ML17349A226

pump.

Unit 3

had

been

on line since

February 5,

1992.

The following evolutions

occurred

on this unit during

this assessment

period:

On February

29,

1992, at 9:20 a.m.,

power ascension

from 50 percent

'was

commenced.

On February 29,

1992, at 1:00 p.m., reactor

power reached.

87 percent,

and

reduced

power operations

at this power level

was

recommenced

in

order

to

extend

the unit run

time until the

beginning of the

August 24,

1992, refueling outage.

Unit 4

At the

beginning

of this reporting

period,

Unit 4

was

operating

at

100 percent

power

and

had

been

on line since

February 3,

1992.

The

following evolutions occurred

on this unit during this assessment

period:

On March 16,

1992, at 7:10 p.m.,

a load reduction to 50 percent

was

commenced

to facilitate the cleaning of the

4B north

and

4B south

waterboxes

and the

4A TPCW heat

exchanger.

(Refer to paragraph

7.g

for additional information.)

On March 16,

1992, at 9:00 p.m., Unit 4 reached

50 percent

power.

On March 17,

1992, at 6: 10 a.m.,

power ascension

was

commenced.

On

March 17,

1992,

at ll:25 a.m.,

Unit 4 reactor

power

reached

100 percent.

On March 25,

1992, at 3:25 p.m.,

a load reduction

was

commenced

due

to the identification of moisture

in the turbine generator

exciter

housing

causing

a

generator

field

brush

ground.

(Refer

to

paragraph 7.i for additional information.)

On March 25,

1992, at 5:50 p.m.,

the turbine generator

was taken off

line,

and the unit entered

Node 2.

On

March 26,

1992,

at

1:35 a.m.,

the

prerequisites

for entering

Mode

1 were completed,

and startup

was

commenced.

On

March 26,

1992,

at 5:55 a.m.,

the turbine generator

was

placed

back

on line.

On

March 26,

1992,

at

6:45 a.m.,

reactor

power

was

stable

at

30 percent

(chemistry hold).

C

On

March 26,

1992,

at

10: 15 a.m.,

Unit 4 received

a Train

8

safeguards

actuation

signal

and reactor trip during the performance

of

a routine surveillance

on the containment

racks.

(Refer to

paragraph 7.j for additional information.)

On March 27, 1992, at 7:40 p.m., reactor startup

was

commenced.

On

March 28,

1992, at

1:Ol a.m.,

the turbine generator

was

placed

back

on. line.

On

March 28,

1992,

at

12:40 p.m.,

reactor

power

was

stable

at

100 percent.

3.

Followup on Inspector

Followup Items

(92701)

Actions taken

by the licensee

on the item listed below was verified by the

inspectors,

(Closed)

URI 50-250,251/91-11-04

- Modification Made to Fire Water Supply

System

Without Prior

10 CFR 50.59

Safety Evaluation

and Without Proper

Work Process

Controls.

This

URI was .initiated following the discovery that Turkey Point fossil

construction

personnel

were accomplishing modifications to the shared fire

protection

system without adequate

coordination or controls.

The fire

protection

system is just

one of many shared

systems

between

the fossil

and nuclear units at Turkey Point.

Corrective actions consisted partly of

the following actions:

The

licensee

issued

Turkey

Point fossil

plant

administrative

procedure

FOP-ADMIN-013, Authorization of

Work Requests

on

Plant

Operating

Systems

Common to Turkey Point Fossil

and Nuclear Plants.

This

procedure

defines

the

process

for authorizing

work to

be

performed

on shared

systems,

A caution

note for design

changes

for the Turkey Point,fossil units

was

added

to- Power

Plant

Engineering

Department

(non-nuclear)

administrative

procedure

AP 3.8,

Engineering

Process

to Complete

a

Request for Engineering Assistance.

The

licensee

issued

nuclear

engineering

quality

instruction

JPN-gI

3. 1-9,

Shared

Fossil/Nuclear

Systems

(PTN only).

This

procedure

provides the requirements

for JPN review of proposed

Turkey

Point fossil

engineering

packages

on

systems

shared

between

the

nuclear

and fossil units.

A new administrative

procedure

O-ADM-216, Control of Work on Shared

Systems,

was

issued.

This

procedure

requires

the

NPS to notify

nuclear

engineering

of fossil

work requests

to

ensure

nuclear

engineering's

review of the work is complete

and that results

are

satisfactory.

PTN assumed all responsibilities

for maintenance

and operation of the

raw water system.

Nuclear engineering

up-.dated

affected

drawings with an information

statement

requiring'PS

authorization

prior to starting

work on

shared,

systems,

cross-tie

valves,

isolation valves,

and

the fire

protection

system.

Land utilization interfaces

were identified.

In the

above

noted

documents,

the licensee

identified shared

systems

and

cross-tie

connections

between

Turkey Point nuclear

and fossil units.

In addition,

as part of the industry concern

regarding

switchyard

events

and prior to the

1991

dual

unit outage,

the

licensee

had

issued

a

temporary

procedure controlling work activities

such that the

NPS

had to

be informed prior to performing work in the switchyard.

