ML17157A205

Power

s Light Co.

SUBJECT:

Forwards

EOP Insp

6 Requalification

Reexam Repts

50-387/90-08

& 50-388/90-80

on 900423-27.

DISTRIBUTION CODE:

IE42D

COPIES

RECEIVED:LTR

ENCL

SIZE:

TITLE: Operator Licensing Examination Reports

NOTES:LPDR

1

cy Transcripts.

LPDR 1 cy

Transcripts.

05000387

05000388

RECIPIENT

ID CODE/NAME

PDl-2

PD

INTERNAL: ACRS

NRR SHANKMAN,S

NRR/DLPQ/LOLB10

RGN1

FILE

01

EXTERNAL: LPDR

NSIC

NOTES:

COPIES

LTTR ENCL

1

2

1

2

RECIPIENT

ID CODE/NAME

THADANI,M

AEOD/DSP/TPAB

NRR/DLPQ/LHFBll

EG F

02

NRC PDR

COPIES

LTTR ENCL

1

NOTE TO ALL"RIDS" RECIPIENTS:

PLEASE HELP US TO REDUCE WASTE! CONTACT THE DOCUMENT CONTROL DESK.

ROOM P 1-37 (EXT. 20079) TO ELIMINATEYOUR NAMEFROM DISTRIBUTION

LISTS FOR DOCUMENTS YOU DON'T NEED!

TOTAL NUMBER OF COPIES

REQUIRED:

LTTR

15

ENCL

15

~ g

JUN

8 199Q

Docket Nos.

50-387

50-388

Power

and Light Company

ATTN:

Mr . Harold W.

Kei ser

Senior Vice President

Nuclear

2 North Ninth Street

Al 1 entown,

Penn sy1 van ia

18101

Gentlemen:

SUBJECT:

EMERGENCY OPERATING

PROCEDURES

INSPECTION AND REQUALIFICATION

RE-EXAMINATION- REPORT

NOS 50-387/90-80

and 50-388/90-80

This refers to the special

safety inspection

conducted

by an

NRC Emergency

Operating

Procedure

Inspection

Team

on April 23-27,

1990, of acti vities at the

Susquehanna

Steam

El ectr ic Station

(SSES) Units

1 and 2,

and requal ification

re-examinations

admi ni stered

on Apri 1 25,

1990,

and to the di scussi on of our

findings with Mr.

H .

G. Stanley

and other members of your staff at the concl u-

sion of the inspection

~

The purposes

of the i n specti on were to veri fy that the

Emergency Operating

Procedures

( EOPs)

are technically correct, that the

EOPs can

be physically

carried out in the plant,

and that the

can

be implemented

by the plant

staff, ~

The inspection

concluded

the

EOPs are generally acceptable

~

However, there

were

many differences identified between

the

and the

BWR Owner '

Group

Emergency

Procedure

Guidelines

and the

Emergency

Procedure

Guidelines

which need addi tiona1 attenti on

~

The inspection

concluded that the

can

be physically carried out in the

plant and the operators

can

implement the procedures.

However, findings and

concerns

were identified which affected both areas.

The most significant

finding i s the limited avai 1 abi 1 ity of suppression

chamber

pressure

i ndi cati on

to make decisions

in the primary containment control

.

Another area of

concern is the

suppor ting procedures

for carrying out the

EOP di rected tasks .

The steps

necessary

to carry out the

EOP di rected tasks

( e

~ g ~, venting of

primary containment)

generally involve use of multiple procedures

and

do not

reference

the procedure

section utilized to per form the specific steps

needed,

this determinati on i s left to the user.

While the training and ability of your

staff allowed the tasks to be p'erformed during the

wa 1 kdown s, the procedura

1

method could result in delay or error i n accompl i shi ng

EOP directed tasks .

Your staff took prompt action to i n form the plant operator s of the suppression

chamber

pressure

indication issue

and determined that

an engineering

analysis

would be completed.

90062 i0048 900b08

P DR

ADOCK 05000387

9

PNU

II

~

r,ro

c

Power 5 Light Company

In a telephone

discussion

between your staff (R. Wehry, J. Maertz,

and

D. Kaposchinsky)

and

D. Florek of this office on May 18,

1990,

we were informed

of the results of the engineering

analysis

and short term and long term plans

regarding

the suppression

chamber

pressure

issue.

Procedure

changes

are to be

implemented

by June

15,

1990,

and long term plans include adding wide range

suppression

chamber

pressure

indication in the control

room.

Several

unresolved

items are

summarized

in the executive

summary of the

enclosed

inspection report.

We note that your staff had identified that

a

schedule for resolution of the inspection findings,

as presented

to your staff

by the

NRC inspection

team,

would be provided by June

15,

1990.

We request

that you respond,

in writing, within 30 days of receipt of this letter confirm-

ing your staffs verbal

commitments in the

May 18,

1990 telephone

discussion

and

identifying the actions

taken or planned to address

the specific unresolved

items identified in the Executive

Summary of the enclosed

inspection report.

In addition, requalification re-examinations

were administered

to two reactor

operators

who had previously failed the simulator portion of the requalifica-

tion examination.

Both reactor operators

passed

the requalification re-exami-

nations.

In accordance

with 10

CFR 2.790 of the Commission's

regulations,

a copy of

this letter and the enclosures will be placed in the

NRC Public Document

Room.

The responses

requested

by this letter are not subject to the clearance

proce-

dures of the Office of Management

and Budget as required

by the paperwork

reduction act of 1980, Public

Law No.96-511.

Should you have

any questions,

please

contact the undersigned

at (215) 337-

5291.

Sincerely,

Original Signed Bg$

ROBERT M. GALLO

Robert

M. Gallo, Chief

Operations

Branch

Divisi on

of Reactor Safety

Enclosure:

Combined Report Nos. 50-387/90-80

and 50-388/90-80

cc w/encl.:

A.

R. Sabol,

Manager,

Nuclear Quality Assurance

J.

M. Kenny, Licensing Group Supervisor

R.

G.

Bryam, Superintendent

of Plant-SSES

S.

B. Ungerer,

Manager, Joint Generation

Projects

Department

J.

D. Decker,

Nuclear Services

Manager,

General

Electric Co.

OFFICIAL RECORD

COPY

FLOREK/SSES

REPORT/5/15/90 - 0001.1.0

06/07/90

'l

h

1P

I

h

Jl

E

t

lI

pgg

1 'p H

Power 5 Light Company

cc w/encl. (cont'd.):

B. A. Snapp,

Esquire, Assistant Corporate

Counsel

H.

D. Moodeshick,

Special Office of the President

J.

C. Tilton, III, Allegheny Electric Cooperative,

Inc.

C. Meeker,

System Specialist,

COMEX

L. Ostrom,

Human Factor Specialist,

INEL

Public Document

Room (PDR)

Local Public Document

Room (LPDR)

Nuclear Safety Information Center

(NSIC)

'RC

Resident

Inspector

Commonwealth of Pennsylvania

bcc w/encl.:

Region I Docket

Room (with concurrences)

Management Assistant,

DRMA (w/o encl)

R. Bellamy,

DRSS

P.

Swetland,

J. Caldwell,

M. Thadani,

M. Hodges,

R. Gallo,

R. Conte,

D. Florek,

Master-Exam

Fi1 e

OL Facility File

DRS Files (5)

06/

/90

06

/90

Gallo

06/

/90

Jo

on

06/ /

Ho

06/ /

OFFICIAL RECORD

COPY

FLOREK/SSES

REPORT/5/15/90 - 0002.0.0

06/07/90

4'

ll

U.S.

NUCLEAR REGULATORY COMMISSION

REGION I

SUSQUEHANNA STEAM ELECTRIC STATION

EMERGENCY OPERATING PROCEDURE

INSPECTION

Combined

Re ort Nos.

Faci1 it

Docket Nos.

Facilit

Licence Nos.

Licensee:

N

Ins ection Conducted:

Team Members:

50-387/90-80

and 50-388/90-80

50-387

and 50-388

NPF-14 and NPF-22

Power

and Light Company

2 North Ninth Street

Allentown, Pa.

18101

Susquehanna

Steam Electric Station Units

1 and

2

Berwick,

Pa

April 23-27,

1990

C. Meeker,

System Specialist,

COMEX

J. Stair,

SSES Resident

Inspector

L. Ostrom,

Human Factor Specialist,

INEL

T. Walker, Senior Oper tions Engineer,

Region I

Team Leader:

Donald J. Flore

,

r. Operations

Engineer

D te

chard J.

Conte,

hief,

BWR Section

Operations

Branch,

DRS

ate

r

I

1

QtWT

~

I %I I I I

h f

1 %Ptgl t

% I/1'll t

~

%

'I et 'QIW 4

','

'>'9'5

Alt>>, th) tV

~

IN: W'. h

t 0, ~ 4',,l

g'%(

sA%.

%

I h)Vh

Ins ection Summar:

Ins ection

on A ril 23-27

1990

Combined Ins ection

Re ort Nos. 50-387/90-80

and 50-388/90-80

Areas Ins ected:

Special

announced

inspection of the Susquehanna

Steam Elec-

tric Station

SSES)

Emergency Operating

Procedures

(EOPs) to include

a compa-

rison of the

EOPs with the

BWR Owner's

Group Emergency

Procedure

Guidelines

and

the plant specific

Emergency

Procedure

Guidelines,

a review of the

by

control

room and plant walkdowns,

an evaluation of the

on the plant refer-

ence simulator,

a

human factors analysis of the

a review of the on-going

evaluation

program for EOPs,

and the quality assurance

program involvement in

the

Results:

See Executive

Summary in Report,

N'

P

em~

<<p)}g~ ei'g,

"

~

- w ~i -- ra" i'c w )yacc" g>>'" vnarl

Executive

Summar

The technical

adequacy

review (Section

4) identified differences

between

the

Susquehanna

Steam Electric Station

Emergency

Procedure

Guidelines

(SSES

EPGs),

the

BWROG Emergency

Procedure

Guidelines

(BWROG EPGs)

and the

These

differences

included different entry condition values, different logic sequences,

different system

usage,

and different setpoint values.

In the differences identified between

the

and the

EPGs (Un-

resolved

Items 387 & 388/90-80-01),

the documented justification was not always

sufficient to determine that the differences

were technically acceptable.

The

major differences

include entry condition into the

RPV Control guideline

on low

reactor water level, entry condition into the Primary Control guideline

on high

suppression

pool temperature,

a majority of the entry conditions into. the

Secondary

Control guideline,

and the level/power control strategy.

The differences

between

the

and the

EOPs include activities

or logic

required in the

EPGs that cannot

be identified in the

as well as

activities or logic found in the

EOPs that cannot

be supported

by the

(Unresolved

items 387 & 388/90-80-02).

The team identified that suppression

chamber pressure

indication would not

always

be available during emergency conditions which affects the ability of

the operator to make the decisions

required in the primary containment control

EOP.

The control

room indication is limited to 3 psig, is isolated for 10

minutes following a

LOCA signal,

must

be read locally when it exceeds

3 psig

and the local indication

may not be accessible

due to environmental

conditions.

This was the most significant individual item identified by the

NRC inspection

team.

The licensee

took prompt corrective action

as discussed

below.

(Un-

resolved

items

387 & 388/90-80-03).

The walkdowns of the

EOPs in the plant concluded that the

can

be performed

(see

section 5.0).

However,

the supporting

procedures

for carrying out

directed tasks

are generally difficult to use

due to the method of

referencing'etween

procedures

and the use of a series of procedures

(ES/ON/OP) to accom-

plish

some

EOP directed activities.

This method of procedure

use results in

unnecessary

steps

which may not be able to be accomplished

and could result in

delay or error in the completion of the

EOP directed task.

The inspection

determined that

some procedural

steps

are identified in

EOP basis

documents

and

not in procedures,

some confusing

steps

are contained

in the

and

some

equipment is difficult to access.

(Unresolved

items

387

& 388/90-80-04).

Notwithstanding the above,

the operators

accomplished

the

EOP tasks with reli-

ance

on their'knowledge

and training.

The simulator exercises

(section

6) demonstrated

that the operators

can effect-

ively utilize the.EOPs

to respond to plant accidents.

The simulator exercises

and follow-up discussions

with the operators

confirmed many of the items that

were identified in the

NRC human factor and technical

reviews.

~>,,

t

0

<HLI~t

g t

V A'

t

' '

>>t'v,"t'h <<l', 8'g

g,.i

~t4%e ~

) r, tqeA'% V/-'

VP',s" 'tc'4 'i~

k W%*.

>>t. A P

5'

4

The

human factors review (section

7) concluded that the

EOPs are high quality

with an appropriate

level of detail

and

a clearly designed

format.

Operator

acceptance

of the flow chart format is very high.

From

a

human factors stand-

point, operators

used

the flowchart portion of the

EOPs very well in the

simulator.

Human factors concerns

(Unresolved

items

387 5 388/90-80-05) with the

stem

primarily from the inconsistencies

in the implementation of the direction from

the

EOP writers guide

(AD-QA-330) or lack of direction for formatting numerous

steps.

The numerous

inconsistencies

suggest that the verification of the

was less than adequate.

Although the inconsistencies

did not cause

any obvious

problems in human performance

in the simulator scenarios,

in real

emergencies,

inconsistencies

may impact the use of the

The

human factors review also

supported

the concern

on the manner in which the operators

were directed to

various supporting procedures.

The number

and type of transitions takes

time

and

may cause

operator error and confusion.

The ongoing evaluation

program (section 8) for the

EOPs is recently developed.

This program identifies and tracks

open items, deficiencies

and enhancements

for the

and the

EPGs identified outside of the validation and veri-

fication program.

The program is acceptable

with additional effort needed in

the licensee's prioritization of

EOP open items.

