ML17348B345

employee

or if personnel

practices

resulted

in a

chilling effect vith regard to pursuing

a safety issue.

Some of

the allegations

involved discrimination in the form of threats,

coercion,

harassment,

and negative

evaluations for vhich the

US

Department of Labor is evaluating

the specific

case of employee

discrimination.

The

NRC vill monitor the

Department

of Labor

activities regarding this case for potential enforcement.

The team

did attempt to determine,

in the general

sense, if there

vas

an

atmosphere

vhich prohibited or discouraged

engineers

from pursuing

nuclear safety concerns.

In each of the thirteen allegations,

the

objective vas to determine if it vas:

SUBSTANTIATED

The allegation has substance

and is

considered for the most part true.

PARTIALLYSUBSTANTIATED -The allegation has some substance

and

"

is considered partially true.

NOT SUBSTANTIATED-

No

substance

could

be

found

to

support the allegation.

If the

allegation

vas either

substantiated

or partially

substantiated,

a determination of safety significance vas made.

Additionally, vith respect to the technical areas identified, the

team evaluated vhether there vas a condition adverse to safety by

inspecting

the

end

products

such

as

safety

evaluations,

plant

change

modification

packages,

and

setpoint

calculations

to

determine if they vere adequate.

A perfonnance-based

inspection

vhich includes inspecting the end products- should find sufficient

end products

vhich are

inadequate

in oxder to substantiate

or

partially substantiate

the allegation.

2.

~scc n:

ghe tean inspecticn activities

9.nc1uded, engineering

staff. intervievs and end product inspection at both the

PPL Juno

Beach Offices and at the Turkey Point Nuclear Plant.

The scope of

the inspection vas limited to the specifics of each allegation and,

if )ustified, expanded to a programmatic inspection.

3.

CONCZUSZON:

Inspection

of

the

thirteen

allegations

resulted in the following:

11

NOT SUBSTANTIATED

1

NOT INSPECTED

(EEOC iJURXSDZCTION)

1

PARTIALLY SUBSTANTIATED

The

following

allegation

was

determined

to

be

partially

substantiated:

ana

ement~s decision to

ost one

due to bud etin

or other

constraints

im ortant modifications such as the correction'f

the

Powe

ismatch

C rcuits

Each modification that was postponed during the dual-unit outage at

TPNP was determined to have no impact on plant safety.

There was no evidence

found to substantiate

the allegations of an

overall atmosphere of intimidation, threats,

coercion, harassment,

or negative evaluations to limit the pursuit of safety issues.

No

unresolved safety issues

were identified by the team.

ENPORcEMENT:

Within the

scope

of this

inspection

three

violations were identified.

)

50 250 g 251/9 1 45

0 1 )

Non-Ci ted

Violation

Failure

to

implement adequate

design integration

(paragraph 4).

Based

on the review of the licensee~s

design integration program,

the inspectors

determined that the licensee

had an adequate

program

for ensuring

that

applicable

information is available

to

FPL

engineers involved in performing design integration for appropriate

design activities.

The team concluded that, while there

was

an

'nstance

noted

where

design

integration

was

not

adequately

performed in accordance

with program requirements,

the instance

described

in

paragraph

4

did

not

constitute

a

programmatic

brecdrdown of the design integration process.

Consequently,

the

allegation that

design

integration

was

almost non-existent

and

fundamentally flawed was not be .substantiated.

50<<250,251/91-45-02,

Violation.

Failure to maintain design

control of the Eagle

21 system

(paragraph

13).

50-250,251/91-45-03,

Violation. Failure to use correct Delta

T Subzero for calculation of the Overtemperature

Delta T and

Overpower Delta T setpoints

(paragraph

13).

The

team

concluded that, while'here

are

two cited violations,

which

were

identified

and

described

in

paragraph

13,

these

violations did not constitute

a programmatic

breakdown in

design

and

configuration

control.

Consequently,

alleged>>grave

deficiencies<< in plant configuration were not substantiated.

Kl

'

~ ly

Instrument

Setpoint

Document

vhich

contains

all

setpoints,

including design

bases,

both safety

and non-safety

related,

is

considered

by the

HRC to be an important enhancement

and vill be

inspected at a future date.

50-250<251/91-i5-0i, Inspector Pollovup Item, Create

a single

Instrument

Setpoint

Document,

including

design

bases

(paragraph

10) .

RPLg as part of evaluating

a 10

CPR Part

2 1 report,

has completed

65 percent

and vas in the process

of performing

a study of 100

percent

of circuits

that

contain

devices

or vi.ring in

the

miscellaneous

relay racks.

So safety problems, vith respect

to

keeping

MRR annunciator.circui.t relays separate

from the'RPS pover

supply, have been identified to date.

The study is scheduled to be

completed by March 31, 1992.

NRC villreview the final results of

this study

50 250 )251/91

45 05) MRR annunciator circuit relays separation

from RPS pover supply (paragraph

12).

iv

TABLE OF CONTENTS

pacai

EXECUTIVE SUMMARYe ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 'o ~ ~ ~ ~ ~ ~ e ~ ~ ~ ~ ~ ~ ~ oi

TABLE OF

CONTENTS ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ e ~ ~ o

~ iV

ALLEGATIONS~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~. ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 1

ENGINEERS DISCOURAGED FROM PURSUING SAFETY CONCERNS ~ ~ ~ ~ ~

1

INTZMXDATED TO CHANGE VCT SETPOZNT CALCULATXONe~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 8

3 ~

PERFORMANCE EVALUATIONS PUNZTZVE %HEN SAFETY RAXSEDe ~ ~ ~ ~ ~ 11

4

DESIGN INTEGRATION HAS BECOME ALMOST NON EXISTENT

~ ~ ~ ~ ~

~ 12

5 ~

FAILURE TO COMPLY %ITH HUMAN FACTORS COMMITMENTS~ ~ ~ ~ ~ ~ ~ ~ ~ 17

6 ~

MODIFXCATIONS POSTPONED

DUE TO BUDGET/OTHER CONSTRAINTS

~ 25

7 ~

ETHNIC DISCRIMINATIONAGAINST CUBAN AMERICANS

~ ~ ~ ~ ~ ~ ~ ~ ~

~ 31

P

8 ~

EMPLOYEE PROTECTION FROM

DISCRXMINATIONe ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~

~ 32

9 ~

RELIABILITYOF OVERPRESSURE

MITIGATION SYSTEMe

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 37

10 'ELXABXLZTYOF EXISTING SETPOXNT

PROGRAMe

~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 42

11.

QUESTIONABLE ENGINEERING PRACTICES

~ ~ ~ ~

~ ~ ~ ~ ~ ~ ~ ~ ~

~ ~ ~

~

~ 46

12 'ISCELLANEOUS RELAY RACKS

(PART 21 NOTIFICATION)~ ~ ~ ~

~ ~ ~

46

13 ~

GRAVE DEFICXENCZES ZN PLANT CONFIGURATION

e ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 52

14 ~

EXIT MEETINGo ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 59

APPENDXX A

ABBREVIATIONS AND ACRONYMS

APPENDIX B

PROCEDURES

REVIEWED

APPENDIX.C - EXIT MEETXNG ATTENDANCE

LEGAT ON TEAM ZNSPECTXON RESULTS

1 ~

NGXNEERS

DXSCOURAGED PROM PURSUXNG SAFETY CONCERNS.

The statement of the concern

was as follows:

Mana ement

has

en a el in threats'oercive

behavior

arassment

ne ative

anl untruthful-

n

neerin

ersonnel

evaluatio

s

w thholdin of necessa

train n

and assi

e'nt

o

wor

unrelated to the en

neeris disci

ine while removin

a

si

ificant ass

ents

elated

'to his disci line to

discoura

e

en ineers

om the

ursuit of tasks

that

such

'en ineers

consider critical .to Nuclear

Safet

and

rudent

lant o eration.

DxscUssxoNs

The objective of this team inspection was to determine

'f

there

existed

any unsafe

engineering

practices

or operating

conditions or..if personnel practices resulted in a chilling effect

with'egard'o pursuing a safety issue.

This allegation involved

discrimination in the form of thr~ats,

coercion,

harassment,

and

negative

evaluations

for which the

US

Department

of Labor is

evaluating the specific case of employee discrimination.

The

NRC

willmonitor the Department of Labor activities regarding this case

for potential enforcement.

The team attempted to determine, in the

general

sense, if there

was

an

atmosphere

which prohibited

or

discouraged

engineers

from pursuing nuclear safety concerns.

The inspectors

conducted formal interviews of all of the following

non-supervisory

engineers

which were available at. the time of the

interviews:

RPL Juno Beach Engineering staff, the

TPNP Production

Engineering Group (PEG), and the Outside Services Management staff.

A total of 43 engineers

were interviewed to ascertain if engineers

were being prohibited or discouraged

from pursuing safety concerns.

The interviews were conducted in- the following manner in order to

foster open anl candid discussions:

two NRC inspectors

conducted

one-on-one

interviews concurrently in separate

and private rooms,

thirty minutes each, in the

same location each lay, luring normal

.working hours,

asking

each

the

same

set of cpxestions,

with no

suhsequent

followup discussions

during the team inspection.

The

questions

were focused to allow comparison

and correlation of the

interview results

and to prompt discussion

of facts which would

assist in determining the validity of the allegations.

Xn addition/

approximately

20

informal

interviews

were

conducted

of

the

engineering supervisory staff as part of the inspection into each

of the allegations.

On October

31,

the

team

leader

was notified that

an internal

memorandum

from the

FPL Law Department to the Director, Nuclear

2

Engineering,

d'ated October 25, 1991, had urged RPL emplayees ta not

Ciscuss

the matter of the legal praoeedings

betveen

RPL and the

alleger in the interest

of fai.mess

to both

si.des.

Another

memoran4um

dateC October 30,

1991, corrected the guidance of the

October

25

memorandum

by stating that non-supervisary

employees

shauld feel free to caoperite

and talk about their knovledge in the

subject

legal

proceedings if they

so

desired.

Supervisory

employees

vere

advised

that

they

should not

speak vith anyone,

making=a claim against

RPI.

The alleger raised the concern that

~

these

memoranda

may have caused

RPI emplayees ta not feel free to-

-di.scuss

any of the allegations

openly vith the

NRC.

The. team

evaluated

this

concern

and

concluded,

that

the

discussions

canducted vith over 60 engineers,

43 of vhom vere non-supervisoryf

vere open and candid." There vere some comments,

the sum of vhich,

in the

judgement

of the

team,

indicated

some

anxiety over the,

pending

RPL reorganiiati.on, but did not i.ndicate a lack of freedom

.to discuss

the concerns

addressed

in this report vi.th the NRC.

~.Additionally, vith respeot to the teohnical

areas identified, the

team evaluated vhether there vas

a conditian adverse to safety by

inspecting

the

end

praducts

such

as

safety

evaluations,

plant

'change

modification

packages,

and

setpoint

.calculati.ons

to

determine

'9.f

they

vere

adequate.

Xf intervievs

did

not

substantiate

that engineers

vere 4isoouraged

from pursuing safety

concerns,

then

a

performance-based

inspection,

vhich

i.ncludes

-inspecting the

end produots,

should find sufficient end'products

vhich

are

inadequate

i.n'rder

ta

substantiate

or partially

substantiate

the allegati.on.

l.a

The folloving amplification of the above concern vas provided:

Plant maintenance instructions affectin'PS

ESPAS ta

raceed

under certain restricted modes

Safet

evaluation JPN-91-0094

vas

revised

vithaut

subse

ent

reviev

b

the

alle er.

Violation af anon

others

I 3.2.

Westin house vas directed

ta kee

him isolated from

ra ect

PC Ms90-508

and 90-509

I

Discussion:

The RPL safety evaluati.on vhich allaved the pracedures

to be revised

and implemented

under certain restricted

modes

was

JPN-PTN-BEZEL-91-008.

The safety

evaluation

vas transmitted

to.

Turkey Paint site by letter JPN-91-0094.

The inspectors

revieved

the safety evaluation vhich allaved plant maintenance instructions

to be revised in accordance vith applicable marked-up versi.ons of

the procedures.

The maintenance instructions vere marked-up by the

NSSS

based

on

the

propose4

license

amendment

vhioh

had

been

previously

submi.tted to the

NRC.

The inspectors

also

revi.eved

quality instruction QI 3.2, Design and Bafety Analyses.

During revievs af the safety evaluation, selected plant mai.ntenance

instructions,

and

QZ 3.2, the inspectors

faund that the revisians

P

3'o

the

plant

maintenance

instructions

did

not

affect

the

conclusions of the safety evaluation.

Since the. safety evaluation

was not impacted by the xevised maintenance

instruotions,

QZ

3 2

was .not violated when the maintenance

instructions, were not sent

,'ack to the safety evaluation preparer prior.to implementation.

In

addi.tion,.

the

safety

evaluation=

4id

not

require 'hat'he

'aintenance

instructions

he

routed

back

through

the

safety

, evaluation preparer prior.t'o revision and implementation.

The inspectors

determined that the maintenance

i.nstructions

were

reviewed and approved at the Turkey Point si.te in accoxdance

wi.th

. plant administrative controls.

These controls included, hut were

not limited to, a safety review by the Technical Department; review

and approval by the responsible

system engineer,

as appropriates

review and approval

hy the

1

0

C Department

headt

and review and

approval by the Plant Nuclear Safety Committee.

The inspeotors reviewed selected maintenance instructions that were

revi.sed,

and verifi.ed that the technical

changes

inoluded in the

marked-up

instructions

were

incorporated

into -the

revised

,- maintenance instructions.

The inspectors also verified that other

selected

maintenance

instructions, 'hich

were

revised

=to

incorporate" the changes

from=the marked-up versions

submitted hy

~ the NSSS, vere reviewed and approved in accordance with applicable

TPNP administrative controls.

conclusion:

The inspectors

concluded that the revisions to .the

maintenance

instructions

did

not

violate

QX,. 3.2

nor

any

requirements of the safety evaluation.

1.h

The following amplification of the above concern vas provi4ed:

The alle er xeceived

a ne ative evaluation as a result of his

efforts

to

esolve

rohlems

w'ith

ressuriser

ressure

rotection transmitters.

His work was exhaustive

and met with

o

osition

conflict'nd

fxi.ction.

Transmitters

were

e laced.

PC

M

acka

es90-528 f 90-529

Discussion:

The

inspectors

determined

as

baokground

to

thi.s

concern

-( pressuriser

low pressure

transmitter replacement); that

the'ressurizer

Pressure

Low Safety Injection actuation function

was previously performed using a Rosemount

1153 Series'

pressure

transmitter.

The Rosemount transmitters

were i.nstalle4 in 19&3 and

1984

an4

replaced

obsolete

Fisher-Porter

transmitters.

The

setpoint for this instrument loop was provided hy the

NSSS vendor

as part of the original scope of supply.

4

As a result of the design basi.s reconstitution effort, the licensee

determined that certain plant setpoints

should he recalculated.

A

pragram vas undertaken ta recreate the bases far these setpoints in

accordanoe

vith currently accepted

methods,

standards.

an4,test

, information.

The

NSSS

vendar recalculated

the Reactor

Protectian

Syst'm

and

Engineered Safety Features Actuation System setpoints in accardance

with the previausly acoepted

Nestinghouse

>>Five Calumn>> Setpoint

Calculation

Methadolagy.

awhile

applying

.the

nev

setpoint

calculation

methodalogy

to the Pressurizer

Pressure

Lov Safety

Zngectian

instrument

loop,

the

MSSS

vendor identified'hat

available test information, such as the lack of harsh enviranment

qualification vhich resulted in greater response

uncertain.nties,.may'esult

in spurious Safety Zngeotion aotuations.

As a result,.the.

vendar reoommended that the 1153 Series

D transmitters

he replaced

with transmitters

which had lover dooumented errors under adverse

environmental conditions.

The licensee

investigated

scope 'of replacing

the

1153 series

D

transmitters vith Rosemount

1154 Series

H transmitters.

The vendor

.calculate4

setpoint

vas

conservative.

The published

Rosemount

errar specifications

provide tvo sets af passible

Environmental

Allowance terms depending

on the type of environment in which the

transmitteri were expected ta operate

(mild or harsh).

-Because the

~

transmitters vere vithin the scope of 10 CFR 50.49, Environmental

Qualification of Electrical Equipment,the

vendor concluded that

the mare restrictive

environmental

allowance

terms

(+4.54

Upper

Range Limit'

3.5%

span. for temperature

uncertainty

and

+6% for

radiation

uncertainty)

vere

applicable.

These

environmental

allowance terms correspon4 to the vorst case errors that Rosemount

experienced

during

Environmental

Qualification

testing

at

temp'eratures,

pressures

and

radiation

levels

(420

degrees

Fahrenheit,

85, psig an4

52 MegaRad),

each af vhich significantly

exceed the expected operating conditions at TPNP.

The

licensee~s

investigations

involved consideration

of using

.

realistic environmental allovance terms: +(0.75% Upper Range Limit

+

0.5%

span

per

100

.degrees

Fahrenheit)

for

temperature

uncertainty.

This

= investigatian

involved

quantifying

the

environmental

conditions during design basis

events at the time

Safety Zn)ecti.on actuation vas expected to occur.

Time to actuate

ranged from about

1 second for the maximum hypothetical'ipe break

to 'about 30,seconds for the 3 inch small'break analysis.

Since the

function of this trip was to protect the core 4esign temperature

limits,

no

abnormal. radiation

vas- expected

at Safety

Zngection

actuation.

The vendor provided preliminary infarmation on expected

containment

temperatures

that indicated

temperatures

vould not

noticeably

change in one

second

during the

maximum hypothetical

Design'asis

Event.

Data far tvo, three,

and six inch break sizes

indicated'hat

the

maximum

expected

temperature

increase

vas

appraximately

20 degrees

Fahrenheit for the first 30 seconds in a

three inch break loss, of caalant accident.

5

Preliminary

information

indicateC

that

the

time

to

actuate/

containment

temperature

evaluation

cauld

be used to )ustify the

lover environmental

allavance,term.

The setpoint aoceptahility

using this Xover envixonmental

allovance

term vas evaluated vith

respeot to hav it'oulC increase the prahahility .of spuriaus safety

injections and vas found to be acceptable.

The relative merits of replacing the

1153 Series

D transmitters

vith 1154 Series

H vere weighed- against continued use af the 1153

Series

D transmitters.

Tvo dominant factors led to the decision to

replace

the transmitters.

First, the vendor requested

that

dacument the time to actuate/containment

temperature evaluation and

provide specific direction on vhat values for transmitter error ta

use for the calculation.

Th'I vendor took this positian because

use

of the <<time to trip<< argument for a

10 CFR 50 49 component

vas

inconsistent

vith previous

voxk they

had

performed

on

other

projects.

Second,

Rosemount

had limited test data for temperatuxe

changes vithin the

range of interest

and cauld nat support

the

target

954-95% probability and confidence

level far use of the

lover environmental allovance term.

The licensee

.concluded that if the nev calculation methods

vere

applied to the existing setpoint

(1723 psi), that loop errors could

cause actuation to ooour belav the calibrated span (I'l00-2500 psi)

of the

pressurizer

pressure

transmitter.

The

basis

for the

existing

setpoint

vas

not

recoverable,

but'ppeared

to

be

consistent

vith the

level

of

knovledge

and

test

infarmation

available in the late

1960~s

vhen

the setpoint

vas originally

established.

The licensee did not consider it necessary to )ustify

the existing setpoints using oontemporary methodologies.

Hovever,

this particular setpoint did receive further evaluation because it

vas unique in that it vas close to the low end of the 'calibrated

range.

Based

on

the

channel

uncertainty

of

7.92%

or

63.4

psi,

the

actuation setpoint could potentially be reached

at

1723

63 F 4

1660 psi. This value is approximately

2% belov the calibrated span.

Since the comparator vas set to trip an a signal slightly above

4

Milliamp, it vas logical to conclude that

on falling pressure,

actuation vould occur vhether or not the process

vas autside

the

tcalibrated pressure

range.

An additianal error of

1% applied t

he channel unoertainty'orresponds

to 71.4 psi and an actuation

0

point. of 1652 psi.

Rosemount provided information vhich supported

the conclusion that actuation

vould occur hy this point.

The

licensee

concluded that this pxovided reasonable

assurance

that

Safety Zngection actuation vauld oocur before the assumed

1600 psi

safety analysis limit vould be reacheC.

Safety Injection vas 'also

'actuated

fxom the independent containment pressure instrument loops

praviding additional assurance af praper Engineered Safety Features

Actuation System aperation.

g

p

options in order to )ustify the high cost

associ.ated

with this

modi.fication.

The

19.censee

made

the

conservative

decision

to

replace

the transmitters.

The inspectors

ver9.f9.ed

information

provided

by the

licensee

and

ooncluded

that, vhile

an

unsafe

'ondi.ti.on did not ex9.st with the previous

Rosemount transmi.tters,.

the 19.censee

had taken a prudent course of action relative to the9.r

evaluation in order to provide'ransmitters

qualified for a more

harsh envixonment'and

more oonservative setpoints.:

Zt could not be

substantiated

that a negative evaluation resulted

from trying.=-to

solve

a problem with the previous

Rosemount transmitter.

During

the engineering staff intervievs, there vere no concerns identified

.

that pe'rformance

apprai.sais

vere adversely affected for pursuing

safety concerns.

'.c

The follovi.ng amplifi'cation of the above concern vas provided:

er enc

Res

onse

Data

Ac isit on

D s la

'

stem

ERDADS

Isolation

ro ect

modif cation 'as

dela ed

unti.l

a

demonstrati.on

vas

conducted

to

show

the existin

rohlem

im ro er electrical i.solati.on

with ERDADS.

'I

Discussion:

The

licensee

had

. experienced

problems

vith the

interfaoe of the BRDADS and the process loops in that certain loops

caused

the

control

room 'ndi.cators

to

read

inaccurately

vhen

connected vith the BRDADS.

