ML17286B115

In

addition,'he

inspectors

performed

an assessment

of the clarity and useabi lity

of the procedures,,

During this inspection,

Inspection

Procedures

41500

and

42001

were used,

2<<7<<9 ~!till)

None

911

$ 040044

>1101h

PDR

ADDCK 05000~~i7

Q

5'l.if<

4

I

Oj

Results:

The licensee

did not adequately justify several

significant technical

deviations

between their

ECPs

and the

Also, the inspection

identified numerous

other- less significant examples

of inadequate

justification of deviations

between

the

EOPs and'PGs,

and

between

the

and Plant Specific Technical

Guidelines

(PSTGs).

In addition,

the inspection

identified several

examples of deviations

which were not identified by the

licensee.

.The inspection

concluded that the licensee's

EOP verification and

validation program

was flawed in its execution

and quality.

By the

end of the inspection period,

the licensee

had revised

the

EOPs further

to eliminate the most significant of these deviations,

They agreed

at

a

meeting

on August 28,

1991 to supply additional technical justification for

the balance of the deviations.

They also agreed

to provide this information

thirty days after this inspection report was received,

The licensee's

training program for operators

appeared

thorough,

Management

and peer utility participation in training evaluation

was extensive,

and

appeared

effective.

The licensee's

corrective action plan appeared

complete,

'The inspection

verified that all open restart

items were being tracked,

and

no

new restart

items were appropriate.

The licensee's

revision of the

appeared

to have significantly improved

the, clarity and useabi lity of'the

Bonneville Power Administration

However, the inspection

made sev'eral

specific observations

for further improvement of their useabi lity.

~tl

Open

Item 91-27-01

was identified to track the licensee's

corrective actions.

IN

P ECT ION DETAILS

Persons

Contacted:

A~ L, Oxsen,

Deputy Managing Director

C, M, Powers, Director of Engineering

D, Bouchey, Direc'tor, Licensing

and Assurance

J. Baker, Plant Manaoer

S. L. McKay, Plant Operations

Manager

D. R.

Kobus, Manager,

Technical Training

B, Barmettlor,

Manager Nuclear License Training

D, Topley, Supervisor,

Requalification Training

D. Conserriere,

SRO on assignment

to training

B. Mixson, Communication

and Assessment

Specialist

E. Bates,

Instructor/Simulator

Evaluator

(General

Physics)

D, Rodgers,

I'nstructor

(Gener'al

Physics)

M. Elliot, Instructor (General

Physics)

M,,Williams, Peer Evaluator

(Brunswick)

R, Tate,

Peer Evaluator

(Brunswick)

B. Nunez,

Peer Evaluator (Limerick)

C. H, McGitton, Manager,

Operations

Assurance

D. L. Williams, Nuclear Engineer,

The inspectors

also interviewed

a number of other licensed operators,

supervisors

and managers

in the operations,

training, quality assurance,

and licensing departments.

Attended the Exit Meeting

on August 2,

1991, at WNP-2.

Summar

of Results of the Ins ection

Onsite

and Review

NRC Head uarters)

The onsite inspection

concluded that the licensee's

Plant Specific

Technical

Guidelines

(PSTGs)

did not accurately

incorporate

the guidance

of Revision

4 of the

and that the licensee

had not adequately

evaluated their deviations

from the

EPGs to provide

a clear

technical justification for numerous potentially significant deviations.

The review at

NRC Headq'uarters

concluded that

none of the individual

deviations

required

immediate corrective action by the licensee,

However,

the following significant concerns

related to the

EOP development

process

were identified:

2.

The licensee

did not identify or justify deviations

from

numerous

BWROG EPGs with sufficient quality or depth of effort,

The licensee

inappropriately applied the licensing design basis

analysis

when identifying and justifying deviations

from some

of the

3,

The licensee,

in some cases,

removed available

equipment

and

mitigation strategies

from use

based

on operator

judgement without

sufficiently analyzing

the safety significance of removing the

options.

The licensee,

in some cases,

created

PSTG steps

and

EOP flowcharts

which did not reflect the accident

management

strategy

described

in the deviation documentation,

2

These errors

were manifestations

of significant weaknesses

in the

licensee's

verification and validation program,

At the meeting

between

the licensee

and the

NRC on August 28,

1991, the

licensee

agreed

to respond to the

NRC's concerns

specific deviations identified by the

NRC in the next revision to

the

They also

agreed

to withdraw Implementation Deviation 428

(from the licensee's list of design,

strategy,

and implementation

deviations)

and correct. the

EOPs in a'udicious

manner.

This deviation

restricted

the reactor pressure

vessel

vent path during containment

flooding to the main steam lines only, using the main steam isolation

valves.

In addition to the concerns

related to the

EOP development

process,

the

inspection

and review both identified several

human factors

concerns

WNP-2

Open Item 50-397/91-27-01

was created

to track the licensee's

completion

ov corrective action for,all of the concerns

identified in this report.

Ins ection of Emer enc

Operatin

Procedures

(41500

42001)

a

~

~Back round

Following the Three Nile Island

(TMI) accident,

the Office of

Nuclear Reactor

Regulation

(NRR) developed

the

"TMI Action Plan,"

(NUREG-0660

and

NUREG-0737) which required

licensees

of. operating

plants to reanalyze

transients

and'ccidents

and to upgrade

(NUREG-0737 Item'.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 Procedures

Generation

Package

(PGP) to prepare

The .licensees

formed four vendor

owners

groups

corresponding

to the

four major reactor

vendor types in the United States:

Westinghouse,

General Electric,

Babcock

E Wilcox, and Combustion Engineering.

Working with the vendor companies

and the

NRC, the owner's

groups

developed

generic

procedures

that set forth the desired

accident

mitigation strategy,

For General Electric plants,

the generic

guidelines

are referred to as the

These guidelines

were to be used

by the licensee

in developing their

PGPs,

Generic Letter 82-33,

"Supplement

1 to NUREG-0737 - Requirements

for Emergency

Response

Capability," required

each licensee

to

submit to the

NRC

a

PGP which included,

( 1) Plant Specific Tech-

nical Guidelines

(PSTGs) with justification for safety significant

differences

from the

(2)

a Plant Specific Writer'

Guideline

(PSWG), (3)

a description of the program to be used for

the verification and validation of EOPs,

and (4)

a description of

3

the training program for the upgraded

The generic letter

required

the development

of plant-specific

EOPs which would provide

the operators

with directions to mitigate the consequences

of

a'road

range of initiating events

and subsequent

multiple fai lures

or operator errors,

The upgraded

EOPs were. required to be

symptom-based

procedures

which would not require

the operators

to

diagnose

specific events.

NRC Information Notice (IN) 86-64

was issued

on August 14;

1986

and

IN 86-64,

Supplement

1,

was issued

on April 20,

1987,

IN 86-64

alerted

the licensee

to problems

found in review and audits of

Procedure

Generation

Packages

(PGPs)

and

The

IN indicated

that many utilities had not appropriately

developed

or implemented

upgraded

.and identified deficiencies

in the development

and implementation of each of the four major aspects

of the upgrade

program (i,e.,

undocumented

deviations

from and inappropriate

adaptation

of

BMROG EPGs, 'failure to adhere

to the

PSWG, failure to

adhere

to the verification and validation programs,

and deficient

training programs),

Supplement

1 to IN 86-64 alerted

the

licensee

tn significant problems that were continuing with plant

Deficiencies

were identified in all the major aspects

of

the

EOP upgrade

program.

The licensees

were requested

to review

=

the information for applicability to their facility and consider

actions to correct or preclude similar problems

from occurring.

0~i

WNP-2 is

a General Electric

BWR-5 plant,

The objective of this

portion of the inspection

was to determine

whether the

revisions effectively

( 1) improved the useabi lity of the

EOPs;

(2)

corrected

the previously identified significant technical

weaknesses;

and (3) verified and validated

the

EOP changes,

The inspection

team compared

Revision

4 of the

BWR Owner's

Group

.(BWROG) Emergency

Procedure

Guidelines

(EPGs) to the Plant Specific

Technical

Guidelines

(PSTGs),

and

compared

the

PSTGs to the

The inspection

was

based

on

a draft of the

EOPs which incorporated

Revision

4 of the

and corrected

deficiencies

which had

been identified during

an

NRC. Emergency Operating

Procedures

Inspection

(Inspection

Report 50-397/90-20).

