Coordinator himself.

was

fully cognizant of, and involved with. the day-to-day workings of the

EP

program.

The Protection Services

Manager reported to the Services

Manager,

an individual with extensive experience in supervision of the

EP function,

and who was

a designated

Recovery

Manager (the lead

position in the EOF).

Notwithstanding the favorable aspects

delineated

here, the licensee will be challenged to maintain vigilant management

oversight of the

EP program with so many organizational

and staffing

changes

occurring simultaneously.

Conclusions

No degradation

had occurred in the organization

or management

of the

emergency

preparedness

program.

Emergency

preparedness

appeared

to be

receiving solid management

support at Turkey Point, but maintenance of

strong

management

oversight will be an area of challenge.

Quality Assurance in EP Activities

10 CFR 50.54 t

Audit of Emer enc

Pre aredness

Pro ram

Ins ection Sco

e

82701

The inspectors

reviewed this area to assess

the quality of the requi red

audit and to verify that the audit met the requirements

of

10 CFR 50.54(t).

Enclosure

2

b.

Observations

and Findin s

33

The inspectors

reviewed documentation

associated

with the following EP

program audits conducted

by the licensee's

Quality Assurance

(QA) group:

o

QAS-PMON-96-1, issued

February

27,

1996

o

QAS-EHP-96-1,

issued

August 16,

1996

o

QAS-EMP-96-2,

issued

October 30,

1996

~

QAO-PTN-97-004,

issued

June 20.

1997

These audits were all judged to be thorough

and independent,

and the

nature of the identified issues

indicated inclusive understanding of the

EP area

by the auditors.

The audits provided evidence of the licensee's

ability to self-identify emergency

preparedness

program deficiencies.

In addition to the above audits

requi red by 10 CFR 50.54(t). the

licensee initiated independent

self-assessments

in the

EP area in

response to (1) the significant

EP issues

from an

NRC inspection at the

St. Lucie facility in October

1996.

and (2) the two emergency

declarations

discussed

above in Section

P3. 1.

These audits were

excellent

and useful efforts to extend self-assessment

in EP beyond what

NRC regulations

requi re.

c.

Conclusions

The 1996-1997

EP program audits fully satisfied the

10 CFR 50.54(t)

requirement for an annual

independent

audit of the

EP program.

Additional self-assessments

in EP were excellent

and useful efforts by

the licensee's

QA group.

P8

Miscellaneous

EP Issues

P8. 1

Closed

IFI 50-250

50-251/97-05-01:

Exercise

Weakness

-- Failure to

perform

a prompt damage

assessment

of safety-related

equipment.

The

inspectors

reviewed the licensee's

July 31,

1997 response

to this

finding.

To the extent possible.

the inspectors

independently verified

the corrective actions delineated

in this letter,

as well as other

improvements

not listed in the letter.

The licensee

had aggressively

pursued appropriate

actions to prevent recurrence of the subject

weakness,

including special

emphasis

on timely dispatch of OSC teams in

the quarterly drill conducted

on August 1.

1997.

This item is closed.

Enclosure

2

X1

Exit Meetin

Summar

34

V:

Mana ement Meetin s

The inspectors

presented

the inspection results to members of licensee

management

at the conclusion of the inspection

on December

12,

1997.

The licensee

acknowledged the findings present.

The inspectors

asked the licensee

whether

any materials

examined during

the inspection should be considered

proprietary.

No proprietary

information was identified.

Partial List of Persons

Contacted

Licensee

T.

V. Abbatiello, Site Quality Manager

R. J. Acosta, Director, Nuclear

Assurance

J.

C. Balaguero,

Plant Operations

Support Supervisor

P.

M. Banaszak.

Electrical/l&C Engineering Supervisor

B.

C.

Dunn, Mechanical

Systems

Supervisor

R. J. Earl,

QC Supervisor

S.

M. Franzone,

Electrical Maintenance

Supervisor

J.

R. Hartzog.

Business

Systems

Manager

G.

E. Hollinger, Licensing Manager

R. J.

Hovey, Site Vice-President

M. P.

Huba,

Nuclear Materials Manager

D.