This concept

has

been

made

permanent

by

issuance

of

a

procedure

change

to

procedure

0-ADM-216 which requi res

NPS approval

(written or verbal

based

on the type

of

activity)

prior

to

approving

work

in

the

switchyard.

Procedure

0-ADM-216 is

now titled, Control of Work on Systems

Shared

by

Turkey Point Fossil

and

Turkey Point

Nuclear

Plants,

and

Switchyard

Access.

Other fossil

and nuclear interface

problems that have

been identified

are

as follows:

IR 50-250,251/91-46,

paragraph

10.c, identified that during one short

time period,

three of the eight offsite power lines

were lost and

noted

that there

were

no requirements

for maintaining

a

minimum

number of- offsite power lines.

In addition, at any given time, the

nuclear operators

are not aware of how many offsite power sources

are

available

since

the switchyard status

display is in the Unit

1 and

2

(fossil) control

room.

The number of offsite power sources

to the

Turkey Point switchyard is not currently controlled

by TSs or other

regulatory requirements;

however,

the

number of offsite power sources

at Turkey Point exceeds

that found at other facilities

and appears

to

be adequate.

VIO 50-250,251/91-39-01

identified Turkey Point Unit 3 and

4 transfer

'inhibit relays

that

were

not included

in any

PM program.

These

rel ays

were

under

the

control

of

the

Protecti on

Divisi on

(non-Nuclear) of FPL,

and the

PM/C that nuclear engineering

issued

to

utilize

a

spare

set of contacts

of an existing relay failed to

identify

the

need

to test

the

dropout

time.

A

procedure

(0-PMR-005. 10,

HGA 162/TDDO Relay Calibration)

was

issued

to check

the relay every refueling outage.

TS 6.8. 1 requires that written procedures

be established,

implemented,

and

maintained

covering

the facility fire protection

program.

equality

Instruction gI 3-PTN-1,

Design Control, dated

February

26,

1991, controls

all

plant

changes

and

modifications.

Paragraph

5. 1

of

equality

Instruction gI 3-PTN-1 requires that permanent

plant changes

be controlled

by design

packages

"originated by Nuclear Engineering

(JPN).

As noted in

URI 50-250,251/91-11-04,

the modification to the fire protection

system

piping was being accomplished

by

a fossil plant engineering

package that

was

not originated

by nuclear engineering

and

pen

and ink changes

were

made

to the working copy of the engineering

package

without required

review and approval.

The failure to follow procedure

gI 3-PTN-1 is

a violation.

This violation

'will not be subject to enforcement

action

because

the licensee's

efforts

'n identifying and correcting the violation meet the criteria specified in

Section

V.G. 1 of the

NRC Enforcement Policy.

This item will be tracked as-

NCV 50-250,251/92-07-01,

failure to follow procedures

for work on shared

systems.

This item is considered

to be closed.

Monthly Surveillance

Observations

(61726)

The inspectors

observed

TS required surveillance testing

and verified that

the test

procedures

conformed to the requirements

of the

TSs

testing

was

performed in accordance

with adequate

procedures;

test instrumentation

was

calibrated;

limiting conditions for operation

were met; test results

met

acceptance

criteria requirements

and were reviewed

by personnel

other than

the

individual directing

the test;

deficiencies

were identified,

as

appropriate,

and

were

properly

reviewed

and

resolved

by

management

personnel;

and

system restoration

was adequate.

For completed tests,

the

inspectors verified testing frequencies

were met and tests

were performed

by quali'fied individuals.

The

inspectors

witnessed/reviewed

portions

of the

following test

activities:

Section 7.3,

Returning

'Reactor

Trip .Breaker

A to

Service,

of

procedure

4-0P-049,

Reactor Trip Breaker Operation for Maintenance

(Refer to paragraph

7.d for additional information.)

and

Procedure

4-OSP-049. 1,

Reactor

Protection

System

Logic Test,

for

Train A (Refer to paragraph

.7.e for additional information.).

The inspectors

determined that the above testing activities were performed

in a satisfactory

manner

and

met the requirements

of the TSs.

Violations,

or deviations

were not identified.

(Refer to paragraphs

5

and 7.b for

information'egarding

a missed

post maintenance

test of a

CCW drain valve

and

a missed 'surveillance

on the automatic fuel

makeup valve to the

4B

EDG

day tank.)

.

Monthly Maintenance

Observations

(62703)

Station

maintenance

activities of safety-related

systems

and

components

were observed

and reviewed to ascertain

they were conducted

in accordance

with approved

procedures,

regulatory guides,

industry codes

and standards,

and in conformance with the TSs.

0

The following items

were considered

during this review,

as appropriate:

LCOs were

met while components

or systems

were

removed

from service;

approvals

were

obtained

prior to initiating work; activities

were

accomplished

using

approved

procedures

and were inspected

as applicable;

procedures

used

were

adequate

to control

the activity; troubleshooting

activities

were controlled

and repair records

accurately

reflected

the

maintenance

performed;

functional

testing

and/or

calibrations

were'erformed

prior to returning

components

or systems

to service;

gC records

were maintained;

activities

were

accomplished

by qualified personnel;

parts

and materials

used

were properly certified; radiological controls

were properly implemented;

gC hold points

were established

and observed

where

required;

fire prevention

controls

were

implemented;

outside

contractor

force activities

were controlled

in accordance

with the

approved

gA program;

and housekeeping

was actively pursued.