The latest draft version of the licensee's

EOPs were derived from

Revision

4 of the

BMROG EPGs,

This

EPG revision had incorporated

a

revised accident strategy

and calculational

methods

which were

'approved

by the

NRC in

a generic Safety Evaluation

Report

(SER)

issued

on September

12,

1988.

The inspection

team reviewed the

draft

because

the licensee

was in the final stages

of

implementing

and training the operators

on this significant

revision to their EOPs.

This revision

had iust been

made

as

a

result of unsatisfactory requalification program results

which were

partially related

to

EOPs which had

been difficult to use.

The

licensee

had scheduled full implementation of this draft of the

EOPs prior to restart.

The previous version of the licensee's

had also derived from Revision

4 of the

BMROG EPGs.

l

','l

l

During the inspection,

the

team reviewed

a version of the

PSTG

which the licensee

provided in WYP-2 Procedure

5.0,8,

"VNP-2

Emergency

Procedure

Guidelines,"

dated 7/13/91, 'lthough this

version

was annotated "final draft," it contained

numerous

deletiors

and handwritten

changes

and

had not been

approved,

I Gl .~IG I

Twenty-s'ix deviations

were identified between

the

and

the plant-specific technical guidelines

(PSTGs).

The inspection

team identified that several-of

the differences

resulted

from one

strategy deviation which resulted

in multiple differences

from the

The inspection did not attempt to identify every example of

these

changes.

However, it was

an extensive

sample

comparison of

the

PSTGs,

and

Seventeen

specific strategy

devia-

tions were identified.

The inspection

team was concerned

that the licensee

had not ade-

quately evaluated

the strategic deviations

from the

In

support of this inspection,

the licensee

provided

a document

titled "WNP-2 Deviations to Revision

4 of the Emergency

Procedure

Guidelines,"

Although this document

(annotated

as "Tim's Copy,")

was not dated or approved,

the licensee

indicated that it

represented

the latest version of their deviation document.

The

deviation document's

stated

purpose

was to "...identify and

document

the 'deviations'hat

WNP-2 has

taken to Rev.

4 of the

BWROG Emergency

Procedure

Guidelines

(EPGS),"

The document's

stated

scope

was to pro'vide "...a detailed

comparison of the

generic

guidance

provided in the

and the plant-specific

guidance

provided in thy WNP-2 EPGs.

Where deviations

to the

generic

guidance exist, justification is provided.

A deviation

was defined

as

a change

in intent or philosophy relative to the

actions/strategies

provided in the generic

BWROG Guidance,"

The inspection

team noted that the Justification Section for each

of the deviations listed in the deviation

document

provided the

licensee's

engineering

judgement or conclusions,

In most cases,

these

judgements

and conclusions

were not supported

by

a detailed

analytical engineering

evaluation,

Rather,

the licensee's

iustification provided

a conclusion regarding their technical

judgement of the feasibility of the different strategy

and the

consequence

of the deviations.

Specifically, the inspection

team identified the following five

significant deviations:

( 1)

Prevention of RPV Cooldnwn with Potential Recriticalit

- The

deviation document

page

39

de eted the override prior to

EPG step

RC/P-3,

This override required returning to the

pressure

control actions of step

RC/P-2 if the reactor

became

recritical during the subsequent

cooldown actions of step

RC/P-3,

In addition, the deviation

document

(page

40)

deleted

the fourth bullet of. EPG step

RC/P-.3

and

(page

45)

the third bullet of step

RC/g.

These

steps

required depres-

0

surization

and cooldown when the reactor

was

shutdown

and

no

boron

has

been injected into the reactor

pressure

vessel

(RPV).

Based

on these deviations,

the deviation

document

(pages

43 and

156) also modified

EPG step

RC/P-5

and deleted

the fourth bullet of

EPG step

C2-2 which required verifica-

tion that 'the control

rods

have

been fully inserted

or the

reactor

was

shutdown,

or boron

has

been injected prior to

proceeding

to cold shutdown,

The

EPGs allow cooldown

and depressurization

with the reactor

subcritical with th'e possibility of recriticality, because

delaying the cooldown

and depressurization

is not necessary

unless

boron is being injected into the core.

The

RC/P steps

provide adequate

assurance

that the positive reactivity

addition of this cooldown would be slow and controlled,

The

licensee justified this deviation

becaus'e

they concluded

that the

BWROG guidance

was "not conservative,"

because

they

want to delay cooldown until subcriticality "could assuredly

be maintained,"

The inspection

team identified these

deviations

as

items

CAV-13, CAV-15 and

CAV-25 during the inspection

and concluded

that they were significant deviations.

Although the licensee

had identified it as

WNP-2 Strategy Deviation No. 2,

a

detailed

engi neering evaluation of the consequences

of this

strategy deviation

was not performed,

Dela

ed Entr

into Power/Level

Control if Two Standb

Li uid

ontro

um

s are

unnsn

-

T e deviation

document

page

1

6

added

a

new step to

EPG step

C5-2 (Level/Power

Control) to require "Less, than two

SLC pumps are injecting

into the

RPV or (emphasis

added)

reactor

power is not

decreasing,"

before

RPV water level will be lowered to

decrease

reactor

power during

an anticipated transient

without scram

(ATWS).

The effect of this deviation

was to

prevent the operator

from lowering

RPV water level during

an

ATWS to reduce reactor

power when other. actions

have not been

effective, provided

two SLC pumps were running.

The licensee justified this deviation

because

their

plant-specific

ATWS analysis

showed that if two

pumps

were running the integrity of the primary containment

would

not

be threatened.

The justification for this deviation

stated that the licensee

decided

not to lower

RPV water level

unless

the injection of boron did not occur because

con-

trolling reactor

power in this manner

was unstable,

(3)

The licensee's

justification neglected

the potential that

both

pumps

may

be running, but not injec'ting boron into

the

The additional

step delayed

the operator's

response

to the

symptom of high reactor

power based

upon the assump-

tion that

two running

SLC pumps would'be effective in reduc-

ing reactor power., The l.icensee's

plant-specific

ATh'S

analysis

was

based

upon the assumption

of

a single-failure

analysis

which assumes

that only one of the

SLC pumps could

fai 1,

However, the actions of the 'EPG are intended

to

address

both above-

and below-design

basis

accidents,

As

a

result, this deviation prioritizes

ar

"event-based"

action

before

a "symptom-based"

response.

The inspection

team identified this deviation

as item CAY-31

durino the inspection

and concluded that it was

a signi.ficant

deviation.

Although the licensee

had identified it as

MNP-2

Strategy Deviation

No, 8,

a detailed

engineering

evaluation

of the consequences

of this strategy deviation

was not

performed.

(See Attachment

C, Strategy Deviation 8 for.

the

NRC review team's additional

concerns

with this item,').

Deletion of Hi

h Pressure

Core

S ra

HPCS)

Net Positive

Suction

Head

NPSH

Limits - The deviation

document

page*8)

de eted

EPG Caution.No,

5 concerning

the

NPSH limits.

The

EPGs provide these limits in an overall caution step

so

'that the operator

could refer to them during

a subsequent

accident,

Although this information is important for all

~ pumps,

the

EPGs place the limits for the reactor core isola--

tion cooling (RCIC) and

HPCS systems

vortex

and

NPSH limits

.

in an overall caution step

based

upon the importance of

monitoring these limits during the degraded

conditions of

, primary containment

and drywell pressures,

temperatures

and

levels.

The licensee's justification indicated that this information

was deleted

from the caution

because

the guidance

was only

applicable

to

EPG step

RC/L-2 and at this poi'nt in the

EPGs:

( I) plant conditions

have not degraded

to the point that

operation,

irrespective of hPSH limitations,

was authorized;,

and (2) suppression

pool heatup or

a reduction in suppression

pool level

was not significant enough to threaten

the

NPSH.

Additionally, the justification concluded that the

caution is unnecessary

because

the

HPCS system

was designed

to prevent cavitation

due to pump runout.

lhe licensee's justification did not address

the possibility

that the operator

may

be required to reenter

EPG step

RC/L-2

at

a later stage of an accident

when the plant conditions

have

degraded,

In addition,

these

NPSH limits are important

because

they may form the basis for deciding which of several

available injection systems

should

be used,

The

HPCS system

may not

be the most appropriate

choice if a lower

head

pump

that would not cavitate is available.

I

~,

(4)

The inspection

team identified this deviation

as item CAV-3-

during the inspection

and concluded

tha.t it was

a significant

deviation,

Although the licensee

had identified it as

WNP-2

Design Deviation No,

1,

a detailed engineering

evaluation of

the consequences

of this strategy deviation

was not performed.