Temporary System Altexat9.on

(TSA)

4-89-'5-20

and

4-89-95-'21

vere

incorporat'ed

vhi.ch

corrected

approximately

14

loops

by eleotrically relocating

the

control

modules in the instrument loops to minimize- the current loss

and

thereby 'reduce

the effect

on the control

xoom indicators.

Xt

should be noted that the control room indicators vere electrically

isolated from the control functions of the reactor control system

so that there vas never a problem vith the reactor control system.

NCR 89-0709 vas vritten as the result of these problems.

The inspectors

reviewed NCR 89-0709 vhich identified a problem with

excessive

loading at the high signal

end caused

by interference

from the

SPDS circuitry.

The

evaluation

vhich

the

li.censee

performed resulted in,.the installation of an i.solation system vhich

provided both digital and analog isolation from the process

loops

and

imposed

no

load

on

the

instrumentation

loops.

This

modificati.on also

removed

TSA 3-89-95-28

and -29 vhich had

been

i.ssued for tvelve non-isolated inputs to the

SPDS.

The isolation

system vas in place and operating'nd plant personnel

advised that

there have been

no difficulties experienced.

7

Conclusi.an:

There vas

same initial'esi.stance

to performing'this

, modifi.cation

until.

the

problem

vas

- understood.

.

Once

the

si.gnifi.cance- of -the effects

of the 'oor

BRDADB,isolation 'vas

, demanstrated

,ta

engineering,

'a

TSA

. vas

implemented

and

the

permanent modifi.catian vas .oampleted during-the 4ual unit autage.

There

vas

no indioation that harassment

vas

used to prevent ar

delay this project.

1.d

The follovi.ng amplificati.on of the above concern vas provi,ded:

acta

ate t on S stem

ineered Sa et

Features

ctuati.an

'

stem

m

ementat

an of set aint met adola

is .exam le of

Item 1.

Na

tten detai

s

rovi.ded.

Di.scussion:

The inspectors reviewed Westinghouse

%CAP-12201; Bases

.

,Document

for Westinghouse

Setpaint

Methodology for Protection

Systemsg

Revision

lg

and

WCAP, 12745@

Setpoint

Metho4olagy Por Protecti.on

Bystems - Turkey Point Units 3 and i-

Plorida

Pover

and Light Company,

Revision 0..

These

documents

pravi.ded the. basis for calculation of instrument'-uncertainty

and

setpoints for Reactor Protection System/Bngineered

Safety Features

Actuati.on Bystem.

The documents included acoeptable oalculatianal

methodology.

Westinghouse perfarmed the RPB/BSPAS calculations for

TPNP and daes these

same calculations for. most Westi.nghouse

design

plants.

Canclusion:

There were no pr'ablems noted 'vith these calculations

vhich vere inspected

and found to be acceptable.

PPL management

practi.ces

in

the

implementation

of

the

RPB/EBPAS

setpoint

methadolagy,

vhich vould 4iscourage

engineers

from the pursuit of

safety concerns,'as

not substantiated.

CONCLUSION.

LEGATION 1 - NOT'SUBSTANTIATED

'I

Open an4 candid discussions

vere conducte4 vith over 60 engi.neers,

i3 of vhom vere non-supervi.sory.

There vere some comments, the sum

of

which,

in

the

judgement

of

the

team,

did

not

indicate

management>s

engaging

in

threats, 'aeroion,

harassment,

or

intimidatian.

The inspectors

concluded that this allegation

was'ot

substantiated

because

evidenoe

vas not found that engineers

were prohibited

or discouraged

from pursuing

safety

concerns..

Additionally, the evaluated

end products (i.e. safety evaluati.ons,

PC/Ms,

and setpoi.nt calculations)

vere determined to be adequate.

2 ~

8

I ID TED

0 CHANGE VCT SETPOINT CALCULATION

~ t

The statement ai the cancern

was as follows:

L Mana ement have attem ted ta i.ntimidate

e i.nta chan in

the

conclusions

af

an

En ineeri.n

Calcu ati.on

re ardin

et pints

and

Uncertainties

- RJ -91-005

far

Volume

Control

ank

T ansmitter

Re laoement

Packa

e

PC MIs91-037

and

9 -038.

.

PPZ

ntimidatian

to

chan

e

conc1usi.ans

of

en ineer n

calcu ation.

Assum tions

chan

ed to

su

art

desired conclusions.

Adverse effect an

e

armanoe

a

raisal.

Threatenin

an en ineer'ta alter the content ar results af a

cal'oulatian.

1 in

re risals for fa

ure ta

com

1

DISCUSSION

The inspectors

di.scussed the methods the lioensee used

to resalve

di.fferences

when independent

calculati.ons

arrived at

'disparate results.

The li.censee

desoribed their approach to the

, resolution af techni.cal differences that occur during the setpoint

verifi.cation or review prooess

as follows:

Obtaining

different

final

results,- when

performing

two

indepen4ent

and technically correct

analyses

is

a

common

occurrence

when. determining 'nstrument

setpoi.nts.

Various

available

methods

for generating

instrument

setpoi.nts

is

generally the raot cause af differing results.

'

Typically, the difference occurs when the prepared calculation

i.s

undergoing

the

independent

verification process.

The

method

judged

apprapriate

by

the

preparing

engineer

to

determine or combine the speci.fi.c instrument uncertainti.es ar

determine

the

fi.nal naminal

setpoint

may differ from the

methods

judged to be applicable by the verifying engineer.

Due to

the

strai.ght

forward nature

of

and

i.ndustry

setpoint

guidance

along with the availability of in-house

setpoint

experti.se, it i.s the very rare

i.nstance

when the

differi.ng methods cannot be resolved into a oaloulation which

is technioally acceptable

to'both the preparer

and veri.fi.er.

The vast majority of differences are resolved wi.thaut the need

. for a technical

management

deci. sian.

The inspectars

independently

reviewed the licensee!s .methodology

for the resolution of disparate setpoint calculation. resolution and

concurred that the lioensee

demonstrated

an understanding

of the

causes of most setpoint calculati.anal discrepancies

and that their

methodolagy far resolving these discrepancies

was adequate..

Chemical

and Volume Control System Calculations:

The inspectors

revi.ewed the PPL Engi.neexing calculatian PTN-BPJZ-91-005 which was

performed

to support

PC/M No.91-037

and

91-038,

regarding

the

replacement

of the

VCT level cantrol

and

alarm

swi.tches

with

9

electronic txansmitters.

The modification involved the removal of

the level switches used for alarm and cantrol and the installatian

af tvo 4ifferential pressure transmitters, instrument manifolds and

sensing lines in the area of the VCT.

The corresponding instrument

loops cantained the necessary

pracess

rack mounted instrumentation

to perform the cantrol and indication functions.

Only one af the

loops provides

an alarm functian.

The VCT lovel transmitters

axe

not required for the

CVcS to perform its active safety functians

.

related to reactivity contrail consequently,

they are not safety

The

calculation

contained

apprapriate

assumptions

vhich

vere

in

line

vith

standard

acceptable

methodology.

The methodology use4 for the calculations

vas

an adaptatian,

for

non-protective setpoints,

of the guidelines

and structures listed

helav:

Plant Bngineering Group fPBG), Training Manual on Turkey Point

Setpoint Methodologyp Revisian 0, 4ated February

1991

%CAP

12201,

Bases

Dacument

for

%estinghouse

Setpoint

Methodology for Protection

Systems

'

%CAP 127i5, %estinghouse

Setpoint Methodology For Protectian

Systems - Turkey Point Units 3 and 4 - Florida Power and Light

Company

The revised. engineering

VCT calculation vas performed in accoxdance

vith

the

applicable

portions

of

%CAP-12201

and

%CAP

127i5

methodology,

vith modifications

for non-safety

related,

non-

protection system,

control functions.

Calculation No. PTN-BFJI-91-005, Setpoint Calculation for VCT Level

Transmitters

Loop, Revision

0 vhich vas approve4

May 21@

1991@

was

revieved

to

determine

the

origin

and

acceptability

af

the

assumptions

used in the calculations.

Installation dravings vexe

reviewed to verify the location of the VCT instrument taps

as they

relate to the instrument calibration span and the instrument range

selection.

The

calculation

.considered

the

various

process

measurement

uncertainties

such

as

the variation of the fluid

specific gravity due to boron concentration,

transmitter

ambient

temperature effect, rack ambient temperature

effect@ sensor errors,

calibration accuracy

and drift, and sensor

measuxement

and test

equipment accuracies.

The alleger vas asked ta perform calculatians, in support af a PC/M

which

replace4

the

existing

transmitters

vith

more

accurate

been

transmittexs,

consequently

hardvare modifications should n t h

required

(i.e.

transmitter

relocation).

A disagreement

occurred over the calculation xesults, vhile at, the

same time'he

calculatian

vas

becoming critical path far the

VCT transmitter

replacement

PC/M.

%hen

agreement

coul4

not

be

reached,

the

1.0

supervisor

removed the alleger from the project and performed the

calculation.

Since both calculations used the same standard setpoint methodology

discussed

above,

and

there

vere

many

differences

in

both

calculations

(other

than

assumptions)~

it

could

not

be

substantiated

that the supervisor'copied

the alleger~s calculation

and changed the assumptions

to get the desired results.

The PPL 'final VCT calculation resulted in a change to a setpoint

which vas required to remove the possibility of demand for both

letdown and makeup at the same time.

This setpoint change

vas. not

identified in the alleger~s calculation.

The inspectors

independently revieved the allegerIs draft and the

PPL final calculations for the

VCT level transmitter loop.

The

inspectors

concurred

with

the

calculation

results

that

indicated

a

change in the control setpoint in question

vas not

necessary.

The'lleger~s

calculation

contained

unnecessary

. conservati.sms.

The safety related portions of the calculation were

not in question

and yielded the same results in both calculations.

The only sijnificant problem that vas identified in either of the

calculations

vas

identifiid in- the

managerIs

verified

calculation.

As a result-of this calculation there vas a change in

VCT LC-112A setpoint from 374 to 40%.

This change vas to prevent

overlap

betveen

the vorst

case drift for the

makeup

and

the

letdown.

Kith the vorst

case drift there

could

have

been

a

simultaneous

demand for both VCT makeup and letdown.

The setpoint

has been

changed

and this potential problem has been corrected.

The approved calculation vas found to be technically adequate

in

that the setpoints values vere consistent vith the proper operation

of the

CVC8

as

described

in technical

system

descriptions

and

licensing documents.

The inspectors

reviewed the current setpoints

for the

VCT and determined that the operating setpoints

and the

safety-related

setpoints

vere

appropriate.

No other

setpoint

discrepancies

vere identified.

The

issued

calculation

vas

correct

and

the

assumptions

vere

accurate.

Bvidence vas not found to substantiate

that any portion

of the final calculation had been falsified.

Therefore, it could

not

be

substantiated

that

the

superv9.sor

vas

attempting

to

intimidate

the alleger to

change

or falsify the

VCT setpoint

calculation.

PPL had a consultant reviev the PPL approved

VCT calculation and it

vas found to be acceptable.

CONCLUSIONt

LEQAT ON 2

NOT

SUBSTANTIATED'he

RPL.approved

VCT calculation vas determined to he

adequate.'he

inspectors

concurred with the

RPL 'calculati.on results

that

indicated

a change in the control setpoint in question

vas not

necessary.

The

alleger~s

calculation

contained

unnecessary

conservatisms

for non-safety related applications.

The RPL final

VCT calculation resulted in a change to another setpoint vhich vas

required to remove the possibility of demand for both letdown and

makeup at the

same time.

This setpoint

change vas not identified

in the alleger~s calculation.

The safety related portions of the

calculation vexe not

9.n cyxestion and yielded the

same results in

both

calculations.

The

issued

VCT

setpoint 'ocuments

are

conservative

and demonstrate

an appropriate

safety perspective.

Evidence

vas not found to substantiate

that

any portion of the

final calculation had been falsified.

Therefore, it could not be

substantiated

that the supervisor was attempting to intimidate the

alleger to change or falsify the VCT setpoint calculation.

3 ~

PERFORMANCE EVALUATIONS PUNITIVE %HEN SAFETY CONCERNS

RAISED'he

statement of the concern vas as follows:

Performance

evaluations

of

en ineers

tasked

with nuclear

safet

. have

been

done

exclusivel

a ainst

criteria of hud etin

and schedulin

with unitive actions for

concern

h

the

en Sneer with technical

and safet

im act of

,work and

ro ects.

DIsc088IoN:

Most non-supervisory

engineers

interviewed stated

that their performance is based

upon six different criteria of

vhich budgeting

and

scheduling

are

a part.

The six factors

evaluated

are:

1o

TECHNICAL/JOB KNOWLEDGE

2 ~ INITIATIVE

3 ~ JUDGEMENT/PROBLEM ANALYSZS

4 ~

ORGANZSATZON/PLANNING

5 ~ DEPENDABILITY

6 ~

COOPERATION

While gxeater

emphasis is placed

on budget,

and schedule

vho axe assigned to the

OSM group,

the interviews of 43 engineers

did not indicate

an inappropriate

emphasis

on budget

and schedule

considerations.

The candid comments, while supporting that there is variation among

supervisors with respect to their emphasis

on budget

and schedule

related criteria, did not.support that these factors vere used in

a punitive manner to suppress

safety concerns.

12

LEGATION 3

NOT SUBST

IATBD

N

This allegation was not substantiated in that budget and scheduling

are neither the exclusive criteria nor the overriding factors used

on performance appraisals.

ESIQN INTBQRA ION

ECOME ALMOST NON BXISTENT.

The statement of the concern

was as follows:

esi

inte ration has

become

almost

o -existent with the

estructurin

o

e

ee in

e a

ent.

No v lid means

exists to make co

isant en ineers aware of modifications that

af ect thei

work

esi

nte ration is fundamentall

flawed.

The following amplification of the above concern was provided:

eview of

PL res

onse to NRC 'stions of 6

6

9

on Technical

8 ecification

submittals

L-90-417

and

-91-098

concernia

Reactor Protection

S stem

En ineered Safet

Features Actuation

8 stem"set oint Tech 8 ec:

Licensin

en ineers acknowled

e at

CNRB meetin

of 6 28 91 the

are un

alified to res

ond to NRC

esti'ons'ilure

to

review

res

onse

w knowled cable

en ineers

within the

de artment

assi

ed to Westin house

res onsibilit

o

res

onse assurin

NRC of RPL confidence in

Westin house

work

and

on a

revious occasion

Westin house

res

onse

L-91-098

to a set of NRC

estions while in midst

of

review si

ature

rocess

but after

review

from

licensin

were

rou ht to alle er b

a co-worker who-noticed

several=errors.

DISCUSSION:

Design Integration ensures

that the cognisant

design

organi.sation is able to identify activities which may affect (or be

affected

by) other current

design activities.

The licensee

has

implemented procedure

QX F 1 7g Design Integration, which provides

recpirements

for design

integration 'ctivities using

available

design

integration

tools.

The

procedure

applies

to

design

integration activities performed by JPN and its contractors,

as the

activities relate to the preparation of all design outputs

and the

control of in-process

design.

Design integration tools included

the following:

DCTS is a database

which lists drawings affected

by issued

PC/Ms,

CRNs,

and

DCRs.

The

DCTS will also list anticipated

affected drawings for in-process

engineering

packages.

PC/M Index lists all

PC/Ms for which

a

number

has

been

assigned.

Additional PC/M related information is typically

included

in the

index

such

as

PC/M title,

description,

13

affected

systems,

etc.

This index allows identification of

PC/Ms potentially affecting the same

system or component.

Calculation Index lists JPN and contractor calculations.

This

index allows the identification of related calculations which

may provide the basis or change the basis for a design.

This

information has not been fully input into the data base.

Engineering

Evaluation

Index lists

JPN

and

contractor

engineering

evaluations.

The

engineering

evaluations

are

still being maintained manually until they all have been input

into the data base.

The inspectors

noted, that procedure

QI 3.1-7 was first issued in

May 1991.

During discussions

with licensee

personnel, it was

stated that various design integration tools have been avai.lable to

JPN personnel for a number of years.

The requirements

fax design

integration were previously addressed in other QIs such as

QX 3.1,

Design

Control

. and

QI

3.1-3,

Engineering

Package.

The

Configuration Management Manager is responsible for maintaining the

design integration tools.

The 'nspec'tors

reviewed.

selected

PC/Ms

- and

verified

that

appropriate

design integration tools had been reviewed for each of

the

PC/Ms

and evidence of the review was

documented within each

PC/M package.

In addition to reviewing the PC/Ms, the inspectors

held discussions

with JPN personnel

involved in PC/M development

who demonstrated

how the

PC/M index

and the

DCTS are

used for

design integration.

During further

review of the

design

integration

process,

the

inspectors

noted that it was not clear (from reviewing the selected

PC/Ms

or- the

QIs) at

what point in the

development

of design

outputs

should design integration

be performed.

The inspectors

discussed

this item with JPN personnel

who stated that there

had

been a recent instance where the design integration process

had not

been properly implemented.

The instance

where design integration

was not adequately

performed involved the licensee~s

PZk submittal

for the RPS/ESP& setpoints

and the issuance

of PC/Ms90-508

and

90-509,

Implementation of Setpoint Methodology.

The instance of

inadequate

design

integration

was

identified

by

the

licensee

following receipt of an NRC letter dated June 6, 1991, which was a

RAX concerning the

RPS setpoints.

The licensee

documented

these-

discrepancies

in problem report

JB 91 06 p

Errors in Technical

Specification Submittal to NRC on RPS/ESPAS Setpoint Methodologyp

dated September

10,

1991.

The NRC asked if the assumptions

and inputs used in developing the

setpoint study had been reverified.

While preparing PPL~s response

to the

RAI,

JPN

determined

that neither

PPL nor Nestinghouse

reverified

the validity of

the

original

inputs

used

in

the

performance of the setpoint calculations.

During reverification of

the inputs,

%estinghouse

found. that the setpoint inputs for tvo

functions

(Containment

Pressure-'High

and High-High)

had

changed

from those originally used in the 1988 setpoint calculations.

The

changes

vere

caused

by 'the

implementation

of tvo

DEEPs

vhich

replace4 the existing containment pressure

switches vith svitches

.having a 4ifferent span.

The span

changes

resulted in changes to

the

Technical

Specifications

allovable

values'or

the

tvo

functions.

The actual setpoint did not change.

During further

review of the

design

integration

process,

the

licensee determined that the NSSS vendor failed to provide adequate

design integration prior to implementation of the setpoint

PC/Ms90-508 and 90-509.

JPN and Westinghouse

reaccomplished

the entire

design, integration process

for the

PC/Ms.,

As a result of that

effort, tvo 'additional functions

used

as. inputs to the original

submittal vere determined to be incorrect..'One

input involved a

typographical error in the instrument

index and the calibration

procedure

(used as original inputs) resulted in an incorrect model

number

being

used for the turbine trip auto

stop oil pressure.

switch.

This resulted in an incorrect span for the device being

used

in: the original input.

The other input involved

a

DEEP

performed .iq. 1989

=which

changed

out the'eactor

coolant

pump

=

underfreque'noy* relays vith a model having a span different from

that originally assumed in the setpoint metho4ology.

The licensee

documented

these errors in their response

to the RAZ dated July 8,

1991 ~

The licensee

evaluated all of these

additional

changes

to the

Technical Specifications

and determined that the changes

did not

affect the

>>no significant hazards

consideration>>

determination.

The licensee~s

evaluation results vere confirmed by the NRC via an

SER,dated

August 26, 1991, vhich accompanied

the approved license

amendments

and Technical Specification changes.

The inspectors

informed the licensee that

QZ 3 ~ 1p

QZ 3 ~ 1-3~ and

QZ

3.1-7 require design integration for all design

outputs

and the

control of in-process

4esign.

Contrary to the above,

inadequate

design

integration

was

performed-

for

the

PIA submittal

for

RPS/ESPAS

setpoints

and

PC/Ms .90-508

and

90-509.

The

design

integration

reviews

failed to 'dentify that

three

DEEPs

were

implemented

vhich affected

the

inputs

used

in performing

the

setpoint calculations.

This failure to follov procedure is not being cited as a violation,

because

the criteria specified in Section V 6.1 of the Enforcement

Policy vere satisfied.

This

item vill be tracked

as

NCV 50-

250,251/91-i5-01,

Pailure to Perform Adequate

Design Integration

During Implementation of RPS/ESPAS Setpoint Methodology.

This item

is considered

closed.,

During further discussions

of this item vith licensee

personnel,

the inspectors revieved Problem Report JB-. 91-06 vhich described the

25

cause far the errors

i.n the Technical Specification submitta1 to

the NRC.

The problem report also pravi4ed coxrectiv'e actions which

should'e4uce

the probability 'af the design integrati.on= problems

reoccuriing.

These actions include4 the follaving:

Design

integration

training

@as

provided

to

appli.cable

%estinghouse

personnel.

The inputs vere reverified by a joint team of westinghouse

and

JPN engineers.

Addi.tional written gui.dance

+as provi.ded to applicable

JPN

personnel

on the level of discipline review necessary

for

contracted work.

A Technical Alert was issued August 16, 1991

on this subject.

In addition'g QI 3 '2@

NRC Submittals,

and QI

6.7,

Engineering Evaluations,

have

been .revi.sedto

require

more

revt.ev and/or

approval

by the applicable

disciplines

vithi.n JPN.

Input contrals are being established

by develaping a matrix on

the .bases

for the inputs to the setpaint

methadology,

and

i.ncorp'arating this informatian in the Westinghouse

setpaint

'calculatian.

Thi.s matrix i.s scheduled ta be completed by the

end of 1991.

V

Duri.ng review of the concern

about licensing engineers

not being

qualified to respond ta

NRC questions,

the inspectors

faund that

, the licensing engineer i.s nat required ta be the qualified reviewer

for technical

adequacy

for

NRC

RAI

and

submittals.