The inspectors

witnessed/reviewed

portions of the following maintenance

activities in progress:

swap out of the

4A reactor trip breaker

per

PWOs 5280/64

and 5284/84

and

procedure

0-PME-049. 1,

Reactor

Trip

and Trip Bypass

Breaker

Inspection

and

Maintenance

(Refer to paragraph

7.d for additional

information.);

replacement

of

a faulty reactor

protection

relay

(RT-6-A)

per

PWO 7138/64 (Refer to paragraph

7.e for additional information.);

and

re-termination of the

3B

ICW pump motor following replacement

due to

seal leak-off problems.

On

February

24,

1992,

during

a

gC

review of post

maintenance

work

activities,

the

licensee

discovered

that

post

maintenance

testing

performed

on valve 4-50-364

(a drain valve to the inlet waterbox of the

4B

CCW heat

exchanger)

was

not adequate

because

the work plan for the

replacement

of this quality-related

valve did not identify the guality

Group which designates

the work as

an

ASME Section

XI repair/replacement.

The

CCW heat

exchanger

associated

with this valve

(4B)

had

been

out of

service during the valve replacement

and

had

remained

so until the valve

was

tested

in

accordance

with

Section

XI

repair/replacement

requirements.

During

a subsequent

review (February

27,

1992) of similar valve repairs,

gC identified that post

maintenance

testing of valve 4-50-377

(a

4A

CCW

heat

exchanger

channel

head drain valve)

was also not in accordance

with

ASME Section

XI repair/replacement

requirements.

As with the incident

described

above,

the

work plan for the

repair/replacement

of this

quality-related

valve also

did not identify the guali ty Group which .

7

designates

the

work

as

an

ASME Section

XI repair/replacement.

In

addition, the work scope of this leak repair

was

changed

in the field from

valve repacking

to valve replacement,

and

the post

maintenance

testing

requirements

were

not revisited.

As

a result,

on October

18,

1991,

valve 4-50-377

was replaced,

but the post maintenance

testing prior to the

return of the

4A

CCW heat

exchanger

to service

was performed in accordance

with the maintenance

work package for the original work scope

(packi ng

replacement).

Therefore,

testing

in

accordance

with

TS 4.0.5,

Surveillance

Requirements

for Inservice Testing of ASME Code Class

1, 2,

and

3 Components,

was- not completed prior to the return of the

4A

CCW heat

exchanger

to service.

Successful

testing

of valve 4-50-377 at nominal

operating

pressure

and

temperature

in accordance

with procedure

0190.90,

ASME Section

XI Pressure

Tests for guality Group A, B,

and

C System/Components,

was

completed

on

February

27,

1992.

The event safety analysis

states

that* if there

had

been

a total failure of this valve in the

open

posi tion (The valve is

located

on

a 1-1/2 inch line.), the

4A CCW heat

exchanger

ICW flow would

have

remained

adequate

and

the

heat

exchanger

would still have

been

operable.

The licensee's

analysis

of the

missed

post

maintenance

testing. for

valves 4-50-364

and 4-50-377

concluded that the

PWOs which were generated

to replace

valve 4-50-364

and to repack

valve 4-50-377

were

planned

in

accordance

with procedure

O-ADM-701, Plant

Work Order Preparation.

The

PWO safety classification

and guality Group fields

on the

Nuclear

Job

Planning

System Total

Equipment

Data

Base identified these

valves with a

quality-related

classification

but did

not identify

a guality Group.

Procedure

0-ADN-701 does

not require guality Groups to be identified for

work that does

not meet the definition of repair or replacement

as stated

in

procedure

AP 0190.89,

ASME'ection XI

Repair/Replacement.

The

,requirements

of procedure

AP 0190.89

apply to

components

identified

as

guality Group A, B, or

C (Class

1, 2, or 3), but this was misinterpreted

by maintenance

personnel

to apply to safety-related

'components

only.

Because

these

valves

were classified

as quality related,

they

were

incorrectly

assu'med

not to meet the requirements

for guality Groups

A, B,

or C;

and therefore,

the

ISI requirements

of procedure

AP 0190.90,

Section

XI

Pressure

Tests

for

equality

Groups A,

B,

and

C

System/Components,

were not included

in the

work plan.

These,

valves

should

have

been identified

as guality

Group

C valves.

In addition,

because

the valves

in question

were not properly classified,. the

PWOs for

maintenance

on

these

valves

were

not

routed

to the

ISI

Group for

designation

of .ISI testing

requirements,

and the

PWOs did not include the

post

maintenance

testing

requirements

of

procedure

AP 0190.28,

Post

Maintenance

Testing.

Another contributing

cause

was

the failure to

revisit the post

maintenance

testing

requi rements

following a change

in

work scope.