(See also Attachment

C, Design Deviation No.

1 for the

NRC

review team's

additional discussion

of this item.')

Deletion of Low Pressure

Core

S ra

(LPCS)

and

Low Pressure

~ore

n ectton

t

page

22

modified t e fs t

and sixth bullets in EPG step

RC/L-2 which require ensuring that the

LPCI and

LPCS system

flows are controlled

and maintained

below curves for both the

NPSH and vortex limits.

The deviation

document deleted

the

reference

to the

LPCI

NPSH limits and

removed

the curves

entirely.

The removal of these limits from the step

and the deletion of

these

curves

from the

EPGs entirely were not discussed

in the

justification section of the deviation document.

The

intend the operators

to control

LPCS flow within the

NPSH

curve for the

pumps,

The

EPGs did not incorporate

these

limits in an overall caution statement

like the

HPCI

NPSH

limits because

the

LPCS curves

are not flat like the

HPCS curve.

The inspection

team identified this deviation

as item CAY-7

during the inspection

and concluded that it was

a significant

deviation.

Because

the licensee

had not identified it as

a

WNP-2 Deviation,

a detailed engineering

evaluation of the

consequences

of this strategy deviation

was not performed,

(See also Attachment

C, Design Deviation No,

1 for the

NRC

review team's

discussion of this item.)

Incom lete

Im lementin

Procedures

for EPGs.

The inspection

team also noted that the licensee

had not

developed all the implementing procedures

for the

especially

those actions that are to be accomplished

outside

the control

room.

Although the licensee

did not develop

these

emergency

support

procedures

(ESPs)

as flowcharts, they

are

an integral part of the

EOPs which must

be available to

accomplish all the

EPG actions.

For example,

the

ESP for EPG

Contingency

No,

6 (Containment

Flooding)

was not available

for review at the time of the inspection.

This concern

was identified as

CAV-16 during the inspection,

The licensee

was developing

these

procedures

during the

inspection;

therefore, it was .not identified as

a deviation.

However,

the inspectors

concluded that the absence

of these

procedures

for training

and validation was

a significant

omission

from the training of operators

which had occurred

by

that time,

Yany additional

examples

of inadequately justified EOP/EPG deviations,

as well as other deviations

were identified by the inspection,

These

are detailed in Attachment

A,

<'I

f,

The inspection

team

was concerned

that the licensee justified many

of the deviations identified based

upon the conclusion that the

licensing

and design

basis of VNP-2 precluded

taking the actions

recommended

by the

As stated

in Section

2 of the

BWROC

the

EPGs were developed

as

an accident mitigation strategy

that makes

the optimum use of plant equipment

and design,

regard-

less of the type of event which occurs.

All plant conditions for

which generic operational

guidance

could

be practically provided

were addressed,

irrespective of the probability of their occurrence

or whether they involved multiple failures or operator errors.

Thus,

the

address

a spectrum of conditions

more severe

than

were considered

in developing

the plant design

and licensing basis,

In this manner,

the entry conditions

and operator actions

are

keyed

.

to certain plant parameters

or symptoms.

Actions are specified

as

appropriate

to restore

and maintain these

key plant parameters

to

within limits which define safe operation.

Operator actions,

limits, and action levels

are

based

on realistically bounding

best-estimate

engineering calculations

as

opposed

to design-basis

analytical

methods

and assumptions.

Although the

were intended to provide the best possible

operational', guidance, it was not intended that the

EPGs would

extend

any design

basis

beyond that which was currently estab-

l.ished,

The

NPC staff reviewed the General Electric Topical Report

NE00-31331,

"Emergency

Procedure

Guidelines,

Revision 4," dated

March ]987,

and found the

EPGs to be generally acceptable

for

implementation,

The.SER for this report stated

that each

BWR licensee

who used

Revision

4 of the

should assure

that the

EPGs did not impact

its licensing basis.

Two possibilities could arise

'in this case,

Each

BWR plant could implement

a plant specific strategy

which

would be consistent with its safety analysis,

and provide additional

justification of such

a deviation,

Alternatively, the plant could

revise its licensing basis

and adopt the generic strategy.

Significant deviations

from the technical guidelines

should

be

supported

by engineering

analyses.

NUREG 0899

recommended

that-

these

analyses

consider

(1) the integrated

performance

of the

NSSS

and balance of plant systems,

(2) the completeness

of the accidents

and transients

analyzed,

(3) the

use of appropriate

models,

calculational

methods,

and plant data,

(4) audit calculations

of selected

accidents

and transients,

(5) the adequacy

of 'the

program to develop guidelines

form the analysis of accidents

and

transients,

(6) testing thc guidelines

against

scenarios

including

multiple failures,

and (7) the information and control

needs

of the

.operators

to execute

the instruction of the guidelines,

During the inspection

and at the exit meeting,

the licensee

OuOereasoned

that deviations

from the

BWROG EPGs were justified if the

EPGs specified actions that were not within the scope of their

licensing or design

basis prior to exceeding its design or

licensing basis.

In addition, in several

cases,

WNP-2

I

W

~

'

devi.ated

from the

EPGs for beyond design

basis

events

when

they concluded that the

recommended

actions

were inappropriate

and

an alternate

strategy

was

recommended

for substitution in the

WNP-2

FOPs.

However,

WNP-2 did not provide additional

information or

perform an analytical

engineering

analysis

tc demonstrate

that the

revised

accident strategy

provided

an acceptable

or comparable

technical

guideline.

The licensee

stated

during the inspection

and at the exit meeting

that many of their deviations

were analyzed

and justified by an

internal technical

memorandum,

At the request of the

NRC Project

tlanager,

the licensee

provided

a partial

copy of Technical

Memorandum

(TN-2005, dated

December 4,

1990) titled, "Engineering Basis for

Justifying Deviations to

NRC Approved

EPG Rev.

4 Strategies."

The

inspection

team reviewed this document,

and concluded that it did

not support

the deviations

which had

been taken,

The inspection

team concluded that the licensee's

PSTGs did not

accurately

incorporate

the guidance of Revision

4 of the

and that the licensee

had not adequately

evaluated their deviations

from the

The licensee failed to provide

an adequate

enoineering

analysis

to demonstrate

the acceptability of their

alternate

accident mitigation strategy.

d,

Results of PSTG/EOP

Com arison

The inspection

team also identified se'ven differences

between

PSTG

steps

and their

EOP equivalents,

This implied that, either the

PSTG, or the

EOP,

was incorrect.

The

and the

PSTG must

be

consistent

with each other.

Further licensee

action is'ecessary

to either revise the

EOPs or the

PSTG,

as appropriate,

so that both

are consistent with the

These

PSTG/EOP differences

are detailed in Attachment

B.

4.

Review of Emer enc

0 eratin

Procedure

Deviations

In response

to the major scope

and depth of the inspection

team's

findings in the

EOP area,

a followup review by

a second

NRC team

was

conducted

August 12-27,

1991 at

NRC Headquarters.

A meeting

was held

with the licensee

on August 28,

1991 to further discuss

the

deviations,

The results of that review are discussed

in the next

paragraph,

The purpose of this review was to further assess

the technical

adequacy

of 'the licensee's

deviations

from the

BWR Owners

Group

(BWROG) Emergency

Procedure

Guidelines

(EPGs).

The review did not assess

the overall

technical

adequacy

of the

WNP-2 Emergency Operating

Procedures

(EOPs).

This review focused

on the deviations identified by the licensee

in their

"deviation document."

It did not include

a complete

EPG to

PSTG

comparison

or

a comparison, between

the

PSTG

and

except

when

necessary

to understand

the intent of the deviation.

"

l

.1

l

~ i,

f

. 10

The licensee

withdrew

a

number of the deviations following the onsite

inspections,

The licensee's

withdrawal of several

deviations following

the onsite inspection indicated to the

NRC the licensee

recognized

these

deviations

to

be undesirable.

The licensee

provided additional information

to support the remaining deviation justifications.

This information was

used

along with the draft "deviation document" during the review of the

MNP-2 deviations

from the

Descriptions

of the specific deviations that

WNP-2 has

taken from the

.

are provided in .Attachment

C.

The following findings are

supported

by examples of deviations

referenced

to the licensee's

three

lists of design,

strategy,

and implementation deviations,

respectively.

The documentation

of the justifications for many of the deviations

between

the

and the

MNP-2

PSTG -.in the "deviation document"

was

not adequate.to

assess

the technical

adequacy

of, the deviation.