Nuclear

Licensing provides the administrative control of NRC submittals.

QI 3.11,

NRC Submittals,

states'hat

the

engineering

project

managers

are responsible for approving

NRC submittals relating to

nucleir engineeri.ng,

assigning

the lead discipline, coordi.nating

schedules

and responses,

an4 tracking or completing action items

associate4

with NRC submittals.

%hile it is true that a li.censing

engineer did acknowledge at the CNRB meeting of June 28,,2992@ that

he i.s unquali.fie4 to respond to

NRC questions,

QI 3.11

does not,

.requi.re that level of knowledge.

The=- OSM project engineer is responsible for determining the level

of

revt.ev.

Although

the

responses

vere

not,

reviewed

by

knowledgeable

engi.neexs within JPN, the responses

vere reviewed by

a knavledgeable,IfC engineer at the TPNP,

@ham the alleger referred

to 's

being

<<...highly

respected

both

far

his

'echni.cal/Prafessi.onal

abiliti.es and Ethical qualities....<<

As a result of erxors found in the

PLA submittal to the

NRC

(PPZ

letter L-90-417 dated December 19, 2990), the li.censee

has revised

applicable procedures

requi.ring JPN interdiscipline review of all

NRC,submi.ttals.

16

vas

contracted

to

provide

the

PLA

and

safety

evaluation far the

RPS setpoint

changes.

The li.censee

assigned

desi.gn

authority,

and

design

integratian

responsibility

to

Westinghouse.

The NRC asked, in their RAZ dated June 6, 1991, for

assurances

that the inputs used to develop the nev values 'in the

December

1990 Technical Specification submittal

(PPL letter L-90-

417)

vere still valid.

. asked

to

pravide

assurances

(such as vhether the design inputs vere reverifi.ed pri.or

ta submittal af the

PLA) of, Westinghouse~s

confidence in the

PLA

and

SER.

As

di.scussed

previously in this

inspectian

report

(paragraph

2), neither

PPL nor Westinghouse

had reverified the

validity of the inputs prior to submittal of the

PLA.

- PPL and

Westinghouse )ointly reverifi.ed the inputs

and found the errors

that vere documented in RPL~s July 8,

1991

(PPL letter L-91-186)

response

to the RAI.

The

inspectors

considered

that,

while

retains

ultimate

responsibility for the accuracy of information provided ta the NRC,

PPL took appropriate actians in requesting Westinghouse to provide

assistance

in responding

to the

NRC RAI since

had

design responsibility for developi.ng the PLA submittal.

Westinghouae initially transmitted the response

(L-91-098) to the

RAI vi.a facsimile to the licensing

engi.neer at the

TPNP.

This

transmittal did not have errars in the equation.

Westinghouse also

transmitted the

same informatian to TPNP via computer

modem.

The

information that had been transmitted to TPNP vas placed in normal

reviev cycle.

This reviev consisted of a technical reviev hy the

various departments prior to reviev and approval hy the PNSC.

The

revi.ev performed by plant licensi.ng personnel is not a revi.ev for

technical adequacy.

The inspectors

discussed this item vi.th

plant'icensing

personnel

vho stated 'that concurrent vith the technical

revi.ev,

licensing

personnel

revieved

the facsimile transmittal

against

the

modem transmittal

and identifi.ed the

exponent

and

square raot errors in the modem transmittal.

During

their

normal

. technical

reviev

af

the

transmittal

(modem versian),

and independent of the Plant Li.censing

reviev, the,IRC engi.neer in the plant

ZSC Maintenance

Department

also identifi.ed'he

errors

in the

equations.

The

inspectors

discussed

this

item vi.th the plant

ISC

engineer

and

the

ZfC

Maintenance

Supervisar

vho stated

that after

the

errors

vere

identi.fied, discussions

vere held vith the alleger to verify the

validity of the errors.

ZtC maintenance

personnel further stated

that

they

had

revieved

each

response

to

an

NRC

RAI priar to

submittal to the NRC.

The inspectors

revieved

PPL response

to NRC questions oi June

6,

1991,

on TS submittals L-90-417 and L-91-098 concerning

RPB/ESPAS

setpoint.

The inspectors

alsa revieved. the

SER i.ssued

on August

26,

1991,

vhich contai.ned

a technical

reviev of the

RPB/ESPAS

setpoint

changes.

The

SER concluded that the setpoi.nts

had been

17

appropriately

)ustified.

The

NRC

has

concluded,

based

an

cansideratians

di.scussed in the

SER that

(1) ther'e

i.s reasonable

assurance,

that the health

and safety of the public vill not be

endangered

hy operation in the proposed manner,

(2) such activities

vi.ll be conducted in compliance vith the NRC~s regulatians; and,(3)

the- issuance of the amendments vill not be inimi.cal to the

common

defense

and securi.ty ar to the health and safety af the puhli.c.

/

4

Based

on the revi.ev of,the licenseeis

design integration programs

the inspectars

determined that the licensee

had an adequate

program

',for ensuring

that

applioable

information is

avai.lable

to

JPN

engineers involved in perfarming design integratian far apprapri.ate

design activtti.es.

The design process vas revieved and found to he

suffici.ently

detailed

and

functional.

Detailed

procedures

addressi.ng

design integration and the required taols are avai.lahle

ta engi.neers for accomplishing the task.

The i.nstance

concerning

the RPB/ESRAS setpoint methadolagy where design integratian vas not

adequately

implemented appeared to he an i.solated i.nstance.

Other

PC/Ms vere " revieved

vi.th no . other

design

integratian

prablems

found.

5 ~

RAZLURE TO COMPLY %ZTH HUMAN RACTORS

COMMZTMENTB.

The statement of the concern vas as follows:

Rai.lure to

corn

1

wi.th commitments

with res ect ta

Human

Ractars.

\\

, DZBCUSSZON:

NUREG-0737,

Task Action Plan I.D.Z, Contral

Room

Design

Revievs,

requires

that all li.oensees

conduct

a detailed

control-room

desi.gn

reviev

to

identi.fy, and 'orrect

design

deficiencies.

. The purpose of the reviev vas to

(1) review and

evaluate the contral roam vorkspaoe, instrumentation, controls, and

ather ecpxipment from a human factors engi.neering point of viev that

takes i.nto accaunt both system

demands

and aperator oapabilitiesg

and

(2) to identi.fy, assess,

and

implement cantrol

raom design

modi.fications that correct inadequate

or unsui.table

i.tems.

RPL submitted the TPNP Detailed Control Room Design Review program

plan to

the

NRC

on

May 20@

1983'he

program

plan utilized

Supplement

1 to NUREG 0737) NUREG-0700( and NUREG-0801 as the bases

for the pragram

development.

. The

DCRDR Summary Report

was then

submitted to the NRC on September

30,

1983.

This report identifi.ed

about 300 Human Engi.neering Defi.cienci.es per unit and the'status af

each.

The

NRC reviewed these

documents

and provided

PPL with a

SER and

Technical Evaluation Report of the TPNP DCRDR on pehruary 2, 1984.

~ Thi.s report indi.cate4 that

a pre-implementation

audi% would he

necessary

to resolve the open or confirmatory items identified in

the

SER.

The

NRC then conducted the pre-implementation

audit of

the

DCRDR program at TPNP on Apri.l 2 through 6, 1984.

The results

of the

NRC audit identified the resolved

items

and those

items

requiring additional i.nformation.

The

NRC stated that

a meeting

would he appropriate to discuss

PPL plansg

methods,

and schedules

for suhmi.ttal of a supplement to the

TPNP DCRDR Summary Report.

PPL met with the NRC on October 2, 1984, to discuss the outstanding

items for the

TPNP

DCRDR Summary Report Supplement

and the report

was submi.tted to the

NRC on April 1, 1986.

Section

3 an4 Appendix

6B of the supplemental'eport

i.denti.fied the

HEDs that remained

open.

PPL provided the

NRC with a sohedule for completion of the

open HEDs on September 3, 1986, with a commitment to inform the NRC

of any changes to the schedule.

On November 23'987i the NRC issued

Li.cense Amendment No.

126 and

No.

120 to the Pacility Operating

Li.censes for Turkey Point Unit

Nos.

3

and

4,

respectively.

These

amendments

ad4ed

license

conditions

which requi.re

implementation

of PPLIs plan for the

integrated scheduling of plant modi.fications for the TPNP.'he I/S

- resulted

i.n implementation of schedules for new and existing plant

modifications and ohanges

whi.ch reflect the importanoe of the items

in relation to overall plant safety.

This would he achieved

hy

improved control of plant modifications

or resource

intensive

activi.ties

and

timely implementation

of the

modifications

or

activities.

The amendment required

NRC notification of changes in

the schedule.

Subsequent to the issuance of the amendment,

the I/S

became the method for tracking the status of open

HEDs required by

the NRC.

The status of the open HEDs specifically referenced

hy the alleger

was as follows:

(1). Turbine Runback Selector Switch

The Turbine Runback Selector

Switch allows the operator to

choose inputs desired for the turbine governor and loa4 limit

runback i.nitiating logic.

The selector

switch is

a four

position switch with the following positions:

NIS

RPI

Selects

Nuclear

Instrumentation

System

inputs to the turbine runback i.niti.ating

logio.

Selects

Ro4 Position Indication inputs to

the turbine runback initiating logic.

19

NZS/RPI

Selects

both NZS and

RPZ inputs.

Disables the

NZS and

RPZ inputs.

(2)

The

normal

position

of

the

seleotor

svitch is

the

RPI

position.

The svitch pasition is annunciated'n

the Control

Room to provide

an alarm vhen the seleotor'vitch is in a

'*

position other than RPZ, or when the lagio matrix for the RPI

portion af the selector svitch fails to actuate.

The

scope of the modification consisted in eliminating the

>>Off>> position on the Turbine Runhaok Seleotor Switch.

This

modification vas required to prevent the plant fram returning

ta power operatian vith the svitch erroneously .left in the

>>OPP>> pasitian.

The >>OPP>> pasition an the selector switch vas

designed to be used when the plant vas in hot shutdown,

cold

shutdown,

ar refueling

" operations.

Xts

purpose

was

to

facilitate maintenance

an the system.

Hovever, maintenance,

activities an the Turbine Runback System can also be perfarmed

vhen

the

selector

svitch is. in the

NIS position vithout

altering

the

turbine

runback

initiating lagic;

This'odificat'ian

involves replacing

the existing four positian

svitch with a three position keylacked switch vith position

locations at 11 a~clack (NZS), 12 alclock (RPZ), and 1 a~clock

.

(NIS/RPZ).

The

new

three

positian

selector

switch is

essentially a one-for-one replacement for the existing Turbine

Runback Selector Svitch, and therefore this madification will

not adversely affect the existing turbine runback initiating

logic.

I

This modificatian vas identified on the I/S as

MOD 1245 for

Unit 3 and

MOD 1246 for Unit 4.

MOD 1245 vas completed

and

clased

out in May of 1990

and the

NRC vas notified in the

. semi-annual

update to the I/S in PPL letter L-90-345 dated

September

20, 1990.

MOD 1246 is currently scheduled

on the

X/8 to be accomplished dqring the 1993 Unit 4 refueling outage

with a 'completion

date of April lp

1993@

which is

63 days

ahead of the

NRC commitment date of June 3, 1993.

Contral

Room Lighting,

HED Nos.

6.1.5'.3.a.

and 6.1.5.4.c.

These tvo HEDs vere identified as still being apen in Appendix

63 of the

DCRDR Supplemental

Summary Report as fallows:

(a)

~Pindin:

(Seotion 6.1, Rile No

30,

.NBD No. 6.1.5.3.a)

Contral

raom

ambient

lighting

is

brighter

than

recommended

75 faot-candles

on operators~

desks;

maximum

recommended

on main consoles,

NXS panels.

Emergency

lighting too'im.

20

Planne4

Res onse:

Sunli.ght spectrum li.ghting vill reduce light levels and

glare.

FPL i.s presently review.ng the emergency lighting

problems

and plans to

madge detaile4 light measurements

for both normal and emergency lighting after the panels

are painted.

FPL is also conducting a new noise analysis

due to removal of'sbestos

from the control room ceiling.

These

studies vill he integrate4

to provide the hest

solution for noise

and light problems.

Status:

(h)

The old lights have been replaced vith sunlight spectrum

li.ghts (Dura Li.te, 3i watts) which appear,to

have reduced

glare problems.

The control boards

have been painte4

a

lighter

color

that vill brighten

the

room

during

emergency

conditions.

The

planned

light

and

noise

surveys villbe used to develop an improved control room

ehvironment if, required.

~Rindin:

(Section 6.1, Ri)e No. XS,

BED No. 6.1.5.4.c)

Inadequate

emergency

li.ghting levels

on the vertical

panels

i.n the primary operating area (vertical panel

B)

does

not

meet,

10

footcandle

minimum requirement

for

primary operating

a'rea.

Planned

Res onse:

Revi.se or add li.ghting fixtures to achieve

10 footcandles

in all primary operation areas.

Status:

Neo lights have been installed

and the vertical panels

have

been painted

a lighter color.

After start-up of

Uni.t i, FPL villperform a light survey to 4etermine the

adequacy of the lighting.

The commitments to the

NRC for these

HEDs vere identified on the

I/S

as

MOD 792.

This

MOD required

the

li.censee

to perform

a

control

room lighting evaluation vith a

NRC commitment date for

completion of October 27, 1991.

The lighting stu4y was completed

by Tech-U-Fit Corporati.on in June of 1990

and the review by the

licensee vas completed November 21; 1990, as documented in JPN-PTN-

90-5071.

Si.nce the commitment to the

NRC @as to perform a study

only,

MOD 792

@as

shorn

as

complete

on the I/S and the

NRC

@as

informed by FPL letter L-91-087 dated March 27, 1991.

The stu4y

indicated that the lighting'n the cantzol room could be improved.

Although the NRC commitment vas completed and the MOD removed fram

the I/S,

PPL is still tracking the lighting HEDs

an their ovn

commitment tracki.ng system

(C-TRACK) under item numbers 87-0099

34

and 87-0100-3i.

It shaul4

be noted that

even

though the study

identifi.ed areas

for improvement,

there

have

been

numeraus

NRC

inspections in the contral rooa over the past several years,

and

inadequate

lighti.ng vas not identifi.ed as an issue.

Por example;

EOP team inspection

members

vere directed to observe

normal

and

emergency lighting thraughout the plant vhen valki.ng 4own EOP~s;

Preoperational

testing

inspections

4uring

safeguards

testing

required inspectors

to be present in the control room vhile the

control

zoom vas

an

emergency

lighti.ng for extended peria4s'f

timey SRC inspectors provided extende4 control room coverage duzing

both unit startups after the dual. unit outage;

and the resident

inspectars

rautinely taur the control room at variaus times.

(3)

Control Room Annunciator HED Nos. 6.3.1.2.a.l and 6.3.1.2.c.1.

These tva HEDs vere identifi.ed as still being apen in Appendix

6B of the

DCRDR Supplemental

Summary Report as follavs:

(a). ~india:

(Seotion 6.3, Pile No ~ 2, EED No. 6.3.3.2.a.l)

~

There are several

alarms that occur so frequently that

they become a nuisance

and the operators disconnect

them.

P1anned

Res onse!

. The

nuisance

alarms

are

to

be

corrected by eliminating alarms that

are not needed

and changing logic as

a part of the

annunciator

system

upgrade.

Status:

Annunciator upgrade under study.

(D)

~Pindin:

(Section 6.3, PiIe No. 5, ESD No

6.3..3.2.o.l)

Same alarms vi.th multiple i.nputs

do not have reflash.

Planned

Res

oases

Reflash capability villbe avai.lable

as

require4

as

part

of

the

annunciatar

system upgrade.

Status:

Annunci.ator upgrade under study.

The commitments to the

NRC for these

HEDs vere identified on

the I/S as

MOD 1011.

Thi.s'OD vas similar to the lighting MOD

(I/S MOD 792) in that the commitment on the I/S vas to perform

a control roam annunciator

stu4y only.

22

The I/B shoved

the

annunciatar

study'o

be

completed

by

November 5, 1991.

The study vas completed on March 29@ 1991,

.

as

4ooumented

in

JPN-PTN-91-5011,

and vill be

shown

as-

oomplete in the next formal I/B submitted to the NRC.

After

the ainunci.atar

MOD is olosed

on the I/B the licensee vi.ll

continue to track the reoommen4ations

from the study under C-

TRACK item number 87-0103-3i.

There has been a noted improvement in the past fev years vi.th

regard

to

control -room

deficiency

tags,

vhich

includes

annunciators.

There

has

been

a continued reduction

from a

high of approximately

255 noted in the 1989

SALP report

(NRC

Znspecti.on Report Nas. 50-250,251/89-36),

to.an all time law

of 4i noted i.n the 1991

BALP (NRC Inspeotian Report Nos. 50-

250,251/91-i1)

~

. The licensee recently oammenoed tracks.ng the

number of annunciatars

in an alarm condition vhich is off-

normal for the current plant conditian.

Thi.s is hei.ng used as

an

indicator

for

management

to

determine if

i.ncreased

attentian is required.

On November

7,

1991,

there

vere

a

total of eight annunci.ators listed for this indicatar (three

for Unit 3 and five for Unit i), vhich is an improvement over

the past.

Recent inspection effart vas revieved to determine if there vas any

indioatian af a generi.o

human factors concern.

Both an

ORAT

(NRC

Inspection Report Nos. 50<<250,251/91-38)

and an

EOP Pollovup Team

Znspectian

(NRC Znspectian

Report Nos. 50-250,251/91-33)

reviewed

portions of the licensee~s

human factors program.

The

ORAT inspection results in the area of human factors vere

as

follows

ll

The inspectors

revieved

a

sample of the

NOPs

and

ONOPs to

ensure

that

the

prooe4ures

adequately

i.ncorporate

human

factors

considerations

and that the

TPNP operations

staff

clearly understand

and cauld use the procedures

as written.

The

reviev

consisted

of:

(1)

a reviev of the

procedure

'vriter~s guide,

ADM-1011

.(2)

comparison

of the

procedures

against

the

administrative

guidelines

far

procedural

develapment;

and

(3) plant valMovns of selected

procedures

vith operatians staff.

The inspectors

reviewed the licensee>s

prooedures

vriter~s

guide ta

ensure

that it a4equately

addressed

the previous

concerns

identified

during

the

EOP

Team

Inspection

(NRC

Inspection

Report

Nos.

50-250/89-53)

an4

incorporated

the

human

faotors

principles

as

described

in

NUREG

0899@

<'uidelines

for

the

Preparation

of

Emergency

Operating

Procedures.~~

The licensee

has inoorporated revisions to the

prace4ure

vri.ter~s

guide

in

response

to

the

inspecti.on

fin4ings.

Most si.gni.ficantly, the vriter~s guide

has

been

23

expanded to include all operating, off-normal, and emergency

'perating procedures.

The procedures reiiewed generally agreed vith the recpx9.rements

of the vriter~s guide.

A sample .of the procedures

reviewed.

vere

walked

down with . operations

staff'. to

determine

the

adequacy

of the procedures,

and to ensure that 'appropriate

controls and indications vere presented.

Particular emphasis

- vas placed

on reviewing the modifications to the Unit 3 and

Unit i Emergency Diesel Generator controls'he

team found

that.

the

procedures

vere

adequately

detailed

and

the

operations staff vere

capable of performing the activities

described

in the

pxocedures.

Xn general,

the

ecpipment.

nomenclature

used

in

the

procedures

matched

the

label

i4entification

on

the

equipment.

Xn

those

cases

where

labelling discrepancies

vere identified, the licensee took the

appropriate

administrative

actions

to.

correct

the

discrepancies:

The inspectoxs

reviewed the control

room and local control

panel- revisions associate4

with the EPS Enhancement

Project.

The

rev9.ev

consisted

of<

(1)

an

evaluation

of

the

documentation supporting the control panel modifications;

(2)

review of the modifications through plant

and control 'room

valkdowns of the affected panels. vith operations staff;

and

(3) review of the resolutions'o

the

HEDs identified during

the design process.

The

inspectoxs

reviewed

the

licensee~s

documentation

supporting

the control

panel

modifications

to ensure'he

design

process

adecpxately

incorporated

human

factors

engineering principles described in NUREO 0700@

>>Guidelines

for Control Room Design Reviews.>>

The inspectors

found that

the licensee

had implemented

an adequate

process to identify

important operator. actions associated vith the,

EPSOM identify

controls

and indications

necessary

for those

actions,

and

incorporate accepted

human factors principles into the design

of the control panel mo4ifications.

The inspectors

reviewed the 'control

room and local control

panel

modifications

to

ensure

that

the

operations

staff

recognised

and. understood

the modifications,

and to ensure

that the appxopriate controls

and indications necessary

for

operator

activities

had

been

incorporated

into

the

modifications.

The inspectoxs

found that the operations staff

recognised

an4 understood the modifications,

and vere capable

of performing the activities

associated

vith the. affected

control panels.

=

The inspectors

found that indications

and

'ontrols vere adequate for performing the required activities.

The inspectors reviewed the resolutions to the EEDs identified

Curing the control panel

design

and validation process.

In

most

cases

the

licensee

has

incorporated

adequate

design

t

modifications

to

resolve

the, HEDs

i4entifi.ed,

and

had

24

. adequately

documented the resolutions.

Hovever, the licensee

did not adeyxately

address

the

one major control panel

HED

i.dentifi.ed during the performance'validation

process

(PA-SEI-

'PS.02,

Discrepancy

41) related to distinguishing between the

diesel

~~emergency

start<<

and <<rapid start<<

contrals.

The

inspectors revieved the discrepancy with the license'e,

and the

licensee ini.tiated the appropriate admini.strative controls to

resolve the concern.