Maintenance

personnel

have

been

trained

to verify the guality Group

designation

for

equipment

by

review

of

various

'ocumentation.

These

personnel

have also

been trained

on the

importance

of reviewing the

complete

package for -scope

changes

which could require

post maintenance

testing

changes.

In addition, quality control

personnel

have

reviewed all ready

to work

PWOs to ensure

that the guality Groups

specified

are correct.

equipment

were

also

reviewed

to ensure

correct specification

of the

guality Groups,

and the records

providing the guality Group of the valves

in question

and of similar valves

have

been revised to reflect the correct

status.

The licensee

also

plans to revise

the initial and continuing

training

program for this

work group

to reflect

the

information in

LER 50-251/92-003,

Component

Cooling Water Channel

Head Drain Valves Not

Post-Installation

Tested in Accordance with Technical Specification 4.0.5.

The

inspectors

will followup

on

any

additional

corrective

actions

regarding this issue.

TS 4.0.5 requires

that ISI of ASME Code

Class

1, 2,

and

3 components

and

IST of

Code

Class

1,

2,

and

3

pumps

and valves

be

performed in

accordance

with Section

XI of the

ASME Boiler and Pressure

Vessel

Code

and

applicable

Addenda

as required

by

10 CFR 50.55a(g),

except where specific

written

relief

has

been

granted

by

the

NRC

pursuant

to

10 CFR 50.55a(g)(6)(i).

Section

IWA-7530,

Preservice

Inspection,

of

ASME Section XI, Rules for Inservice

Inspection of Nuclear

Power Plant

Components

- Division 1, Article IWA-7000,

Replacements,

requires

that

prior to return to service,

a preservice

inspection

shall

be

made in

accordance

with Sections

IWB-2200,

IWC-2200,

IWD-2100,

IWE-2200,

or

IWF-2200 for the

component

or part replaced,

as applicable,

including the

joints that

connect

the

replaced

component

or part to the

system.

Table IWA-5210-1,

Reference

Paragraphs

for System

Pressure

Tests

and

Visual

Examinations

(VT-2)

Requirements,

of

Section XI,

Article IWA-5000,

System

Pressure

Tests,

requires

that tests for repairs

and

replacements

of

Code

Class

3 (guality Group C)

components

be

performed in accordance

with Section

IWA-5214, Repairs

and

Replacements.

Paragraph

(e) of Section

IWA-5214, Repairs

and Replacements,

states

that

if only disassembly

or reassembly

of mechanical joints are involved, then

a system

pressure

test in accordance

with paragraphs

(a), (b), or (c) of

Section

IWA-5211, Test Descriptions,

shall

be acceptable

in lieu of a

. system

hydrostatic

test

in

accordance

with

paragraph

(b)

of

Section

IWA-5214.

Paragraphs

(a), (b),

and (c) of Section

IWA-5211, Test

Descriptions,

respectively

refer to

a

system

leakage

test

conducted

following opening

and

reclosing

of

a

component

in the

system

after

pressurization

to normal

operating

pressure,

a

system

functional test

conducted

to verify operability in systems

(or components)

not required to

operate

during

normal

plant operation

while

under

system

operating

pressure,

and

a

system

inservice

test

conducted

to

perform

examination

VT-2 while the

system is in service

under operating

pressure.

Contrary

to

these

requirements,

following

replacement

of

a

quality-related,

guality Group C, channel

head drain valve (4-50-377)

on

the

4A CCW heat

exchanger

on October

18,

1991,

the licensee

failed to

complete testing

in accordance

with the surveillance

requirements

for ISI

of ASME Section

XI guality Group A, B, or

C

(Code

1, 2, or 3) compon'ents

prior to the return of the

4A CCW heat

exchanger

to service.

e

This missed

post maintenance

test constitutes

one example of a violation.

(Refer to paragraph

7.b for the

second

example of this violation.)

This

violation will not be subject to enforcement action because

the licensee's

efforts in identifying and correcting

the violation m'eet the criteria

specified in Section

V.G. 1 of the

NRC Enforcement Policy.

This item will

be tracked

as

NCV 50-250,251/92-07-02,

missed

post maintenance

test

on

a

CCW drain valve and missed surveillance

on the automatic fuel makeup valve

to the

4B

EDG day tank.

This item is considered

to be closed.

For those

maintenance

activities observed,

the inspectors

determined that

the activities were conducted

in a satisfactory

manner

and that the work

was

properly

performed

in accordance

with approved

maintenance

work

orders..

With the exception of the

NCV documented

above,

violations or

deviations

were not identified.

6.

Operational

Safety Verification (71707)

The inspectors

observed

control

room operations,

reviewed applicable logs,

conducted

discussions

with control

room operators,

observed

shift

turnovers,

and monitored

instrumentation.

The inspectors verified proper

valve/switch alignment of 'selected

emergency

systems,

verified maintenance

work orders

had

been

submitted

as required,

and verified followup and

prioritization of work was accomplished.

The inspectors

reviewed tagout

records,

verified compliance

with

TS LCOs,

and verified the return to

service of affected

components.