As discussed

in section 9.0,

QA involvement in the initial development of the

was minimal.

The

QA Department is scheduled

and prepared

to be

an active

participant in the major

EOP revision process

that will incorporate revision

4

the

BWR Owner's

Group

The inspection

concluded that the apparent

reason for the majority of the

inspection findings was that the verification and validation process

performed

on the prior revisions of the

was less

than adequate.

The verification

process

compared

the

EPGs to the

EOPs to ensure that

EPG actions were

contained

in the

but did not ensure that all

EOP actions

were justified

in the

The validation program did not walkdown all of the support-

ing EOPs.

In addition, the problems

appear to have

been

compounded

by failure

to update

the

EPGs when revising the

Prior to the inspection,

the

licensee

revised the

EOP program controls for future

EOP revisions

based

on

lessons

learned

from other facility EOP inspections

(NUREG-1358).

The

program controls for future revisions of the

EOPs were generally acceptable

and

should preclude the additional similar problems in the future.

Prior to the

inspection,

the licensee

reviewed the current

EOPs using the

new program

controls

and identified many of the

same

items that were identified by the

inspection

team.

The staff at

SSES took prompt action to inform the plant operators of the

suppression

chamber pressure

indication issue

and identified that an engineer-

ing analysis would be completed

by May 11,

1990, with follow-up actions to be

implemented

by May 18,

1990.

A schedule for resolution of the remainder

detailed inspection findings would be provided by June

15,

1990.

<< ~ 11

0

1

'<< t1

<<Ptt )

"

.

'>>t ),i I'$, t<<f $

1 )<< t

1 tt P,<<4

<<<<

~<<g

<< I <</%V

<<I

0 <<+<<

I

<<<<V<< t<<<<t *',

j

',

1<<tg<<V<<th,

Section

11.0 discusses

the requalification re-examinations

administered

to two

Reactor Operators

(ROs)

who had failed this portion of the requalification

examination administered

during the week of January

22,

1990.

Both operators

passed

the examinations.

I

t

DETAILS

1.0

~Back round

Following the Three Mile Islan'd (TMI) accident,

the Office of Nuclear

Reactor Regulation developed

the "TMI Action Plan"

(NUREG-0660

and

NUREG-

0737) which required licensees

of operating reactors to reanalyze transi-

ents

and accidents

and to upgrade

emergency

operating

procedures

(EOPs)

(Item I.C. 1).

The plan also required the

NRC staff to develop

a long-term

plan that integrated

and expanded efforts in the writing, reviewing,

and

monitoring of plant procedures

(Item I.C.9).

NUREG-0899,

"Guidelines for

the Preparation

of Emergency Operating

Procedures,"

represents

the

NRC

staff's long-term program for upgrading

and describes

the use of a

"Procedure

Generation

Package"

(PGP) to prepare

The licensees

formed four vendor

type owner groups corresponding

to the four major

reactor types in the United States.

Working with General Electric and the

NRC, the Boiling Water Reactor

Owners

Group

(BWROG) developed

the

BWR

Emergency

Procedure

Guidelines which are generic

procedures

that set forth

the desired

BWROG accident mitigation strategy.

The

EPGs were to be used

by the licensee

in developing their

PGP.

Submittal of the

PGP was

made

a

requirement

by Generic Letter 82-33,

"Supplement

1 to NUREG-0737, Require-

ments for Emergency

Response

Capability.".

The generic letter requires

each licensee

to submit

a

PGP which includes:

(i)

Plant-specific technical

guidelines

(ii) A writers guide

(iii) A description of the program to be used for the validation

of EOPs

(iv) A description of the training program for the upgraded

From this

PGP, plant specific

EOPs were to have

been developed that would

provide the operator with the directions to mitigate the consequences

of

a broad range of accidents

and multiple equipment failures.

The

PGP for the Susquehanna

Steam Electric Stations

(SSES)

was submitted

to the

NRC in

a letter dated

May 13,

1985.

The Safety Evaluation for the

PGP

was issued

on March 16,

1990.

To determine

the success

of the implementation,

generically,

a series of

NRC inspections of EOPs were conducted

in 1988 which examined

the final

product of the program,

the

The results of the

NRC inspections

conducted during 1988 were

summarized

in NUREG-1358 "Lessons

Learned

from

the Special

Inspection

Program for Emergency Operating Procedures."

This

inspection is

a continuing effort of the

NRC to evaluate

the

EOPs at

licensee facilities.

During the week of April, 23-27,

1990,

an

NRC team of inspectors consist-

ing of two

NRC license operators

examiners/inspectors,

a reactor

systems

consultant,

a

human factor specialist

and the resident inspector

conducted

an inspection of the Emergency Operating

Procedures

(EOPs) at the Susque-

hanna

Steam Electric Station

(SSES) Units

1 and 2.

SSES is a

BWR 4 with a

Mark II containment structure.

The objectives of the inspection

were to

determine if: the

EOPs are technically correct;

the

can physically

carried-out in the plant;

and that the

can

be performed

by the plant

staff.

The objectives would be considered

to be met if review of the following

areas

were found to be adequate:

comparison of the

EOPs with the

emergency

procedure

guidelines

(SSES

EPG)

and the

BWROG emergency

proce-

dure guidelines

(BWROG EPG), review of the technical

adequacy of the

deviations

from the

BWROG EPG, control

room and plant walkdowns of the

real time evaluation of the

on the plant simulator, evaluation

of the licensee

program

on continuing improvement of the

and perform-

ance. of human factor analysis of the

The inspection

focused

on the

adequacy of the end product,

the

and did not depend

'on the review of

the process

to develop the

If any of the areas

were not found to be

acceptable,

the inspection

would assess

other areas

as necessary

to under-

stand the basis for the deficiencies.

-The-EOPs

were implemented in essentially their current form in August

1985.

The facility utilized the

EPG

(SSES version of the plant

specific technical guideline), writers guide, verification and validation

program

as described

in the procedures

generation

package

submitted to the

NRC in May 1985.

Two procedure

revisions

had

been

made to the

since

August 1985.

The facility has modified their administrative

program

controls

and

EOP development

process

since the initial revision of the

EOPs following issuance

of NUREG-1358.

The revised

program

has identified

many of the

same

items

as the

NRC inspection

team.

2.0

Persons

Contacted

Sus

uehanna

Steam Electric Station

J. Diltz, Plant Control Operator

R. Dixon,

QA

"A. Dominguez,

Sr, Results

Engineer

"A. Fitch, Operations Training Supervisor

E.

Heckman,

Sr. Project Engineer

"D. Heffelfinger, Coordinator Engineer - NQA

"D. Kapuschinsky,

Sr. Nuclear Plant Specialist

M. Kirkpatrick, Plant Control Operator

"W. Lowthert, Manager

Nuclear Training

J. Maertz, Operations

Engineer

T. Markowski, Dayshift Supervisor

tb

t VV'ly Illghtq,yb(AVW,(pVYQI/ge'~Vg~CPP+J lllo f gpt ls'V4'"P

2.0

Persons

Contacted

Cont'd.

J. Miller, Plant Control Operator

L. Patnaude,

Human Factors Specialist

M. Peal,

Nuclear Operations Training Supervisor

"R. Prego,

QA Supervisor - Operations

"J. Refling Sr. Project Engineer-Systems

Engineering

"E. Stanley,

Superintendent

of Plant

"R. Wehry, Compliance Engineer

U. S. Nuclear

Re ulator

Commission

S. Barber,

Senior Resident

Inspector

"D. Florek,- Sr. Operations

Engineer

"C. Meeker,

NRC Consultant

COMEX

L. Ostram,

NRC Consultant - INEL

"J. Stair,

Resident

Inspector

T, Walker, Sr. Operations

Engineer

The inspectors

also contacted

other members of the licensee

operation

and

technical staff.

Denotes those present at the exit meeting conducted

on April 27,

1990.

3.0

Basic

EOP/BWR Owners Grou

EPG

Com arison

A comparison of the facility EOPs

and

BWR Owners Group Emergency

Procedure

Guidelines (BWROG EPGs),

Revision 3,

was conducted to ensure that the

licensee

has developed

the procedures

indicated in the

BRWOG EPGs.

The

EOPs reviewed are listed in Attachment

A of this report.

The facility

EOPs are in agreement with the'WROG

on the type of procedures

required to respond to symptoms which result in entry into these

proce-

dures'~

4.0

Inde endent Technical

Ade uac

Review of the

Emer enc

0 eratin

Procedures

The

EOPs in Attachment

A were reviewed to assure that the procedures

are

technically adequate

and accurately

incorporate

the

BWR Owners

Group

Emergency

Procedure

Guidelines

(BWROG EPGs).

A comparison of the

Emergency

Procedure

Guidelines

(SSES

EPGs) to the

and

was

also performed.

Differences

between

the

and

EPGs were

assessed

for adequate

technical justification.

Selected

specific values

from the procedures

were reviewed to determine that the values

were

correct.

4.1

Com arison of BWROG EPGs

and

In general,

the differences

between. the

and the

have adequate

technical justification.

Several differences

identi-

fied by the

NRC inspection

team did not have adequate

technical

l

II

"1>> "'V

justification.

These justifications are for differences

in entry

conditions to

RPV Control, Primary Containment Control

and Secondary

Containment Control, deletion of the secondary

containment water

level control guidelines,

and for not removing fuses to de-energize

RPS

scram solenoids

in the reactor

power control leg of RPV Control

(RC/Q).

The details of these differences

are discussed

in Attachment

B of this report.

The differences

between

the

and the

EPGs is considered

to be

an unresolved

item (387/90-80-01

and

388/90"80"01).

The

EPG accident mitigation strategy for Level/Power Control

differs from the

BWROG EPGs.

SSES limits the controlled lowering of

RPV water level to -129 inches rather than to the top of active fuel

(-161 inches).

This results

in a higher steady state

power level

being maintained for the

ATWS condition.

The differences

between

the

EPG strategy

and the

EPG strategy

have

been

the topic of

several

meetings

between

the licensee

and

NRC Headquarters

staff.

. This inspection did not assess

whether the licensee

developed

strategy is technically adequate,

but only assessed

whether the

licensee

has

implemented their strategy in the

The inspectors

identified discrepancies

between

the

and the

EOPs for

level/power control

as discussed

in Section 4.2.

The inspectors

also

questioned

the facility as to whether their accident mitigation

strategy

should defer to the

EPG strategy

when suppression

pool

temperatures

approach

the

HCTL curve as discussed

in section 4.4.

4.2

Com arison of SSES

and

The

NRC inspection

team identified a large

number of inconsistencies

between

the

and the

These inconsistencies

include

directions in the

EOPs that are not included in the

EPGs;

differences

between

the

and the

EOPs for procedure refer-

ences,

figure titles,

and parameter

values;

cases

in which the logic

of the

EPGs is not preserved

in the

EOPs;

and

EOP directions

that do not meet the intent of the

EPG guidelines.

Examples of

these

inconsistencies

are provided in the following paragraphs.

The

detailed findings are discussed

in Attachment

B.

The steps

in the

EOPs do not have to correspond

verbatim or on

a

one-for-one basis with the plant specific guidelines

in the

EPGs, but the

EOPs must preserve

the logic delineated

in the plant

specific guidelines.

The inspection

team identified areas of RPV

Control, Primary Containment Control, Secondary

Containment Control,

Level Restoration,

Level/Power Control

and

RPV Flooding in which the

logic of the

EPGs is not preserved

in the

Examples of

logic sequences

that are not preserved

in the

EOPs include the

direction for reactor

power control

when power is less

than

5/o, but

all control rods are not inserted; direction for rapid depressuriza-

.tion while implementing Secondary

Containment Control

and Level/Power

Control;

and direction for RPV flooding in the Primary Containment

Pressure

Control leg of E0-103.

r

(

c )1:

I

f8pp

~ $ $ l

h

w

. g

1

(g~:

g.

$

~ (j (

l II~

t JVp

~

1(

l

5

I

10

The inspection

team identified

EOP directions that did not meet the

intent of the

EPG guidelines.

These inconsistencies

resulted in

omission of SSES

EPG directions, conflicting direction in the

and incomplete

or incorrect directions in the

Examples of

these

problems include conflicting guidance for RPV pressure

control

when pressure

must be reduced for suppression

pool level or temper-

ature control,

no direction to reduce

RPV injection when performing

RPV flooding with more than

one control rod not inserted,

and entry

into Secondary

Containment

Control based

on conditions rather than

symptoms of high secondary

containment

temperature.

The inspection

team identified several

parameter

values that are not

consistent

between

the

and the

In most cases,

the

values in the

EOPs are

more conservative

than the values in the

In these

cases,

the

EOP values were clearly chosen

because

they could be easily determined

using available indications.

While

this is an adequate

reason for choosing

these

values, it is not

documented.

For example,

the limitation for use of SRVs was changed

from 4.5 feet as specified in the

EPGs to

5 feet in the

In several

cases,

the deviations

in the parameters

are not clearly

conservative

and

may result in incorrect direction in the

For

example,

the

EPGs specify

111 psig as the Minimum RPV Flooding

Pressure,

while EO-114 specifies

values

based

on the

number of open

SRVs.

All of the values in EO-114 are lower than

111 psig.

The

EPGs often reference

specific procedures

for performing

related actions.

One of the purposes

of the

EPG is to specify

the technical

guidelines for the procedures.

The verification

process for the

EOPs should ensure that all the technical

guidelines

are incorporated into the

and procedures

referenced

by the

Other plant procedures

should not be used

as

source basis

documents

for the

Several

discrepancies

were identified with

procedure

references

in the

and

For example,

the

EPG referred to a procedure for cold shutdown that was in-

correctt.

EO-101 referred to the correct procedure.