The'RAT 'nspected

the

licenseeIs

corrective

actions

associated

vith the

=human

factors

findings

from the

EOP

Rollov-'up Inspection

(NRC Inspectian Report No. 50-250/91<<33),

dated September

3, 1991

The licensee

implemented procedural

revisians

and cantrol panel modifications in response

to the

inspection 'iport findings.

The ins'pectars-

faund

- that the

licensee

adequately

addressed

minor discrepancies

identified

in Section

7 of NRC Inspection Report No. 50-250/91-33.

With regard to the EOP inspectian

team finding related to the

actions

taken to verify cantainment

integrity following a

phase

A .or phase

B isolatian

(NRC Inspection Report No. 50-

250/9X-33,

Sectian.

2),

the,

licensee

has

commi.tted

to.--.

incorporate additional procedural

guidance inta the

EOPs to

help ensure'appropriate

operator actions to allow far local or

manual isolatian of the affected

containment

penetrations.

This is more consistent

with actual isolation methodology.

The ORAT found the propose4 actions to be adequate.

CONCLUSION'.

LLEGATION 5 - NOT SUBSTANTIATED

In summary the allegation could not be substanti.ated.

Almost 400-

~ HEDs per unit vere identified by the initial DCRDR Report and.the

Supplemental

Summary Report.

The inspectors revi.eved'the status of

open

I/S

Mods

associ.ated

vith

HEDs

and

compared

them

to

the

licensees

HED tracking system.

Currently there are six open I/S

Mods related to HEDs

(Mods 550, 569, 1297'nd

1298 are associated

wi.th

svitchesg

MOD. 1011

is

the

annunciator

study

di.scussed

previously; and MOD 1290 concerns the control room phone).

The NRC

has

remained

informed of

HED status

through

formal

meetings,

audits,

and correspondence

prior to November 23,

1987.

After that

date status

vas formally provided by the I/S.

The open status af

the remaining six HEDs does not constitute

a safety concern an4 the

resolution of each

item is schedule4 via the I/S. Additianally,

human factors

i.s now incorporated into the overall design process

by the admini.strative

prace4ure

O-ADM-006,

Human Ractors

Review-

Program.

25

6 ~

MODIPICATIONB POSTPONED

DUE TO BUDGET OR OTHER CONSTRAINTS.

The statement of the concern

was as follovs:

ani ement~s

decis9on to

ost one

due to bud et9.n

or other

constxa nts

m ortant

od

9.cations

uc

as the correct on of

t e

over

ismatch Ci cuits to automat

ca

co trol Reactor

ower

thru 4 rection and s eed of

od

nsert9.on

.

Effort to

itiate

mod

9,cation

to

nstal

estore

over

m9.smatch

circuit

has

een deadlocked.

over

ismatch circuit

was

ino erational

in at

east

one of the

two nuclear

units.

urious xeactor tri s v t

the9.x'nnecessa

-challen

es to

rotect9.on

s stem have often occurred at TP

causin

adverse

e

ect on

eactor vessel

nte rit

at

east

one as recentl

as

990

with. runbacks

that

were

ot

surv9ved

at

least

artiall

as a result of 9.no erational'od control s stem.

DXSCUSSXON:

The inspectors revieved licenseees

detailed procedure

for

prioritiaing

each

PC/M

based

on

a

decision

matrix.

Approximately

50

percent

of the

importance

veight9.ng

9n

the

dec9.sion

matr9x is

based

on

safety

sign9.ficance

and

be9.ng

a

regulatory 'requ9.rement.

The prioritsation process

vas determined

to be adequate.

During the ORAT, the inspectors ver9.fied that the

PC/Ms that vere

be9.ng

canceled for the dual

un9.t outage

did not

present

a safety

concern.

The results

of the

ORAT inspection

follow:

Por this

DUO approximately

310

PC/Ms

were planned,to

be

accomplished

and 22 of these ver'e canceled.

In order for the

licensee to delete

an activity that was initiallyplanned for

the

outage,

9.t

had

to

be

recommended

by the

applicable

Department

Head,

Technical

Depaxtment

Supervisor,

Outage

Manager,

Operat9.ons

Superintendent,

and Plant

Manager,

and

approved by the Bite Vice President.,

The recommendations

and

approval are documented, on Attachment

3 of O-ADM-003, Outage

Management.

The inspectors

reviewed the

22

PC/Ms that vere

deleted and agreed that they d9.d not impact plant safety.

The

canceled

PC/Ms ranged

from modifying components

for system

enhancement

to

installing

removable

hand

rails

at

the

containment

equipment

hatch

area.

Eleven of the

canceled

PC/Ms

vere

replaced

by

14

other

PC/Ms that

the

licensee

considered to be more important than the original PC/M.

For

example,

PC/Ms

90 301)

304'nd

305@

to modify

11 pipe

supports,

vere postponed

in order to procure, install,

and

test

the

hydrogen

recombiner.

In addition,

the

canceled

modifications were added as candidates for either the >>Top 20>>

or <<Top 30>> lists.

These lists vere recently implemented

by

the licensee

to control the

number of modifications

being

installed in the plant.

In order for a modification to be

9nstalled it

must

be

19 sted

on

the

<<Top

20>>

list

(modifications scheduled for the next'outage)

or the

~'Top 30>>

26

list (modifications that can be accomplished

an-the-line or

during short notice outages).

For a modification to be ad4ed

to the lists there

must

be room'or it or

a modification

currently

on

the list

aust

'be

canceled

and

the

new

modification

added.

The

inspectors

considered

this

an

excellent

.method

of controlling- the

number

of

changes

occurring in the plant at any one time.

The inspectors specifically reviewed the pover mismatch circuit to

access

the

PC/Ms

made

to

the

circuitry

and

to

review its

operability.

The pover mismatch circuit is a part of the automatic rod control

system

and- is classified as non-safety grade.

%hen the rod control

system is in automatic, the pover mismatch circuit vill respond to

a rapid change

betveen nuclear pover

(QN) and turbine load

(Q ).

Signals

generated

are

then sent to the rod speed

and

di.rection

.

program restoring the balance

betveen

QN and QT.

The reactor control system is designe4 to enable

the reactor to

follow

load

reductions

automatically

vhen

the

output

is

approximately

15% oi

nominal

pover.

Control

rod positioning

(insertion)" automatically occurs vhen output is above this value.-

Zn addition manual control rod positioning may be performed at any

time.

The inspector reviewed the following plant procedures

and concluded

that detailed

an4 specific instructions are provided that specify

conditions vhen the rod control system is to be in the automatic

mode.

Znstructions

also direct plant operators

to place the rod

control system in manual for ecpxipment malfunction or off normal

events

vhere

automatic

control is not stabili.sing

and maintain

plant conditions.

4-GOP-103,

Pover Operation to Hot, Standby

i-GOP-301, Hot Standby to Pover Operation

3-ONOP-028,

Dropped

Rod

i-ONOP-059.8,

Pover

Range

Nuclear

Znstrumentation

Malfunction

3-0NOP-089,

Turbine Runback

The inspectors reviewed ZfC Maintenance Znstruction i1-017, T

to

Rod

Speed

Control

and

Pover

Mismatch,

vhich is

used

for. Poop

calibration of the pover mismatch circuit.

The circuitry for both

units vas calibrated during the current

DUO in January

1991.

The

calibration data was found to meet proce4ure

acceptance criteria.

Zn addition to the calibration test

a monthly operability test is

performed on the pover mismatch circuit vhen the plant is operating

27

C

above

15% power;

The paver mismatch circuit monthly operability

checks are pexformed in accordance vith surveillance procedure

4-

OSP-059

4,

Pover

,Range

Nuclear

Znstrument

Analog

Channel

Operational Test.

The inspectors

held di'scussions with ZtC engineers

and operations

personnel

concerning the operating history of the povex mismatch

circuit.

The inspectors

concluded as a result of these discussions

that the rod control system has been primarily operated in manual

on both Units.

The licensee

stated that the xeasons

the control

system

has

been

operated

in manual

are

because

of calibration

problems

(defective

electronic

components)

and

temperature

deviation problems

(- 1/2'F)

between

T

-T

=

.

The latter vas

causing rods to move in.

These problems Nre SKrrected during the

DUO

The inspectors

reviewed the folloving PC/Ms which vere implemented

over a period of years

and affected the rod control system and the

pover mismatch circuit.

PC/M 81-13 (Unit 3) g 81-14

(Unit 4), Deletion of Power

Mismatch Circuitry, from the Rod Control System

r

PC/M 83-88

(Unit 3); 83-89

(Unit 4), Deletion of Flux

Rate Input to Turbine Run Back

PC/M 84-208 (Unit 3),84-209 (Unit 4) Reinstatement

Power

Mismatch Circuits Nithout Automatic Rod Withdrawal

PC/M 84-210,

(Unit 3),84-211 (Unit 4), Turbine Runback

Modifications

The

NRC ZE Information Notice No. ?9-22, Qualification of Control

Systems,

dated

September

14,

1979 notified licensee that the rod

control

systems

(non-safety

grade

system)

could

potentially

malfunction

due to

a high

enexgy line break inside or outside

containment.

The

licensee~s

long

term corrective

action

vas

described in FPX letter X-79-284 dated October 8, 1979.

PC/M 81-

13 p toll PC/M 81-14 vere implemented and removed the power mismatch

signal

and

modules

vhich eliminated all automatic

control

rod

functions.

PC/M

84-208

and

84-209

restored

pover

mismatch circuitry for

ca abi

automatic

rod .insertion

only

and

removed

the

rod vithd

1

p

lity.

The purposes

of these modifications vere to enhance

v

rawa

opexational control during turbine runback, events

and to maintain

the

purposes

of

PC/M 81-13

and

PC/M 81-14 which prevent

a rod

vithdraval event

due to a steam line break.

A Recpaest for Engineering Assistance,

REA 89-667, Restoxe

Symmetry

to Power Mismitch Circuit, vas approved by Engineering July 1991.

The REA restores

symmetry to the pover mismatch circuit by sloving

28

the, control

rod insertion rate, during the latter -part of the

turbine

runback

anl

reduce

possible

excessive

reactar

caolant

'ystem

temperature

decrease.

During an earlier inspectian conducted August 26-30, 1991 the paver

mismatch oircuit for ral control vas revievel.

REA 89-667

had

addressed

a oancern that RCS temperature

may decrease significantly

belav set point during a turbine runback due ta the power mismatch

circuitry of the

Ral Control

System

not haying

symmetry.

The

existing power mismatoh circuit can only accilerate initial rod

insertion, it can not slow it later'during the transient.

f

The simulator vas

used to investigate

whether

a plant stability

problem exists.

The licensee

oonduoted

several

turbine runback

scenarios

on the plant simulatar to assess if plant stability is

achieved vith the current pover mismatch circuit installation.

The

turbine runback scenarios

were conductel using the existing power

mismatch

design

anl also vith ohanges

oontainel in'EA 89-667.

Plant parameters

(T

and T

) shoved very similar responses

for

both designs with no s%ebllHggroblen identified.Af,ter

reviewing.'he

capies

af the

computer printouts which -displayed

the plant

parameters

(T.

and T'

the inspectors

agreed. that the need far

'mmediate

ohk7fes

ta

RKe .pover

mismatch circuit vould, not

he

required

and vauld not present

a safety

concern.

Zt vas

the

opinion of the I f

C Supervisor

and the Operations

Supervisor-

Nuclear that the present

runback results vere acceptable

and the

addition of the

symmetry

(negative 'feedback)

modificatian vould

enhance

the system hut vas not required.

The inspectars

observed

th'at'the

power mismatch circuit is operable vithout the

symmetry

modificatian (REA'89-667) vhich is planned; hut is not presently on

the plantgs

>>Top 20<< list.

The

inspectors

reviewed all reactor trips, that

occurred

from

January

1, 1990, to November 4, 1991, to determine if there vere

any spuriaus reactor trips or runbacks vhich resulted in a reactor

trip, at least partially as

a result of inaperational rod-control

system (e.g. inoperable

Paver Mismatch. Circuit).

A summiry of the

reactor trips is listed belov in ohronalogioal order.

On April 9p, 1990@ at 6:14 p.m., Unit 4 tripped while at

100%

pover.

The trip vas initiated hy the failure of UP relay No.

4B2 vhich indioated

an

UP condition of less

than 56.1

Hs on

the 4B 4Kv hus.

No UP condition existed, hut the failel relay

monitors the

4B 4Kv bus which feels the

4B anl 4C RCPs.

The

false

UP signal tripped the

4B anl

4C

RCP breakers

which

resulted in a reactor trip. All safety systems functioned as

designed.

Zev flov from the charging

pumps vas experienced

luring the recovery operation and the licenseegs investigation

shovel that the calibration of VCT level transmitter

LT-115

was aut by

5% inhibiting the automatic svitch aver of the

charging

pump suctian

fram the

VCT to the

RIST.

Degraded

charging

pump flov occurred

when the

VCT level vent to sero

29

and

hydrogen

fram the

VCT vas

inducted into the

charging

pumps.. Unit 4 vas scheduled to be braught

down on Apri.l 12,

1990, far safeguards tests in con)unction with Unit 3 which is

presently in a refueling autage.

Unit 4 remai.ned in Mode

3

for shart- noti.ce outage

work until the safeguards

test

was

'anducted.

On

May 26,

1990,

at

5 s 56 a.m.,

Unit

4

vas

inadvertently

manually tri.pped while at approximately A pover.

No

SZ

, ooourxed and plant conditions remained fairly constant

The

li.oensee vas in the. process of filtering the turbine lube oil

to remove metal

fragments

(reference

NRC Znspecti.on

Report

Nos. 50-250,251/90-14)

hy conducting 4-OSP-089,

Main Turbine

Valves Operability Test,

steps

7.2.4 thru 7.2.11

and 7.2.55

during vhich the

main turbine vas latched

and tripped- ten

times to facili.tate lube oil elean up. 'uring the time the

lube oil flush was in process

the Unit 4 reactor

vas at IA

pawer vith cantral rods withdrawn.

Pollaving the flushes

and

verifi.cati.on that no metal fragments vere faund follavi.ng the

last time the main turbine vas tripped, the decisian vas made

ta

conduct

4-OSP-089

to

oomplete

the surveillance.

Step

7.2.59. qtates

>>Trip the Reactor Trip Breakers

or conti.nue

plant "startup. in acoordanoe

vith the, requi.rements

of the

applicable

GOP

(N/A if breakers

vere

not reset

in

Step

7.2.8).<<

When the

RCO reached

step 7.2.59

he obtained

the

PSN~s

concurrenoe

and tx'ipped'he

reactor trip breakers

resulti.ng in a reactor trip.

One contributing factor vas the

sequence

of performing 4-OSP-089.

The startup procedureg

4-

GOP-301,

Hot Standby to Pover Operatian,

step 5.3,

has the

operators

perform Seotion 7.2 of 4-OSP-089 priar ta apening

the MSZVs-in preparatian

for warming the main steam

header

prior to reactor startup.

The operators

vere familiar vith

accomplishing step 7.2.59 of 4'-OSP-089 vith rods inserted.,

On June

9,

1990 vith Unit 3 in Mode 1-at 264 pover the uni.t

experienced

an automatic tuxbine trip and subsequent

reactar

trip at 6:47 a.m.

due to High-High level in the

>>C>>

SG,

The

aperators-had

plaoed the unit online at 6:37 a.m. that day and

vere prepaxing to i.ncrease

load vhen the operatars

noted the

>>C>>

SG feedvater level increasi.ng

and i.noreased

demand signal

on PC-498P to'the main feedvater regulating Valve (PCV-498).

The flov controller

(PC-498P)

vas still in manual.

The

.

=

operator attempted to close the valve by pushing the decrease

button on PC-498P.

Hovever, the

SG vater level continued to

rise.

The operator tried to close the feedvater isolation

valve to the

>>C>> SG.

With SG NR level

~75% the

RCO manually

tripped the reactor.

A review af the

DDPS printout revealed

that

the

reactox

txipped

autamatically

approximately

.20

seconds

before

the

RCO manually tripped the reactor.

= The

turbine tripped on High-High SG level "(804 NR) vhich caused

the subsequent

reactar trip.

The plant xeceived

a feedvater

isolation and

APW initi.ation as expected.

Znyestigation of

r

30

FC-i98F revealed that the manual/auto pushhutton far increased

feedvater flov,stuck closed.

ISC techni.ci.ans

replaced

the

flov cantroller and the plant restarted

on June

11, 1990.

On

June

15@

1990@

Unit

3

automatically

tripped

fram

approximately

104

reactor

pover.

The

turbine

had

been

manually removed fram service due to high conductivi.ty in the

steam generators

due to condenser

tube leaks.

The operators

vere performing this evolution in accordance with pracedure 3-

GOP-103,

Power Operati.on to Hot Standby.

Prior to tripping

the

turbine,

the

operators

vere

required

to verify that

reactor pover was belav the P-10 setpoint

(10% indicated

on

PRNIS)

and that turbine

power vas belov the

P-7 setpoint.

These condi.tians vere satisfied;

hovever, the

RCO noted

T

decreasing

due to the

imbalance

hetvien the reactor

poNS

level 'and turbine load.

The turbine laad vas maintained at

approximately

35 Ãfe vhich vas draving off toa much steam for

the reactar

system ta maintain T

stable.

The control rods

vere i.nserted previously to loweVQaver level belav the P-10

setpoint.

The

RCO

deci.ded. to vithdrav central

rods

ta

increase

T

.

Havever, the RCO did not monitar reactor pover

level.

ThV turbine was manually tripped with reactor pover

belaw "104.

However,

pover

vas

increasi.ng

and

reached

10

percent

.15 seconds after the turbine vas tripped,

enabling

the

>>at-pover>>

reactor trips.

At this point the reactor

tripped due to the presence

of the turbine trip si.gnal vith

reactor pover above the P-10 setpoi.nt.

Following the trip,

the plant vas stahilised in Made 3.

In summary, the

PBN- did

not adequately direct the Unit 3

RCOs as the unit vas being

taken offli.ne.

The resulting poor cammuni.cation betveen the

RCOs i.ndependently controlli.ng the reactor and the turbine led

to

reactar

pover

increasing

above

the

P-10

setpoint

(10% reactor pover) and the subsequent

automatic reactar trip.

On August

12,

1990, at i:28 p.m., vith Unit

4 at '100'4,

a

reactar trip occurred due to Lav-Lov level in the >>A>> SG.

The

event

vas

caused.

hy

the

iB condensate

pump tripping

on

overcurrent vhich vas immediately folloved hy a trip af the 4A

feedwater

pump.

The trip of the feedvater

pump initiated a

.

turbine runback to less than

60% pover as desi.gned.

SG levels

dropped belov

15% narrov range

due to shrink caused

hy the

combined effects

of

a partial loss of feed flow, turbine

runback,

and suhsecpent

reactor trip.

The trip of a running

condensate

pump vill normally start the standby

condensate

pump and not,trip the feedvater

pump i.f the svap occurs within

five seconds.

The five seconds

i.s timed hy an Agastat relay

in the feedvater

pump breaker trip lagic.

Upon investigation

i.t vas

discovered

that

the

Agastat

relay

vas

set

at

.15

seconds in lieu of the.recpxired five seconds.

The lov setti.ng

af the relay did nat allov enough

time. for the start of the

standby condensate

pump to be sensed hy the breaker trip logic

and therefore

a

SGFN

pump trip signal

vas generated.

The

31

relay vas reset to 5.0 sec + 10% for the 4A feedvater

pump and

the relay for the

4B feedvater

pump vas

also reset

after

testing

found it to be set 'at

3.-3

seconds.

The unit vas

subsequently

returned

to

servi.ce

at

4:43'.m.

an

August 14,

1990."

On October

3g

1991@ at 11:57 a.m.,

the Unit

3 reactor

vas

manually tripped fram

50%, paver

due to, a sudden

decrease

i.n

turbine/generator

load.

The'power decrease

was caused hy the

loss of turbine control oil pressure resulting from a break in

-the cantrol oil pipi.ng near

a turbine intercept valve.

No

automatic reaotor trip signal vas generated since turbine. auto

stop oil pressure

vas not lost and both turbi.ne stop valves

did not fully clase.

Polloving the manual reactor tri.p, all

safety systems

responded

as designed,

and .ane

SG safety valve

lifted briefly. Zni.tial raot,cause

evaluation attributed the

pi.pe break to fatigue stress of a threaded pipe.

The licensee

repaired the control ail piping and then restarted the unit an

'= Octaber 4, 1991,, at 5!53 a m., to continue the startup program

follaving the extended

DUO.

CONCLUBION.

LLEGATZON=6

NOT BUBB ANTZATED

The

licensee~s

pracess

for prioritising, modificati.ons

vas

determined

to

be

adequate.

During the

ORAT,

the

inspectors

verified that the

PC/Ms that vere being canceled for the

DUO did

not present

a safety concern.

The Power Mismatch Ci.rcuit, vithout

the, modification ta restare

symmetry,.

has

been verified to

be

aperational

and.i.n us'e.

With respect to the reactor tri.ps., two of

the six trips vere caused hy personnel error

(May 26, 1990 and June

15, 1990)S the remaining faur trips vere due ta equipment failure.

Based

on the

inspectors

reviev of', the six reactor trips that

accurred

since

January

lg 1990'here

-vere

no spurious

reactor

trips or runbaoks that vere caused, at least partially, as a result

af an inaperati.anal

Pover Mismatch Circuit or because.af

lack of a

restore

symmetry modificatian to the Paver Mi.smatch Circuit.

This

concern vas not substantiated.

7 ~

THNIC 'DISCRIMINATION AGAINST >>CUBAN-AMERICANB>>~

The statement of the concern vas as follavs:

Ethnic discrimi.nation a ainst >>Cuban-Americans.>>

DISCUSSION:

This allegati.on

vas not inspected,

because

of its

heing vi.thin the'jurisdiction of the Equal Employment Opportunity

Commission.