The

additional

information provided

by the licensee

subsequent

to the onsite

inspection

to support

the deviations

was more complete,

but was still

insufficient in many cases.

For example,

the justification for deletion

of the primary containment

vent valve closure

pressure

in the Primary

Containment

Pressure

Limit (PCPL) calculation did not address

the

consequences

of attempting to close the valve above its .rated closure

pressure

(Implementation Deviation ¹32).

Discussions

with the licensee

concerning the, deviations that did not have

adequate

technical justification indicated that the quality and depth of

effort associated

with analysis of the deviations

was lacking,

For

example',

the licensee

specified that multiple level instruments

must

be

available, prior to termination of RPV Flooding rather than

a single level

instrument without consideration of the negative effects of RPV Flooding

( Implementation Deviation ¹26),

The licensee

also took

a deviation in

allowing bypass

of main steam tunnel

high temperature

isolation

interlocks without adequate

assessment,

of the

EPG bases

for

restricting the action

( Implementation Deviation ¹35),

In addition to the withdrawal of deviations,

and the deviations

between

PSTGs

and

EOPs which were not adequately justified, the

NRC identified

several

differences

between

the

BMROG EPGs

and the

WNP-2

PSTGs that were

not identified

as deviations

in the "deviation document,"

For example,

the licensee

deleted

the Standby Liquid Control

(SLC) test tank as

an

injection source,

but failed to identify and justify the deviation,

It

is important to identify and justify all deviations

from the

that result in logic or strategy

changes

to ensure that the overall

effectiveness

of the

BMROG

EPG accident mitigation strategy is not

diminished,

This is another indication of poor quality in the

development

process.

Further,

a

number of deviations

were noted

by the

NRC that were

identified in the "deviation document,"

but were not included in the

licensee's list of deviations.

Additionally, the list of deviations

often did not reference all of the applicable

steps

in the

PSTG affected

fj

l

i1

~,

!

11

by the deviatioh,

For example,

the 'deviation to utilize RCIC suction

from the suppression-pool

did not reference

the applicable

section of the

Primary Containment

Flooding contingency

procedure

(Strategy Deviation

¹I). It is important to assess

the effect of

a deviation

on the entire

accident mitigation strategy.'herefore, it is necessary

to ensure that

all sections

of the

EPGs affected

by the aeviation

are addressed,

The licensee

based

the justification for

a number of deviations

on design

basis

analyses.

'Ihe'licensee

made conclusions

based

on the results of

analyses

for specific accident

sequences

without consideration of other

potential malfunction or adverse

conditions.

,For example,

WNP-2

EOPs did

not lower level to control reactor

power in an anticipated transient

without scram

(ATWS) condition if'two SLC

pumps

were operating

and

reactor

power was decreasing

(Strategy Deviation ¹8).

The justification

for this deviation

was

based

on

a design

basis

ATWS analysis that

, indicated that the reactor will be shutdown

and the containment integrity

will be maintained with the

SLC pumps operating

as designed.

The licens-

ee did not consider

the adverse effects

on the containment

from the

additional'heat

input if the

pumps were to subsequently fail.

As

discussed

in the previous section,

the

are designed

to

mitigate the consequences

that can occur

as

a result of multiple

failures.

The

EPG strategy to lower level in addition to boron

injection with SLC prov'ides

a "defense

in depth" strategy that assures

continued

safe operation of the plant under

degraded

conditions.

Some of the deviations

tal en by WNP-2 removed options

and mitigation

strateqies

that are specified in the

For example,

WNP-2

deleted

the direction to bypass

drywell cooling isolation interlocks to

allow drywell cooler operation for drywell temperature

control

(Design

Deviation ¹6),

They also

removed the option to rapidly depressurize

the

RPV to the main condenser

when Emergency Depressurization

is anticipated

(Design Deviation f4),

These actions

were deleted without an adequate

assessment

of the consequences

of deleting the strategy or option.

WNP-2

deleted

several

mitigation strategies

without clearly demonstrating

the

negative

consequences

of -implementing the strategy,

or compensating

for

removal of the strategy.

In several

cases,

the

WNP-2

EOPs did not reflect the logic presented

in,

the

PSTG,

For example,

the

PSTG directed termination of steam cooling if .

an injection source

was lined up while steam cooling was in progress.

The

WNP-2

EOPs did not direct termination of steam cooling until level

dropped

below -205" regardless

of injection system lineup,

Termination

of steam cooling when

an injection source is lined up is

an integral part

of the analysis

used to justify the deviation to delete

the

low pressure

override from the Alternate Level Control Guidelines

(Strategy Deviation

¹6).

The technical

adequacy of the

PSTG is dependent

on accurate

implementation of the

PSTG logic into the

The

EOP verification and

validation

(VSV) program should

ensure

that the

PSTG logic is accurately

reflected in the

~

l

12

In conclusion,

during review of the deviation justification documentation,

NRR identifiea several

concerns

related to the

EOP development

process.

'The quality and depth of effort associated

with identification and

justification of deviations

from the

was 'not adequate.

The

documentation

of the justifications did not provide sufficient information

to evaluate

the technical

adequacy

of the deviation in many cases.

Application of the licensing design basis

analysis

was inappropriately

applied

when identifying and justifying deviations.

Conclusions

were

based

on

a design

basis

analysis for specific accident

sequences,

excluding consideration

of other malfunctions or adverse

conditions,

Deviations were taken that removed available

equipment

and mitigation

strategies

for use

based

on operator

judgement without sufficient

analysis of the safety significance of removing the option.

Some

PSTG

steps

and

EOP flowcharts did not reflect the accident strategy

described

in thedeviation documentation

indicating deficiencies

in the licensee's

V&V program,

Each of the discrepancies

identified was

an indicator of significant

EOP verification program weakness.

Human Factors

Review of EOPs

a

~

~Summa r

A human factors review of the revised

WNP-2 Emergency Operating

Procedures

(EOPs)

was conducted

in accordance

with Inspection

Procedure

42001,

"Emergency Operating

Procedures,"

and the criteria

outlined -in the

WNP-2 restart inspection plan.

The inspection

plan

criteria

used

was:

have

been revised to eliminate siginificant human factor

errors,

such that

and supporting

procedures

could

be

physically and correctly performed.

The

WNP-2 Symptomatic

Emergency Operating

Procedures

Writer'

Guide, Plant Procedure

Manual 5.0.2 (P.P.H. 5.0.2),

WNP-2 Emergency

Operating

Procedures

User's

Guide, Plant Procedure

Manual 5.0.7

(P.P.H, 5.0.7),

and

a selection of EOPs were reviewed for

consistency

with human factors principles described

in NUREG-0899,

NUREG-1358,

and

NUREG/CR-5228.

Generally,

the licensee's

revised

EOP development

guidelines

incorporated

human factors principles described

in these

NUREGs,

and the

were developed

in

a manner consistent

with the

WNP-2

EOP development

guideline criteria.

However,

the review identified

a number of human factors

concerns

including:

( 1)

inconsistent

and excessive

use of transitions,

(2)

embedded

logic/decision steps,

1

(3)

lack of definitive

EOP development criteria

on the use of color-

coding

and override decision steps,

and

(4)

a lack of guidance

on placekeeping

and the intent of contingency

statements'The

licensee

was apprised of these

findings and committed to review

the

EOPs to ensure

these

concerns

were addressed.

Inconsistent

Use of Transitions

Transitioning within and

between

procedural

flowpaths

and support

procedures

can cause

confusion,

delay accident mitigation,

and

contribute to operator error.

Because

of these

concerns,

definitive .criteria should

be established

to ensure consistent

development

of transition steps

in procedures.

Additionally, the

development of EOPs

should focus

on minimizing the

need for

transitioning within and between

procedures

where possible.

The

MNP-2

EOPs contained

several

examples

of concerns

associated

with transition points including:

(I)

the inconsistent

use of exit arrows following contingency

statements,

(2)

excessive

transitions

based

on the use of contingency

statements

and associated

overrides (in some instances

the

transition from

a contingency

statement

-to an override

statement

and then to the appropriate

contingency flowpath

introduced

an unnecessary

intermediate transition),

(3)

the lack of any demarcation

(or grid) pattern

on the

flowcharts to aid the operator in transitioning to the

appropriate

entry point(s) of another flowchart or flowpath,

(4)

the lack of definitive color-coding criteria for match-mark

symbols

used to aid the operators

in transitioning

between

flowpath segments

on individual flowcharts,

and

( 5)

the lack of definitive criteria for the implementation of

override steps

and subsequent

actions

associated

with these

override steps

when they have

been

reached

through

a

contingency

statement.