E. Jernigan,

Plant General

Manager

T. 0. Jones,

Operations

Supervisor

M. D. Jurmain,

I8C Supervisor

V. A. Kaminskas.

Services

Manager

A. N. Katz, Mechanical

Maintenance

Supervisor

J.

E. Kirkpatrick, Protection Services

Manager

G.

D. Kuhn, Procurement

Engineering Supervisor

R. J. Kundalkar,

Vice President.

Engineering

and Licensing

M. L. Lacal, Training Manager

V. G. Laudato,

Fire Protection Supervisor

E.

Lyons, Engineering Administrative Supervisor

J.

A. Marco,

Human Resources

Manager

D.

D. Miller, Projects

Supervisor

C. L. Howrey, Licensing Specialist

H.

N. Paduano,

Manager,

Licensing and Special

Programs

H. 0.

Pearce,

Maintenance

Manager

K.

W. Petersen,

Site Superintendent

T.

F. Plunkett,

President,

Nuclear Division

K. L. Remington,

System Performance

Supervisor

R.

E.

Rose,

Work Control

Manager

Rossi,

QA and Assessments

Supervisor

Skelley, Plant Engineering

Manager

Enclosure

2

35

R.

N. Steinke,

Chemistry Supervisor

E. A. Thompson,

Engineering

Manager

D. J.

Tomaszewski,

Systems

Engineering

Manager

J. Trejo, Health Physics

and Chemistry Supervisor

G. A. Warriner, Quality Surveillance

Super visor

J.

D.

Webby Plant Change Control Supervisor

R.

G. West, Operations

Manager

Other licensee

employees

contacted

included construction craftsmen,

engineers,

technicians,

operators,

mechanics,

and electricians.

Partial List of Opened,

Closed,

and Discussed

Items

~0ened

50-250/97-12-01

NCU

Failure to Test

AFW Pump (section Hl.3)

50-250.251/97-12-02

NCV

Inadequate

Sump Screen

Inspection

Procedure

(section

M8.1)

50-250/97-12-03

Failure to Meet the

AFW Initiation Logic

For'GFP

Trip (section 04.1)

t

50-250,251/97-12-04

Failure to follow 10 CFR 50.54(q)

requirement

that revision of the Radiological

Emergency

Plan

must not reduce its effectiveness

(Section

P3. 1)

Closed

50-250.251/96-04-01

50-250/97-12-01

50-250,251/97-12-02

50-250/97-12-03

LER 50-250,251/97-08 LER 50-250/97-09

50-250,251/97-05-01

IFI

Charging

Pump Response

During SI (section

E8.2)

NCV

'Failure to Test

AFW Pump (section H1.3)

NCV

Inadequate

Sump Screen

Inspection

Procedure

(section

M8. 1)

Failure to Meet the

AFW Initiation Logic For

SGFP Trip (section 04.1)

LER

ECCS Containment

Sump Screen

Issues

(section

H8.1)

LER

Failure to Meet the

AFW Initiation Logic For

SGFP Trip (section 04.1)

IFI

Exercise

Weakness

Enclosure

2

List of Inspection

Procedures

Used

36

IP 37551:

IP 40500:

IP 61726:

IP 62703:

IP 71707:

IP 71750:

IP 82701:

IP 90712:

IP 90713:

IP 92700:

IP 92902:

Onsite Engineering

Effectiveness of Licensee Controls in Identifying, Resolving,

and

Prevent

Problems

Surveillance

Observations

Maintenance

Observations

Plant Operation

Plant Support Activities

Operational

Status of the

EP Program

Inoffice Review of Written Reports

Review of Periodic Reports

Onsite Followup of Written Reports of Nonroutine Events at

Power

Reactor Facilities

Followup - Engineering

List of Acronyms and Abbreviations

AC

ADM

Emergency Operations Facility

a.m.

amp

ANPS

C(E)DE

CFR

cpm

cPs

CR

CS

CSR

CV

CVCS

DB/DBD

DC

Alternating Current

Administrative (Procedure)

Auxiliary Feedwater

Ante Meridiem

Ampere

ATWS Mitigation System Actuation Circuitry

Assistant

Nuclear Plant Supervisor

Annunciator

Response

Procedure

Anticipated Transient Without Scram

Balance of Plant

Component Cooling Water

Committed (Effective) Dose Equivalent

Code of Federal

Regulations

Counts

Per Minute

Counts

Per

Second

Condition Report

Containment

Spray

Cable Spreading

Room

Control,Valve

Chemical

Volume Control System

Design Basis

(Document)

Direct Current

Enclosure

2

DP

dpm

e.g.