The inspection

team also identified numerous actions

in the

EOPs that

are not justified or addressed

in the

The

do

not need to delineate

specific actions that must be performed,

but

all

EOP actions which affect the accident mitigation strategy

should

be contained

in the

EPG and justification should

be provided for

any actions that are not addressed

in the

BWROG EPGs.

Examples of

actions in the

EOPs that are not addressed

in the

EPGs include

bypassing

high steam tunnel

temperature

and low condenser

vacuum MSIV

closure interlocks, initiation of ARI, and

shutdown of Core Spray

pumps

when performing rapid depressurization

with more than

one

control rod not fully inserted.

This problem appears

to have

resulted

from simultaneous

development of the

and

EPGs,

rather than developing the

EOPs from the plant specific guidelines.

C

I

IE

I

l

'I

E

~,'

V

f

'

t

A

11

Several

discrepancies

between

the

and

EOPs related to plant

equipment

were identified by the inspection

team.

For example,

the

EPGs direct use of the Reactor Water Cleanup

system for inject-

ion of boron, but there is no method available for performing this

action.

The verification process

that was performed

on the current

and prior

versions of the

EOPs did not detect the numerous

inconsistencies

between

the

and

due to deficiencies

in the process.

The verification process

compared

the

EPGs to the

EOPs to ensure

that

EPG actions

were contained

in the

but did not ensure

that all

EOP actions

were justified in the

This problem

appears

to have

been

compounded

by fai lure to update the

when revising the

Prior to the inspection,

the licensee

revised the

EOP program

controls for future

EOP revisions

based

on the lessons

learned

from

other facility EOP inspections

(NUREG-1358).

The

program

controls for future revisions of the

EOPs were generally acceptable

and should preclude the type of inspection findings in the future.

Prior to the inspection

the licensee

reviewed the current

EOPs using

the

new program controls

and identified many of the

same

items that

were identified by the inspection

team.

(Licensee identified items

-- are ind'icated in the detailed findings in Attachment B.)

Many of the

facility identified items still remain

open

(see Section 8.0).

The differences

between

the

and the

EOPs are considered

to

be unresolved

item (387/90-80-02

and 388/90-80-02).

4.3

Technical

Ade uac

of EOPs

During the technical

adequacy

review of the

the inspection

identified deficiencies

in several

areas.

A few incorrect transi-

tions caused

by typographical

errors were identified.

.Several

proce-

dures contained

steps that did not appear to be necessary

or steps

that did not appear to be in the correct order for performance of the

desired action.

The majority of the technical

adequacy deficiencies

consisted of

terms that were are not clearly defined and steps that do not provide

complete direction.

For example,

the terms "reactor shutdown"

and

"SRV cycling" are not clearly defined in the

EOPs or in the

EOP basis

documents.

Procedural

direction is provided to restrict

use of HPCI

and

RCIC with low suppression

pool water level, but EO-103 does not

provide direction to override initiation signals which would be

necessary

to prevent automatic operation of HPCI and

RCIC.

The inspectors identified one technical

adequacy

problem that indi-

cated that the associated

procedures

could not be utilized.

Suppress-

ion chamber

pressure

above

3 psig cannot

be monitored for at least

10

,s ~

0

~

w

h

c

e *(tax

t Pal

a

OP 9 Y+ '

v

tet \\\\4

12

minutes following a high drywell pressure

isolation signal at 1.72

psig

~

Suppression

chamber pressure

indication is not available in

the Control

Room above

3 psig.

Local indication using the Contain-

ment Atmosphere Monitoring (CAM) system is isolated for 10 minutes

following the isolation signal

and must be realigned manually and

read locally.

Actions for Primary Containment

Pressure

Control,

Drywell Temperature

Control,

Level Restoration,

and

RPV Flooding are

dependent

upon suppression

chamber pressure.

The licensee

took

prompt corrective action to identify the issue to the operators

and

provided additional direction

on

how to handle the loss of suppress-

ion chamber

pressure.

The licensee

indicated that by May 11,

1990 an

engineering

evaluation

would be completed

on alternate

indications to

be utilized for primary containment control.

This was acceptable

to

the inspection

team.

Pending licensee

actions to resolve the adequ-

acy of suppression

chamber pressure,

this item is considered

to be

unresolved

(387/90-80-03

and 388/90-80-03).

The inspection

team identified that references

to procedures

in the

EOPs were inconsistently

employed.

Some actions that operators

would

be expected

to perform without referring to the procedure

referenced

specific procedures,

while other actions that operators

would be

expected to perform with the procedure

in hand did not reference

the

procedure.

These

inconsistencies

did not result in any specific

-- technical

adequacy

problems,

but provide the potential for missed

actions while implementing the

The licensee identified the

inconsistency

in referencing

procedures

prior to the inspection

and

planned to review the

EOPs to correct the problem.

4.4

Technical

Ade uac

of Calculations

The inspection

team identified several

concerns

based

on review of

the technical justification and calculations of the Heat Capacity

Temperature

Limit (HCTL) and Pressure

Suppression

Pressure

(PSP)

curve.

The

HCTL curve during the

ATWS conditions

was determined

based

on

two loops of suppression

pool cooling in service

and assumed

a time

to insert control

rods

by normal

manual insertion.

The inspectors

questioned

whether the curve was also appropriate for use with only

one loop of suppression

pool cooling in service.

In addition the

inspectors

were concerned that the curve was based

on insertion of

control rods by normal

methods.

If control

rods or boron injection

is delayed,

the actions identified in the

EOPs to reduce

pressure

may

not be sufficient.

In that case,

further reduction of RPV water

level to the top of active fuel

may be appropriate

to further reduce

reactor

power and the resultant

energy reduction into the suppression

pool.

There was

no documented

basis for the lower curve,

5 psig below the

PSP curve, at which suppression

pool sprays is directed in E0-103.

h

~

C

l;

=0

I

'

W

X

P g>r

~ t 6'

<

(

'ert ',I *

qadi <'I

'

i ",'

~'Iv ':,

~ V9';;I rr')V"7h

13

5.0

Control

Room and Plant Walkdowns

The inspectors

walked down the

and procedures

referenced

therein to

confirm that the procedures

can

be implemented.

The purpose of the walk-

downs was to verify that instruments

and controls required to be used to

implement the procedures

are consistent with the installed plant equip-

ment;

ensure that the indicators, controls

and annunciators

referenced

in

the procedures

are available to the operator;

and ensure that tasks

can

be accomplished.

The walkdowns of the

EOPs in the plant concluded that the

can

be

performed.

Detailed

comments

are identified in Attachment

C.

Notwith-

standing

the comments,

the operators

can accomplish

the

EOPs with reliance

on their knowledge

and training.

Pending

licensee

actions to resolve

the

detailed walkdown comments, this item is considered

to be unresolved

(387/90-80-04

and 388/90-80-04).

A concern identified by the inspection

team is the method in which normal

operating procedures

and abnormal

procedures

are

used for performance of

EOP required tasks.

The majority of the tasks directed

by the

require

use of one or more procedure that are written for a purpose other

than performance of the desired

task.

As a'esult, it is sometimes diffi-

cult to locate the appropriate

section of the procedure,

numerous

proce-

--dural actions

would be unnecessary

during emergency conditions,

and it is

not clear whether

some specified actions

should

be performed considering

the degraded

conditions that would be present

when the task was performed.

For example,

the directions for venting primary containment to reduce

pressure

at:

1) any time when performing Primary Containment

Pressure

Control (PC/P),

and 2) to prevent containment failure regardless

of off-

site dose limitations at primary containment

design limits are both

contained in the

same off-normal procedure

(ON) for loss of Reactor

Building Chilled Water.

The Primary Containment Control

EOP does not

specify the section to be performed for either case

and the

ON does not

have

a table of contents in the beginning of the procedure.

The

same

section of the

ON is used for reducing containment

pressure

with or

without impending containment failure.

This section of the

ON references

normal operating

procedures

(OPs) for sampling containment

and actual

performance of the venting.

The

OP that is referenced for venting does

contain

a table of contents,

but the section that must be used for venting

is labeled "Primary Containment Nitrogen Makeup and Pressure

Control."

This section of the

OP contains

numerous prerequisites

and precautions

that are applicable only during normal operations.

Reduction of contain-

ment pressure

is addressed

in three sub-sections

of the designated

section

of the OP.

These sub-sections

then reference

another

OP for operation of

the Standby

Gas

system

(SGTS).

As

a result,

the operator

who is directed

to vent the containment

must make

numerous decisions

as to which procedure

sections

must

be performed

and which procedure

steps

are applicable.

This

process

could result in performance of unnecessary

actions

and interrupt-

ion of the

SRO for guidance, all leading.to potential

delays

and operator

errors in performing the assigned

task.

g4

g

l

.1

~ )

~ t

Q

~.<<,

g ~ 4

4

I

~ .

'

h

-

t

P 'i rtgPVO

14

Only the

ES procedures

were walked-down step

by step during the facility's

initial validation of the

The initial validation process

did not

identify the deficiencies

in the use of numerous

support procedures

because

of the failure to walk-down the

EOs,

ONs,

and

OPs that support the

6.0

Simulator

Six scenarios

were conducted

on the plant specific simulator by two shift

crews.

The simulator scenarios

provided information on real time activi-

ties.

The purposes

of these

exercises

were to determine that the

provide operators

with sufficient guidance

such that their responsibili-

ties

and required actions during emergencies

both individually and

as

a

team are clearly outlined; verify that the procedures

do not cause

opera-

tors to physically interfere with each other while performing the

EOPs;

and verify that the procedures

do not duplicate operator actions

unless

required (i.e.,

independent verification).

In addition,

when

a transition

from one

EOP to another

EOP or other procedure

is required,

precautions

are taken to ensure that all necessary

steps,

prerequisites,

and initial

conditions are met or completed

and that the operators

are

knowledgeable

about where to enter

and exit the procedure.

The simulator exercises

demonstrated

that the operators

can effectively

-utilize the

EOPs to respond to plant accidents.

The simulator exercises

and follow-up discussions

with the operators

confirmed many of the items

that were previously identified in the

human factor and technical

reviews.

Most items identified related to confusing

EOP steps

and level/power

control issues.

When implementing

E0-103,

Primary Containment Control, the

SROs are

slow

to direct initiation of suppression

pool cooling and bypassing

drywell

cooling logic isolations to allow restoration of drywell cooling for

containment

pressure control.

In follow-up discussions,

the

SROs stated

that they would perform ON-159(259)-002 to verify isolations prior to

bypassing drywell cooling logic isolations.

The bases for EO-101 state

the ON-159(259)-002

should

be performed

as time permits to verify isola-

tions.

The bases

for EO-103 do not address

ON-159(259)-002.

Bypassing drywell cooling logic isolations is a time consuming task and

it did not appear that there

was adequate justification for delaying

direction of that task to verify isolations in accordance

with an off-

normal procedure.

7.0

Human Factors

Review of the

As a result of the

human factors review of the

several

concerns

have

been generated.

A desk top review of the

was conducted prior to the

on-site inspection.

Observation of simulator exercises,

interviews with

SSES staff, plant walk downs,

and control

room tours were used to both

corroborate

those

items noted during the desk top review and to identify

additional

concerns.

p1

k

V

-

~

15

Generally,

the

EOPs are high quality with an appropriate

level of detail

and

a clearly designed

format.

The flow charts

are laminated to a semi-

rigid plastic material

which gave

them strength

and durability.

The

EOP text is legible under all conditions for which they will be used.

However, the text used for "Yes" and "No" answers

to decisions is smaller

than the other text and may not be legible under certain conditions (i.e.,

degraded lighting).

The supporting

procedures

(ES,

OP,

and

ON) are

readily available in the control

room and are well maintained.

Operator acceptance

of the fl'ow chart format is very high.

From a

human

factors standpoint,

operators

used the.flowcharts

very well in the simu-

lator scenarios.

There were

no problems with operators

physically handl-

ing the flowcharts or finding steps

on the flowcharts.

In this

same

regard,

the place

keeping aids provided by the flow charts is adequate.

It was noted that

a

common convention for operator

placekeeping

on the

flowchart does

not exist;

however,

no decrement

in human performance

was

observed during the simulator scenarios.

The

human factors concerns with the

stem primarily from the incon-

sistencies'in

the implementation of 'the direction from the

EOP. writers

guide (AD-gA-330) or lack of direction for formatting numerous

steps.

Also, numerous

action verbs are not defined in the procedures writers

-guide.

When action verbs are defined in the writers guide, the action

verbs

used

on the flow charts

are not always

used in

a manner consistent

with the definitions in the writers guide.

The numerous

inconsistencies

suggest that the

human factors verification of the

was less

than

adequate.

Although the inconsistencies

did not cause

an obvious decrement

in human performance

in the simulator exercises,

in real

emergencies

inconsistencies

may impact the

use of the

Another concern in the

EOPs is the manner in which the operators

are

directed to various other

EOPs or supporting

procedures

(ES,

OP,

and ON).

In most cases

during the simulator scenarios,

the operators

handled the

transition from one procedure

to another without much difficulty.

How-

ever, in some flowchart procedures

the operator is directed to an

ES,

ON,

or OP procedure

and then to another

ON or OP procedure.

The

EOPs utilized

four types of transition formats,

but the

EOP writers guide only discussed

two formats.

A summary of concerns is listed below.

Attachment

D contains detailed

examples of the concerns.

Pending

licensee

actions

on the

human factor

concerns,

this is considered to be unresolved

(387/90-80-05

and 388/90-

80-05).

7.1

Verification of EOPs from a

Human Factors

Pers ective

In numerous

instances,

the

do not follow the direction of the

EOP writers guide.

The result of this is

a lack of consistency

both

within and

among the procedures.