EGP transition steps

should

be structured consistently

because

there is the potential for degradation

of decision

making under

highly stressful

conditions,

Additionally, decision

steps

should

be incorporated into the procedural

structure in

a manner which

ensures

that they are perceived

and evaluated

appropriately.

I

II

Imbedded

Lo ic Ste

s

The

WNP-2

EOPs contained

several

decision

steps

(e,g, logic

statements)

which were

embedded

in tables

referenced

from the steps

in the

EOP flowpaths.

In several

instances

these

decision steps

contained

an override condition, which if present,

required

an

additional transition to an entry point on another flowpath (e.g.

RPV-Control, Table 13),

Where practical,

these

logic statements

should

be incorporated

into the flowpath structure directly,

In

instances

where these logic statements

pertain only to the table

information, they should

be emphasized

appropriately

to ensure

they

are perceived

and evaluated

by the operators,

Im recise

EOP Develo ment Criteria

The

EOP Writer's Guide (P,P,N. 5,0.2)

and the

EOP User's

guide

(P,P.N, 5,0;7)

lacked defini tive guidance

in several

areas

including:

( 1) color-,coding for match-mark transition symbols,

(2)

override decision steps,

and (3) placekeeping,

This lack of

guidance

may contribute to inconsistencies

in th'e development of

the

and their subsequent

use

by operators.

Color-coding

was not used consistently in

the

WNP-2 EOPs,

Color coding was

used to aid the operator in identifying

override conditions which are applicable

when specific

contingency

statements

are encountered,

By design,

objects

of "like" color were related to one another (e.g,,

emergency

depressurization

contingency

and override statements

are

coded "green").

However, color-coding

was also

used for

match-mark

symbols which represent

connections

between

flowpaths

on

a specific flowchart,

The

EOP Writer's Guide described

in detail

the color-coding

conventions for override

and contingency statements,

but did

not contain

any additional

information on the color-coding

conventions for the match-marker

symbols.

As

a result,

several

match-mark

symbols

used

the

same color-coding

conventions

as override

and contingency

statements

and

additional match-mark

symbols,

This practice could lead to diluting the effectiveness

of

color-coding

used in the flowcharts (e.g.,

adding "visual

noise" to the flowcharts)

and create

a condition where the

operator falsely establishes

relationships

between flowchart

symbols which are not intended,

Definitive criteria should

be established

for the color-coding

corventions

used for match-marks

in the

EOP flowcharts.

I

15

'2)

The

WNP-2

EOPS did not have

a consistent orientation for

the

Y/N (Yes/No) exit points from decision steps,

1

'ecision

steps

are inherently difficult to deal with under

stressful

s itua tions.

Therefore,

where practical,

deci s i on

steps

should

be developed

which are simple

and consistent.

In doing so', operators

can'develop

expectations

based

on the

fact that

a decision

step

has

been encountered

and take the

appropriate

actions

based

on predefined

established

rules.

By providing consistency with respect

to the direction on the

flnwpath to be taken from a decision point, the operator

can

implement these

rules which may aid in navigating through

a

complex network of procedural

paths,

If practical,

the primary direction of movement

should

be

based

on the actions

and decisions

operators

need to make

and

not on the arbitrary placement of Y/N exit points to avoid

operator

expectancies

as described

in the

EOP Writer's Guide.

If the development of

a consistent orientation for the

Y/N

exit points requires

rephrasing

the decision

steps

in such

a

way that it introduces

confusion (e.g.,

using double-negative

phrases),

then it may

be more appropriate

to vary the

orientation of the

Y/N exit points

and retain the original

format,

(3)

,'Placekeeping

provides

the operator with

a mechanism for

tracking pr'ogress

through the complex network of procedural

paths,,and

helps

ensure

that the Control

Room Supervisor

maintains situational

awareness

throughout transient

mitigation.

The

EOP Writer's Guide

and

EOP User's

Guide did

not describe

the development of placekeeping

or define

any

method for implementing placekeeping,

Because

nf the benefits

provided

by establishing

placekeeping

methods,

guidelines for the use of placekeeping

should

be

provided,

and operators

should

be trained to implement these

methods.

Ins ection of 0 erator Trainin

Effectiveness

a,

Overview

A total of 22 interviews were conducted

from July 29 through

August 1,

1991.

The interviews were used to determine

the

effectiveness

of the licensee's

corrective actions related to

training and evaluation of operators

on the revised

Included

in those

interviewed were licensed

operators

with various

success

histories

on the requalification

exams

and operating evaluations,

operations

managers,

training managers,

operations

instructors,

and

peer evaluat'ors,

Interviewees

were

asked to comment

on three

specific areas:

EOP training content

and quality; management

expectations

of and participation in the training process;

and

operator

feedback

on training

and recent.

EOP revisions,

I)

tt

4

lt

I

J

I

t

l

t

'16

Classroom Trainin

Classroom training to prepare

the operators

to use revised

was

not derived using

a systems

approach

to training,

However,

the

training content

was derived conservatively,

with all operators

. receiving the

same

leve'l of classroom training on the

The

lesson

plans

used to present

the classroom portion of the training

were not in the standard

WNP-2 format but contained

adequate.detail

for successful

presentation

of the topics.

Contract instructors

presenting

the classroom trainino were viewed by the operators

as

being

knowledgeable

in the

The two days of classroom

training consisted

of

a step-by-step

review of each of the

EOP flow

charts with emphasis

on the basis for each step,

The training was

well received-and

the operators

performed well on the written

evaluation

given at the

end of the training,

On the basis of interviews

and

a review of the lesson

plans,

the

methods

used to develop

and present

the classroom portion of the

EOP training for the operators

were effective in preparing

the

operators

to use the revised

Simulator Trainin

The team observed

two crews trainino on the

EOPs in the WNP-2.

simulator

.

.The team noted that the operating

crews worked effec-

tively with the training staff to establish

an understanding

of the

revised

EOP flowcharts

and to identify potential

procedural

deficiencies,

The licensee

stressed

three

areas

during the

exercises:

improving crew communications

during transient mitiga-

.tion, ensuring

the operators

understood

any revisions to the

and using the

EOP flowcharts in their intended

manner.

Procedural

deficiencies identified during the exercises

were noted

by the

trai ning staff for input to the procedural

development staff.

Host operators

interviewed described

current simulator training as

having increased

in pace

and complexity when compared

to training

before the requalification program

was declared, unsatisfactory.,

The operators

noted

an increase

in the formality and professionalism

required for

a successful

evaluation in the simulator.

Increased

emphasis

on communication

was consistently identified as

a change

in management

expectations

that was reflected in the simulator

training and evaluation.

Nest of the operators

interviewed

specifically cited recent revisions to the plant procedure

on

conduct of operations

as providing more detailed

standards

for

communication,

Peer evaluators

from other utilities were being

used to evaluate

instructors

and crews during the conduct of simulator trainino.

The peers

were asked

by the licensee

to provide frank feedback

in

the areas

of crew communication,

command

and control,

and in-

structor critiques,

Interviews with the peers

indicated that their

comments

were being well received

by the licensee,

The peers

also

.

e

0

f)

N

II

17

noted that they felt confident their suggestions

were being given

appropriate

attention

due to the level of management

interaction

with them,

They specifically noted

the involvement of training

management,

the operations

manager,

and the Deputy Nanaginq

Director. in their daily debriefing sessions.

A strength identified by the oper'ators

during several

interviews

was the specificity of the feedback

on their performance

in the

simulator being provided

by the training staff and operations

management.

The operators

indicated that they

knew what~standards

their performance

was being evaluated

against

and felt comfortable

that the standards

were being consistently applied.

A strength

identified by the inspector

was the licensee's

efforts to develop

detailed

standards

of performance for evaluating

the

command

and

control

and communication skill of the Control

Room, Supervisor

and

the communication

and

teamwork skills of the Control

Room Operator.

On the basis of interviews

and observations

of simulator training,

the training and evaluation of crews

had improved,

Performance

standards

for both the operators

and instructors

was being

established

at appropriate

levels.

Mana

ement

Ex ectations

Licensee

management

oversight of training had increased

over the

past

two months,

Operators

consistently

mentioned that the

Operations

Yianager

and the Assistant

Operations

Yianager

had taken

an active role in setting

standards

and evaluating

crews in the

simulator,

Management

had established

desired

operator

performance

levels to be achieved prior to retesting.