EP2

oF

FL

FPL

gal

GL

GMI

GOP

gpm

HDP(T)

HHSI

HP

HPSS

IA

I8C

ICW

i.e.

IFBA

IFI

IST

JCO

JPN

KV

L

LCO

LCV

LER

LOCA

LOOP

LPDR

LT

ml 1 s

M&TE

MOV

MS(IV)

37

Differential Pressure

Disintegrations

Per Minute

Power

Reactor License

Division of Reactor Safety

Emergency

Core Cooling System

-Emergency Diesel Generator

For Example

Emergency Notification System

.

Emergency Operating

Procedure

Emergency

Preparedness

Emergency

Plan Implementing Procedure

Emergency

Planning

2one

Emergency

Response

Data Acquisition and Display System

Engineered

Safeguards

Feature

Degrees

Fahrenheit

Florida

Florida Power

and Light

gallons

Generic Letter

General

Maintenance

- I&C

General

Operating

Procedure

Gallons

Per Minute

Heater Drain Pump (Tank)

High Head Safety Injection

Health Physics

HP Shift Supervisor

Instrument Air

Instrumentation

and Control

Intake Cooling Water

That Is

Integral

Fuel Burnable Absorber

Inspector

Followup Item

Inservice Test

Justification for Continued Operation

Juno Project Nuclear (Nuclear

Engineering)

Kilovolt

Letter (licensing)

Limiting Condition for Operation

Level Control Valve

Licensee

Event Report

Loss-of-Coolant Accident

Loss of Off-Site Power

Local

PDR

Level Transmitter

mi1li

.001 inches

Measuring

and Test

Equipment

Motor-Operated

Valve

Main Steam Isolation (Valve)

Enclosure

2

HSR

HWe

No.

NRC

NWE

ODI-CO

ONOP

OP

OSEP

OTSC

PC/M

p.m.

PHT

PNSC

P00

PSA

psig(a)

PT

PTN

PWO

PWR

QA

QC

QI

RPBC

RCA

RCO

RCS

Rem/mRem

REA

38

Moisture Separator

Reheater

Megawatts Electric

Non-Cited Violation

Number

Notice of Violation

Nuclear Plant Operator

Nuclear Plant Supervisor

Net Positive Suction

8ead

Nuclear Regulatory

Commission

Office of Nuclear

Reactor Regulation

Nuclear Safety Speakout

Nuclear Watch Engineer

Operations

Department .Instructions

(Conduct of Operations)

Off-Normal Operating

Procedure

Out-of-Service

Operating

Procedure

Operational

Support Center

Off-Site Emergency

Procedure

Operations Surveillance

Procedure

On-the-Spot

Change

Personnel

Contamination

Event

Plant Change/Modification

Public Document

Room

Post Meridiem

Post-Maintenance

Test

Plant Nuclear Safety Committee

Plan of the Day/Plant Operating

Document

Probabi listic Safety Assessment

Pounds

Per Square

Inch Gauge

(Absolute)

Pressure

Transmitter

Project Turkey Nuclear

Plant

Work Order

Pressurized

Water Reactor

Quality Assurance

Quality Control

Quality Instruction

Radiological Protection

and Chemistry

Radiation Control Area

Reactor Control Operator

Reactor Coolant System

Roentgen

Equivalent Man/milli rem

Request for Engineering Assistance

Residual

Heat

Removal

Reactor Operator

Reactor Protective

System

Radiation

Work Permit

Refueling Water Storage

Tank

Steam Generator

Safety Injection

SG Feedwater

Pump

Enclosure

2

SNI

SNPO

TG

TS

TSAS

TSC

UFSAR

URI

V

VAC