For example, if an operator

expects

v

~

~ i q

y q-

v

"

y "y 4"~,

yY= 45(

'

=.s'r~

I'

16

a right exit from a decision

diamond to always

be

a "Yes" on

a

certain flow path

and it is not, then the operator

may perform

actions which might cause

the plant condition to get worse.

Human

factors verification of the

EOPs is expected to identify

inconsistencies

in the procedures.

7.2

Actions Verbs

Action verbs

used in the procedures

are not always defined in either

the

EOP writers guide (AD-gA-330) or the procedures

writers guide

(OI-AD-055).

The use of action verbs in the procedures

is not always.

consistent with the definitions given in the writers guides.

This

leaves

the interpretation of the action verb up to the individual

operator,

which has

a major effect on the actions

they take.

7.3

Cautions

and Notes

Cautions

are

used to describe

hazardous

conditions that can

cause

injury and equipment

damage

and should describe

the consequence

of

the hazard.

Notes are intended to provide supplemental

information

to the operator.

Neither cautions

nor notes

should contain operator

actions.

Because

of the critical nature of the information contained

in cautions, it is particularly important that cautions

be emphasized

- in a way that distinguishes

them from notes

and that they be located

where operators will not overlook them.

Direction for properly placing cautions is contained

in the writers

guide, but is not always followed in the flow charts..

In the current

, revision of the flow charts cautions

and notes

are placed together

and appear at various locations

on the flow chart.

Cautions

do not

always appear before the step to which they pertain.

7.4

Writers Guide

The

EOP writers guide does not contain direction

on

how to format

many types of steps.

This lack of direction caused

inconsistency

in

the writing of EOPs.

7.5

Transitions

Although the information in this section pertains

to the

EOP writers

guide,

the importance of this information warrants its own section.

The

EOP writers guide provides

two methods of transitions

between

the

various types of procedures.

These

are

a concurrent

type of transi-

tion (concurrent exit) and exit.

Concurrent exit means to continue

with the actions required in the current procedure

and also perform

the actions in the referenced

procedure.

Exit means to leave the

current procedure

and

go to

a step in the referenced

procedure

or

another

step in the

same

procedure.

However,

two other

types of

transitions

are

used in the flow charts that are not addressed

in the

writers guide.

These

appear

as

"IAW" (in accordance

with) and

P¹¹

4W ¹ Q

bg ¹¹,,

I

¹¹

~ ¹f¹ht

4

P

1 ¹ 'P

¹ ¹

I 8 ~

g

+

~ ~ 'Ig'fV'p

4

O'

.

5 j'"lgVWP/ '*;%'y ",, I'

1%',%PE'I

Wt) 't 1,/(

'

lP

V

Y'Og

17

7.6

"perform" statements

on the flow charts.

The types of transitions in

flow charts

should

be consistent

and minimized in order to provide

clear consistent

operator direction.

The operator

should

have clear directions

as to the steps

they need

to perform.

The

IAW transition

assumes

the operator

understands

which steps

are important and which are not.

This may not always

be

the case in an emergency situation

and unnecessary

steps

may be

performed or critical steps

may be missed.

The steps

necessary

to

perform the task should

be clearly indicated in the procedure.

In

this regard,

and supporting

procedures" should avoid sending the

operators

into numerous other procedures

and clearly state

the speci-

fic procedure

reference

where the operator

should transition.

If the

entire procedure is to be performed,

then

a reference

to the entire

procedure

is appropriate.

If only a portion of the referenced

proce-

dure is to performed,

then the transition should clearly state

the

portion of the procedure to be performed.

The operator

should tran-

. sition into as

few procedures

as possible.

Ste

and Table Wordin

7.7

Several

steps

in the

and

ES procedures

were worded in a confusing

manner.

Examples

are provided in Attachment

D.

Human Factors

Involvement in Procedure

Develo ment and On-Goin

Evaluation

8.0

On-

Experience

has

shown that

a team effort should

be used in the

development

and on-going evaluation/upgrading

of EOPs

(NUREG-1358).

This team should include

a

human factors specialist.

The

human

factor specialist

involvement in the development of EOPs

was limited

to the original validation of the

and was not included in the

development

and writing of the

It is apparent

from documentation

provided by the facility (verifi-

cation checklists

and personal

interviews) that the

human factors

professional

was not involved in the verification of the flow charts

and has not been involved in the continuing evaluation of the

does plan to have

human factors involved in the future upgrade

of the

EOPs to implement revision

4 of the

BWROG EPGs.

oin

Evaluation of EOPs

The

NRC team inspected

the ongoing evaluation

program for the

The

licensee

had recently developed

a program to evaluate

the

on

a

regular basis.

OI-AD-071, EOP/EPG

Open Items Tracking,

was written to

identify and track open items, deficiencies

and enhancements

for the

and the

EPGs identified outside of the validation and verification

program.

1

'I

, ~ p,4,

~,,

g

i

f

p

q, gtf ~ gA g9

tp

CA 4/

g

I

Jg

t,14 I

8

-I 1 -Ill'Ill,(t4

i "tP,,W

t, ". L,/II

tHV1

IC

'Af'

1 ',+1 +t

'

W/VHV

/

18

The inspectors

questioned

the adequacy of the licensee's

prioritization

of EOP open items.

The licensee

had identified numerous

open

items prior

to the inspection

and

had prioritized them based

on criteria defined in

OI-AD-071.

The majority of the items were designated

as Priority 2 items

because

they were based

on differences

between

the

EPG and

It

did not appear that

a thorough evaluation

was performed

when items were

identified to ensure that they did not have potential

adverse effect on

procedure

implementation or create

adverse

consequences

not previously

evaluated

(which would meet the criteria for Priority 1 designation).

For

example,

the licensee

had identified two open items associated

with the

discrepancies

in the Reactor

Power Control leg of RPV Control concerning

the definition of "reactor shutdown"

and the required actions

when reactor

power is below 5%.

These

items were designated

as Priority 2 items,

because

they were differences

between

the

and the

A

thorough review was not performed to determine

the extent of the impact of

these

items

on procedure

implementation.

9.

99

The

NRC team inspected

the

QA organization

involvement in the programmatic

approach of the

EOP program.

The inspection

focused

on those policies,

procedures

and instructions

necessary

to provide

a planned

and periodic

audit of the

EOP development

and implementation

process.

During the development

and implementation of Revision

0 of the

EOPs in

1985, the

QA Department

was not

a participant.

Since revision

0 of the

was issued,

the

QA Department

has

conducted periodic audits of the

EOPs with a focus

on ensuring that subsequent

revisions

were correctly

incorporated into the

The

QA Department is prepared to be

an active participant in the major

revision process that will incorporate revision

4 the

BWR Owner's

Group

The

QA Department

expects to focus primarily on ensuring that the

EPG revisions are correctly incorporated in the

The

QA Department

plans to use technically knowledgeable

personnel

to support their effort

in this process,

and all aspects

of the revision process

can

be covered.

10.0 Unresolved

Items

Unresolved

items are matters

about which more information is required to

ascertain

whether they are acceptable

items,

items of noncompliance

of

deviations.

Unresolved

items identified during the inspection

are

discussed

in sections

4.0, 5.0 and 7.0.

11.0

Re uglification Examinations

Dynamic simulator requalification re-examinations

were administered

to two

reactor operators

(ROs) who had failed this portion of the requalification

examination

administered

during the week of January

22,

1990,

The exami-

nations

were administered

using the guidelines described

in

NUREG 1021,

19

"Operator

Licensing Examiner Standard,"

Rev.

5, section

ES-601,

"Admini-

stration of NRC Requalification

Program Evaluations."

The facility submitted

proposed

scenarios

to be used for the examinations.

The

NRC reviewed the scenarios

and selected

two to be used for the exami-

nations.

These

scenarios

were run in advance

on the plant specific simu-

lator.

Facility personnel

that participated

in the preparation

of the

examination

signed security agreements

to ensure

there

was

no compromise

of the examinations.

Both operators

passed

the examinations.

The facility licensee

was effect-

ive in remediating

the operators with respect

to their previous

examina-

tion results.

Since only two operators

were examined, this review did not

constitute

a program evaluation

and

no generic strengths

or weaknesses

were noted.

12.0 Exit Interview

At the conclusion of the inspection

on April 27,

1990,

an exit meeting

was

conducted with those

persons

indicated in paragraph

2.

The inspection

scope

and findings were

summarized.

The licensee did not identify as

proprietary

any of the materials

provided to or reviewed

by the inspect-

ors during the inspection.

The licensee

actions to respond to the inspection findings are

summarized

as follows.

The licensee

took immediate actions to inform the operators

'egarding

the uncertain availability of the suppression

chamber

pressure

indication

and provided additional

guidance

on

how to respond if the

suppression

chamber

pressure

indication is not available.

By May 11,

1990,

the licensee

was expected

to complete analysis

and use of drywell

pressure,

or other alternate

indication, instead of suppression

chamber

pressure

for EOP implementation.

By May 18,

1990, the licensee

would

implement drywell pressure

in the

EOPs if it was determined to be techni-

cally adequate

and identify a schedule

for other methods if drywell

pressure

cannot

be used.

By June

15,

1990,

the licensee

would develop

a

plan for the resolution of the inspection findings.

The inspection

team

found the licensee

actions to be acceptable.

W '4'

4

+V

'*'

P

!

'l

Flowchart

ATTACHMENT A

DOCUMENTS REVIEWED

"EO-100-101

EO-100-102

"EO-100-102

EO-100-103

"EO-100-104

EO-100-105

"EO-100-111

EO-100-112

"EO-100"113

EO-100-114

EO-200-101

EO-200-102

EO-200-103

EO-200-104

EO-200-145

EO-200-111

EO-200"112

EO-200-113

EO"200"114

EOP Bases

EO-100-101

EO-100-102

EO-100-103

EO-100-104

EO-100-105

EO-100-111

EO-100-112

EO-100-113

EO-100-114

EO-200-101

EO-200-102

EO"200" 103

EO-200-104

EO-200-105

EO-200-111

EO-200-112

EO"200-113

EO"200"114

Revision

1 and

2

RPV Control

Sh.

1, Revision

1 and

2

RPV Control

Sh. 2, Revision

2

Primary Containment Control, Revision

1

Secondary

Containment Control, Revision

Radioactivity Release

Control, Revision

Level Restoration,

Revision

1

Rapid Depressurization,

Revision

1

Level/Power Control, Revision

1 and

2

RPV Flooding, Revision

1 and

2

Revision

1

RPV Control

SH 1, Revision

1

RPV Control

SH 2, Revision

1

Primary Containment Control, Revision

1

Secondary

Containment Control, Revision

Radioactivity Release

Control, Revision

Level Restoration,

Revision

1

Rapid Depressurization,

Revision

1

Level/Power Control, Revision

1

RPV Flooding, Revision

1

Revision

2

RPV Control, Revision

2

Primary Containment Control, Revision

2

Secondary

Containment Control, Revision

Radioactivity Release

Control, Revision

Level Restoration,

Revision

2

Rapid Depressurization,

Revision

2

Level/Power Control, Revision

2

RPV Flooding, Revision

2

Revision

1

RPV Control, Revision

1

Primary Containment Control, Revision

1

Secondary

Containment Control, Revision

Radioactivity Release

Control, Revision

Level Restoration,

Revision

1

Rapid Depressurization,

Revision

1

Level/Power Control, Revision

1

RPV Flooding, Revision

1

and 2.

1 and

2

1 and

2

1

< ~

i ~

i

q -,

r

Emer enc

Su

ort

ES

and Related

Procedures

"ES-134-001

ES-134-002

ES" 134-003

ES-149-001

"ES-150-001

ES-150"002

"ES-152-001

ES-152-002

ES-155-001

ES" 156-001

ES-184-001

ES-249"001

"ES"070-001

"EO-100-030

"EO-100-032

"ON-134-001

"ON-155-007

ON-159-002

EO-200-032

"OP-070-001

"OP-173-001

"OP-218-001

OP-225-001

"OP-234-001

Bypassing

Drywell Cooling Logic Isolations,

Rev

2 with PCAF

Bypassing

Drywell Cooling Logic Isolations during

a

LOOP,

Rev

2

Re-establishing

Rx Building HVAC, Rev 2

Overriding

pump initiations,

Rev 2

RCIC Turbine Isolation and Trip Bypass,

Rev

2

Boron Injection Using

RCIC System,

Rev

3

HPCI Turbine Isolation, Trip and Initiation Bypass,

Rev

3

HPCI Suction Auto Transfer Bypass,

Rev

1

Vent

CRD to Insert Control

Rods,

Rev

1

Bypassing

RSCS

Rod Blocks,

Rev

1

Bypassing

MSIV Isolations,

Rev

3

Bypassing

Drywell Cooling Logic Isolations,

Rev

2 with PCAF

Re-establishing

Rx Building HVAC, Rev

2

Overriding

pump initiations,

Rev

4

RCIC Turbine Isolation and Trip Bypass,

Rev

2

Boron Injection Using

RCIC System,

Rev 4

HPCI Turbine Isolation, Trip and Initiation Bypass,

Rev

3

HPCI Suction Auto Transfer Bypass,

Rev

2

Vent

CRD to Insert Control

Rods,

Rev

2

Bypassing

RSCS

Rod Blocks,

Rev

1

Bypassing

MSIV Isolations,

Rev

3

Manual Initiation of SBGTS in Automatic Control,

Rev

2

Fire Water Injection, Revision

7

Operation of HPCI with High Suppression

Pool Temperature

Loss of RBCCW (Vent Drywell and Suppression

Chamber),

Rev 8

Cross connect

CRD from Unit, Rev

7

Restore

Containment

Instrument

Gas,

Rev

12

HPCI System Operating Guidelines During Station Blackout,

section 2.3

Standby

Gas Treatment

System

Containment

Atmosphere Control System,

sections

3.5 and

3 '

Instrument Air System,

section

3.1

Containment

Instrument

Gas System,

section 3.2

Reactor Building Chilled Water System,

section

3. 1

Administrative Controls

AD-gA-330 Symptom - Oriented

EOP Writers Guide,

Rev 4

AD-gA-331 Verification Program for SSES-EPG

and

Symptom

Oriented

AD-gA-332 Validation Program for Symptom - Oriented

OI-AD-055 Procedures

Writer's Guide, Revision

4

OI-AD-071 EOP/EPG

Open Items Tracking,

Rev

0

Procedures

Generation

Package

Volume

1 and

2 dated

March 1984

EOP Trainin

Material

PP002A

EOP Simulator Scenarios,

Rev

2

SM001C Training Plan Event Based

Rev

0

I

'

'I

'J

'W 'PA

<<

I

A

5'f

~

p'

ewart, ~~ no

s

r

w

r eery

EOP Trainin

Material

Cont'd.