The alleger vas notified that he should i.dentify this

concern to the

EEOC for their di.spositi.on

and

he vas given the

necessary

information on hov to contact the

EEOC.'ONCLUSION%

ALLEGATION 7

NOT INSPECTED

~ 32

8 ~

., EMPLOYBB PROTECTION PROM DISCRIMINATION.

The statement af the concern vas as follovs':

V olatian

a

ederal re

lations

conce

rotection from

discr minat on a ainst

Em la ees for

ress

n ta Mana ement

and

ar

Che

'

ear

Re

lato

Commission

concerns

about

c ear Safet

as

s clearl

de ined in NRC Form 3.

DISCUSSION

HRC Parm 3 states,

~~Pederal lav prohibits an employer

fram firing or otherwise

discriminating

against

a vorker for

bringing safety concerns to the attenti.on of the

NRC.~~

- As stated

in paragraph

1, the

team~s

objective vas to determine if there

existed any unsafe engineering piactices or operating conditions ar

~ ifpersonnel, practices resulted i.n a chilling effect vith regard to

.pursuing a safety issue.

The US Department of;Labor i.s evaluating

Che specifi.c case af employee di.scrimination.

The NRC vi.ll.monitar

the

Department

of

Labor activities

regarding

this

case

for

potential enfarcement.

Par this allegation, the team,objective vas

to

determine,

'in the

general

sense, if there

vere practices,

especi.ally in the Speak

Out and Pi.tness

Por Duty programs,

which

prohibited ar discouraged

engineers

fram pursuing nuclear safety

. concerns.

Because it vas alleged that the Speak'Out

Program vas being used ta

discriminate

against

employees,

the

inspectors

conducted

an

interview of the Juno

Beach. Engineering Staff.

,As discussed

in

paragraph

1, open and candid discussions

vere conducted vith over

60, engineers,'43

af vhom vere in non-supervisory positions.

There

were some comments, the sum of vhich, in the )udgement of the team,

indicated some.auciety over the pending PPL reorganisation,

but did

not indicate a lack of freedam to discuss this concern vith the NRC

=and did not indicate management

engagement in di.scriminati.an.

Reviev of Speak Out files indicated. that Chere vere individuals i.n

.supervisory positions vho vere reprimanded for harassing

employees

vho allegedly raised safety concerns.

One case,

as recent as 1991,

- invalved the removal of the supervisar.

The licensee~s

executive

management

has

made it well known through their General

Employee

Trai'ning that it is

contrary

to

PPL policy to

take

adverse

employment

action

against

any

individual

vho

raises

safety

'oncerns'.

It was alleged that the

Speak

Out

Program did not protect

the

identi.ty of individuals.

The 'engineering interviews di'd indicate.

a concern 'that Speak Out could not maintain confidentiality.

The

inspectars

revi.ewed

the

Speak

Out

process

for protecting

the

identity of individuals vho xai.se concerns.

Speak Out purposefully

does not maintain a list of individuals vha have used the pxogram.

33

Speak Out uses

a sequential

numheri.ng system to assi.gn

a speci.fic

number for each

concern.

The inspectors

determined

that, this

procedure

vould ai.d in preventing

inadvertent

disclosure

of an

individual~s i.denti.ty.

There

are

cases

vhen

an

individual~s identity

could

not

he

separated

from the issue,

or the investigation

reached

a point

vhere the individuals identity could be compromised.

At that point

the individual vas advised. 'f the indivi.dual vas satisfied th t

he conoern has been satisfactori.ly addressed,

then the issue vas

closed. If the individual vas not satisfied,

then the desire for

confidentiality vas revisited.

In some

oases,

Contractors

vere

used to investigate

conoerns

vhen special expertise

vas required

in protecting the individual~s identity.

The engineering staff interviev results indi.cateC that there vas a

perception that individuals vho raise safety concerns to Speak Out

vould be knovng hovever, the interviev results also indi;cated that

a very small number of individuals usi.ng Speak

Out vere actually

knovng and of those that vere knovn, i.t vas primarily because

the

individuals told other employees that they had raised concerns to

Speak

Out.

. "The interviev results

also

indicated

that

some

individuals" had

a perception that their identities vould not he

protected.

Hovever,

most of these

indivi.4uals had n ith

4

S eak

p

Out nor knev of individuals vho ha4 gone to speak

Out vhile

ne

er used

desi. ring confidentiality.

During the inspection of various concernee followup techni.ques that

Speak

Out vas using,

the determination

vas

made that it vould be

beneficial if the in4ividual vho raised

a concern,

had

a hetter

understanding of vhat identity protection vas.

Speak Out concurred

vith the inspectors

observition

and initiated a guidance letter

dated

October

31,

1991,

vhich- addresses

>>Confidentiality of

Employees Bringing Concerns to Speak Out.<<

The stated objective of

the letter vas that

<<the oonfi4enti.ality

and

anonymity of our

concernees

i.s a very important goal bf this program and should he

emphasized

at all times.<<

The inspectors

concluded that Speak Out has ma4e ff t t

indivt.du

~

uals

identiti.es.

By the issuance of the October 31'991/

a e e

or s to protect

letter

from the

Manager

Nuclear

Safety

Speak

Out to the

Vice

President,

Nuclear Assurance,

PPI vas making additional effort to

inform employees of the acti.ons taken to provide confidentialit

vhen concerns

are brought to Speak Out.

The licensee vas alleged to he using psychological te ti

d d

g

4iscriminate

against

. employees

vho

voioe

saf ety

concerns.

In general, the allegation state4 that the li

a

e

censee

used

qu

e

Fitness for Duty program to retaliate

through

harassment

anC intimidation,

against

employees

'vho

have

taken

safety concerns to the Speak Out organization.

Specifically, vhen

intervieved, the alleger stated that he vas drug tested ei.ght times

34

.i.n

one

year,

and,

was

directed,

withaut

justification,

ta

he

psycholagi.oally evaluate4 by,a cantract psycholagist."

"10 CPR Part

26~ Pitness for'Duty Rule@ effective January

3

f990@"

requires a lioensee to provide for a Pitness for Duty pragram vhi.ch

identi'fi.es nat. only drug and alcohol abuses

hut also,

~~...mental

stress,

fatigue, and i.llness...

~> Additi.onally, Part 26 requires,

~~...an employee assi. stance pragram to achieve early i.nterventian by

offering

assessment,

counseli.ng,

referral,

and

treatment

of

.employees

vi.th ,problems

that

could

adversely

affect

their-

performance....I~ It is the objective of Part 26.that nuclear plant.

personnel perform their duties in a reli.able and trustwarthy manner,

and are not mentally or physically impaired fram any cause vh'ich in

any

vay

vould

adversely

affeot their ahili.ty to 'saf ely

and

campetently perform their duties-.

Given the allegatian

and regulatory requi.rements

as stated

above,

the i.nspector

audi.ted records relative to random

and ~~for cause~~

drug tests

and psychologi.cal evaluations,

and then compared that

information'ith the use af the

Speak

Out program. It should

be

noted that

due to extensive* confidentiality,

and in many

cases

anonymity, in..the Speak Out recards,

the inspector .couN not in all

instances ve'rify the i.denti.ty of the Speak Out user far purposes of

crass-indexing

to.'drug

and psychological

testing

recor4s.

The

Quality Assurance audits of the licensee~s Fitness for Duty program

were revieved,

as vas the 1icensee~s

Supervi.sor Pitness for Duty

'raining han4hook. It is noted that pri.or ta this allegati'an',

the

" NRC had inspected

the Fitness for Duty program at the Juno

Beach

Corporate

Offioe,

St.

tuoie,

and

TPNP.

No vi.olati.ons

were

identifi.ed in these tvo inspect'ians

(NRC Xnspection Report Nos. 50-

250g251/91

40 and 50-335@389/91

05)

~

In early 1991, the licensee concluded that Juno Beach employees

vho

vere

badged

at both St Lucie

and .TPNP vere statistically

more

likely to he randomly chosen

because

they vere in both population

pools.

Consequently,

some personnel

were being 4rug tested

more

than statistically

expected

due to heing in the

two

separate

populati.on pools.

Hovever,

as of March 1991, all multi-badged

individuals at Juno

Beach vere anly in the St.

Lucie population

pool

and therefore

an

an equal

random selecti.on

basis

with all

other

personnel.

This

resolved

the

concern

that

Juno

Beach

employees vere randomly chosen for drug tests more often than their

fellow plant covorkers

Pormal interviews were conducted with three supervisors

and four

coworkers

of the alleger.

The

li.oensee's

Ombudsman

vas

also

'

intervi.ewed.

As noted

elsewhere

in this report,

a total af i3

employees

in the licensee>s

Nuclear Engineering

Department

vere

intervieved relative to use of Speak

Out and no corroboration of

the allegation vas estahli.shed.

35

Based

upon the inspection af various saurces

of PPD i.nformati.on,

the inspeotar

determined the folloving relative to drug testing:

All of the allegeris

drug tests

occurred pri.or ta,

and not

after, his use af Speak Out.

Prom the effective 4ate af the

SRC~s Pitness far Duty, Rule

(January

3,

1990)

until

the

date

of

hi.s

termination

(August

19@ 1991), the alleger had been randomly tested four

times, along vith 479 other employees

an4 contractors

each af

vhom had been tested on four or more oooasions during the same

time periad

(as documented

hy an independent laboratory).

Xn accordance with the NRC Pitness Por Duty Rule, the licensee

has randomly tested at least

1004 of the plant population at

each

af its

tvo

nuclear

stations

on

an

annual

basis.

Statistically, random drug testi.ng has resulted in individuals

being tested

from one to eight times.

The alleger

has

been

tested

four times

which is approximately

the

mean af the

testing distrihution.

The a?leger

vas not one af the

34 individuals vho had been

tested <<far cause<<

as of August 19, 1991.

Slightly less than half of all. the Speak Out users

have been

-randomly

drug

tested

which coincides

with the fact that

approximately

half of all staff have

been

randomly

drug

tested.

Specifically, with respect to the Juno-Beach Corporate Office,

approximately 33%'f the Speak,out users vere teste4 prior to,

and not after, their visit ta Speak Out, and approximately

25%

were tested after,

and not before, thei.r visit ta Speak Out.

Of all the random drug tests given to all the Speak Out users

at Juno Beaoh, exactly 50% occurred prior to, and 50% occurred

after visiting Speak Out.

Only one individual was psychologically evaluated,

visited

Speak Out (before and after the evaluation)

and vas randomly

4rug tested

(before and after use of Speak Out)..

With respect to that part of the allegation regarding the recpxired

psycholagical evaluation,

the inspector determined the following:

Psychological

evaluations

vere ini.tiated by the lioensee in

January

1986,

as

part of i.ts

screening

program

pri.or to

granting access

to the nuclear sites.

36

There

have

been

10 individuals, other than the alleger,

vho

have.

been

directe4

by

aanagement

to

he

psycholagically

evaluatedg

tvo resigned,

seven .vere still emplayed,

and one

vas released,

based in part on the results of the evaluation.

The alleger vas the only individual vho refused

a management

directed psycholagical

evaluation.

The inspectar-

found no

inappropriate

or

discriminatory

use

of

psycholagical

evaluation requirements.

The alleger

expressed

concerned

about.

an 'evaluati.on

hy

a

psycholagist

employed

by 'PPL

vho

vould

not 'llow= his

evaluation to he'ecorded

and would not -allov the

alleger>s'ttorney:"to

observe

the evaluation.

Whi.le- the

licensee~s

contract psycholagist vould reviev another evaluati.an

from a

psycholagist

of the allegerIs

choosing,

he considered .the

presence of a third party and the recor4ing'of his evaluatian

to he contrary ta prafessional

stan4ards.

PPL initi.ate4 the

requirement

that all employees

must

be

psychalogi.cally

teste4

using

the

Minnesota

Multi-Phasic

Personality

Xnventory.

While

10

Part

26

allows

.~~granCfathering,~~ vi.th respect to the psychological test for

some employees, it 4oes not prohibit broadening the scope'f

'the

psychological

test

requirement.

,

Xnspecti.on

of

the

licenseees

use of the test results revealed no discriminatory

practice.

i

CONCLUSION

LLEQATION 8

NOT.SUBSTANTIATED

1

Based 'on the results of the engineering staff intervi.ews

and the.

inspection of documented employee concerns, this allegati.on was not

substantiated.

The inspection did not substantiate

that the Speak

Out Program is heing use4 to discrimi.nate

against

employees

vho

raise safety concerns.

Based upon the above described inspection

effort, no correlation could he found hetveen the drug testing and

psycholagical

evaluation,

and

. the

i4enti.fi.cation

of

emplayee

concerns to PPL management,

Speak Out, or the NRC.

Analysis .of the

FPD screening

data indicated only random use of the program.

The

inspectian indicated no correlation between disciplinary action and

going to Speak Out or being Psychologically tested.

The licensee

, was in compliance vith 10

CPR Part

26, therefore

the allegatian

regarding

the

misuse

of the

Pitness

Por

Duty pragram

vas

not

substantiated.

37

9 ~

RELIABILITYOP 0

RPRESS

MIT CATION SYSTEM.

The statement of the concern

was as follows:

e

est

or

NRC invest

ation of reliabilit

af '>>all ather

elevant

as ects

- of

ea t a

s stem

el abilit

for

such

m artant

s stems

as the

e

ressu

i ation

S stem...>>

se ce of documented

de ensib

e calcu a

ans far Ove

ressure

iti ation

S stem that ean

arantee

ade

ate

max in between

set

a

ts.

ss t an safet - rade surveillance

ractiees

and

ca

b at an

act ces

a

OMS.

ess

than

safet - rade

e

ment

control

rom

rocurement

rou h

com onents~

traeeabilit

to

maintenance.

Re ianee

on

control- rade

ave

essure iti ation s stem.

neert tude af

OMS as to a

sin le failure criteria.

The validit

oi

reactor vessel

P essure-Tem

erature limits is controversial and inconclusive.

DIscUssIoN.

Pc/M 75-81) Nil Ductility Transition

Temperature

Contxol,

was

implemented

on January

6,

1978 for Unit 3) .and

on

November 9,

1977 for Unit 4.

This

PC/M modified

PORV control

circuits to provide low pressure relief settings.

The setpoint of

415 psig fdr low temperature

operatian

(below 300

degrees

R) is

designed

to keep the primary laop pressure

below the

10 CFR 50

Appendix

6 limits.

The

follawing

PC/Ms

were

subsequently

implemented to meet additional design requirements:

PC/Ms 78-27,-

28, Overpressure Mitigation System - Permissive Status Panel Light

and Annunciator Interlocksg

PC/Ms

78-16)-17)

Pressurizer

PORVs

Backup N-2 Supply; PC/Ms,78-23,-24,

OMS Test Switch and Relabel

Components

g

PC/Ms

81 162 ) 167 ) Installatian of Inadequate

Core

Cooling System Instrumentationg

PC/M 86-50, Nitrogen Backup Supply

Pressure

Regulatox

Replacement

for

OMSg PC/Ms88-396)

399)

PORV

Diaphragm Replacement

and Lockwasher Additiong and PC/Ms88-427,-

535,-565,

Pressurizer

PORV

Air

and

Nitrogen

Supply

Tubing

Enhancements.

The pressurizer

PORVs are spring-loaded-clased.

Air is recpxired to

open the valves and is supplied hy instrument air.

In the event of

a lass of instrument air,

a backup

N-2 system is provided which

will supply enough N-2 for a minimum of ten minutes of operatian.

Drawing 5610-M-339

shows the N-2 backup

system provided for each

PoRv.

Each

PoRv

has

two redundant

solenoid

valves

which are

energized in arder to open the

PORVs.

These solenoid valves fail

clased

an a loss of power.

However,

each solenoid is powered off

the

125 volt vital

DC supply.

Thexefore

on

a loss of offsite

power,

the

station

batteries

will be

available

to

allow the

aperation of the

PORV.

Drawings 5613-8-25,

sheet

64,

and 5614-E-

25) sheet

64,

show the wixing configuration and power supply for

the

PORV solenaid valves far Unit 3 and

4 respectively.

38

There are

two

PORVs

and thei.r associated

block valves vhich are

sham

an dravi.ng 5610-T-E-4501.

Zf one

PORV is i.noperahle,

the

remai.ni.ng

PORV i.s capable of relieving the RCS to prevent exceeding

Appendix 6 limits.

Zf the

PORV fails in the

open position, i.ts

assaciated

black valve

can

he

closed

ta isolate

the

PORV to-

terminate the pressure

transi.ent.

Dravings 5613-E-25,

sheet

27,

-and

5614-E-25,

sheet

27,

shav the wiring confi.guration for the

motor operated block valves.

By referencing the breaker list, the

inspector verified that

the

block valves

were

powered

from

a

separate vi.tal pover source.

The block valves are povered from the

vital

. portion of the

3B/C

and

4B/C

MCC'or

Uni.t

3

and

4,

respectively.

Each block valve fai.ls as, i.s.

The failure of ane

black valve villnat affect the operability of the associated

PORV,

therefore it would not create

a pressure transient.

Each'ORV

i.s apened

by the energisating

of. tvo solenoid valves

which realign to allov instrument air or N-2 to flov ta the

PORV

actuator.

These salenai.ds

are redundant

such that the fai.lure of

one will prevent the

PORV from=opening.

Zf the

PORV vas open and

the solenoid valve failed, the

PORV wauld fail closed.

Havever,

the

remaini.ng

PORV would not'e

affected

and cauld

be

used to

mitigate the;.pressure

transient.

Draving 5610-T-D-16A shovs the control system far the

OMS.

Each

PORV has its om svitch installed on the main control hoard.

The

operator can enable/disable

the

OMS hy selecting

>>LO Pressure

OPS>>

ar >>Normal OPS,>> respectively.

The setpoint pressure

and actual

pressure

are

derived

fram

redundant

temperature

and

pressure

transmi.tters.

PORV 456, vhich is the primary OMS channel,

uses

TE-

430B and PT-403.

PORV 455C, the backup

OMS channel,

uses

TE-423B

and PT-405.

Through

inspection

of responsible

maintenance

and

engi.neering

personnel activi.ties, the inspectors

deternd.ned that OMS, including

the PORV and block valves, are treated. as safety related equipment.

The folloving I f C maintenance

procedures

vere revi.eved to ensure

the

associ.ated

equipment

was

maintained

and calibrated

in

accordance

vith safety related

procedures:

3/4-PMI-041. 10,

RCS

Subcooling Margin Monitoring Train B Calihrationg 3/4-PMI-041.22,

Reactor Coolant Pressure,

1i.de Range,

P-3-405 Channel Calibrationg

3/4-PMI-041.39,

RCS

PORV Actuator Overhaul/Maintenance

PCV-*-455C

and PCV-*-456.

Operations

department survei.llance procedure 3/4-

OSP-041.4,

Overpressure Miti.gating System Nitrogen Backup Leak and

Functional

Test,

preforms

the

surveillance

required

by

TS 4.4.9.3.1.a.

The i.nspectors also reviewed the Total Equipment Data

Base vhich.lists all, components

and their safety classification far

systems

at

the

faci.lit@.

This list indicated that

components

associ.ated

vith

and

the

PORVs

vere

designated

as

safety

related.

The li.st of PC/Ms was revi.eved and all PC/Ms associ.ated

vith OMS vere classified

as

NSR or SR in lieu of NNSR or QR.

This

indicated all

PC/Ms associated

with

OMS were treated

as

safety

39

In addi.tian,

the

licensee

responded

to

Generic Letter 90-06,

. Resolutian oi Generic

Issues

70

and

94, in PPL letter L-90-396

dated

December

21,

1990.

Generic

Issue

70

addresses

~~Power-

Operated Relief Valve and Black Valve Reliahi.lity,>> and Generic

Issue

9h

addresses

I%4ditional

Lav-Temperature

Overpressure

Protecti.on for Light-Rater Reactors.>>

In summary, the licensee~s

response

to these issues indicated the

PORVs an4 block valves are

currently treate4

as ,safety

to the

Quality

Assurance

Program vith regard

to

the

TBDB,

maintenance,

and

procurement.

Zn

an effort to

determine if there

are

documented

defensible

calculations for OMS setpoints,

the inspector revieved the letter

fram

to

FPL

on

Heatup

an4

Cooldovn

Curve

and

Overpressure

Mi.tigatian System Setpoint Instrument Uncertainties

4ated

September

13,

1988.

The letter contained

a review af the

overpressure

mitigation system setpoints.

The letter stated in

part:

The

Overpressure

Mitigation

System

pravides

a

means

of

reducing

the

possibili.ty

of

Reactor

Coolant

System

averpressure

transients

from

exceeding

the

pressure-temperature

limits

on

the

reactor

vessel

during

heatup and cooldovn operations.

This is accomplished hy usi.ng

the

Pover

Operated

Reli.ef Valve~s

as

a

means

of reli.eving

potential cold overpressure

events.

f

Zn order to provide averpressure

miti.gati.on, the Overpressure

Mitigation System

senses

Reactor

Coolant

System

pressure.

Shen Reactor Coolant System pressure

exceeds the Overpressure

Mitigation System setpoint,

the Power Operated Relief Valves

are si.gnaled to open.

Due to control system delays and Pover

Operated

Relief Valve

opening

times,

the

Reactor

Coolant

System pressure vill overshoot the setpoint pressure

hy some

amount."

The amount of overshoot

depends

on the severity of

-the transient.

Zn

determi.ning

Overpressure

'Mitigatian

System

setpoi.nts,

therefore,

thi.s pressure

overshaot is accounted far so that

the design basis cold overpressure

transi.ent vi.ll not exceed

the Technical Specifi.cation pressure-temperatuxe

limits.

The

design

basi.s

transients

assumed

are

more

severe

than

transi.ents that might be expecte4 to accur at the plant.

Zn

addi.tion,

the

setpoi.nt

calculati.on

methodology

i.ncludes

several

conservatisms.

This

combination

of conservative

assumpti.ons

far

postulated

transients

and

conservative

setpoi.nt

calculations,

makes

the

additional

inclusian

of

instrument uncertainties

unnecessary

ta prevent vessel

damage

due to realistic plant transients.