By. observation

and direct i nterviews,

verification was

made that the

physical

security

plan

was

being

implemented.

The

implementation

of

radiological

controls

and plant housekeeping/cleanliness

conditions

were

also observed.

Tours of the intake structure

and diesel, auxiliary, control,

and turbine

buildings

were

conducted

to observe

plant equipment conditions

including

potential fire hazards, fluid leaks,

and excessive

vibrations.

The

inspectors

walked

down

accessible

portions

of

the

following

safety-related

systems/structures

to verify proper valve/switch alignment:

t

g *

A and

B emergency diesel

generators,

control

room vertical panels

and safeguards

racks,

intake cooling water structure,

4160-volt buses

and 480-volt load

and motor control centers,

Unit 3 'and

4 feedwater platforms,

Unit 3 and

4 condensate

storage

tank area,

auxiliary feedwater

area,

,

10

Unit 3 and

4 main steam platforms,

and

auxiliary building.

The licensee

routinely performs

QA/QC audits/surveillances

of activities

required

under its

QA program

and

as

requested

by management.

To assess

the effectiveness

of these

licensee

audits,

the inspectors

examined

the

status,

scope,

and findings of the following audit reports:

Number of

Audit Number

~Findin

s

T

e of Audit

QAO-PTN-92-001

QAO-PTN-92-005

QAO-PTN-92-006

QAO-PTN-92-010

Plant Systems,

TSs 3/4.7. 1 through

3/4.7.5

Document Control

4

January

Performance

Monitoring

Audit

1

February

Performance

Monitoring

Audit

No additional

NRC followup actions will

be

taken

on

the

findings

referenced

above

because

they were identified by the licensee's

QA program

audits

and corrective actions

have either

been

completed or are currently

underway.

Plant management

has also

been

made

aware of these

issues.

On March

2 - 3,

1992,

the inspectors

performed

an audit of the licensee's

TSA program utilizing procedure

O-ADM-503, Control

and

Use of Temporary

System Alterations,

dated

January

21,

1992.

The operators

had

access

to

the correct

system

drawings either

by the set of control

room

PODs or by

the red-lined

drawings in the

TSA File in the control

room.

Three of the

fifteen

open

TSAs were walked

down.

The following discrepancies

were

noted:

The asterisk

in Enclosure

2, Safety Classification

Guidelines,

of

procedure

0-ADM-503 referred

the

reader

to the Q-List although

Section 1.9, Quality Assurance

Program,

of the

FSAR stated

that the

Plant Q-l ist was replaced with the Total Equipment Data

Base in 1990.

Paragraph

4.9 of procedure

0-ADM-503 referred to the placement

of the

Log of Operating

Diagrams

(Attachment 5) in front of the control

room

PODs to identify drawings affected

by TSAs, but it did not refer to

placement

of thi s log in front of the

POD book.

Although not

required

by the procedure,

this log was located

in front of the

POD

book in the

~

Paragraph

5,7.4.3

of procedure

0-ADM-503 requires

that control

room

and

TSC drawings

be

red lined to reflect

new plant configurations.

Attachment

3,

TSA Log-Tracking

Sheet,

of this

procedure

contains

columns for red lining and restoration

of control

room

PODs but did

not refer to red lining and restoration of TSC PODs.

Paragraph

5.7.4.3 of procedure

0-ADM-503 requires

that control

room

and

TSC drawings

be

red lined to reflect

new plant configurations,

11

and

paragraph

5.7.4.7

of this

procedure

requires

that

the

TSA

Log-Tracking

Sheet

(Attachment 3)

then

be

updated.

The following

discrepancies

were noted:

On March 2,

1992, the control

room copy of Attachment 5, Log of

Operating

Drawings

Affected

by

TSAs,

indicated

that

six

controlled

drawings

were affected

by eight

open

TSAs, but the

seventh

column

(Control

Room

PODs,

Red

Lined

Yes/No) of

Attachment 3,

TSA Log-Tracking Sheet,

did not indicate whether

or not affected control

room

PODs were red lined for the

15 open

TSAs.

Although the

Log of Operating

Drawings Affected by TSAs provided

a reference

to the

TSA,

and

th'e

TSA file packages

contained

red-lined drawings;

the actual

control

room and

PODs

had not

been

red lined.

(By March 3,

1992,

three of eight affected

control

room

PODs

and

one of eight affected

PODs

had

been

red lined,

and the remaining

PODs in the control

room and

in- the

POD

book

had

been

red

lined

by

March 4,

1992.

The

full-sized

PODs in the

TSC were red lined by March 9, 1992.)

During

a comparison

of the control

room

and

TSC Logs of Operating

Drawings

Affected

by

TSCs

on

March 3,

1992,

the

following

discrepancies

were noted:

TSA 3-89-21-2,

which affected

sheet

3 of drawing 5610-T-E-4530,

had

been restored

on January

23,

1992,

per the control

room log,

and

no restoration

date

was indicated

on the

TSC log.

The control

room log also indicated that

TSA 4-92-47-3,

which

affected

sheet

3 of drawing 5610-T-E-4505,

had

been

implemented

on February

23,

1992,

and restored

on February

25,

1992.