SY015F-9 Training Plan

Emergency Support Procedures

Ot~er tvte

EPG and source

documents

contained therein,

Revision

1

Calculations

Reviewed

EO-104 Max normal

and

max safe temperatures

EO-103 Pressure

Suppression

Pressure

Curve

SLC tank levels vs boron weight

EO-103 Drywell spray initiation limit curve

EO-103 Heat capacity temperature limit curve

Denotes those

procedures

walked down

ht

p 1 %'7

4 4't

J

$

'h

4

~ ) "t f

'F 4

V,',NWt71

4

tO

-%9j

1 t

I, t'th

ATTACHMENT B

DETAILED TECHNICAL ADE UACY COMMENTS

1.

Com arison of BWROG EPGs

and

A.

RPV Control

Reactor

Water Level Entr

Condition

The

EPG justification for lowering the reactor water level entry

condition from the

scram setpoint (+13") to -38" is not technically

adequate.

The

EPG justification for this difference is to

prevent

an unwarranted

entry into the

RPV Control Guideline.

No

technical justification for the difference is documented.

Addition-

ally, the

EPG indicates that entry into E0-101,

on

a low

water level

scram ensures

that all

EPG required actions are

performed.

The review of the

EOPs indicated

two procedural

actions

(monitoring

RPV water level

and ensuring isolations

and

actuations)

that are not adequately

addressed

by EO-101

and E0-102.

B.

Primar

Containment

Control

Su

ression

Pool

Tem erature

Entr

Condition

The

EPG justification for raising the suppression

pool temper-

ature guideline from 90 degrees

F to 105 degrees

F is not technically

adequate.

Entry into Primary Containment

Control at

105 degrees

F

conflicts with the actions of the Suppression

Pool Temperature

Control leg (SP/T) which require initiation of suppression

pool

cooling at

90 degrees

F,

The

SSES justification for reducing the

operator

response

time addresses

one specific event (inadvertent

opening of a safety relief valve).

This is not adequate justifica-

tion because

the

EOPs are designed

to address

symptoms not specific

events'.

Secondar

Containment Control Secondar

Containment Differential

Pressure

Entr

Condition

D,

The

EPG justification for changing the secondary

containment

differential pressure

entry condition is not technically adequate.

The

EPG justifies altering the entry condition by a percent

change to the Technical Specification value.

This does not provide

adequate justification for including

a time criteria for the entry

condition.

l

Secondar

Containment Control

HVAC Exhaust Radiation

Level Entr

Condition

The

EPG justification for not including Zone I and Zone II

HVAC radiation levels

as entry conditions for Secondary

Containment

~

$g 'g

" 'P

h'Pp+'

~ "g""i * g \\

lh *14

Vl'

V7 t I+ ~

I

V

t>

'Oft 4~11

Pl Al ~'Lg l1I

' ~ II

'gCE 'l\\p

lp I 'l

l(pWfs

'JW'+gal

Control is not technically adequate.

The fact that these

systems

do

not isolate

on high radiation levels is not adequate justification

for not requiring entry into Secondary

Containment Control if high

radiation levels are detected

in the reactor building exhaust

vents

by the Split Particulate

Iodine and Noble Gas

(SPING) monitors.

High

release

rates detected

by the

SPING monitors would be indicative of

secondary

containment

problems.

Requiring entry into Secondary

Containment Control

when

Zone I or Zone II HVAC is not in service for

an extended

period time is not an equivalent substitution for exhaust

radiation level entry conditions.

E.

Secondar

Containment Control Area Radiation

Level Entr

Condition

The

EPG justification for selecting

ten times the alarm value

as the

maximum normal operating radiation level is not technically

adequate.

The justification to allow operators

to use alarm response

and off-normal procedures

prior to entering the

EOP is not technic-

ally adequate.

Allowing sufficient margin to the

maximum safe

operating radiation level is not adequate justification for delaying

entry into the

EOP.

There is no apparent correlation

between

ten

times the alarm and the normal operating radiation levels specified

in the Final Safety Analysis Report.

(The

FSAR was used to determine

~

the maximum safe operating radiation levels.)

F.

Secondar

Containment Control

Sum

and Area Water Level Entr

Conditions

and Secondar

Containment

Water Level Control Guidelines

The

EPG justification for deleting the floor drain

sump

and area

water level entry conditions into Secondary

Containment

Control

and

the secondary

containment water level control guidelines is not

technically adequate.

The fact that there is no area water level

indication available is not adequate justification for these differ-

ences.

Local indication of water level

can

be utilized.

Addition-

ally, the off-normal procedures

referred to in the

EPG justifi-

cation

do not address all the

BWROG EPGs for secondary

containment

water level control

and do not direct the operator to enter

E0-104,

Secondary

Containment Control.

G.

RPV Control

Reactor

Power

Control

Removin

Fuses

to De-ener ize

Scram Solenoids

RC/ -5. 1

The

EPG justification for not removing fuses to de-energize

the

RPS

scram solenoids is based

on

SSES policy that prohibits operators

from removing fuses during

an emergency.

Actions to open the break-

ers to de-energize

the

scram solenoids

were originally substituted

for pulling fuses.

These actions

were subsequently

deleted.

The

EPG justification for deletion of the direction to open the

breakers

to de-energize

the

scram solenoids

does not indicate that

the direction to pull fuses

should

be deleted for the

same

reasons

(to prevent closure of the MSIVs).

The justification for not remov-

ing fuses is not technically adequate.

2.

Com arison of SSES

and

A.

Cautions

Caution ¹14

EOP steps that include this caution for depressurization

without

motor driven pumps available

are not consistent with the guide-

lines in the

The

EPGs caution that the

should not be depressurized

below 104 psig unless

motor driven

pumps are available.

The

EOPs caution against depressurization

below 150 psig.

There is no documented justification for this

deviation.

2.

Caution ¹26

Caution

9 in the

EOPs is not consistent with Caution ¹26 of the

Caution

9 alerts the operator to the potential for

water level

and pressure

transients

when

RPV water level i'

<-90".

Caution ¹26 cautions

the operator

about reactor

power

osci llations, but does

not specify

a level at which oscillations

are expected

to occur.

At the time of the inspection,

the

licensee

was performing

an analysis

to determine if -90" is the

limit for anticipated

power oscillations.

B.

RPV Control - Reactor

Power Control

Reactor

Power

< 5/. With More Than

One Control

Rod Not Inserted

The Reactor

Power

Control leg (RC/Q) of RPV Control of the

does not preserve

the logic of the

EPGs for reactor

power

control.

Step

RC/Q-2 of EO-102 is an awareness

decision

step

which provides direction to exit RC/Q when power is <

SFo

~

The

logic of the

EPGs requires

the actions of the

RC/Q leg to

be performed until-all but one control rods are inserted to

position

00 or the reactor is shutdown

and

no boron

has

been

injected.

These conditions

do not correspond to

SX reactor

power.

EO-102 does not direct insertion of control rods if

reactor

power is <55.

Additionally, because

step

RC/Q-2 is an

awareness

step that is applicable while performing the entire

RC/Q leg it provides conflicting direction with steps

RC/Q-13,

which directs that boron

be injected until the

SLC tank level is

<100 gallons or all but one control

rods are inserted,

and

RC/Q-17, which directs

rod insertion until all but one control

rods are inserted.

(The discrepancy

between

5% power and all

but one control rod inserted

was identified by the licensee

prior to the inspection).

~ ~

w

rem,+

i tstep,

ew

+

c

'

~

--

r

'.w,

'

see r,

.

e wt

w

ss w. t w ~~ ws <>>,e e, ~~Write + ~re

". PI v,w'r av

el're"

~

P'

pts~s

Initiation of ARI

E0-102,

step

RC/Q-4 directs initiation of ARI.

This action is

not included in the

EO-102 does

not provide direct-

ion to reset

ARI prior to manual insertion of control rods.

Control rods cannot

be manually inserted

unless

ARI is reset.

The operating

procedure for resetting

a scram directs reset of

ARI, but the operators

are not required to refer to this proce-

dure during emergency

conditions

and, therefore,

could miss the

direction for resetting

ARI.

Boron Injection Usin

Reactor Water Cleanu

step

RC/Q-4 directs

use of the Reactor Water Cleanup

(RWCU) system to inject boron.

The

do not address

this action.

Maximizin

CRD Flow

EO-102 provides direction for maximizing

CRD flow to insert

control rods (steps

RC/Q-14,

RC/Q-15 and RC/Q-16).

These

actions

are not included in the

(This item was

identified by the licensee prior to the inspection.)

Restoration

of S stems

Followin

Vent of Scram Air Header

E0-102,

step

RC/Q-20 is not consistent with SSES

step

5. 1

for restoring

systems

to normal after venting of the

scram air

header.

step 5.1 directs restoration

"when control

rods are not moving inward."

E0-102,

step

RC/Q-20 directs

restoration

when "inward rod motion stops," which implies that

the systems

should

be returned to normal only if rod motion

occurs.

If no rod motion occurred

and the

header

remained

vented,

manual

insertion of control rods would not be possible.

The bases

for E0-102,

step

RC/Q-20 indicate that restoration

should

be performed

when rod motion stops or if no rod motion

occurred.

Reset of Scr'am With More Than

One Control

Rod Not Inserted

EO"102 is not consistent with SSES

step 5.5 for resetting

the scram while attempting to insert control rods.

step

5 '

directs reset of the

scram only if control rods

moved

inward following the last scram.

EO-102 directs reset of the

when possible

regardless

of rod movement.

E0-102,

steps

RC/Q-22 and

RC/Q-34 are both awareness

steps that provide

direction if the

can

be reset while attempting to insert

control rods.

,These

steps

could cause

confusion

when implement-

ing.the

EOPs resulting in failure to reset

the scram in accord-

ance with step

RQ-21.

Additionally; EO-102 does not ensure that

the

HCU charging water header

valve is closed prior to manually

inserting control

rods in accordance

with step

RC/Q-33.

,P

V H,

I

'

~ t

gf g%%

h

"

I

%,A teaw /~ 'A h4'rC

~ ', 'P', r

>H w1

'

t'Yt r%,v

v .vh, wwW+w'~ eth'I

A

.%%09 artwelrl>>

C.

RPV Control

Reactor

Level Control

Entr

into Level Restoration

2.

E0-102,

step

RC/L-5 which directs entry into Level Restoration

. if RPV level cannot

be maintained

above -129" is not consistent

with SSES

step

RC/L-2 which specifies entry into Level

Restoration if level cannot

be maintained

above -161".

There is

no documented justification for this inconsistency.

(This item

was identified by the licensee prior to the inspection.)

Cold Shutdown

D.

step

RC/L-3 provides direction to proceed

to cold

shutdown in accordance

with GO-100-005.

.EO-101 directs cold

shutdown in accordance

with GO-100-011.

GO-100-005

does

not

provide directions for placing the plant in cold shutdown.

Control

Reactor Pressure

Control

Pressure

Control Usin

SRVs

2.

step

RC/P-2 directs that the control switches for each

ADS SRV be placed in the

"OFF" position to assure

that the

valves will not be opened

except for rapid depressurization

or

by the safety

mode of operation.

This direction is not contained

in the Pressure

Control leg (RC/P) of E0-102.

Pressure

Control Usin

Reactor

Water Cleanu

3.

E0-012,

step

RC/P-8 does not indicate

any restriction for using

Reactor Water Cleanup

(RWCU) for pressure

reduction.

This is

not consistent with SSES

step

RC/P-2 which specifies

use of

RWCU only if no boron

has

been injected.

Additionally, no

procedure exists for operation of

RWCU in blowdown mode

as

specified in these

steps.

Pressure

Control Usin

Main Condenser

Deaeratin

Steam

EPG, step

RC/P-2 directs

use of Main Condenser

Deaerating

Steam for pressure

control.

This method is not addressed

in

E0-102,

RC/P.

(This item was identified by the licensee prior

to the inspection.)

Pressure

Reduction

The Pressure

Control leg (RC/P) of EO-102 does not include

an

override to address

pressure

reduction if required to maintain

conditions below the Heat Capacity Temperature

Limit or the

Suppression

Pool

Load Limit as indicated in the

VHK't)hl'hl'\\'Wt

1 ~ W'*E'4

t PTpt

~l

0 / % t NA

5

P ~ h yl I

8 fl

E0-103,

steps

SP/T-13

and SP/L-19 direct pressure

reduction

and

entry into EO-102 at step

RC-1.

Without an override,

the

direction in E0-102,

RC/P for pressure

control conflicts with

the direction in E0-103.

5.

B

assin

MSIV Isolations

ES-184-001

provides instructions for bypassing

the

steam tunnel

high temperature

and low condenser

vacuum

MSIV closure signals

in addition to the low level closure signal.

section

PC/P-1 only addresses

bypassing

the low level

MSIV closure.