The operators

wer'e

familiar with the expected

standards

and consistently felt that

their opinion on readiness

for retesting

would be considered

in

making that determination,

Although the interviewed operators

currently in training were

familiar with the evolving standards

and changing training methods,

the interviewed operators on-shift were not.

Of particular note

was the on-shift operators'ependence

on the "grapevine" for

information about the changes

they would be experiencing.

The

operators on-shift were less

knowledgeable

than their counterparts

in training about management

expectations.

Licensee training and operations

managers

discussed

the reasons

for

incr easing

management

involvement in and changing

management

expectations

for operator requalification training.

The managers

consistently

mentioned

the

need to maintain

an awareness

of

evolving training and testing trends

in the industry in order to

maintain

a successful

requalification program.

On the basis nf interviews

and observation

of managers

in crew

briefings

and training critiques,

the level of management

in-

volvement

had increased

and

had resulted

in improvements

to the

training program,

However,

management

involvement with keeping the

0

)

t

H

0'

on-shift operators

informed about the events

in training to reduce

their dependence

on less reliable information sources

was weak;

Both the operators

and the managers 'indicated in interviews that

they expect

the level of management

involvement to remain high

after restart,

e,

Feedback

was being actively collected

from the operators

in the

areas

of training and

The

EOP feedback

included both

technical

and useabi lity issues,

Operator

comments

and questions

were being reviewed.

Responses

to these

issues

were being .compiled,

and distributed to the operators,

During interviews, operators-

'onsistently

stated that their feedback

was being satisfactorily

addressed.

An SRO/Shift Manager

had

been

assigned

to the training

department

to compile the responses

and coordinate

the distribution

of the information to the operators,

On the basis of interviews

and

a review of operator

feedback

and

responses,

the feedback

mechanism

appeared

adequate

to ensure that

operator

comments,

concerns,

and questions

were reviewed

and

resolved.

Conclusions

In summary, this portion of the inspection

concluded that:

.The methods

used to develop

and present

the classroom portion

of the

EOP training for the operators

were effective in

preparing

the operators

to use

the revised

EOPs,.

The training and evaluation of crews

had improved.

(3)

Performance

standards

for both the operators

and instructors

were being established

at appropriate

levels.

The level of management

involvement

had increased

and

had

resulted

in improvements

to the training program.

The feedback

mechanism

appeared

adequate

to ensure that

operator

comments,

concerns,

and questions

were reviewed

and resolved,

(6)

Management

involvement with keeping the on-shift operators

informed about the events

in training, to reduce their

dependence

on less reliable information sources,

was

weak

at the time of this inspection.

N

I

~,i

'19

Ins ection of Corrective Action Plan

The licensee's

Corrective Action Plan, Revision',

was reviewed. All

restart

items which were

on the list appeared

appropriate',

No items which

were identified to be non-restart

appeared

misclassified.

The licensee

Training Manager

agreed that the Corrective Action Plan would be placed

on the docket to update

the previous submittal

which had .been

made ir.

Nay,

and which was out of date at the time of the inspection.

The only concern identified during this review was that the licensee

had

not collected closure information for each

item so that it was readily

retrievable for review.

However, several

items of closure

documentation

were requested,

and were retrieved

by the licensee

by the completion of

the inspection,

ATTACHMENT A

In addition to the most significant examples identified in Paragraph

3 of the

inspection report,

the inspection identified the following deviations

which

were not adequately justifieo:

Deletion of the Condensate

Stora

e Tank

(CST)

as

the Preferred

Suctior

or t e

eactor

ore

so ation

oo in

stem -

e

eviation

document

page

22

modified the third and fourth bullets of EPG step

RC/L-2 which specified using the

RCIC and

HPCI systems

with suction from

the

CST instead of the normal suction from the suppression

pool-(SP).

The revision deleted

the action to take suction from the

CST and

incorporated

a

new action to observe vortex limits when using

RCIC or

HPCS with suction

from the

SP,

The deviation document

(pages

87

and

192) also

made similar modifications in the fourth bullet of

EPG step

RC/P-2

and

EPG step

C5-3 of Contingency

No,

5 (Power/Level Control),

The licensee's justification for this deviation indicated that the

elimination of the

SP suction

as

a water source for RPV injection was

not justified because it was of lower quality than the

CST and might be

at higher temperatures

than the

CST under certain conditions.

The

licensee

also believed that these deviations

preserved their licensing

basis

because

RCIC operation with suction from the

SP was allowed.

The licensee's justification did not address

one important aspect of the

EPG's

basis for initially using

RCIC with CST suction.

Specifically,

the

EPGs specify starting with CST suction

because

in the event'of

a

station blackout transfer to the

CST suction

may not be possible.

Also',

the

SP (i,'e,, primary containment) will heat

up faster if RPV injection

is from the

SP rather than from the

CST.

e

2

The inspection

team identified these

items

as

CAV-6, CAV-12, and

CAV-32

during the inspection.

Although the licensee

had identified them

as

WNP-2 Strategy Deviation No,

1

and Design Deviation No, 5,

a detailed

engineering

evaluation of the consequences

of this strategy deviation

was not performed.

(See also Attachment

C, Strategy Deviation No.

1 for

the additional technical

review of this deviation

by the review team.)

Dela

in@

RPV In'ection if a

Low ualit

Water Alternate In'ection

Subs

stem

Becomes Available, when

RPV Level can

be Maintained

at- 2/3

il

Cl-3 and Cl-4 and

added

new steps

Cl-6 and Cl-7 to Contingency

No,

1

(Alternate Level Control).

EPG Steps

Cl-3 and Cl-4 required injecting

the

RPV with low quality water injection subsystems

when the

RPV=

pressure

dropped

below the highest

RPV pressure

at which the shutoff

head of

a low quality water alternate

injection subsystem

(excluding

SLC) was reached,

New steps

Cl-6 and Cl-7 added

a

new override to delay

proceeding

to Contingency

No.

2 (Emergency depressurization)

or Contin-

gency

No.

6 (Containment

Flooding) if RPV water level

can

be maintained

above 2/3 core height

and

combined

and

LPCS

RPV injection is above

6000 gallons

per minute (gpm),

S

1

A2

The

EPGs direct the

use of Contingency

No,

1 (Alternate Level Control)

when

RPV water level cannot

be maintained

above the top of active fuel

(TAF):

Contingency

No. 1'ttempts

RPY injection with all the injection

subsystems

to maintain

RPV water level

above

the TAF, irrespective of

the systein's

NPSH and vortex limits.

With RPV pressure

above the

maximum shutoff head of the alternate injection subsystems,

Contingency

No,

1 requires

entry into Contingency

No.

2 (Emergency Depressurization)

or Contingency

No.

3 (Steam Cooling) when

RPV water level drops to the

TAF.

When

RPY pressure

decreases

to the

maximum shutoff head of the

alternate

injection systems,

Contingency

No.

1 requires injection by all

alternate

injection systems

(low quality water systems).

With RPY

.pressure

below the maximum shutoff head of alternate

injection systems,

Contingency

No,

1 requires

entry into Contingency

No.

2 (Emergency

.Depressurization)

or Contingency No,'6 (Containment

Flooding) when

RPY

water level drops to the TAF.

In this manner,

when the

RPV water level falls to the TAF, the

requi re emergency

depressurization if any iniection system is available.

In addition,

the

EPGs allow the

RPV water level to fall below the

TAF

and,enter

a steam cooling mode if the high

RPY pressure

prevents

the use

of an alternate

injection system,

When the

RPV pressure

decreases

sufficiently, the

then require using the low quality water systems

to control the

RPY water level to the TAF,

When

RPV water level cannot

be restored

and maintained

above

the

TAF by the. use nf alternate

injection systems,

the

EPGs require containment flooding.

The licensee's justification for deleting

EPG steps

Cl-3 and Cl-4 .

indicated that this deviation allowed the use of the steam cooling mode

(i.e.,

RPY water level

below the

TAF) until either

an injection subsys-

tem becomes

available or until the minimum zero injection level (2/3

core height)

was reached.

The justification indicated that this

approach

maximized the time for operator action to establish

an injec-

tion system while maintaining adequate

core cooling prior to proceeding

to Contingency

No.

6 (Containment

Flooding).

The justification also

indicated that the

EPG strategy

had tied the effectiveness

of steam

cooling to the shutoff head of the high pressure .alternate

injection

systems

(excluding

SLC).