40

The inspectars

concurred vith the

%estinghause

conclusian

that

because

of the safety margin designed into the limi.t curves,

the

setpaint

uncertainties

nee4

not

he

included

in

the

setpoints.

The inspector revi'eved

OMS - Pi.nal Report dated Rebruary 14'989.

This vas the final report on the evaluatian of the

PORV apening

times.

The inspector

revieved

the analytical

basis

for these

setpoints

and determined that they vere adequate.

The inspectors

revieved the safety evaluation JPN-PTN-SBMJ-88-076

calculations

for

PORV stroke times.

The safety

evaluati.on

concluded that for the most limiting-pressure transi.ent event the

OMS could mitigate the transient vi.th the teste4

PORV stroke times

as

long as

3.45

seconds.

The strake

time of 3.45

seconds

vas

beyond

the 2.0

second

PORV apening

time

speci. fied in the

Safety

Bvaluation

Report

dated

March

14,

1980.

The

NRC

had

previously

investigated

this

and

i.ssued

violation

No.

50-250,251/89-27-01.

The NRC revi.eved the licensee~s

response

and

'concurred

vith

the

corrective

actions

as

discussed

i.n

NRC

Znspectian

Report Nos. 50-250,251/90-25.

The

NRC has'valuated

the

OMS setpoints far adequacy vith respect

to brittle fracture at TPNP.

Beginning in June 1988, the NRC began

veri.fi.cati.an that the licensee

had implemented commitments relati.ng

to Unresolved Safety Zssue A-26, Reactor Vessel Pressure

Transi.ent

Protection.

The plant modified

PORV control ci.rcuits to provide

lov pressure relief settings.

The setpoints vere used to keep the

primary

loop belav

the

Appendix

G limits for low temperature

operations.

This is documented in NRC Znspection Report Nos. 50-

250 g 50 251/88

14 ~

The i.nspector revieved the

SBR issued hy NRC related to amen4ment

number 55 far,Unit 1 and amendment

number 47 for Uni.t 2.

The staff

concluded

that

the

assumptian

for

these

calculations

vere

conservative.

The

inspectors

revieve4

the

ariginal

pressure/temperature

limitations curve and the most recently updated curve.

The curve

had been appropriately updated to reflect plant aging.

The inspectors

determined that licensee~s

OMS setpoint i.s adequate

vith respect ta the higher hri.ttle,fracture susceptibili.ty at TPNP.

The inspectors

revieved the substantive

documentation

supporting

the validity af fracture toughness

methodolagy for calculating the

reactor

vessel

pressure/temperature

limits.

The

inspectoxs

revieved the recent history of radiation embri.ttlement of reactor

vessel materials at TPNP.

Zn May 1988, the

NRC issued Regulatory

Guide 1.99, Radiation Bmhrittlement of Reactor Vessel Materials,

Revi.sian 2.

The Regulatory Guide provi.ded the staff positian for

the implementation of General Design Criteria 31 of 10 CPR Part

50

"41

Appendix A.

General

Design criterian

31 also requires that the

design reflect the uncertainti.es

in determining

the effects af

irradiation

on

materi.aX

properties.

Appendix

G,

~Praoture

Toughness

Requirements,<>

and Appendix 8 ~~Reactor Vessel Material

Survei.llanoe

Program

Requirements,

~ ~

which 'implement,

i.n part,

Cri.terion 31> necessitate

the oalculati.on of changes

i.n fracture

taughness

of reactor vessel materials

caused

by neutron radi.atian

thraughout

the

service

lifo.

The

guide

described

general

praoedures

acoeptahle to the NRC staff far calculating the effects

af

neutron

radiati.on

embrittlement

of

the

lov-alloy

steels

currently

used

for light-water-cooled

reactor

vessels.

The

Advisory

Cammittee

on

Reaotor

Bafeguards

has

been

consulted

concerning this guide and has oanourred in the regulatory posi.tion.

On July 12, 1988, the NRC issued Generic Letter 88-X1g NRC Position

an Radi.atian

Embrittlement af Reactor

Vessel Materials

and Its

Impact

On Plant Operations.

The purpose

of the Generic Letter 88-11 vas to identify that

NRC intended ta use Regulatory

Guide

1.99 in revieving suhmittals regarding pressure/temperature

limits

and for analyses other than'pressurised

thermal shock that require

an

estimate

of the

embrittlement

of reactor

vessel

heltline

materials.

-On September

21, 1988,

PPL submitted

a proposed license

amendment

to incorporate revised pressure/temperature

limit curves that vere

applicable for 20 effective full pover years af service life.

The

new

curves

vere

developed

using

Regulatory

Guide

1.99

and

= therefore,

the submittal also satisfied the reporting requirements

of Generic Letter 88-11.

On, January

10, 1989, the

NRC i.ssued

Amendment No.

134 to Facility

Operati.ng

License

No.

DPR-31

and

Amendment

No;

128 to Pacility

Operating License No. DPR-41, in response to the September

21@ 1988

request.

As stated in the

NRC~s

SER vhich vas enclosed vi.th the

amendments,

the NRC staff found that PPL~s submi.ttal vas acceptable

and that the neutron embrittlement calculatian

vas in accordance

With Regulatory Guide 1.99.

Additionally, the inspectors

evaluated

the final deci. sion of the

ASLABg 50 250

Of% 4 and 50-251-OLA 4g dated June

24@

1991

which

concluded

that

there

vere

na

unresolved

issues

relative

to

pressure/temperature

limits for the reactor caolant system at TPNP.

Based on the reviev of the documentation listed above the i.nspectar

concluded that the determination of the pressure/temperature

limi.ts

at TPNP vere performed in accordance

with the latest industry and

regulatory

guidance.

Additianally, the

NRC concluded

that

the

current pressure/temperature

limits vere valid.

h2

CONCLUSZON0

LEQA

ON 9

0

SUBSTANTIATED

Based

on

the

above

documentation

and

inipection,

the

OMS is

designed,

maintained,

and operated

as a safety related. system.

The

methodology

useC

to

determine

setpoints

and

pressure/

temperature

limits

compl'y vith

the

industry

and

regulatory

guidance.

Consequently, this allegation vas not substantiated.

10 ~

RELIABILITYOP EXZSTZNQ SETPOZNT

PROGRAM

The statement of the concern vas as follovs:

e

est fo

NRC to

nvesti ate reliabilit of the existin

set oint

ro ram.

Prematurel

emoved

om set oint effort

for attem tin to extend this methodolo

to balance of lant

e i ment such

as

Ove

ressure Miti ation 8 stem.

DzscUsszoN.

To address this'llegation',

a

~~setpoint Methodology

Inspection>> vas conducted

on the PPL Instrument Setpoint Program,

including its

documentation,

implementation,

and

end

product

quality (i.e. setpoint calculations).

One objective of the SMI vas

to determine if the existing setpoint

methodology in use

by RPL

conforms

to

industry

standards

and

Regulatory

Guide

1

105'nstrumentation

for Safety-Related

Systems.

The

inspector

reviewed

the

Instrument

Setpoint

Program

document.

The

purpose

of the

document is to provide

the

philosophy,

management

commitment,

and description of the Nuclear

Engineering

Instrument

Setpoint

Program

vhich

= includes

the

folloving: provisions for documentation

of setpoints

for

safety'elated

instruments

and devices,

setpoint

change

and control,

and

setpoint methodology.

The inspectors

examined the current methodology used by PPL for the

calculation of setpoints.

The licensee

employs Nuclear Engineering

Department Standard Number ZC-3.17, Instrument Setpoint Methodology

for Nuclear Pover Plants,

vhich is consistent vith ISA standard

ZSA-RP67.04,

Part

ZZ-1991,

Craft

9,

Methodologies

for

the

Determination

of

Setpoints

for

Nuclear

Safety-Related

Instrumentation.

The draft ISA standard

reflected

a reasonable

'ndustry

consensus

for setpoint

methodology.

Standard

IC-3.17

basically implemented the ZSA standard.

Both Standard

ZC-3.17 and

the

ISA standard

vere vritten to

comply vith Regulatory

Guide

1 ~ 105 ~

The

licensee~s

program

contained

treatment

of

'individual

uncertainties,

combination of uncertainties,

and determination of

normal trip setpoint

and

allovable

value.

Additionally, the

43

licensee

actively

parti.cipate4

in 'he

i.ndustry

group

vhich

- developed the

ZSA standard.

r

The inspeotors

revieved

ZC-3.17

and determined

the methodologies

cantained in the standard vere accurate

and acceptable

to perform

the

recpxired

identifi.catian

and

cambination

of

instrument

uncertainties to ensure that vital plant protective features vere

actuated

at

apprapriate

times

during transients

and

acci.dent

canditions.

The standard

provi.des

the necessary.

methodology ta

ensure that safety limits defined hy the accident analysis vould

.

not be exoeeded.

The

RPS/ESRAS

setpoints,

vhi.ch are

the

most safety si.gnificant

setpoi.nts,

have been calculated using the latest %estinghouse>>five

calumn>>

methodology vhich clasely parallels

that of ISA 67. 04.

Maintenanoe prace4ures

vere vri.tten to account for the calculatian

assumptians.

Scaling calculations

and a draving vhi.ch li.sted both

the praoess

an4 calibratian units vere also prepared.

The licensee

commission'ed

an i.ndependent reviev hy an Zac systems

consultant.

The inspector revieve'd Turkey Point Setpai.nt Cantrol

Assessment

.Report

dated

September

25,

. 1991.

The report

vas

a

thorough, critical, and independent laok at the licensee~s

setpoi.nt

program.

The

report

i4enti.fied

some

strengths,

some

minor

veaknesses,

and a fev recommendations

for improvements.

Rar the

identi.fi.ed veaknesses,

RPL

has

initi.ated corrective

actian

ta

improve the practices

i.n the'se

areas.

Overall the

TPNP setpoint

control pracess

vas evaluated

hy the consultant

as heing

on par

vi.th the rest of the industry and cansi.derably hetter than most

plants of this vintage.

I

, Another. objective of the "SMI vas to determi.ne hov RPL insures that

the i.nformation the existing setpoints vere based upon i.s accurate.

The licensee

us'ed the folloving sources:

1.

Information verified in Rail of 1988

Instrument Index

Total Equipment Data Base/Q-List

Instrument Calibratian Pr'aoedures

Eagan

Loop Dravings

PC/Ms

Plant Iork-Orders

-

Selective

valkdavns

to veri.fy

any

changes

implemented

This informati.on vas re-veri.fied in July,

1991.'.

Numerous valkdowns vere performed vhich included:

Environmental. Qualification revi.ev

Regulatary

Guide 1.97,

Rosemount Part 21 on oil.loSs reviev

44

3 ~

Eagan

7100

modules

are not physically compatible

vith components

'of other

vendors

and therefore,

cannot be intermixed in the

RPS cabinets.

4.

The licensee

performed

confirmatory valkdovns

on

October 30, 1991.

These valkdovns included:

First stage turbine pressure transmitters

(PT-

3-474,-484,

and

-485)

vere verifi.ed to

be

Rosemount

Model 11536B9.

This vas consistent

vith the

methodology

and

resulted

in

%CAP

12745 ~

Eagan

"rack

for

instrument

loop

P-4-456A

(Pressuriser

Pressure)

vas verified to

be

,consistent

vith methodology

and results

in

WCAP

12745.

This

confirmed that

the

loop

consisted

of four single input comparators,

one lead/lag module,and

a pover supply.

Model

numbers

vere

verified

vtth

maintenance

instruction 4-PMI-041. 69.

The

inspectors

revieved

applicable

portions

of

WCAP-12201,

Setpoint

Methodology

for

Protection

System,

Re&sion 1.

The revised engineering

VCT calculation vas

, performed in accordance vith the applicable portions of WCAP-12201

methodology,

vith modifications for non-safety

functions.

The inspectors

concluded that the VCT calculations,

as

discussed in paragraph

2,

had been performed satisfactorily.

The

current

methodology

used

by

PPL for the

caIculation

of

setpoints

vas

inspected

to determine if the existin'g setpoints

presented

a safety concern.

The inspectors revieved the licensee~s

independent

calculations

of various

setpoints

to 'see, if the

differences

present

a

safety.

concern.

While there -vere

some

methodology,

assumption,

and calculational errorsg the errors vere

minor

and

did

not significantly affect

the 'conclusions.

The

variations vere not the result of significant techni.cal differences

and vere minor enough to not present

a safety concern.

~

The

inspectors

selected

several'etpoints

and

calculated

the

results

independently.

The resulting

differences

between

the

inspectors~

independent calculations

and the PPL calculations vere

vithin an acceptable

band.

In each case,

the ansvers reflected

a

reasonable

consensus

betveen the tvo setpoint calculations

and did

not present

a safety concern.

One aspect

of, this concern is that the alleger

vas prematurely

removed

from the setpoint effort for attempting to extend this

methodology

to

balance

of plant

ecpxipment

such

as

OMS.

As

discussed

in paragraph

9,

the

OMS is designed,

maintained,

and

operated

as

a safety-related

system.

The methodology

used

to

determine

OMS setpoints

and pressure/temperature

limits comply with

the industry

and regulatory guidance.

The inspectors

concurred

i5

with the Nestinghouse

conclusion that because af the safety margin

designe4

i.nto the current pressure/temperature

limit curves,

the

OMB setpoint

uncertainties

nee4

not

he

i.ncluded

in

the

,setyoints.

Additionally,

the

conclusion

that

the

current

pressure/temperature

limits vexe valid and that the licenseeis

setyoint

vas

adecpxate

with respect

to

the brittle fracture

susceptibi.lity at TPHP vas accepted

hy the

NRC in the ammendments

listed above.=

/

Another objective of the SMI vas ta inspect the licensee~s

actions

vith respect

to .extending

setpaint

methodology

to

BOP.

Their

program vas divided into tvo basic parts:

1.

Placing the safety and non-safety related (including BOP)

setpoints into a central sitpoint dacument,

and

2.

Reconstructian of the setpoint design bases.

The effort to provide

a single consoli4ate4

Instrument Setpoint

Document

whi.ch contains all setpaints

(including 4esign

bases),

both safety and non-safety related,

i.s considered

hy the

NRC to he

an impartant.enhancement

and villhe falloved as IRI 50-250,251/91-

45-0i,

Create

a single

Instrument

Setpoint

Document

(including

design bases)

~

Entering the safety related

and

BOP setpoints

into the setpoint

index draving vi.ll involve several sources of setpoint information.

BOP

setpoints

from controlled

plant

dravings

other

than

the

setpoi.nt index (instrument index,

PRXDs, etc.)

and setpoints

fram

other

sources

(RBAR, plant

pracedures,

vendor

manuals,

vendor

dacumentatian,

etc.) vill he transferred into the setpai.nt

i.ndex

drawing after

an apprayriate

level of engi.neering

review.

This

review would in fact be similar to the

method

i.n vhich vendor

setpoints

vere originally placed

into plant dravings.

As the

setpoint index is a draving controlled by Engineering, the setpoint

additions

and any other future changes

requested

by the plant to

the contents of the dxaving vill require

a

PC/M to evaluate

the

acceptability of the additions or changes.

The process of reconstructing the design basis of BOP setpoints is

4esi.gned to include both planned

and future activi.ties.

Any BOP

setpaint

calculati.ons

which are

discovered

through, the safety-

RPL

Instrument Setpoint Program dacument) willbe retxi.eved and entered

i.nto the

Nuclear Engineering

calculation

database.

The actual

setpoint

values vill alsa

be

included in the

setpoint

index

draving.

Recovery of the safety-related

design basis information

has

been yrioritised

ahead

of

a

BOP effart.

Therefore,

an

evaluation of the needs of a BOP infarmation reconstruction villhe

made at the conclusion of the safety-related effort.

46

CONCLUSION

.

LEGATION

0

NO

SUBSTANTI TED

The

FPL setpoint

methodology for safety -related'nd

bal'ance

af

plant systems. is described in the PPL Instrument Setpoint Program

document.'ased

on standard

industrr practice

the

method. the

licensee

vas

using

for, safety

- relate4

and

BOP

setpoints

is

acceptable.

While it is appropriate that the rigor required for-

safety related setpaints is not necessary

far,BOP setpoints,

the

licensee

does have a documented program to collect or recalculate,

as necessary,

safety related

and

BOP setpoints

(including design-

hases)

on a safety prioritised basis.

11.

uestianable

en ineerin

ractices exist throu haut the

nuclear

ra ram.

DIscUssIoN:

This allegatian is nonspecific

and is considered

ta

have been addressed

hy the in'spectian of the other allegations in

this inspection report.

\\

CONCLUSION.

LEGATION 11

NOT SUBSTANTIATED

Based

on the results of this

team inspection,

the existence

of

questionable

engineering 'practices

@as not substantiated

.

4

12 ~

MISCELLANEOUS, RELAY RACKS

PART 21 NOTIFICATION

The statement of the concern

was 'as follows:

iscellaneaus

cabinets that contain rela s ar other com anents

that

ma

erfarm safet

and 'critical control functions

Part

21 Notification .

These

cabinets

dan~t satisf

electrical

se aratian criteria ar seismic

alificatians.

Rith respect

to electrical separation criteria the team revieved

whether

or not

, the

plant

meets

the

electrical

and

physical

separation

requirements

imposed

on

safety-related

circuits.

Focusing

on miscellaneous

relay racks

QR 46

and

QR h7 for hath

units,

the design basis

separation criteria was

compared to the

actual installation.

In addition, the li.censee~s safety evaluation

for a 10 CPR 21 report, JPN-PTN-SENP-91-006,

Safety Evaluatian for

Safety

Functions

in Miscellaneous

Relay

R'acks,'as

revievedg

because it had a hearing

an

QR i6 and

QR 47.

47

I

The inspeotar valked dovn the subject relay racks vhi.ch are lacated

in the contral

room behind the

main control panel.

, They vere

furnishe4

hy %estinghouse

Electric Corporation

as part of .the

original plant equipment.

QR 46 and

QR 47 are side hy side vi.thi.n

one six feet vide hy six feet high structure.

They have

one

and

ane

half feet

deep

relay

compartments

in

a

hack-ta-hack

configuration.

There

are frant

and

baok

hinged

daors.

The

structure i.s of formed heavy gauge sheet metal> bolted together and

velded to

a hase

vhioh is seourely bolted in place.

External

viring enters

through an opening in the top and conduits through

the bottom.

The miscellaneous

relay racks contain

120 Volts AC,

120 Volt's DC and 125 Volts DC auxiliary relays vith instantaneous

cantacts.

Baoh cabinet contains one timing relay, terminal blocks,

fuses

g and vi.revays

.

The re 1ays in

QR 46 and

QR 47 are used

as

annunciator

relays (i..e., to pravide

a dry contact to the plant

annunciatar)

and for contral lagi.o funetians.

Appraximately 68 of

the

540

relays

are

required

to

have

safety

qualifi.cati.on and the remainder are non-safety related.

All the

relays must have

some type of seismic qualification.

None of the

relays vere part of the RPS.

A report s'ubmi.tted by Westinghouse Electric Corporati.an pursuant ta

10

CRR Par't

21,

presented

some

possible

generio

prahlems vith

mi.scellaneaus

relay racks,

and it therefore applied to QR 46 and QR

47.

The Part 21 report vas.submitted to the

NRC on June 24, 1991,

and issued to the site on July 18,

1991.

The report stated that

the mi.scellaneous

relay racks vere not furnished as safety-related

or seismically qualified.

Hovever, it had come to the attention of

Westinghouse Electric Corporati.on that a fev plants

(TPNP vas not

mentioned)

vere using relays in these

racks far safety related

functians,

had routed non-safety related cables

emanating

from the

racks tagether vith safety related cables outside the racks, or had

i.nadvertently, mixed safety related

and non-safety related vires

inside

the racks.

The lioensee

had

performed

evaluations

and

continues to perform evaluations ta address

the potential prablems

rai.sed in the Part 21 report.

The team revieved these evaluations

and the planni.ng document for ongoi.ng vork.

The relevant requirements

may he summari.zed

as follovs:

As stated

in

RSAR section

8.2.2,

pover

and

control

ci.rcuits

to

the

dupli.cate

equipment

are

routed

in

separately

located cable trays,

ducts,

conduits, etc.,

vi.th

one foot approximate

separition

(horizontal

and

vertical') betveen racevays.

Redundant safety related and non-safety related oircui.try

shall be electri.cally separate.

Xt is nat a requirement to provide physi.cal separatian

(other than normal canstructi.an)

betveen safety related

and non-safety related cables in racevays.

48

It is ~at

a requirement to provide.speci.al

separatian

hetveen

wi.res associated

vi.th redundant

safety related

.devioes

and non-safety related devices vithin cabinets.

As part of addressing

the Part

21

concerns,

the

licensee

had

=determined that QR 46 and QR 47 vere seismically quali.fied hy using

valid analytical techniques.

This analysis

vas reviewed hy the

team.

Where arguments of similarity vere made, the similarity was

confirmed hy on-site inspe'otion..

The great majority of relays vere

quali.fied

by testing.

A fev relays

vere

determined

to

be

seismically qualified hy using industry accepted

procedures

for

older plants.

The team also noted that a previous inspecti.on

(NRC

Inspection Report Nos. 50-250,251/89-203)

had addressed

the seismic

adequacy. of the misoellaneous relay racks and found it acceptable.

With respect

to the

MRR quali.fication,

the .inspectars

reviewed.

Calculatian No. PTN-BRJC-91

009@ Rev

0, for seismi.c qualificati.on

of the MRRs, i.ncluding the sheet metal cabinets, internal mounting/

devices

located vithin the

cabinet's,

and cabinet 'anchorage-to-

ground.

This calculatian vas generated

hy the licensee ta evaluate

the seismic adequacy of MRR Nos.

3QR46,

3QR47,

4QR46,

and

4QR47 in

response to letter No. RPX-91-587, July 18'991@

from Westinghouse

Electri.c

Corporation.