No

justification is provided for bypassing

the additional isola-

tions.

6.

RPV Cooldown

E0-102,

step

RC/P-10 is

a decision

step which asks if RPV cool-

down is required.

There is no justification for this decision

step in the

The

do not provide specific guid-

ance

on when cooldown is "required."

This step

appears

to be

unnecessary

because

the

EPGs "require" cooldown whenever

an emergency condition exists

and

no other conditions dictate

maintaining the

RPV pressurized.

If no emergency condition

exists,

EO-102 can

be exited without performing

a reactor

cooldown.

E.

Primar

Containment Control

Su

ression

Pool

Tem erature

Control

Monitorin

Su

ression

Pool

Tem erature

2.

The bases

for E0-103,

step

SP/T-1 are not consistent with the

. SSES

EPG, section

SP/T requires

use of SPOTMOS to

determine

suppression

pool average

temperature.

The bases for

E0-103,

step

SP/T-1 allow use of the process

computer to deter-

mine suppression

pool temperature

under certain conditions.

Use

of the process

computer is not justified in the

Initiation of Su

ression

Pool Coolin

The direction for initiation of suppression

pool cooling in step

SP/T-3 of EO-103 is not consistent with the direction in SSES

step SP/T-3.

The

EPGs direct operation of available

suppression

pool cooling.

E0-103,

step

SP/T-3 does not indicate

that all available

suppression

pool cooling should

be operated.

Licensee policy is to only operate

one loop of suppression

pool

cooling due to water

hammer considerations.

This policy is not

addressed

in the

EPGs or EOPs.

t

'

"I

P

1 & IW WW 0

'

't ','p

F

APV'P \\

P'(f

'Ph 4

~

'h <

~

'p'lt

3.

Manual

4.

The directions for a reactor

scram in the Suppression

Pool

Temperature

Control leg (SP/T) of EO-103 do not preserve

the

logic of the

Step SP/T-7 of EO-103 directs

a manual

scram if suppression

pool temperature

"cannot

be maintained"

below 110 degrees

F, while SSES

EPG step

SP/T-3 directs

a manual

reactor

scram "before" suppression

pool temperature

reaches

110

degrees

F.

These directions

do not have the

same

meaning

when

implementing

"Cannot

be maintained" requires

an evalu-

ation of system

performance

in relation to parameter

trends to

make

a determination.

Based

on operator

judgement

the action

may

be taken before or after the designated

condition is met.

"Before" requires that the action

be performed prior to meeting

.

the specified condition.

Cautions

E0-103,

steps

SP/T-3

and SP/T-10 contain cautions that should

be applicable while performing all subsequent

steps of SP/T.

By including these

cautions

as action steps, it is not apparent

that the cautions

are applicable for all subsequent

steps.

Primar

Containment Control

Su

ression

Pool

Level Control

Actions Not Included in SSES

2.

E0-103,

steps

SP/L-24 and SP/L-27 direct suppression

pool level

control actions if RPV pressure

is below 200 psig

and termina-

tion of suppression

pool sprays.

These actions

are not included

in the

(These

items were identified by the licensee

prior to the inspection.)

Also, Table

PC-1 of EO-103 which

specifies

the preferred

SRVs to be used for rapid depressuriza-

tion with high suppression

pool water level is not addressed

in

the

(Justification for these

steps

and table are

contained

in the Primary Containment Control Bases.)

Termination of RPV Makeu

From External

Sources with Ade uate

Core Coolin

Assured

The direction to terminate injection sources

external

to primary

containment if suppression

pool level

and

RPV pressure

cannot

be

maintained

below the Suppression

Pool

Load Limit (contained

in

step SP/L-3.1 of the

BWROG EPGs)

was deleted

from step SP/L-3. 1

of the

The justification for deletion of this

direction was based

on performing steps

SP/L-3. 1 and SP/L-3.2

concurrently.

The Suppression

Pool

Level leg of EO-103 does not

preserve

the logic of the

EPGs for concurrent

performance

of steps

SP/L-3.1

and SP/L-3.2 of the

E0-103,

step

SP/L-21 directs termination of injection sources

external to

g

'

/

-~V

"

>

w~ '+ 'p

'~

"'4 g1P'

0>>'I'~W)'%

primary containment

irregardless if RPV pressure

reduction

was

successful

in maintaining conditions below the Suppression

Pool

Load Limit.

This direction could result in injection sources

being secured

unnecessarily.

G.

Primar

Containment

Control - Primar

Containment

Pressure

Control

Actions Not Included in SSES

2.

E0-103,

step

PC/P-4 directs actions for hydrogen control follow-

ing a loss of coolant accident

(LOCA).

E0-103,

step

PC/P-6

provides direction for termination of primary containment

pressure

reduction.

E0-103,

step

PC/P-7 provides direction for

monitoring suppression

chamber pressure

above

3 psig.

These

actions are not included in the

(These

items were

identified by the licensee prior to the inspection.)

Reduction of Primar

Containment

Pressure

The procedures

referenced

in E0-103,

steps

PC/P-3

and PC/P-5 for

reduction of primary containment

pressure

are not consistent

with the procedures

referenced

by the

EO-103 refer-

ences

OP-173-001

and

RPV Control which are not referred to in

step

PL'/P-1.

step

PC/P-1 refers to ES-034-

002 which is not referenced

in E0-103.

3.

Pressure

Su

ression

Pressure

The

and

EO-103 bases

refer to Figure

PC-4 of EO-103

as the Pressure

Suppression

Pressure

Limit.

The title of Figure

PC-4 is "Suppression

Pool Pressure

Limit."

RPV Floodin

step

PC/P-4 requires

RPV flooding concurrent with

initiation of suppression

pool

and drywell sprays if primary

containment

pressure

cannot

be maintained

below the design

limit.

The Primary Containment

Pressure

Control leg (PC/P) of

EO-103 directs initiation of drywell sprays, if conditions

allow, instead of RPV flooding. If conditions allow initiation

of drywell sprays,

venting of primary containment

would be

required without attempting to reduce

containment

pressure

by

flooding the

H.

Primar

Containment Control - Dr well Tem erature

Control

Actions Not Included in SSES

E0-103,

step

DW/T-3 requires

a manual scram

and cooldown of the

RPV if drywell temperature

is >150 degrees

F.

E0-103,

step

~

1

i

'L$~

vr<s

q "

'

',,

'

z ~+

"v"q a~( '~esp.

2.

DW/T-5 directs initiation of suppression

pool sprays before

drywell temperature

reaches

320 degrees

F.

These actions

are

not included in the

(The first of the two items was

identified by the licensee prior to the inspection.)

Maximize Dr well Coolin

3.

E0-103,

step

DW/T-2 directs maximizing drywell cooling when

drywell temperature

exceeds

135 degrees

F.

This direction is

not consistent with SSES

step

DW/T-1 which specifies

operating all available drywell cooling when drywell temperature

exceeds

150 degrees

F.

This discrepancy

results

in conflicting

direction in EO-103 for drywell temperature

control.

There is

no direction in SSES procedures

'to maximize drywell cooling at

135 degrees

F, unless

Primary Containment

Control is entered

on

a parameter

other

than drywell temperature.

RPV Saturation

Tem erature

4 ~

The

and

EO-103 bases refer to Figure

PC-6 of EO-103

as the

RPV Saturation

Temperature

Limit.

The title of Figure

PC-6 is "Drywell Instrumentation

Temperature Limit."

Initiation of Dr well

S ra

s

The direction to initiate drywell sprays

in the Drywell Tempera-

ture Control leg (DW/T) of EO-103 is not consistent with the

guidance in the

DW/T directs initiation of drywell

sprays if drywell temperature

cannot

be maintained

below 320

degrees

F.

step

DW/T-3 directs initiation of drywell

sprays before drywell temperature

reaches

340 degrees

F.

I.

Secondar

Containment Control

Hi

h Area

Tem erature

and Hi

h

HVAC Cooler Differential Tem-

erature

Entr

Condi tions

The entry conditions into EO-104

on high area

temperature

and

high

HVAC cooler differential temperature

isolations are not

consistent with the entry conditions specified in the

The entry conditions for EO-104 are stated

as conditions (isola-

tions) rather than

as

symptoms (temperature

and differential

temperature

values)

as specified in the

There is no

documented justification for not including all areas of second-

ary containment rather than just the areas that have high

temperature

isolations.

, ~

-~

s

e q

v

C

~l

~

~ m

r

'e

~

s

~

10

2.

Haximum Safe

0 eratin

Radiation

Levels

E0-104,

step

SC/R-5 directs

a reactor

and entry into

Control before

any area radiation level exceeds

ten times maxi-

mum normal level.

step

SC/R-2 directs entry into

RPY

Control before

any area radiation level reaches its maximum safe

operating level.

E0-104,

step

SC/R-6 directs rapid depressuri-

zation if more than

one area radiation level exceeds

twenty

times

maximum normal level.

step

SC/R-3 directs rapid

depressurization if more than

one area radiation level exceeds

maximum safe operating level.

There is

no correlation

between

the maximum safe operating radiation levels defined in the

and the multiples of maximum normal operating radiation

levels specified in EO-104.

Additionally the values provided in

Table

SC-3 of EO-104 for the alarm and maximum normal radiation

levels in the

CRD

HCU areas

are not consistent with the values

in the

3.

Ra id De ressurization

J.

Level

E0-104,

step

RC/R-6 directs rapid depressurization

of the

if more than

one area radiation level

exceeds

twenty times

maximum normal levels

and secondary

containment integrity has

been lost.

This direction is not consistent with SSES

step

SC/R-3 which requires

rapid depressurization if more than

one

area

exceeds

maximum safe operating radiation levels.

Including

the condition for secondary

containment integrity to be lost

prior to rapid depressurization

does not preserve

the logic of

the

There is no documented justification for waiting

until secondary

containment integrity has

been lost before

depressurizing

the

Restoration

Lineu

of Alternate In 'ection

Subs

stems

E0-111,

step

LR-2 which directs lining up alternate

injection

subsystems

i s not consistent with SSES

EPB,

step Cl-1.

The

EPGs direct lineup of as

many systems

as possible.

E0-111,

step

LR-2 does

not indicate that all available alternate

injection

systems

should

be lined up.

2.

RPV Floodin

EPG, Contingency

1 requires

RPV flooding if RPV water level

. cannot

be determined at any time during the implementation of

the level restoration

guidelines.

E0-111,

step

LR-3 states that

RPV flooding should not be performed if spray cooling or blow-

down cooling are in progress.

This additional condition does

not preserve

the logic of the

There is no documented

< ~ f

0

.

(

t

I'

>E, ~

~

tg P'

'I

P

4 qV

10

.',0

F'8 '0 'l

P *

"

=P

~ 8

%

1 t'f I'4 W,

0 9 9

f VgW%A

1

4

~ 1

P'e

'

'i"

z ~

/

<<we

> ~

-a

1

s r v,W;R 'P,

~ 9A 7ev,ts,%

s"- tw

-*s-

sv

e

e 5*-'8 rw, '

v raw%

"'),

"

'

t v 'IY~',

<

. ll

> sft,, *ver

11

justification for not flooding the

RPV if spray cooling or blow-

down cooling is in progress.

3.

The directions for spray cooling in EO-104 are

based

on having

three

Core Spray (CS)

pumps injecting into the

These

directions

are not consistent with the guidelines in the

EPGs which direct actions

based

on

a

CS subsystem

(two

CS pumps)

injecting.

(This inconsistency

was identified by the licensee

prior to the inspection.)

K.

Ra id De ressurization-

Manual Scram

2.

E0-112,

step

RD-2 requires

a manual scram prior to depressur-

izing the

This action is not included in the

This step appears

to be unnecessary

because

the

always direct

a manual scram prior to entry into EO-112.

The

direction to'cram the

RPV prior to rapid depressurization

is

included in the

EPGs in all cases

except for the reactor

scram directed

by E0-103,

step SP/L-18.

Control of Injection Sources

With More Than

One Control

Rod

Out

The direction in E0-112,

steps

RD-4 and

RD-5 for control of

injection sources

when more than, one control rod is not inserted

is not consistent with the guidance

in the

Step C7-2. 1 directs

manual control of already established

injections

and prevention of any

new injections.

E0-112,

step

RD-4 directs prevention of injection from 'ECCS

systems

only.

There is no direction to prevent injection from other sources

such

as

Feedwater

or Condensate

pumps.

RD-4 directs overriding

pumps (preventing injection) before

RD-5 directs control of

already injecting systems.

As a result,

these

steps

do not

clearly indicate that it is not necessary

to inhibit systems

that are already injecting.

E0-112,

step

RD-5 directs

shutdown

of Core Spray

(CS)

pumps if they are not required for adequate

core cooling.

This action is not addressed

in the

(This item was identified by the licensee prior to the inspect-

ion.)

3.

Pressure

Reduction

Usin

Main Condenser

Deaeratin

Steam

step C2-1.2 directs

use of Main Condenser

Deaerat-

ing Steam for rapid depressurization.

This method is not

addressed

in E0-112,

step

RD-10.

(This item was identified by

the licensee prior to the inspection.)

~ wn ~

1'it ph VIP

4 4 V~ p,C'5 PVK'8 6.' Tf'"p ae =79 4 5'~l~t

12

L.

Level

Power Control

Cautions

The cautions

associated

with steps

LQ-4, LQ-5, LQ-9 and

LQ-13 of

EO-113 do not correspond

to the cautions specified in the

EPG for these

steps.

E0-113,

step

LQ-9 which directs restora-

tion of RPV water level to normal, contains

a caution that

inhibiting ECCS operation

may be required.

There is no docu-

mented justification for inhibiting ECCS operation

when restor-

ing level to normal.

2.