The licensee

believed that this approach

allowed

a significant variation

in this pressure

based

on

a given plant's

design (e,g,,

some plants

may

have

a 350 psig system while others

have only

a 90 psig system).

The

justification indicated that there

was

no 'relationship

between

the pres-

sure at which steam cooling may become ineffective and the physical

limitation of

a plant's alternate

injection system.

However, the

licensee

had not performed

a detailed analytical engineering

evaluation

of the consequences

of this strategy deviation.

The licensee's justification*for adding

new steps

Cl-6 and Cl-7 indicat-

ed that the deviation

was necessary

to preserve

the integrity of their

design basis for the double-ended

loss of coolant accident

(LOCA),

Their design

basis

indicates

that the

RPY water level will recover to

the elevation of the top of the jet pumps (2/3 core height)

and that

adequate

core cooling will be achieved

by

a combination of steam cooling

and core spray,

The licensee's justification indicated that the

0

0'i

i)

h

A3

performance

of the containment'looding

contingency" when

RPV water level

cannot

be maintained

above

the

TAF would result in direct venting of the

RPV and the containment

to the environment while still within the licen-

see's

design basis,

In addition,

the licensee's

justification indicates

that the

BWROG's

basis for requiring containment flooding when RPV'level cannot

be

maintained

above

the

TAF is inadequate.

The justification indicates

that the

EPGs did not credit spray cooling due to the possibility

that the spray pattern might be affected

by the steam

environment to the

extent that, adequate

core cooling is jeopardized.

Even if the core

spray pattern is not significantly affected,

spray cooling requires

con-

tinuous reliance

on core spray

pump operation.

The

assumed

that core cooling is immediately threatened

in this mode

due to the

potential fai lure of the operating

pump.

The licensee's

justification indicated that their design basis,

as 'represented

by the

WNP-2 Final Safety Analysis Report

(page 6.3-24),

shows that. the core

will remain covered to .at least

the jet pump suction elevation

and that

the uncovered

region is cooled

by spray cooling

as calculated

by

GE

Generic Analysis

(NEDO 20566P).

The inspection

team identified these

items

as

CAV-21 and

CAV-23 during

the inspection.

Although the licensee

had identified them

as

WNP-2

Strategy Deviation No. 6, Strategy Deviation No.

9 and Design Deviation

No. 15,

a detailed engineering

evaluation, of the consequences

of this

strategy deviatioh

was not performed,

(See also Attachment

C, Design

Deviation No. 15

and Strategy Deviation No. 6, for a related discussion

of the review team's findings,)

Deletion of Emeroenc

De ressurization

Usin

the Vain Turbine

B

ass

Va ves - The deviation

document

page

29

de eted the second

bul et of

the override statement

following EPG step

RC/P,

This override required

the operator to rapidly depressurize

the

RPV with the main turbi,ne

bypass'valves if emergency

depressurization

is anticipated

to be needed

and either (1) all control rods

are inserted

or (2) it has

been deter-

mined that the reactor will remain

shutdown

under all conditions without

boron.

The licensee's justification indicated that this override

and its

associated

caution (i.e,,

EPG Caution

No, 5) was not implemented

because

it may cause violation of WNP-2's Technical

Specifications

when the

plant may still be within its licensing basis.

The inspector's

noted

that although this justification indicated that

EPG Caution

No,

5 had

been deleted,

the caution

appeared

in the licensee's

Plant Specific

Technical

Guidelines

and

was not identified in the deviation document

as

being 'deleted.

However, the caution

was not incorporated into the

flowcharts.

(This was identified as item CAV-9 during the inspection.)

The justification also indicated that the

EPG's

basis for this step

was

to preferentially deposit

the energy in the

RPV to the main condenser

rather

than the suppression

pool to the extent that this will not result

in

a low RPV coolant inventory or the release

of fission products.

Therefore,

the

EPGs did not authorize

bypassing

the main steam isolation

A4

valve (NSIY) isolation interlocks.

The justification indicated that the

three main criteria that require

emergency

depressurization

were (I)

inability to maintain

RPV level

above

the TAF, (2)

an unisolable

primary

system discharging into an area

outside of the primary containment,

and

(3) exceeding

one of the primary containment structural limits (i.e,,

PSPL,

HCLL,

etc'

)

The iustification concluded that these criteria for using the NSIYs to

emergency

d'epressurization

were not applicable for the following.

reasons.

b.

The NSIVs isolate at -50 inches

RPY level

and the interlocks are

not authorized to be overridden; therefore,

when

RPV level reaches

TAF the NSIVs will not be available.

However, this rationale

neglected

the fact that the

EPGs direct emergency

depressurization

using the NSIVs when the operator anticipates

the need.

There-

fore, the NSIYs could

be used prior to their isolation

on low RPY

water level.

As an additional

argument,

the justification indi-

cated that the

have not defined,nor

provided guidance

on how

to anticipate

emergency

depressurization.

(For further discussion

of this point,

see

Attachment

C, Design DEviation No. 4.)

If the primary system is discharging

to an area outside primary

containment with

a fuel element failure, the HSIVs will isolate

on

high radiation; therefore,

the HSIYs will again not be available.

However,

the

EPGs specifically preclude

emergency

depressurization

in this circumstance,

Although the justification indicated that

a

discharge

outside

the primary containment without

a fuel element

failure is

a valid situation requi ring the use of the YiSIVs, the

justification specifically states

that:

"...the qualifiers necessary

to correctly implement

(this

EPG step)

would be overly complex

and difficult

for the operators

to use.

Therefore, for ease of

implementation

and operator

use, this action is not

'llowed."

e

c

~

Finally, the justification concluded that the only two credible

events that might pose

a threat to the primary containment limits

were

an inability to remove

long term decay heat

and

a

LOCA with

a

failure of the pressure

suppression

function of the primary

containment.

The justification concluded that long term decay

heat

removal would allow sufficient time for reestablishment

of

the main condenser

as

a heat sink and that

a

LOCA with.a pressure

suppression

fai lure would result in either

a low RPY water level

(and associated

NSIV isolation) or an immediate depressurization.

Th'erefore,

rapid depressurization

to the main condenser

could not

be accomplished

or it is unnecessary.

Again, this justification

neglected

the fact that the operator is required to anticipate

the

need for emergency

depressurization

prior to the isolation of the

-HSIVs. 'ore importantly, this iustification addressed

only two

"credible events,"

when the basis for the

BMROG EPGs

are for the

I

A5

mitigation nf the

symptoms of all credible

and non-credible

events.

The inspection

team identified this item as

CAV-10 during the inspec-

tion',

Althouoh the licensee

had identified it as

WNP-2 Design Deviatior:

No, 4, the inspectors

concluded that

a detailed engineering

evaluation

of the consequences

of this strategy deviation

was not performed.

Addition of an Inside Shroud

In 'ection

S stem Durin

Outside

Shroud

In ection Ste

s - The deviation

document

pages

191,

197,

and

168

added

the

hs,.g

pressure

system

(HPCS)

as

an alternate for the

high pressure

core injec'tion system

(HPCI) in

EPG steps

C5-3

and C5-3.2

in Contingency

No.

5 (Level/Power Control) and in

EPG step C4-1.3 in

Contingency

No.

4

(RPV Flooding).

These

EPG steps

specified the plant

systems

which are available to inject outside the

RPV shroud (i,e,, the

Group

I systems).

The

do not specify injecting with the systems

that inject inside the shroud (i.e,, the Group II systems) until after

the Group

I systems

have not been successful

in controlling

RPV water

level.

The

EPG basis for this selection is to prevent disruption of the

steam cooling occurring in the

RPV and to prevent

a positive reactivity

addition caused

by adding cold moderator to the top of the core

when at-

tempting to control reactor

power during

an

ATWS with:lowered

RPV water

level.

The licensee's

iustification indicated that

RPV injection with HPCS

was

allowed during the time of bo~on injection by the

SLC pumps

because

WNP-

2 had

a plant-specific

ATWS analysis

to support its operation

under

these conditions.

The justification indicated that

HPCS injection

inside the shroud provides

increased

boron mixing.

The inspectors

noted

that this

ATWS analysis

was not referenced

by the justification,

Further evaluation is necessary

to ensure

that the

ATWS analysis

provided

a detailed analytical engineering

evaluation of the consequenc-

es of this strategy deviation,

The inspection

team identified these

items

as

CAV-33 and CAV-26,during

the inspection,

Although the licensee

had identified them

as

WhP-2

Design Deviation No.