This

item had not been entered

on the

TSA log.

On

March 3,

1992,

the

Log of Operating

Drawings Affected

by TSAs

identified the

drawing coordinates

affected

by

TSA 4-90-13-19 for

POD 5610-T-E-4064,

sheet

2,

as A-8.

Coordinate

A-8 of the control

room and

TSC red-lined drawings referenced

TSA 3-87-13-50 in lieu of

TSA 4-90-13-19.

TSA 4-90-13-19

was referenced

at coordinates

B-4 and

C-3

on the control

room

POD;

and although

the red lines

on the

POD were similar, it did not. reference

the

TSA number (4-90-13-19).

On March 3,

1992, while the

Log of Operating

Drawings Affected by

TSAs indicated

that coordinates

B-2 through

B-9,

E-3,

and

E-5

on

POD 5610-T-E-4530,

sheet

2, were affected

by TSA 3-90-71-23;

the red

lines

on control

room POD.5610-T-E-4530,

sheet

2, indicated affected

coordinates

B-5 through

B-9, E-3,

and

E-5.

. The red lines

had not

been

completed.

During

a walkdown of TSA 3-87-13-50,

Installation of Diesel

Driven

Air Compressors

and After Cooler s to Provide

Instrument Air, on

March 2, 1992,

the following discrepancies

were noted:

12

Tag no. 2, Diesel Air Compressor T-2,'ated

September

23,

1987,

was incorrectly hung

on diesel air compressor T-l.

The tag

on diesel air compressor

T-2 (Diesel I.A. Compressor

T-2

dated

October 28,

1988)

was

not identified

as

being tag no.

2

although

paragraph

5.1.6 of procedure

0-ADM-503 states

that

TSA

Category

A and

B Valves, states

that the limiting value of full-stroke'ime of each

power

operated

valve

be

specified

by the

owner

and

that

the

full-stroke time is

the

time interval

from initiation of the

actuating

signal

to

the

end

of

the

actuating

cycle.

Paragraph

IMV-3413(b) states

that

the

stroke

time of all

power

operated

valves

be measured

to the nearest

second for stroke times of

10 seconds

or less

or to

10 percent of the specified limiting stroke

time for full.-stroke times

longer than

10 seconds

whenever

such

a

valve is

stroke

tested.

Appendix D,

Valve

Program

Table,

of

JNS-PTN-200,

Second

Ten Year Inservice

Inspection Interval Inservice

t

20

Testing

Program Test Programs for Pumps

5 Valves, identifies solenoid

valve SV-4-34348

as

a

Class

3 (guality Group C),

Category.

B type

valve.

Contrary

to .these

requirements,

on

March 2,

1992,

the

licensee

identified that

the

measurement

of the stroke

time for

valve SV-4-3434B in accordance

with the surveillance

requirements

for

ISI of ASME Section

XI guality Group A, B,

o'r

C (Code 1, 2, or 3)

components

was

not performed within the surveillance

period.

The

surveillance

was

due to

be

performed

on January

30,

1992, with a

grace period expiring on February 21,

1992.

This

missed

surveillance

constitutes

the

second

example

of

a

violation.

(Refer to paragraph

5 for the first example

of this

violation.)

This violation will not be subject to enforcement

action

because

the licensee's

efforts i n identifying and correcting

the

violation meet

the criteria specified

in Section

V.G. 1 of the

NRC

Enforcement

Policy.

This

item

will

be

tracked

as

NCV 50-250,251/92-07-02,

missed

post maintenance

test

on

a

CCW drain

valve

and missed surveillance

on the automatic fuel

makeup

valve to

the

4B

EDG day tank.

This item is considered

to be closed.

At 12:55 a.m.

on March 8,

1992,

the

4A CCW/ICW basket

strainer

was

taken

out of service for backwashing

per procedure

4-0P-019,

Intake

Cooling Water System,

and Unit 4 entered

a 72-hour

LCO under action

statement

c of TS 3.7.3.

At 1:35 a.m.,

the licensee identified that

the total

ICW flow through the

CCW heat

exchangers

was less

than the

minimum flow required for CCW heat exchanger

performance capabilities

(15,400

gpm)

as

required

by

procedure

4-OP-019.

As

a result,

TS 3.0.3

was entered for the heat

exchangers

not being

capable

of

removing design

basis

heat

loads

per

TS 4.7.2.a.

Backwashing of the

4A CCW/ICW basket strainer

was

commenced

at 1:45 a.m.

At 2:05 a.m.,

ICW flow through

the

CCW

heat

exchangers

was verified to

be

18,000

gpm,

and

TS 3.0.3

was exited.

The

4A CCW/ICW basket strainer

was returned to service at 2:06 a.m.

At 3:00 a.m., it was determined

that no

CCW heat exchangers

were out of service

and that

TS 3.0.3 did

not apply.

This was

based

on utilization of the most recent strainer

and

heat

exchanger

performance

curves

with

the

actual

flow

( 12,700 gpm),

actual

intake

temperature

(82.9 degrees

F),

and

most

conservative

tube

resistance

factor

(.001548)

at the

time of the

event.