Control of RPV Water Level

and

RPV Makeu

Flow

E0-113,

steps

LQ-4 and

LQ-5 do not preserve

the logic of the

EPGs,

steps

C7-1 and C7-2.

step

C7-1 provides

limits for maintaining

RPV water level

and

RPV makeup flow rate

and states

that the direction for maintaining level takes

prece-

dence over the direction for maintaining

makeup flow.

EO-113

does not provide direction or'limits for maintaining

RPV makeup

flow rate.

In addition,

the

EOP bases

document provides

a

"preferred band" which is not addressed

in the

EOP flowchart and

3.

Ra id De ressurization

EO-113 does not preserve

the logic of the

EPGs with respect

to performing rapid

RPV depressurization.

EO-113 directs rapid

depressurization

only if RPV water level cannot

be maintained

above -161".

The

EPGs direct rapid depressurization if

required regardless

of RPV water level.

There are other condi-

tions (i.e., exceeding

the suppression

pool Heat Capacity

Temp-

erature Limit) that would require rapid depressurization

regard-

less of RPV water level.

II.

~V

Isolation of RHR Steam

Condensin

Pi in

step C6-1.2 addresses

closing the

RHR steam condens-

ing isolation valves.

This action is not. addressed

in E0-114,

step

RF-24.

step

C6-2 justifies deleting the direct-

ion to close the

RHR steam

condensing

isolation valves

because

they will be closed

when the

HPCI isolation valve is closed.

The

EPGs contain justification for using

HPCI to assure

adequate

core cooling while problems which required

RPV flooding

are corrected (following step C6-1.2), in which case

the

HPCI

isolation valves would not be closed.

This could result in

failure to isolate

RHR steam

condensing

piping.

~k

'

~

P

$

"IW4f P ISA

I 41

!

O'

N

4

-

t,,p stl

hl

I

~ W

A

~ 'I I 4'9PL 4 ted Ill t At+ e

4<

$PYII~4%l (FAtY, V

L l 4 'C'h, KW,I9

~

. 'C,,

'WP4MpPPf'

13

2.

Minimum RPV Floodin

Pressure

E0-114,

steps

RF-8 and

RF-9 are not consistent with SSES

steps

C6-3. 1 and C6-3.2 with respect to the Minimum RPV Flooding

Pressure.

The

EPGs specify ill psig as the Minimum RPV

Flooding Pressure,

while Table

RF-2 of EO-104 provides values

based

on the

number of SRVs that are open.

All of the values in

Table

RF-2 are lower than

111 psig.

3.

Minimum Core Floodin

Interval

E0-114,

step

RF-11 is not consistent with SSES

step C6-3.4

with respect

to the Minimum Core Flooding Interval.

The E0-114,

step

RF-11 directs injection for at least

one hour, while SSES

step C6-3.4 provides

a table of values

based

on the

number

of SRVs that are open.

All of the values

in the

EPGs are

lower than

one hour.

4.

More Than

One Control

Rod Out

The direction for RPV flooding with more than

one control rod

not inserted

in EO-114 is not consistent with the guidelines in

the

EPG, section

C6-1.

EO-114 provides direction for RPV

flooding if HPCI is not operating or

a primary break exists

and

different direction with HPCI operating

and

no primary break.

The directions with HPCI operating

and

no primary break are not

addressed

in the

The

EPGs contain justification

for using

HPCI to assure

adequate

core cooling while problems

which required

RPV flooding are corrected (following step

C6-1.2), but these actions

are not reflected in the steps

specified in section

C6-1 of the

Additionally,

EO-114 does not provide direction to reduce injection as speci-

fied in SSES

step C6-1.1

~

N.

EPG Format

The format of the

EPG makes it difficult to utilize as

a plant

specific technical

basis

(PSTG) document in'the developing of EOPs.

This is because

the

EPG is principally a "differences type"

document

between

the

EPG and the

SSES plant specific informa-

tion.

The intent of the of the

PSTG is to define the accident miti-

gation strategy that can

be used to develop the

If the licen-

see

had developed

the

EPG by placing the plant specific inform-

ation together in logical order, the accident mitigation strategy

could have

been easily determined

and differences

between

the

EPG and

may have

been minimized.

t

p

<<o P'

y

4

%), gVpl7

p-$

4/ '~$ pp1gW

gN ~tip t'

>. ( 7-%l'kit I,

'

T%%$ %'g ( 't

g" fV N e

"gK

'\\ "',i

g l7

\\

P

14

3.

Technical

Ade uac

of EOPs

A.

Ensure

The

and supporting

procedures

do not contain direction

to ensure that the

Scram Discharge

Volume (SDV) vent and drain

valves close following a reactor

scram.

If these

valves

do not

close,

reactor coolant will be released

into secondary

contain-

ment.

B.

RPV Control

Reactor

Shutdown

2.

E0-102,

step

RC-2 directs exit of RPV Control

when the reactor

is shutdown.

No definition of "shutdown" is provided in the

The

EOP bases for E0-102,

step

RC-2 state that

"shutdown" is defined in step

RC/(}-15.

The bases

for step

RC/g-15 do not discuss

the term reactor "shutdown."

Maximizin

CRD flow

3.

E0-102,

step

RC/g-14 directs starting the second

Control

Rod

Drive (CRD) pump if all rods are not inserted.

No direction is

provided to start the other

CRD pump if it is not running.

Both

pumps

need to be started, if possible,

to maximize

CRD flow.

Drain of the Scram Dischar

e Volume

4.

E0-102,

step

RC/g-24 directs

a manual scram after allowing the

Scram Discharge

Volume (SDV) to partially drain.

The

do not define

an acceptable

limit (time or volume) for draining

of the SDV.'This item was identified by the licensee prior to

the inspection.)

'I

Scram of Individual Control

Rods

E0-102,

step

RC/g-27 directs that control rods

be

scrammed

individually in accordance

with Attachment

B of EO-102.

E0-102,

step

RC/g-28 is a decision

step which directs

repeat of step

RC/g-27 if rod motion was observed

or reset of the

scram if no

rod motion was observed.

It is not clear whether step

RC/(}-28

applies after attempting to scram

each control rod,

each

group

of control rods, or all control rods.

Additionally, Attachment

B does

not provide specific direction for manually

scramming

rods.

No direction is provided in EO-102 to close the

test switch after the rod is scrammed

as specified in SSES

EPG

step

RC/(}-5.4.

The

scram test switch must

be closed to allow

reset of the scram.

L

\\

k

1

5.

Safet

Relief Valve

C clin

E0-102,

step

RC/P-3 is

a decision

step which directs actions

bas'ed

on whether

a safety relief valve

(SRV) is cycling.

The

EOP bases

do not provide

a clear definition for "SRV cycl-

ing." It is not clear whether

manual

operation of SRVs for

pressure

control constitutes

"SRV cycling."

C.

Primar

Containment Control

Use of HPCI and

RCIC with Low Su

ression

Pool

Level

2.

E0-103,

step

SP/L-8 directs that

HPCI and

RCIC not be used if

suppression

pool level is below 18.5 feet.

No direction is

provided to override

HPCI and

RCIC in accordance

with the

ES

procedure for overriding

pump initiations.

ES procedures

cannot

be used unless specifically directed

by the

It

would be necessary

to override the initiation signal, if

present,

to prevent automatic

HPCI and

RCIC operation.

E0-103,

step SP/L-9 requires

a manual scram after

HPCI and

RCIC become

unavailable.

If the

scram is delayed until after HPCI and

RCIC

become unavailable,

Feedwater

and

CRD are the only sources

of

high pressure

feed available

when the reactor is scrammed.

Monitorin

of Su

ression

Chamber

Pressure

There is no suppression

chamber

pressure

indication available

in the Control

Room for suppression

chamber

pressure

above

3

psig.

E0-103,

step

PC/P-7 provides direction for lining up

local indication using the Containment

Atmosphere Monitoring

(CAM) system.

The

CAM system isolates

on high drywell pressure

and the isolation valves cannot

be reopened for 10 minutes

following the isolation signal.

No suppression

chamber

pressure

indication would be available for at least

10 minutes following

a high drywell pressure

signal.

Actions for Primary Containment

Pressure

Control, Drywell Temperature

Control,

Level Restora-

tion,

and

RPV Flooding are dependent

upon suppression

chamber

pressure.

Restoration

RPV Level Indication

EO-114 does not provide direction to restart injection following

termination of injection in step

RF-12 if RPV water level indi-

cation is restored within the time allowed by the

Maximum Core

Uncovery Time Limit.

t

I'M

)

I

k

1l

j

4

'I

ATTACHMENT C

DETAILED WALKDOWN COMMENTS

1.

General

A.

Emergency

Support, Off-Normal, and

Emergency Operating

Procedures

do

not caution operators

to take

an

OPS

E127 key along when performing

emergency

lineups in the plant that require unlocking padlocked

valves.

2.

EO-100

Cauti ons

A.

Caution

1 of the

EOPs warns that drywell temperature

affects

water level indication.

The bases for this caution provide

a

detailed discussion

of the temperature

effects

and indicate which

level instruments

are affected.

Specific restrictions for use of RPV

level indicators are provided in Attachment

A of the bases for EO-

100.

Some of the operators

that were questioned

about this caution,

were not familiar with which level instruments

were affected

by dry-

well temperature

and could not easily locate the attachment that

provided the specific restrictions.

3.

-EO-101

4.

EO-102

RPV Contr ol

A.

EO-102

ste p RC/P-6 directs restoration

of Containment

Instrument

Gas

(CIG) in accordance

with ON-159(259)-002.

If the

CIG system is iso-

lated due to a

LOCA signal (-129" reactor water level or 1.72 psig

drywell pressure),

the isolation signal

must

be bypassed

in accord-

ance with ES-134(234)-001

to allow restoration of CIG.

Procedural

direction to use

ES-134(234)-001

is contained

in E0-102,

step

RC/P-9

which directs opening the MSIVs in accordance

with ES-184(284)-001

and E0-103,

step

PC/P-5 which directs bypassing

drywell cooling logic

isolations.

Neither of these

steps

provides specific direction to

bypass isolations

and restore

CIG.

As a result the operators

do not

take prompt action to restore

CIG after it isolates

on

a

LOCA signal

(specifically high drywell pressure)

and the MSIVs are allowed to

drift closed.

No clear direction is provided to reopen

the MSIVs to

utilize the main condenser

as

a heat sink if this occurs.

A.

E0-101,

step

S-12 directs the operator to reset

main generator

lock-

outs in accordance

with ON-193(293)-002.

The only action necessary

to reset the main generator is to operate

the reset lever, which the

, operator would be expected to be able to do without referring to the

procedure.

I

'

.u.>;ys r

~ -i v'g

si ~,

B.

Attachments

B and

C are not labeled

on the back of the Control

Room

flow charts in Unit 1.

5.

EO-103

Primar

Containment Control

A.

B.

C.

D.

E0-103,

step

SP/T-10 directs operation of HPCI in accordance

with

EO-032 and

RCIC in accordance

with EO-033 if suppression

pool temper-

ature

exceeds

150 degrees

F.

EO-032

and

EO-033 do not clearly indi-

cate which steps

should

be performed to operate

HPCI and

RCIC with

high suppression

pool temperature.

E0-033,

section

2. 1 directs

use

of ES-152(252)-001

and ES-152(252)-002

to bypass

interlocks to allow

operation of HPCI in full flow test

(CST to CST). It is not clear

whether

use of these

ES procedures

is authorized if EO-032 was

entered

due to high suppression

pool temperatures.

Drywell pressure

indication in the Control

Room,

above

3 psig, is in

psia.

Containment

pressure

parameters

are expressed

in psig through-

out the

This could result in confusion

or incorrect

implementation of the

E0-103,

step

PC/P-7 provides direction to lineup and monitor suppress-

ion chamber pressure

locally at the Hydrogen/Oxygen

(H2/02) Monitor-

ing panel

in the reactor building.

The panels

and valves that must

be operated to lineup the indication are located in poorly lit,

contaminated

areas.

The gage

had two scales,

one in inches of water

and psig,

the other in Kpa.

The poor lighting, the size of the gage,

and the dual

scales

made the

gage very difficult to read.

The licen-

see modified the gage face prior to the completion of the inspection

. by removing the inappropriate

scale.

The decision

statements

in E0-103,

steps

PC/P"11,

PC/P"19

and

DW/T-6

require the operator to make two decisions.

Direction to spray the

drywell is dependent

on whether containment

has

been vented

and

whether conditions are

above the Drywell Spray Initiation Limit.

The

majority of the operators

interviewed misinterpreted this step

and

stated that they would not spray the drywell if conditions were below

the Drywell Spray Initiation Limit even if containment

had not been

vented.

E.

E0-103,

steps

PC/P-5

and PC/P-22 both reference

ON-134(234)-001,

"Loss of Reactor Building Chilled Mater'" for reduction of drywell

pressure.

Section 3.4 of ON-134(234)-001

(page

5) directs the opera-

tor to section 3.7 for reduction of containment

pressure.

Pages

1

through

4 of the

ON contain information that is not applicable to

performance of the specified task.

The first two steps of section

3.7 refer to OP-173(273)-001

and ON-159(259)-002 for radiation

monitoring and sampling of containment.

It is not clear whether or

not these

steps

have to be performed'when

venting in accordance

with

E0-103,

step

PC/P-5 or PC/P-22.

ON-134(234)-001

contains

a caution

that

SPING is required

when venting unless directed

by shift super-

vision.

No guidance is provided for shift supervision to determine

I

E

I

r

1

k

C

I't

Iy

t,

'I lP

r

~

when

SPING is required.

The next two steps of ON-134(234)-001

address

bypassing

LOCA and high radiation isolation signals.

It is

not clear when these

steps

are authorized to be performed.