The letter

informed

the .licensee

that

Westi.nghouse Letter NS-NRC-91-3603 to NRC, dated June 24', 1991, had

identified this issue as*a potential Part 21 Report.

The letters

described the potential for the existence of a substanti.al

safety

hazard concerning the installation of the safety related equipment

in. non-safety related relay racks.

The

licensee~s

engineers

perfarmed

walkdavn

inspections

and

recorded physical description

and installation. information about

the above four racks as veil as tvo safety related

RPS Racks,

3QR33

and 4QR33, for oomparative purposes.

The safety related racks were

seismically qualified hy Westi.nghouse previously.

The two sets of

racks are essentially the

same except for,the presence

af plastic

channels for the routing of viring and only 56 relays on the racks

for 3QR33 and 4QR33, vhile the set of non-safety related racks have

no plastic

channels

and

80 relays

on the

racks.. The veight

difference for the tvo sets of relays is only 46 pounds far each

face af a fully-laaded panel.

The above load increase for the non-

safety related racks is very small compared to the total veight or

load of the entire

cabinet.

The

peak

seismic

factor for the

safety-related

rack is eight percent

higher than the non-safety

due, to different locati.ons

and elevations

i.n the

cantrol building.

The higher seismic factor of the safety related

racks affsets the veight increase in the non-safety related racks;

The calculation

also qualified the

cabinet

anchorage-to-ground

based

on the comparison of the various testi.ng data performed hy

Electric

Paver

Research

Institute

and

the

)udgment

af .the

experienced

valkdown

. personnel.

The

licensee

piovided

a

supplemental

ancharage-to-ground

calculation to NRC on November 8,

1991.

The supplemental

calculati.on demonstrated

that the three-

49

eighths

inch diameter

redhead

anchar

bolts

which

anchored

the

cabinet

to

the

graund

vere sufficient to resist

the

cabinet

overturning during,.an earthquake

based

an the total cabinet veight

and

seismic

factor.

The

licensee vill make

this

a

formal

calculation to document the additianal evaluati'on of the ancharage-

to-ground.

Two main

references

used

in the calculation .are:

Mestinghouse

Document %CAP-7817,

(Deoemberg

1971) g Seismio Testing

of Electrical and Control Equipment

(Lov Seismic Plants); Electric

Pover

Research

Znstitute

Document

No.

NP-7148-M,

Procedure

for-

Evaluating

Nucleax

Power

Plant

Relay

Seismic

Functionality,

.

December,

1990.

Based

on

the

licensee

valkdovn

inspections,.

evaluation,

and comparison,

the calculatian is acoeptable

and

MRR

is considered to be seismically qualified.

Since'he

racks and relays vere qualified, it vas aoceptable

that

some af the relays be used for safety related funct'ions.

The team

made spot checks of the routing of external safety related cables

'manating

fram the miscellaneous

relay racks

and faund that the

above mentioned- requirement far-separatian

vas met.

The licensee is in the process

of performing a study of 100% of

circuits that cantain devices or viring in the miscellaneous. relay

panels.

The

study vill'ddress

specifically

vhether,

or not

annunciator circuits are electrically separate

from the

RPS pover

supply.

The study vill also reviev the routing of safety related

cables

emanating

from

QR

46

and

QR

47

to

confirm that

the

separation criteria is maintained.

At the time of the inspection,

the

study

vas

about,

654

complete vith no problems

having

been

identified.

The licensee stated that the study is proceeding at a

.pace that vould guaxantee

completian befare

March 15,

1992.

NRC

villreviev the final results of this study,

ZRZ 250,251/9l-i5-05,

MRR annunciator circuit relays separation

fram RPS power supply.

This allegatian

also

questioned

the credibility af

10

CRR Part

50'9 evaluations.

One issue raised

as part of this concern vas

that

the

Nuclear

Engineering

Lead

Team

Meeting

Minutes

dated

September

3,

1991,

made

a statement,-

which may be contrary to 10

CRR Part 50.59,

as fallovs:

Design

Defense .means

defending the design until it is

proven

wrong.

Zf the

design is vrong it vill be

modified.

The

inspectors

obtained

the

falloving clarification af

this

statement

fram the Directar, Nuclear Engineering,

RPLg on Octaber

30 j 1991

Bring me the design basis

and show me where it is vrong.

Zf the. design can be proven to be vxang, then it vill be

madified.

Zf it can not be

shown where the design is.

wrong, then the design is- defensible.

50

The

inspectors

determined

that

the

above

statements

are

not

contrary to 10 CFR Part 50.59.

-The following evaluations

were inspected

by the team to determine

the

adequacy

af the li.censeeIs

10 CFR 50.59

evaluatians.

The

inspectars

reviewed

the

10 CFR 50.59

evaluation

perfarmed

to

evaluate

the

lowering of low pressure

Safety Injection Safety

Analysis Limit

The evaluatian satisfactorily adCressed

the change

to the plant as described in the FSAR.

The evaluation was complete

and factual.

The inspectors

reviewed the

10 CFR 50.59 evaluati.on perfarmed ta

evaluate

the

VCT level switch replacement

which was contained in

PC/M

91-037

and

PC/M

91-038.

The

evaluation

sati.s factorily

addressed

the

10 CFR 50.59 criteria.

The evaluatian

was complete

and factual.

The inspectors

reviewed the

10 CFR 50.59 evaluation performed to

evaluate

the upgrade. of the conductivity sample

system for steam

generator

-blawdown,

condensate

- pump

discharge,

feedwater,

and

condenser

hotwell

which

,was

contained,.in.,PCjM

90-342.

The

modification..was

not safety 'relited;.,=, However,- portions of the

system were"designed far sei.smi.c-.2, iver 1 concerns.'he

evaluatian

satisfactorily'addressed

the 10 CFR 50.59 cXiteria.

The evaluatian

was complete

and -factual.'

The inspectors

reviewed the

10 CFR 50'9 evaluatian

performed to

evaluate

the

Generic Letter 89-10,

Motor

Operated

Valve

Enhancements,

whi.ch

were

contai.ned

i.n

PC/M

91-004.

The

modification i.nvolved the modification and/ar additions to safety

related Limitorque valve actuators for the following motor operated

valves:

MOV-3-626, Reactor Coolant

Pump Thermal Barriers

MOV-3-

744A/B

Residual

Heat

Removal/Low

Head

Safety

Ingectian

Pump

Discharge Isolationg MOV-3-1400, Main Steam Isolation Valve Bypass

Isolation; MOV-3-1401, Main Steam Isolati.on Valve Bypass Zsolation;

MOV-3-1402, Mai.n Steam Isolation Valve Bypass Isolation; 3-MOV-1420

Steam

Generator

Feedwater

Pump

Discharge

Isolation;

3-MOV-1421

Steam Generator

Feedwater

Pump Di.scharge Zsolati.on; MOV-3-866A/B,

High Head Safety Injection to Hot Leg Isolationg and MOV-0-878A/B,

Safety Infection Cross-tie Isalati.on.

The modifi.cations replaced

or upgraded various components in the valve actuators to ensure the

motax operated valves would perfarm thei.r intended safety functians

during the maximum expected di.fferential pressure

conCiti.ons.

The

evaluati.on

satisfactorily

addressed

the

10 CFR 50.59 criteria

i.ncludi.ng Technical

Specification

changes.

The evaluation

was

complete

and factual.

The

inspectors

reviewed

the

10 CFR 50.59

safety

evaluatians

performe'C for PC/Ms90-331 and 90-332,

>>C>> Bus Transformer Deluge

System >>Power Available>> Light.

These

PC/Ms involved installi.ng a

power available li.ght to the>>C>>

Bus Trans formex

Deluge

System

control panel

(4c 259) which willpermit visual i.ndicati.an of power

51

available to the deluge controls.

The deluge

system requires

120

volts AC power ta operate autamatically.

The PC/Ms vere determined

to he quality related because

they involved modifications to the

fire protection

system.

The safety

evaluations

vere

complete,

factual,

and adequately

addressed

the 10 CFR 50.'59 criteria.

The inspectors held discussians

vi.th li.censee persannel

concerning

thei.r efforts ta improve the overall quality of engineering design

outputs

and services.

One effort involves technical assessments,

perfaxmedby the Engineering Assurance section within JPH, of PPL

architect

engineers

and

contractors,

inoluding

the

Praducti.an

Engineering

Group vi.thin JPN.

One of the

axeas

revieweC vithin

Production

Engineering

Croup

vas

PC/Ms,

vhioh

included

the

assumptions

and

design

inputs

used in applicable

10

50.59

safety evaluations. 'he review af selected

PC/Ms is performed hy

the Discipline Chicfs.

The reviev

may i.nclude

the applicable

design

engineer

heing

called

upon

ta

I~defend<>

the

vari.aus

assumptions

and design inputs included in the

10

CPR 50.59 safety

evaluatian.

This effort is

intended

to identify potenti.al

veaknesses

and verify the averall technical

adequacy of the 50.59

safety evaluations.

a li

In. addition"ta the above

10 CPR 50.59 safety evaluati.ons

PC/M

d

pp

oable

10

CRR 50.59 safety evaluatians

vexe also reviewed and

s an

discussed

in NRC Inspection Report Nos. 50-250,251/91-32.

After

reviewing selected

10

CPR 50.59 safety

evaluations

during this

inspectian

and

during

the

inspection

documented

in the

above

inspectian report, the inspectars

found that, while there vere

a

few

veaknesses

identified for specific

10

50. 59

saf ety

evaluations,

the licensee~s

overall program vas adequate.

CONCLUSXON.

LEGATXON

2

NOT SUBSTANTIATED

Xnadequate

evaluatian

of the

MRR

vas

not

substantiated.

The

licensee

vas appxopriately evaluating the

10

CPR Part

21 report.

The MRRs have been seismically qualified. The team made spot checks

af the routing af external safety related cables emanating fram the

MRRs

and

found that they met the previ.ously described

standard

the

electrical sepaxation

requirements.

PPL has

an ong i

t d

e MRR relays to verify that electrical separation criteria is met

date.

T

inside the cabinet.

No safety prablems

have not been id tifi.

he study is scheduled to he completed by March 31,

1992.

i5 05

MRR

HRC villreviev the final results of this study

ZPZ 50-250

25 /

t

g

1/91

MRR annunciatox circuit relays

separation fr m

RPB

pp y.

Por those

10

CPR 50.59 safety evaluations,revi.eved,

a

safety

concern vith respect

to the

10

CPR 50.59 progr

t

substantiated.

13 ~

GRAVE DEPXCIENCIEB

N PLANT CONFIGURATION.

The statement of the concern vas as follovs:

6

VE DEPICXBNCXBS

N PLANT CONPIGURATION AND IN THE COHERENCE

0

PPL ENQXNEERINQ

UPPORT ORQANISAT ON

DIBCUBBION:

Thi.s allegation vas made vith respect to the Eagle 21

system.

The detailed

concerns

identified by the

allegex'= vere

previously identified hy the licensee

and vere being inspected

hy

the

NRC prior to receiving the allegeres letter.

The results of

the initial inspection are documented in NRC Inspection Repoxt Nos.

50-250,251/91-42.

The Allegation

Team Inspection

continued

the

i.nspection into the Eagle 21 configuration control concern and are

closi.ng

the

folloving unxesolved

item:

(Closed)

URZ,

50-

250 251/91-42-02) Pollovup on non-plant speci.fic settings

i.n Eagle

21 portion of the RPS.

The

licensee

contracted vith the

NBSS

supplier. to furnish

an

upgrade

system

vhich

i.s

a

microprocessor-based

functional

replacement for the originally installed analog process protection

equipment.

" This

system

is

called

. Eagle

21;

The

system

vas

developed

hy the

NSSS for application on any of the nuclear pover,

systems vhich it has manufactured.

%CAP - 12858 vas i.ssued vhich

documents the implementation of the Eagle 21) Replacement

Hardvare

Design, Verification and Validation Plan,

as

applied to Turkey

Poi.nt

Units

3

and

4.

The

Eagle

21

portion of

the

process

instrumentation includes all necessary

devices for the functional

replacement

of the existing analog

process

protecti.on

equipment

used to monitor process

parameters

and initiate actuati.on of the

reactor

trip,

and

engineeri.ng

safeguards

systems

except

the

transmitters,

indicators,

and recorders.

The system processes

the protection

and monitoring channels for:

A. T

and Delta T

B. Pressuriaer

Mater Level,

C. Reactor Coolant %ide Range Temperature

(Monitoring only)

Since this system is

a programmable

processor

the various plant

parameters

vere

programmed

into the

system.

The suppli.er

used

informati.on available from other souxces

(generic)

and set poi.nts

vhich vere

supplied

by the licensee.

The

NSSS

performed

pre-

shipment factory testing of the system at the point of manufacture

using generic programmable constants

based

on the information that

vas available to them.

They then installed the system at the site

and

performed

on-site

startup

tests still using

the

generic

constants.

53

On September 27, 1991, the licensee vas performing procedure

3-OSp-

059.i,

Power

Range

Nuclear

Instrumentation

Analog

Channel

Operational Test, in preparation, for low paver physics testing on

,Unit 3.

During this test,

the

PSN observed that the

Overpower

Delta

T meter, for RPS

channel

2 responded

to a delta flux test

signal

from pover

range

channel

N42,

when it should

not have.

Purther

investigation

determineC

that

incorrect

constants

for

Overpower Delta T calculations had been left in the nevly installed

Eagle

21 system.

This problem vas verified to not exist

on the

other similar channels

on Unit 3 and those

on Unit i.

A pre-operational test had been conducted to test all functions of

the system,

regardless

of intended use.

Thus, constants

to test

the delta flux function of Overpower delta T vere installed Curing

the

preoperational

test.

The

procedure

recpxired

that

plant

specific, constants

be installed following the preoperational test,

but that

vas

not accomplished for channel

Ni2,

and

a non-sero

constant

remained for th'e delta flux function.

The licenseeIs

calibration an4 surveillance procedures

Cid not test the delta flux

function in the

Overpower Delta

T circuits,

because it vas not

expected

to exist (i. e. tuning constants

set to sero).

Thus,

detection of. the Overpover Delta T response

to.a change in delta

flux vas

the

result

of

an alert

operator

vho

recognised

an

inappropriate

and unexpected

response.

=The existence of the delta

flux function is not

a safety

concern

because it conservatively

reduced

the trip set point for all extreme values of delta flux.

- However,

the existence

of an incorrect constant in the 'Eagle

21

system

vas

a concern.

The licensee

conducted

a review of all

constants

in Eagle

21

as

a result of this observation.

.

Pour-

constants affecting the output of tvo RTDs by about 0.10 degrees,

P

each

were.

found to be in error.

Three

constants

of overpower

turbine runback vere

foun4 to be 1.12 degrees

P before the, trip

setpoint instead of the desired

1.50 degrees

P.

The span of the

three

Delta

T lead-lag circuits vas

found to be

150 degrees

P,

" vhich vas

inconsistent

vith the

75 degre'es

P

span

used in the

remain4er of the Delta

T circuits.

This inconsistency

did not

affect the rate output of .the circuit.

The licensee

performed

several safety evaluations,

which vere reviewed by the inspectors,

in order to determine

the safety impact of the above conditions.

1n

perspective,

over=

600

constants

vere

reviewed;

10

vere'iscrepant,

and none of the discrepancies

adversely affected the

.performance

of the protective circuits

and the Eagle

21

system

remained operable.

On October

5,

1991, vith Unit

3 in Mode

1 at

50% pover,

the

licensee

vas

performing

the

planned

Incore/Ezcore

detector

calibration

at

the

50%

pover

plateau.

This calibration is

routinely performed both during post refueling pover ascensions

and

quarterly

during

the

cycle.

When

attempting. to

input

the

calculate4 scaling factor (6-Pactor) for Overtemperature

Delta T,

the

inputs

vere

not

accepted

by

the

Eagle

21

system.

The

calculated factors vere approximately 3.2,, and the .system vould not

54

accept

a

scali.ng

factor af

greater

than

3.0

which

was

not

sufficient

ta

obtain

Che

required

. gain

for

the

delta

flux

functions.

The licensee held the unit at=-50% power, evaluated the

safety of continued operation,

and began an'nvestigation into the

~

raot

cause.

Thi.s

problem

requi.xed

the

replacement " of

a

pxogrammable'hip

(EpRDM)

whi.ch

was

subsequently

provided

hy

Nestinghouse,

and the system was satisfactorily calibrated prior to

continued power ascension.

This condition was reviewed by safety. evaluation JPN-PTN-BEPJ-91-

039, Revi.sion 0, Safety Evaluation to AllowOperatian at Nominal 50

Percent

Power with Eagle 21 6-Pactor Zimitation (Turkey Poi.nt Unit

3).

.The safety evaluation

concluded that

no unreviewe4

safety

questions

existed

and that the plant was operating within i.ts

TS ~

,

The evaluation also cancluded that continued operation at or below

50% power unti.l calibration of the Ovextemperature

Delta

T 'tri.p

'etpoi.nt

was -changed

was acceptable

because

the revi.ew of design

. bases

events concluded that the power range trip; which was set at

80% power, would be actuated earlier. than the Overtemperature

Delta

T trip providing the required protectian.

Performance

of thi.s

calibratian at. 50% power .with the

power range txip'et at

80%

power, is the result of admiiistrative cantrals

desi.gned to prevent

the

plant." fram

operating

outsi4e

its

design

hasi,s.

This

calibration

must

be

completed

prior to

the

power

range

txip

.

setpoint heing set abave

80%.

The Nestinghouse

conclusion that the

power range trip would actuate

before

an Overtemperature

Delta

T

temperature

provided

the industry

bases

for allowing plants

to

perfarm the subject calibrati.ons Curing the normal power ascensian

procedure at reduced power.

The safety evaluation also stated that

when. the axial flux i.s maintai.ned within band

(where the band is

between

-14% and, +104 flux difference),

there is no contribution

from the delta flux functi.on to the Overtemperature

Delta

T trip

setpoint.

)

On October

7,

1991, with Unit

3 at

50% of rate4

power,

during

calibratian of the new digital instrumentation rack (Eagle 21) the

Delta T Subzero

factox used in calculating Overpower Delta

T and

Overtemperature

Delta T hy setpoint farmula was found ta he set at

.

, the design value of 56.1 degrees

P in lieu of the indicated value

as required

by TS.

TS 2.2.1 requires that indicate4 values of

Delta T at xated thermal power be used for Delta T Subzero in the

calculation of Overpower Delta

T and Overtemperature

Delta T.

A

review of the operational history atTPNP prior ta the

RTD bypass

elimination modifi.cati.on (accomplished

during .the

1991 dual unit

outage)

xevealed

Chat indi.cate4 Delta T at rated thermal powex has

been as low as 53;8 degrees

F.

Presently,

the indicated values of

Delta

T at rated thermal power are (in degrees

P)

as follows:

55

,",Lciop,: lD'il'tip,T+~"".":;;;

Unit 3

Unit 'i

51'7

52'2

B

51'8

53'2

52'8

52'3

The licensee

performed

a detailed safety analysis to assess

the

safety significance of the use of the Delta T design value-of 56.1

degrees

P for Delta T Subzero in the setpoints for Overpower Delta

T

and

Overtemperature

Delta

T.

The result of this

analysis

indicated that the affecte4 parameters for DNB and peak linear heat

rate remained within the analysed design basis for both units.

The

licensee

as part of the safety evaluation

determined that power

operation could continue up to 75% reactor power using the design

Delta T value.

Using

the

safety

evaluation

as

a

basis

for

~

continued

operation,

the licensee

proceeded

to escalate

to

75%

power

on October 12,

1991

and

completed

entering

the indicated

Delta T for Delta T

Subsero

on

October 14,

1991.

This

same

approach

was used for Unit i which went critical on October 27,

1991 and reached

75% power on November 3, 1991, at which time the

Unit i indicated

Delta T

was

entered

in place

of the

design

Delta T.

TS 2.2.1 requires reactor trip system i'nstrumentation

and

interlock setpoints be set consistent with the trip setpoint values

shown in Table 2.2-1.

In TS Table 2.2-1, Overtemperature

Delta T

refers

to

Note 1,

and

Overpower

Delta T

refers

to

Note 3.

Table 2.2-1 Note

1 and Note 3, both define Delta T Subsero

as the

indicated Delta T at .rated thermal power.

The'se of the design

Delta T

(56.1

4egrees

P) in lieu of the indicated Delta

T for

computing Overpower Delta T and Overtemperature

Delta T, was non-

conservative

and a violation of TS 2.2.1 and willbe tracked as VIO

. 50-250,251/91-I5-03, Failure to use the correct Delta T Subzero for

, calculation of the Overtemperature

Delta T and Overpower Delta

T

setpoints.

This condition was reviewed and documented in safety evaluation

JPN-PTN-SEPJ-91-i0,

Evaluation of Delta-T Subzero

Used in

Overtemperature

Delta T and Overpower Delta T Reactor Protection

Setpoints.

The review of the Delta T setpoints,

by the licensee

and

NSSS vendor, confirmed that a 10 degree

P margin existed for

the setpoints,

without violating DNBR and linear power density

limits.

The 2.3 degree

maximum recor4ed error in the setpoint

was

well within that bound.

Furthermore,

the

10 degree

R margin

yields a tolerable overpower trip setpoint of 118% RTP, which

bounds the error-induced setpoint of 11i% RTP.

During the .NRC review of the safety evaluation JPN-PTN-SEPJ-91<<40,

the following arguments

were considere4 but given no weight in

support of the above conclusion.

56

The argument that the actual

RCS flov is greater than that

used in the analysis by virtue of the measured

Delta T being

less than the calculated Delta T vas not a justifiable

conclusion.

Zt is veil knovn.that the flov in the hat legs

of this class af 'reactors is not veil mixed and that the

measured

hot leg temperature is not the mixed mean

temperature.