OTSCs

incorporating

these

curves

into plant procedures

were

approved

by the

PNSC

on March 12,

1992.

At 9:48 a.m.

on March 10,

1992,

the

4A reactor trip bypass

breaker

was closed in order to facilitate the

swap out of the

4A reactor trip

breaker.

At this

time,

Unit 4

entered

TS 3.3. 1,

item

19 of

TS Table 3.3-1,

action

statement

8, which allows

one reactor trip

breaker to be bypassed

for up to

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing per

TS 4.3. 1. 1 provided

the other trip breaker

is operable.

While in

this 2-hour

LCO, the

4A reactor trip breaker

was

removed;

and prior

to installation of the

new breaker,

an inspection of the breaker

cabinet

was

performed.

During this

inspection,

the

latching

mechanism

which was tack welded to the left side rail of the breaker

21

cabinet

was

found to

be

bent forward.

The left side rail

and

associated

latching mechanism

were replaced,

and the original breaker

was re-installed

and tested

per Section 7.3, Returning

Reactor Trip

Breaker

A to Service,

of procedure

4-0P-049,

Reactor Trip Breaker

Operation for Maintenance.

The 2-hour

LCO was exited at 11:35 a.m.

when the 4A reactor trip bypass

breaker

was closed.

A similar event

occurred

a

few years

ago

on another

breaker.

Following the previous event, all of the reactor trip breakers

were

replaced.

Placards

were installed

on the cubicle doors explaining

the correct

method of racking

the

breakers

in

and out,

and

the

procedure

was

revised

to include steps

to check

the breaker rails.

The licensee

is currently in the

process

of generating

a Nuclear

Problem Report

(92-035) to document

the results, of its investigation

regarding this matter.

The investigation results

and

any long-term

corrective actions will be reviewed during future inspections.

At 12:59 p.m.

on March 10,

1992,

the

4A bypass

breaker

was re-closed

in order to re-attempt

the

swap out of the

4A reactor trip breaker.

At this time, Unit 4 re-entered

TS 3.3.1, item

19 of TS Table 3.3. 1,

action

statement

8, .which allows

one reactor trip breaker

to

be

bypassed

for up to

2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months for surveillance testing

per

TS 4.3.1. 1

provided the other trip breaker is operable.

While in this 2-hour

LCO, the

4A reactor trip breaker

was

swapped

out

and tested.

At

1:31 p.m.,

during the

performance of procedure

4-OSP-049. 1, Reactor

Protection

System

Logic Test,

RPS trai n

A relay RT-6 failed.

This

caused

the unit to enter

a 6-hour to hot standby

LCO per the

same

TS

and action

statement.

PWO 7138/64

was

generated,

and

the faulty

relay was

removed

and replaced.

The,RPS surveillance

was

resumed

and

completed

satisfactorily,

and

the

4A reactor

trip breaker

was

returned to service at 5:58 p.m.

The relay failure was

documented

in

the

RPS failure log book for trending purposes,

and the failed relay

was

sent

to Westinghouse

for analysis

to determine

the failure

mechanism.

Preliminary investigations

indicate

the

cause

to

be

a

problem in the pickup coil.

The failed relay

had

been successfully

tested

by the

same procedure

on February

12,

1992.

The licensee

is currently in the

process

of generating

a Nuclear

Problem Report

(92-'036) to document

the results of its investigation

regarding this matter

and is planning to update this report

when the

results

of . the

Westinghouse

investigation

are

received.

The

investigation

results

and

any long-term corrective

actions will be

reviewed during future inspections.

At 12:30 p.m.

on

March ll, 1992,

with the fossil units'tartup

transformer

out of service,

Unit

1 (fossi l) lost backfeed

from the

switchyard

while working

on

a field breaker.

This

in turn

de-energized

some

auxiliary

equipment for the blackstart

diesel

generators

including the

soak

back

pumps which keep the diesel oil

warm.

As

a result,'ll five blackstart

diesel

generators

were

t

~

22

declared

out of service.

The blackstart

diesel

generators

were

returned to service

two hours later.

At 7: 10 p.m.

on

March 16,

1992,

a

load

reduction

on Unit 4

was

commenced

in order to facilitate

the cleaning of the

4A TPCW heat

exchanger

and of the

4B north

and south waterboxes.

Unit 4 reached

the

50 percent

power level at 9:00 p.m.

on the

same

day.

Power

ascension

was

commenced

at

6: 10 a.m.

on

the following day,

and

100 percent reactor

power was re-attained

at ll;25 a.m.

During the performance

of procedure

3-PMI-072.5, Turbine First Stage

Pressure

Protection

Instrumentation

Set

IV

Channel

P-3-447,

on

March 19,

1992,

channel

IV

steam

flow

transmitter

test

switches

CT-3-475,

CT-3-485,

and

CT-3-495

were placed

in the test

position.

This action took the reactor protection

steam flow input

to the

steam

flow versus

flow mismatch

to zero.