The

procedure

then directs pressure

reduction in accordance

with OP-

173(273)-001.

OP-173(273)-001

provides instructions for operating

the entire Containment Atmosphere'Control

system,

which includes

containment

purge

and exhaust,

nitrogen inerting and makeup,

H2/02

monitoring,

and the hydrogen

recombiners.

Section 3.5 of OP-173

(273)-001 provides instructions for primary containment nitrogen

makeup

and pressure

control, including prerequisites

and precautions

for normal operations.

Sections 3.5.5, 3.5.7

and 3.5.9 address

decrease

of primary containment

pressure

depending

on plant condi-

tions.

All of these

sections

require

manual start of Standby

Gas

(SGTS) in accordance

with OP-070-001.

The bases for step

DW/T-1 of EO-103 indicate that subsequent

action

levels in the

DW/T leg are

based

on drywell average

temperature,

which is determined

by performing

a calculation in accordance

with

SO-100(200)-007

or determined automatically by SPDS.

Operators

indicated that, in an emergency,

they would use hard-wired control

room indication to determine drywell temperature

and would not take

the time to calculate drywell average

temperature.

G;-- The Heat Capacity Temperature

Limit curve is difficult to use,

because

the axis for RPV pressure

is labeled at

150 psig,

250 psig,

350 psig, etc.,

instead of at the normal

(even)

100 psig increments.

6.

EO-104

Secondar

Containment

Control

A.

E0-104,

step

SC-2 refers the operator to Emergency

Support procedure

ES-070-001,

but there is no information to tell the operator

which

section of the procedure

to use.

B.

In Table SC-2,

Secondary

Containment

Maximum Operating

Values,

the

heading

MAX NORMAL is not annotated

to indicate that it also repre-

sents

the Area Isolation Set Point.

Without this information, the

operator

cannot easily determine if an entry condition

has

been

reached.

C.

Differential temperature

alarm and isolation setpoints

are not

included in Table

SC-2 or provided elsewhere

in EO-104.

Without this

information, the operator

cannot easily determine if an entry condi-

tion has

been

reached.

D.

There are eleven additional

Area Radiation Monitors associated

with

the Secondary

Containment that are not listed

on Table SC-3,

Second-

ary Containment

Maximum Operating Values.

High radiation levels in

these

areas

would require entry into Secondary

Containment Control.

Without the information in Table SC-3, the operator cannot easily

determine if an entry condition has

been

reached.

I

I q

~

(1

~

q

' '; ~

'

'I V J,% g)>+

'P '"

tt1'

7.

EO-111

Level Restoration

A.

E0-111,

step

LR-33 requires

the

use of the Suppression

Chamber press-

ure gage located

on Panel

1C226A(B), which is outside

the Control

Room and

may not be available.

This fact is not noted in the step.

8.

EO-114

RPV Floodin

A.

B.

E0-114,

step

RF-4 directs the operator to flood the

RPV in accordance

with ES-152(252)-001

or ES-150(250)-001.

The referenced

procedures

do not clearly indicate which portion of the procedures

should

be

used to accomplish

the desired action.

E0-114,

Table RF-1, Conditions Requiring

RPV Flooding,

does not indi-

cate that the operator

must use the Suppression

Chamber pressure

gage

on Panel

1C226A(B), which is located outside the Control

Room and

may

not be available.

C,

The bases

for E0-114,

step

RF-11 indicate that two level indicators

must be restored

to exit RPV flooding.

This step

on the flowchart

does not indicate that two level indicators

are required.

9.

E0-.100

200 -030

Unit

1 Unit 2

Res

onse to Station Blackout - RPV In ect-

~ ion ~ Usin

Firewater

A.

Several

steps

in the

EOPs direct injection into the

RPV with the

firewater system in accordance

with EO-030.

The entry conditions for

EO-030 do not address

the

Neither the

EOPs nor

EO-030 reference

the section of EO-030 to accomplish

the desired

task.

B.

Step 2.5 which requires

the operator to remove

a unisolable blank

flange to install

a fire hose,

would result in the loss of fire water

from the fire system.

10.

EO-032

HPCI

S stem 0 eratin

Guidelines Durin

Station Blackout

HPCI

0 eration With Hi

h Lube Oil

Tem eratures

A.

The valve specified for connection of firewater to provide lube oil

cooling for

HPCI is not easily accessible.

Two other root valves',

downstream of the specified valve, are easily accessible.

No adapters

are readily available for connecting

3 inch fire hose

to the 3/4 inch valve connection to provide lube oil cooling for

HPCI.

The adapters

are supposedly available in a warehouse

on

site, but the operator did not know where to attain

them.

11.

ES-134

234 -001

B

assin

Dr well Coolin

Lo ic Isolations

A.

In order to reduce primary containment

pressure

in accordance

with

this procedure

CIG, Instrument Air, and Drywell Cooling must be

7

k

/

)

J

t

\\

1

I

'1

C

I

)

II

I

~ w

4

J

'

II

4

~

f

q

"

"'

Ia

>

P

~

I 8'

B.

restored

"as needed"

in accordance

with the applicable

normal operat-

ing procedures.

These operating

procedures

and ES-134(234)-001

do

not provide direction to open the drywell cooling chilled water in-

board

and outboard isolation valves which close

on high drywell

pressure.

These valves must be open to supply cooling water to the

drywell coolers.

E0-103,

step

PC/P-5 directs

use of ES-134(234)-001

to bypass

drywell

cooling logic isolations

when drywell pressure

is above

1.72 psig.

ES-134(234)-001,

step 4.8 provides direction to run drywell cooling

fans in fast speed if drywell pressure

is less than

2 psig.

The

procedure

does

not refer to section

4. 1 for operation of drywell

cooling fans in slow speed if drywell pressure

is greater

than

2

psig.

It is not clear whether drywell cooling fans should

be run in

fast

speed during emergency

conditions with drywell pressure

above

2

psig.

12.

ES-150

250 -001

RCIC Turbine Isolation

and Tri

8

ass

A.

Step 4.1.1 refers to the

"RCIC Keylock Switch", but the label for the

switch reads

"RCIC SYS A LOGIC".

B.,

C.

'tep 4.3. 1 refers to the "Reactor Vessel

High Water Level Signal

Sealed-in

& Reset" relay, but the label for the relay reads

" RCIC

Turbine Trip

The drawings in Attachment

A do not contain the

name of the relays

that they apply to.

13.

ES-150

250 -002

Bor on Injection Usin

RCIC

S stem

A.

B.

C.

The removal of piping and its replacement with a 2'- 4" pipe coupling

and

hose

appears

to be

a difficult task due to the physical arrange-

ment of the

SLC piping'dditionally, the 2'-4" pipe coupling,

supplied for use in this step,

might not fit the connection.

This is

due to

a chain link.welded to the pipe that could interfere with a

drain pipe at that location.

Step 4. 1 does not contain instructions to secure

the hose to insure

that the

hose

stays

in place,

This is important due to the long

vertical drop of the hose

from the

SLC tank to. RCIC.

The method of clamping the hose to smooth couplings

may not be ade-

quate

when the

hose

becomes filled with water.

14.

ES-152

252 -001

HPCI Turbine Isolation

Tri

and Initiation B

ass

A.

Steps 4.1.17

and 4.1.19 refer to "STM LINE ISO VLV BPV", but the

label

reads

"WARMUP LINE ISO".

J

~

d

B.

Step 4.4.5 refers to "INITIATIONSIGNAL HS-E41-S17

RESET", but the

label

reads

"HPCI INTSG RESET".

C.

In Attachment A, page 2, the relay

name is "HIGH DRYWELL PRESS",

but

the label

reads

"RN HIGH WATER LEVEL SIG SEALED IN 8

RESET".

15.

ES-155

255 -001

Vent

CRD to Insert Control

Rods

A.

There is no caution to tie down the drain tubing at the drain to

prevent kickout.

16.

ES-184

284 -001

B

assin

MSIV Isol ations

A.

Step 4.8 refers the operator to an operating

procedure,

OP-184(284)-

001, which is the procedure

used for normal

system operation.

Many

of the steps

and cautions

in this procedure

would not be applicable

or necessary

in an emergency situation.

17.

ON-155 255 -007

Loss of CRD Flow - Cross

Connect

CRD from Unit 2

A.

The procedure

does not contain

any directions to assist

the operator

in locating the applicable part of the procedure

to accomplish

the

task specified

by the

EOP.

B.

The procedure

does not contain

a restoration

section.

y r

)

1

I

'I

g

'l/'

8

'

l

.

~

g

T

4

/$ 9

I

l

p

.

" '"

9

p

~D1pt

ATTACHMENT D

HUMAN FACTOR EXAMPLES

The following examples

are provided to clarify the types of problems identified

in the areas of human factors concerns

described

in Section

7 of this report.

These

examples

are not intended to be viewed as

an inclusive list of all such

problems

found in the

but rather

as

a set of limited examples of the

types of inadequacies

found through the

human factors analysis.

l.

Verification of EOPs

from a

Human Factors

Pers ective

A.

Item 6.3.11 in the

EOP writers guide states

that lists in steps

which

are not identified as logical

AND lists are

assumed

to be

OR lists.

This direction is not followed in

several

places

in the

Step

S-4 in EO-101 states

that the operator

must ensure

several

items.

From the writers guide, this is assumed

to be

an

OR list; however, it

is an

AND list.

Step S-7 is another

AND list and step

S-10 is an

OR

list and all are formatted the

same.

B..

Item 6.2.10.d.

states that conditional

statements

shall not

appear

in decision

steps.

In Step

RF-18 in EO-114

a conditional

AND appears

in a decision

diamond.

Steps

DW/T-S, PC/P-ll and PC/P-19 of EO-103

are decision

diamonds that contain conditional

statements.

C.

D.

Item 6.3.10.c.

states

that

THEN is optional after

WHENs.

The imple-

mentation of this item in the flow charts is inconsistent.

In some

places

THEN appears after

WHENs and in places it does not

(See

Steps

RC/P-ll, RC-2,

and Lg-9).

Item 6.2.10.b.

states that "Yes" and "No" answers

shall

be placed

consistently

on 'the sides of decision

diamonds.

The main flow path

in EO-112

has three "Yes" answers

on the right side of the decision

diamonds

and then

a "No" on the right.

Consistent

placement of the

"Yes" and "No" answers

minimizes the potential for human error in the

use of flow charts.

2.

Action Verbs

A.

B.

"Slowly" in step

Lg-15 in EO-113 is used

as

an action verb, but is

not'defined in the writers guide.

"Observe" is defined in the writers guide

as "watch for an expected

occurrence

and does not require follow up."

However, in Step

S-7 in

EO-101 "Observe" is used

as

"Ensure."

"Ensure" requires

a follow-up

to cause

the action to occur if it has not already occurred.

"Verify" is also

sometimes

used

as "Ensure."

C.

Action verbs

used in the procedures

that are not defined in the

writers guides include <<Inhibit"

nInsertw, and>>Inform

l

lf'l

I

,3.

Cautions

and Notes

A.

Item 6.2.15 states that cautions shall

be located in the lower left-

hand corner.

In E0-113, the caution

box appears

in the upper right-

hand corner.

B.

C.

D.

E.

What is defined

as

a note in the writers guide (see

Step

S-27; the

box connected

by the dashed line) contains actions.

Cautions

and notes

are contained

in the

same

box, titled "Cautions

and Notes" (see all flow charts).

Cautions

are not placed before the steps to which they apply (see

Steps

S-27,

RC/P-8,

and Lg-13).

Statements

in various steps

read like cautions or notes,

but are.

formatted

as steps

(see

Step

RD-8 in E0-112).

4.

Writers Guide

A.

Steps

LR-6 through

LR-38 are contained

in a large decision

box.

However, the writers guide does not contain direction for construct-

ion of decision

boxes.

Step

S-27 in EO-101 is also

a decision

box.

- NUREG-5228 provides

examples

on

how to format decision

boxes.

B,

Step SP/L-4 is a "case" type decision

diamond.

Although the writers

guide does

not prohibit its use, it does not provide proper formatt-

ing techniques.

C.

The dashed

lines around

steps

LR-24 through

LR-29 and

LR-31 through

LR-34 in EO-111 are not defined in the writers guide.

D.

The formatting of steps

involving time are not presented

in the

writers guide.

However,

steps

RF-8 and RF-12 utilize time dependent

information.

E.

The format of ES-149(249)-001

does

not follow the writers guide

direction to begin each section of the procedure

on

a

new page.

5.

Transitions

A.

Examples of the

IAW (in accordance

with) transitions

are steps

RC/P-9

in E0-102,

PC/P-3

and PC/P-4 in EO-103

and

RR-4 in EO-105.

The

definition for IAW appears

in the procedures

writers guide (OI-AD-

055).

This definition states that .judgement

should

be used

as to

which steps

should

be performed in the procedure.

In emergency

situations

human error could result if judgement is allowed to any

great degree.

This is illustrated by PC/P-3

and PC/P-4.

Both steps

require actions

IAW ES-134-001,

but require actions

in two different

sections of ES-134-001.

If steps

are critical to mitigate the tran-

sient then the transition should clearly identify the section of the

procedure

to enter.'

af

A

I

,P

tlat

'-

<<'

P'

p tr'f '

~ 'ylCQ('(

( s"'

'"

['ll '5 'P'

'

'"

"'

+"

+

t 'p( <

'

~ );

N

'

'I

v ~r v

IAW is not clearly defined in the

EOP writers guide (AD-(A-330).

A format consistent with the

EOP writers guide would be to use the

concurrent exit and to list the section of the procedure to be

entered.

B.

Examples of the "perform" transitions

are steps

S-22 in EO-101

and

RC/g-43 in EO-100-102.

Perform is not defined in the writers guides

as

a transition method.

A format consistent with the