That situation, prevails vhether the hot. leg

temperature is measured in bypass-loops

or hy direct

immersion RTDs.'urthermare,

other reactars

have experi.enced

an increase in the apparent.hot

leg temperature after removal

of the bypass loops.

,At TPNP, apparent hot leg temperature

decreased

after removal of the bypass

loops and installation

of the

RTDs in thermal veils vithin the hot legs proper.

Since the veils replaced. the scaops for the bypass loops, it

is possible that the hydraulics af this facility favor

measuring the cooler portions of the flov stream.

The argument that the hot channel factors for this facility

- have been constant

over time is not correct.

Xt is true

since replacement of the steam generators in approximately

1982, hut, during 'aperation vith the original steam

.

generators vith'

high percentage

af tubes plugged,

the hot

channe1 factors vere much more restrictive.

At the

same

time, the measured

Delta T Subgero

may have been claser to

the setpoint hy virtue of reduced'lov thxough the plugged,

steam generatozs.

%hile the hot channel factors for this

facility have nat.been= constant over timey

NRC concluded,

that further reviev of the history of TPNP operation pri.or to

19&2 vas not varranted.

Even vith the above veaknesses

in the safety evaluation,

the

conclusian that no unresalved

safety question vas created

hy the

error and that the plant vas aperated vithin its design bases is

acceptable

b'ased

upon the

10 degree

P margin for the setpoints.

Additionally, the folloving safety evaluations

vere revieved =by

the team and the conclusions

vere faund to he acceptable.

JPN PTN SEZS-91,'077

Rev.

0

Turkey Point Unit 3 Engineeri.ng

Evaluati.on for the'Veri.f. of Programmable

Parameters

for the Eagle

21 Protection

Racks

JPN-PTN

SEZS

91 077

Rev.

1

Turkey Point Uni.ts

3 f i Engineering

Evaluati.on for the Verif. of Programmable

Parameters

far the Eagle

21 Protectian

Racks

JPN-PTN-SEZS-91-081

Turkey Point Units 3 f h Engineering

Rev.

0

Evaluation for Eagle

21 Tuning Constant

DELTAH

57

JPN-PTN-SEIS-91-083

Turkey Point Units 3

S i Engineering

Rev.

0

Bvaluati.on for Deadhand of OTDT and

OPDT

Eagle 21 Setpoints

JPN-PTN-SENS-91-0&6 Turkey Point Unit 3 Safety Assessment

for

Rev.

0

Bagle 21

JPN-PTN-SEIS-91-090

Turkey Point Unit 3 Safety Evaluation for

Rev.

0

Connection of Test Bquipment to an

Opexational Bagle 2X Channel

JPN-PTN-SBZS-91-093

Tuxkey Point Units 3 f 4 Safety

Rev.

0

Bvaluation for Overtemperature

and

Overpower Delta Temperature for Turbine

Runback Setpoint

The inspectors

reviewed Quality Instruction JPN-QI-&.3, Item

Equivalency Evaluati.ons,

to determine the licensee~s

requirements

for the replacement of the

BPROMs in the Bagle 21 system to allow

proper calibration and allov the system to increase

pover.

The

evaluation JPNS-PTN-91-2152-,

Rev 1, appeared to comply vi.th the

requirements .of the QZ-&.3 for verifying that the replacement

parts would have no impaot on the safety analysis

and would not

reduce the'argin of safety as defined in the Teohnioal

Specifications.

The evaluation also verifie4 that the

EPROMs were

acceptable'lternates

to the originals and vith the nev range

vould improve the items ability to perform thei.r function within

the system.

The form and fi.t of the replacement

EPROMs vere not

changed.

The root cause investigation into both of the above problems

included

a complete reviev of the interchange of informati.on

between

'the vendor and PPL.

Zt vas determined that the share4

responsibilities

betveen the vendor and PPL failed to ensure that

unit speci.fi.c calibration data vas exchanged

and verified and the

divided testing responsihiliti.es did not provide for the proper

exchange of the information critical for the programming of the

Eagle 21 system.

The communications

hetveen the vendox and PPL

pro)cot managers

vere not logged; therefore

no tracking or follov-

up to closure of these

communications

could he performed.

A

contributing cause to this event vas that the level of technical

understanding vithi.n PPL Engineering

and ZtC Maintenance of the

Eagle

21 system design vas not.sufficient to recognize the lack of

adequate test or calibration procedures prior to returning the

system to service.

A4diti.onally, the inspectors

determined that

the lack of one cons'olidated

instrument setpoint

document

contributed to this problem.

10

CPR Part 50, Appendix B, Criterion ZZZ, Design Control, states

in part, that design control measures

shall provide for verifyi.ng

and checking the adequacy of 4esign,...be

established for the

identification and control of desi.gn interfaces

an4 for

58

cooxdination

among participating organisations.

Florida Power and

Light.Company~s implementing Qual'.ty Instructiong

QI 3 PTN 1g

Design Control,requires that design control measures

shall

. provide for veri,fyi.ng or oheoking the adequacy of design,

such as

hy performance of design reviews or hy performance of a sui:table

testing program.

Contrary to the above,

adequate

controls vere not in place during

the exohange of engineering data betveen the vendor and the

'Plorida Pover and Light Company staff to insure that complete

and

accurate

programmable

constants

and programmable

components

vere

installed i.n the Eagle 21 system in that betveen

September

27 and

October 5, 1991, the licensee identified'that the Eagle 21 system

contained non-plant specifio settings in the Eagle-21 portion of

the Reactor Protection

System

(Tuning Constants,

Resistance

Temperature

Device constants,

and Scali.ng Pactor) that vere not

acceptable for proper operation of Overpover. Delta T and

Overtemperature

Delta T.

This is identi.fied as a violation and

will he tracked

as

VZO 50-250,251/91-45-'02,

failure to maintain

.

adequate

design control of the Eagle

21 system.

Kith respect,to

configuxation control, discussions

vere held vith

the li.censee

to-determine

what. controls existed for insuri.ng that

contractors vere meeting the contractual obligations set forth in

engineering specifi.cations.

This inquiry vas

made as the result

of the defi.cienci.es i.dentified in controlling the configuration of

,. the Eagle

21 system.

The licensee

advised that the contract for

the Eagle

21. system vas issued for a complete package,

that is the

design,

engi.neering

approval,

equipment

oheck out at the factory,

field installation of the equipment,

and field testing

(Pre-"

operational tests).

The vendox vas responsible for the entire

, package until the time that startup

and operational testi.ng vas to

start.

t

The licensee

advi.sed that this and the

RPS setpoints submittal

were the only contracts that vere not processed

through either

their AB or the FPL engineering

department.

In the contract for

the sequencers

the

AR and PPL engineering, sections

worked together

to in'sure that the. pxogx'ams vere correct and that drawings

and

equipment vere oorrectly configured.

This vas also true vi.th the

emergency

di.esel generators.

The testing at the site =bore out

that-there vere no program deficiencies in the program porti.on of

the sequenoer.

There vere'ome

hardware problems identified.

Zn

one case the day tank refill valve circuit vas found to he

inadequate

due to a manufacturers

desi.gn erxor.

Manufacturing

defects vere i.denti.fied vhich resulted in the replacement of all

the relays

i.n the sequencer,and

in the removal of permanent

magnet

generator vhich vas furnished vith the nev Uni.t i emergency diesel

generators

for black start purposes.

CONCLUSION'BGAT ON 13

NOT SUBSTANTIATED

It vas concluded that, while tvo violations vere identifiedf the

instances

described

above did nat constitute

a programmatic

design/configuration cantrol breakdown

an4, consequently,

grave

deficiencies in plant configuration vere not substantiated.

on November 1, 1991, the team inspecti.on effort at the PPL

Corporate affices in Juno Beach vas completed. 't that time the

Team Leader informed the li.censee of the preliminary inspection

results to 4ate.

'n

November

18@

1991@ the Regianal Administrator and the Team

Leader conducted

an exit meeting at the PPL Corporate site in Juno

Beach.

The li.censee

and

NRC personnel

attendi.ng this meeting are

listed in Appendix C.

The licensee did not provi4e ta the team

any materi.als identifie4 as praprietary.

During the exit, the

team summarized the scope

and findings of the inspection

as

indicated below.

There vere,no 4issenting

camments

from the

licensee

an the findings.

CONCLUSION:

Xnspecti.on af the thirteen allegatians resulted. in

the folloving:

11

NOT SUBSTANTXATED

1

NOT 1NSPECTED

(EEOC JURISDICTION)

1

PARTIALLY SUBSTANTXATED

The folloving allegation vas determined to be partially

substantiated:

ana ement~s decision to

ost one

4ue to bud etin

or

other constraints

m artant modifications such as the

correction of the Power

M smatch Circuits

Each modification vhich vas postponed

during the

DUO at TPNP was

determined to not impact. plant safety.

Evi.dence vas not found

that would substantiate

an overall atmosphere of intimidation,

coercion, or harassment.

PINDINGS:

%ithin the scope of this inspection

one non-cited

vialation, tvo cited violations,

and tvo inspectar follawup items

were identi.fied.

60

Item Number

50 250 g251/91-45-01

50-250'@251/91

45-02

esc

t on and Reference

Failure to implement

adequate

design integration

(par'agraph

4)

Failure to maintain adequate

design control of the Bagle 21

system

(paragraph

13).

50 250i251/91

45 03

50-250 g 251/91-45-04

50 250i251/91-45

05

VZO

ZFZ

ZPI

Pailure to use correct Delta T

Subsero for calculation of the

Overtemperature

Delta T and

.Overpower Delta T setpoints

(paragraph

13).

Create

a single Instrument

Setpoint Document (including

design bases)(paragraph

10).

MRR annunciator circuit relays

separation

from RPS power

supply (paragraph

12).

AC

ADM

AB

hPW

APSN

ASLAB

'BOP

CCW

CNRB

CRN

CVCS

DC

DCR

DCRDR

DCTS,

DEEP

DNB

DNBR

DUO

ECCS

EEOC

BOOS

BOP

EP

EPRZ

EPROM

EPS

ERDADS

.

ESPAS

P,

PPD

Main Steam Isolation Valve

PSAR

GET

HED

Hs

IRC

ZB

IEE

ZPZ

ZRI/8

ZSA

Kv

LOCA

MCC

MEP

MMPZ

APPENDIX A

ABBREVIATIONS AND ACRONYMB

Alternati.ng Current

Administrative Procedure

'rchitectural

Bngineer

Auxiliar'y Peed Rater

Assistant Plant Supervisor Nuclear

Atamic Safety and Licensing Appeals Baard

Balance of Plant

Camponent Cooling Rater

,Code of Pederal Regulation

Corporate Nuclear Revi.ew Board

Change Request Notice

Chemical and Volume Control System

Direct Current

Drawing Change

Request

Detailed Cantrol

Room 'Design Review

Drawing Change Tracking System

Design Equivalent Engineering

Package

Departure

from Nucleate Boiling

Departure

from Nucleate Boi.li.ng Ratio

Dual Uni.t Outage

Emergency

Core Cooling System(s)

Bqual Emplayment Opportunity Commission

Equipment aut of Service

Emergency Operating Procedure

Engineering

Package

Blectric Power Research Institute

Brasahle

Programmable

Read Only Memory

Emergency

Power System

Emergency

Response

Data Acquisition Di.splay System

Emergency

Safeguards

Peature

Actuati.on System

Parenheit

Pitness

Por Duty

Plorida Power and Light

Pinal Safety Analysis Report

General

Employee Training

Human Engineering Defi.ciency

Herts

Instrumentation

and Control

Inspecti.an

and Enforcement

Item Equivalency Evaluation

Inspector Pallowup Ztem

Inspection Report

Integrated

Schedule

Instrument Society of America

Kilo-volt

Loss of Coolant Accident

Milli.-amp

Mator Control Center

Minor Engineeri.ng

Package

Minnesota Multi.-Phasic Personality Inventory

ABBREVIATIONS AND ACRONYMS continued s

MOD

MOV

MRR

MSZV

MWe

NCR

NCV

NDTT

NZS

NNBR

NOP

NR

NRC

NBR

N-2

ONOP

OBP

QN

Q

PK/M

PEG

PAID

PLA

PNSC

PSZG

PWO

QI

QR

RAZ

REA

RPB

'Modification

Motor Operated Valve

Miscellaneous

Relay Rack

Megawatt Electric

Nonconformance

Report

Non-Cited Violation

Nil Ductility Transition Temperature

Nuclear Instrumentation

System

Not Nuclear Safety Related.

Normal Operating Procedure

Narrow Range

Nuclear Regulatory Commission

Nuclear Reactor Regulation

Nuclear Safety Related

Nuclear Steam

System Supplier

Nitrogen

Overpressure

Mitigation System

Off Normal Operating Procedure

Out of Service

Operational

Readiness

Assessment

Team

Outside Services

Management

Operations Surveillance

Procedures

Nuclear Power

Turbine Load

Plant Change/Modification

Production Engineering

Group

Piping and Instrumentation

Diagram

Proposed

License

Amendment

Preventive Maintenance

Post Maintenance Testing

Plant Nuclear Safety Committee

Pressure

Operated Relief Valve

Probabilistic Risk Assessment

Pounds per Square Inch Guage

Plant Supervisor Nuclear

Pressure

Transmitter

Plant Work Order

Quality Instruction

Quality Related

Request for Additional Information

Reactor Coolant

Pump

Reactor Coolant System

Request for Engineering Assistance

Residual

Heat Removal

Rod Position Indication

Reactor Protection

System

Resistance

Temperature

Device

Rated Thermal Power

Refueling Water Storage

Tank

ABBREVZATXONB

SALP

SATB

SER

SG

86PN

SZ

BMZ'PDB

SR

TTave

ref

TE

TEDB

TPNP

'B

TBA,

UP

URX

V

VCT

VXO

3

AND ACROM9fS conti.pued:

Systematic

Assessment

of Ticensee

Performance,

System Acceptance

Turnover Sheet

.

Safety Evaluation Report

Steam Generator

Peed Rater

Safety Injection

Setpoint Methodology Znspecti.on

Safety Parameter

Display Bystem

Safety Related

Average

RCS Temperature

Reference

RCB Temperature

Temperature

Element

.

Total Equipment Data Base

Turkey Point Nuclear Plant

Technical Specifications

Temporary System Alteration

Underfrequency

Unresolved

Ztem

Volt

Volume Control Tank

Violation

C

NTB

APPENDIX 8

D

PARTIAL

ZBTXNG

NUMBERS)

ADM-101

IC 3 ~ 17.

~INGLE

Procedure writers Guide

PPL Nuclear Engineering Department

Standard,

Instrument Setpoint Methodology

for Nuclear Paver Plants

'SA

67'4

JPN PTN SEIJ-91

008

l

Plant Maintenance Instructi.ans,

10

50.59

Recommended

Pracedure

Changes

JPN-PTN-SENP-91-006

Safety Bvaluati.on far Safety Functions in

Miscellaneous, Relay Racks

JPN

PTN SEIS-91-077

Rev.

0

~ 4

JPH PTN-SEIS-91-077

Rev.

1

JPN-PTN SEIS91-081

Rev.

0

JPN-PTN SEIS '91 083

Rev.

0

JPN

PTN SENS 91 086

Rev.

0

Turkey Point Uni.t 3 Engineering

'Evaluatian for the Verif. of Pragrammable

Parameters

for the Eagle 21 Protectian

Racks

Turkey Point Units 3

0

4 Engineering

Bvaluation for the Verif. of Programmable

Parameters

for the Eagle

21 Protection

Racks

Turkey Point Units

3 t

4 Engineering

Bvaluation for Eagle 21 Tuning Constant

DBLTAH

'

Turkey Point Units

3 f

4 Engineering

Bvaluation for Deadband of OTDT and

OPDT

Bagle 21 Setpoints

Turkey Point Unit 3 Safety Assessment

for

Eagle 21

JPN-PTN-SEIS-91-090

Turkey Point Uni.t 3 Safety Evaluation for

Rev.

0

.

Connection of Test Equipment to an

Operational

Eagle

21 Channel

JPN PTH-SEIS-91-093

Rev.

0

JPN 91 0094

Turkey Point Units

3 f 4 Safety

Evaluation .for Overtemperature

and

Overpower Delta Temperature for Turbine

Runback Setpoint

e

QI 3 '

QI 3 ~ 1-3

QI 3 ~ 1-7

QI 3 '

QX 3'1

QI 6'

3/4

PMZ 041 10

3/4-PMI 041

17

3/4 PMZ-041 ~ 22

3/4

PMZ 041 39

3/4-OSP

041 ~ 4

4-OSP

059 '

PC/M 78-16i17

PC/M 81 162 g 167

PC/M 86-50

PC/M 88-396g399

PC/M

88 427i535g

565

83-88i89

PC/M 84 208 p 209

PC/M 84g211

PC/M 90-301

PC/M 90-304i305

PC/M 83..88g89

PC/M 84 208 g 209

PC/M 81 13g14

PC/M 75-81

PC/M 78-27128

Design Control

Engineering

Package

(EP)

Design Zntegration

Design and Safety Analyses

NRC Submittals

Engineering Evaluations

RCS Subcooling Margin Monitoring Train B

Calibration

T

- to Rod Speed Control and Power

Mismatch

Reactor Coolant Pressure,

Wide Range,

P-

3-405 Channel Calibration.

lRCS

PORV Actuator. Overhaul/Maintenance,

PCV-* 455C

0 PCV-* 456

Overpressure Mitigating Syst: em Nitrogen

Backup Leak and Punction Test

Power Range Nuclear Instrument Analog

Channel Operational Test

Deletion of Flux Rate Xnput to Turbine

Run Back

Reinstatement

Power Mismatch Circuits

Without Automatic Rod Withdrawal

Deletion of Power Mismatch Circuitry from

the Rod Control System

Nil Ductility Transition Temperature

(NDTT) Control

Overpressure

Mitigation System

(OMS)

Permissive Status

Panel Light and

Annunciator Interlocks

Pressuriser

PORV~s Backup N-2 Supply;

PC/M 78-23,24,

OMS Test Switch and

Relabel

OMS Components

Installation of Inadequate

Core Cooling

System Instrumentation

Nitrogen Backup Supply Pressure

Regulator

Replacement for OMS

PORV Diaphragm Replacement

and Lockwasher

Addition

Pressuriser

PORV Air and Nitrogen Supply

.

Tubing Enhancements.

Deletion of Plux Rate Xnput to Turbine

Run Back

Reinstatement

Power Mismatch Circuits

Without Automatic Rod Withdrawal

Turbine Runback Modifications

Modification for %ET-ZT resolution-Main

Steam

System

. Modification of Main Steam

Dump Line

Structure-%ED-ZY Resolution

PC/M 90-331p332

PC/M 90-.342,

PC/M 90 508g509

,PC/M 91 004

PC/M 91 037g038

PTN BPi7Z 91-005

%CAP 12201

%CAP 12745

<<!C>> Bus Transformer Deluge System

>>Power

Available>> Light

Upgrade of Howell'ample System

Implementation of 'Setpoint Methodology.

'MOV Bnhancements

Generic Letter 89-10

Modifications in L-3-112 and L-3-115

Loops

Setpoint Calculation for VCT Level

Transmitters

Loop, Revision

0

. Bases

Document for %estinghouse

Setpoint

Methodology for Protection

Systems

Nestinghouse

Setpoint Methodology Ror

Protection

Systems ; Turkey Point'nits

3

and

4 - Rlorida Power and Light Company

Plant Bngineering Group

(PEG) Training

Manual on Turkey Point Setyoint

Methodology,

Rev 0, Rebruary

1991

APPENDIX C

EXIT ATTBNDANCB

Licensee

Employees at Bxi.t on November 1, 1991

J..H. Goldberg, President,

Nuclear Division

K. N. Harri.s, Senior Vice President,

Nucleax Operations

%. H. Bohlke, Vice President, Nuclear Engineering

R. Licensing

J.

E

Geiger,

Vi.ce President,

Nuclear Assurance

J

B

Hosmer, Director, Nuclear Engineering

R. B. Grazio, Director, Nuclear Licensing

H. N. Paduano,

Manager,

Technical Programs

J.

G. West,, Manager, Nuclear Securi.ty

J. J.

Sudans,

Manager,

A. I ~ Smith, Blectrical/Instrumentation

and Control Chief

.

T. C. Grozan, Principle Bngi.neer, Nuclear Licensi.ng

W; A. Skelley, Senior Staff Engineer

~ 'J. C'allagher,

Senior Investigator,

J. J. Hutchinson,

Supervisory

Component Speci.alist

NRC Representatives

at Exit

K

D

Landisp Section Chief, Region II

L. S. Mellen, Operational

Programs,

RIX

M.

Thomas,

Reactor Znspectox,

RZX

M. D. Hunt, Reactor Inspector,

RXI

P

J ~ Fillion, Reactor Xnspector f RZZ

Licensee

Employees at Exit on November 18,

1991

J. L. Broadhead,

President,

FPI Group

J.

H. Goldberg, President,

Nuclear Division

K. N. Harris, Senior Vice President,

Nuclear Operations

W. H. Bohlke, Vice Presi.dent, Nuclear Bngineering f Licensing

J. B. Geigerf Vice President,

Nucleax

-Assurance

J.

B. Hosmex, Director, Nuclear Bngineering

R. B. Grazie, Director, Nuclear Xicensing

H. N. Paduano,

Manager, Technical Programs

R. C. Gross,

Managex,.Outside

Services/Nuclear

Engineering

J. Scarola,

Manager,

Equipment .Support

and Znspecti.on-

R. X. Wade,

Manager, Analysis and Controls

J. J.

Sudans,

Manager,

D. I. Smi.th, Chief, Electrical/Instrumentation

and Control

O'. Salamon,

Licensing Supervisor,

Turkey Point

T

C

Grozan, Principle Engineer@

Nuclear Li.censing

W. A. Skelley, Senior Staff Engineer

J.

C. Gallagher,

Senior Investigator,