At

6:30 p.m., the Unit 3

RCO notified an

ANPS that the steam flow versus

flow mismatch reactor protection bistables

were actuating

and clearing

as

the test

potentiometer

was

adjusted

to change

the

steam flow for comparison

to the

programmed

flow (FT-447)

as called

for by the test

procedure.

The

ANPS observed

that the

steam flow

indications for channel

IV were indicating zero

and instructed

the

ISC supervisor to terminate

the test

procedure

and to restore

the

protection

racks

to normal.

At this time,

the

IEC supervisor

informed the

ANPS that the testing

had

been

completed

and that rack

restoration

had 'already

been

commenced.

All channels

were verified

to be in the required state, all bistables

were returned

to normal,

and

an investigation

was

commenced.

It was determined that there

were

no procedural

violations; however,

a

procedural

deficiency

was

noted.

The test

procedure

did not

recognize

that placing the

channel

IV steam

flow transmitter test

switches

(CT-3-475,

CT-3-485,

and CT-3-495) in the test position not

only affected

the

RPS

inputs for the

steam

break protection

(steam

flow compared with first stage

turbine pressure)

circuitry but also

affected

the

RPS

inputs for the

steam flow versus

flow

mismatch circuitry.

As

a result,

the test

procedure

permitted the

channel

IV steam flow channel

to reactor protection to be taken out

of service without placing

the bistables

for the

steam flow versus

flow mismatch circuitry (478A2,

488A2,

and

498A2) in the

test position

as it had

done for the

steam line break protection

circuitry.

This in turn permitted

inputs to the reactor protection

logic for steam

flow versus

flow mismatch

as

compared to

low-low steam generator level.

With the

number of operable

channels

one less

than the total

number

of channels,

TS Table 3.3-1,

item 12,

action

statement

6,

permits

continued

power operation until performance

of the

next required

analog

channel

operational

test

provided that the inoperable

channel

is placed in the tripped condition within

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

A detailed review

of

ERDADS archival

data

by the

STA determined

that during the

day

23

shift from

1:11 p.m.

to

2:13 p.m.,

a

period of

62 minutes,

all

channel

IY steam flow protection channels

were out of service without

bistables

478A2,

488A2,

and

498A2

being

placed

in the

tripped

position.

Because

these

bistables

were not placed in the tripped

position within 60 minutes,

an entry into TS 3.0.3'as

required,

but

the

out of service

condition

was

not discovered

by the day-shift

operating

crew.

Therefore,

according to

ERDADS data,

TS 3.0.3 should

have

been

entered

at 2: 11 p.m.

and exited at 2: 13 p.m.

No load

reduction

had

been initiated.

The peak-shift crew made the necessary

notifications

per

procedure

AP 103. 12, Notification of Significant

Events to NRC.

TS Table 3.3. 1, item 12,

Steam

Generator

Water Level--Low Coincident

With Steam/Feedwater

Flow Mismatch,

which is applicable -while the

unit is in Modes

1 and 2, states

that the total

number of channels

is

2 steam generator

level

and

2 steam/feedwater

flow mismatch

channels

in each

s'team

generator.

With the

number of operable

channels

one

less

than the total

number of channels,

action statement

6 of this

TS

permits

continued

power operation

until

performance

of the

channel

operational

test provided that the inoperable

channel

is placed in the tripped condition within

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

TS 6;8. 1

requires

that written procedures

be established,

implemented,

and

maintained

covering

activities

recommended

in

Appendix

A of

Regulatory

Guide 1.33,

Revision 2,

February

1978.

Section B.b of

this

Appendix

recommends

implementing

procedures

for

each

surveillance

test,

inspection,

or 'calibration

required

by

TSs.

Section B.b( l)(l) of this

Appendix also

recommends

that specific

procedures

for surveillance tests,

inspections,

and calibrations

be

written

for

RPS

tests

and

calibrations.

Paragraph

1. 1

of

procedure

3-PMI-072.5,

Turbine

First

Stage

Pressure

Protection

Instrumentation

Set

IV Channel

P-3-447,

states

that this procedure

provides

the instructions,

steps,

and data

necessary

to ensure

proper

calibration

and functional testing of the protection instrumentation

set

IY associated

with turbi'ne first stage

pressure.

Paragraph

1. 1. 1

of this

procedure

states

that all associated

instruments/components

are

contained

in channels

P-3-447,

Turbine First Stage

Pressure;

F-3-475,

Steam

Generator

3A Steam

Flow; F-3-485,

Steam

Generator

3B

Steam

Flow; and F-3-495,

Steam

Generator

3C Steam

Flow.

Contrary to

these

requirements,

procedure

3-PMI-072.5

was

not

adequately

established

in that it did not recognize that placing the channel

IY

steam

flow transmitter

test

switches

(CT-3-475,

CT-3-485,

and

CT-3-495) in the test position'ot only affected

the

RPS inputs for

steam

break

protection

(steam

flow versus first stage

turbine

pressure)

circuitry but also affected

the

RPS inputs for steam flow

versus

mismatch.

As

a result,

the channel

IY steam flow

protection

channel

to reactor protection

w'as

taken

out of service

without placing

the bistables

for steam

flow versus