16,

a detailed

engineering

evaluation of the conse-

quences

of this strategy deviation

was not performed,

(See also

Attachment

C, Design Deviation No.

16 for additional discussion of this

item,)

Deletion of the

Head Vent as

an Alternate

De ressurization

S stem-

The deviation

document

page

154

deleted

the

head vent as

an alternate

RPV emergency

depressurization

system from EPG step C2-1.4 in Contingen-

cy No,

2 (Emergency

RPV Depressurization),

This

EPG step lists every

available

system that can

be used to help depressurize

the

RPV if less

than the minimum number of safety relief valves

(SRVs) are

open

and

pressure

is 50 psig

above

the minimum

SRY reopening

pressure.

t

The licensee's justification indicated that venting steam directly to

the drywell may aggravate

conditions 'in the primary containment,

This

path is not specified

because

venting steam directly to the drywell will

tend to pressurize

the drywell and

have the adverse

impact of increasino

I

0

l'

I'l

f

t

A6

the

SRY's

back pressure

which may affect the ability to maintain the

SRVs open in the power-actuated

assist

mode,

The justification neglected

that

EPG step C2-1,4 only allows the use of

the listed systems if the

RPY pressure

is high enough to allow opening

the

SRVs,

Therefore,

the

EPG would require termination of head ventinc

if the back pressure

increased, 'n addition,

the justification neglects

the potential that the head vent may be the only depressurization

system

available,

The operators

would not, use the

head vent unless all other

methods of depressurization

were unsuccessful.

The inspection

team identified this item as

CAV-24 during the inspec-

tion.

Although the licensee

had identified'it them

as

WNP-2 Strategy

No. 7,

a detailed engineering

evaluation of the consequences

of this

strategy deviation

was not performed.

Failure to

S ecif

Defeatin

Dr well Cool'in

Isolation Interlocks - The

eviation

ocument

page

70

de eted t e

ast part of

EPG step DW/T-l,

This step provides

guidance

to defeat

the isolation interlocks if neces-

sary. to operate all the available drywell cooling when drywell tempera-

ture is high.

The licensee's justification indicated that it was inappropriate

to

provide this direction in an "symptomatic procedure"

and that this

direction violates

the

WNP-2 design basis.

However, the justification

did not identify in what manner this direction violated their design

basis,

The justification indicated that this didn't mean that ".;.this

direction could not

be given to the operator after verification that

a

LOCA has not occurred,

but rather that .this can not be provided

as

symptomatic guidance."

This logic is incor rect.

The verification that

a

LOCA has

not occurred is, in itself,

an event-based

vice symptom-based

action,

In addition, the purpose of the

was to provide the best

operational

guidance

based

on all the equipment available for use rather

than to withhol.d this guidance until after the operators

had verified

that

an event

has occurred.

The inspection

team identified this item as

CAY-41 during the inspec-

tion.

Although the licensee

had identified it them

as

WNP-2 Design

Deviation No. 6,

a detailed

engineering

evaluation of the consequences

of this strategy deviation

was not performed,

(See also Attachment

C,

Design Deviation

06 for additional discussion

of this item.)

Termination of RPV Floodin

Dela

ed Until Multi le

RPV Water Level

Instruments

Become

vai

a

e -

e .deviation

document

page

180

modified t e

irst

u

et

o

EPG step

C4-4 in Contingency

No,

4

(RPV

Flooding) to require multiple level instruments

to be available

and

deleted

the second bullet which ensured

reference

leg temperatures

were

below 212 degrees

F,

The purpose of this

EPG step is to terminate

the

flooding of the

RPV when the operator

concludes

that any

RPY water level

instrument is available

and boiling is not occurring in its associated

reference

leg.

The justification indicated that the licensee's

".. Aesired

and standard

operating practice (especially in

a situation where you are preparing to

,

~

'~

'

drain, the water out of the reactor!)"

was to require that multiple level

instruments

be available for use,

The justification also indicated that

the precaution

on verifying that the reference

legs are not boi lino was

removed

because

the effects of temperature

on the level instrument's

variable

and reference

legs

have

been

implemented

by two "event-based"

abnormal

procedures '(i.e,, fire and high energy line break).

Although normal reactor operations

would normally require

independent

level instrumentation,

the licensee's

justification for these deviations

overlooked

the primary purpose for'PV flooding, namely,

the loss of

level instrumentation,

If the operators

should conclude that any one

system is available

and its reference

leq doesn't boil, the

EPG strategy

is to terminatethe

abnormal

condition of flooding the

In addition,

as

a separate

comment,

the inspectors

could not determine

how the

=.

licensee's

use of event-based

abnormal

procedures

for identifying high

reactor building temperatures

met the EPGs'ntent

to implement

symptom-

., based operator

guidance,

(See also Attachment

C, Implementation

Devia-

tion

19 for additional discussion.)-

The inspection

team identified this item as

CAV-29 during the inspec-

tion.

Although the licensee

had identified it them as

WNP-2 Implementa-

tion Deviation No. 26,

a detailed

engineering

evaluation of the conse-

quences

of this strategy deviation

was not performed.

Unnecessar

Emer enc

De ressurization

of the

RPV When

RPV Mater Level

n ication is Lost -

e

eviation document

pace

a

ed

an

a dition-

a

step in t e override step after

EPG step

RC/L-1.

This

new step

requires

emergency

depressurization

by Contingency

No,

2 (Emergency

Depressurization) if RPV water level cannot

be determined

and less

than

seven safety relief valves

(SRVs) are open,

The, licensee's

justification indicated that this

new step provided the

same

guidance that was provided in the pressure

control section for the

situation where

RPV water level cannot

be determined

and less that seven

SRVs are

opens

Therefore,

the justification concluded that this

directi,on is technically the

same

as what was intended

by the

EPGs, only

this deviation provided it in clearer

terms.

The licensee's justification neglected

the fact that the pressure

control actions of EPG step

RC/P only direct the operator

to Contingency

No.

2 (Emergency

RPV Depressurization) if there is

a problem with

opening

seven

SRVs.

If seven

SRVs are already

open,

then

RC/P directs

the operator to enter Contingency

No.

4

(RPV Flooding) immediately.

If

RPV water level cannot

be determined,

the

do not direct entering

Contingency

No,

2 (Emergency

RPY Depressurization)

from RC/L-1.

This

deviation would delay the accomplishment

of the actions of Contingency

No,

4

(RPV Flooding) concerning injecting water into the

RPV to estab-

lish and maintain four SRYs open

and

PPV pressure

above the minimum

alternate

reflooding pressure

while the operator

attempted

to accomplish

the actions of Contingency

No.

2 (Emergency

RPY Oepressurization)

concerning depressurizing'he

RPY with other systems,

The net result of

the deviation is to delay responding

to the

symptom of

a loss of RPV

level control while the operator

attempts

pressure

control actions,

A8

The inspection

team identified these

items

as

CAV-5, CAY-19, and

CAV-30

during the inspection.

Although the licensee

had identified it them

as

WNP-2 Implementation Deviation No. 8,

a detailed engineering

evaluation

of the consequences

of this strategy deviation

was not performed.

The inspectors

also identified the following deviations

which the licensee

had

not identified as deviations:

9

10.

Deletion of the Standb

Li uid Control

SLC) Test

Tank as

an Alternate

RPV Floodina

S stem - The deviation document

pages

24 and

176~ deleted

the

SLC Test

Tank as

an alternate

RPV injection system in

EPG step

RC/L-

2 and

as

an alternate

RPV flooding system

from .EPG step

C4-3, 1 in

Contingency

No.

4

(RPV Flooding).

These

EPG steps list every available

system that. can

be used to help inject or flood the

The licensee

did not identify these deletions

as

a deviation.

The inspection

team identified these deviations

as

items

CAY-8 and

28

during the inspections

Deletion of the Alternate Boron In'ection

S stems

- The deviation

ocument

page

54

de eted

the contro

rod drive system,

high pressure

core spray system,

feedwater

system,

and

a hydrostatic

pump from EPG

step

RC/Q-6

as possible alternate

methods

to inject boron into the

during

an

ATWS.

This

EPG step lists every available

system that can

be

used to help inject boron into the

The inspection

team identified this deviatio'n

as item CAV-17 during the

inspection,

Reference

to an Incorrect Caution - The deviation document

(page

60)

has

a

new reference

to Caution

No.

7 in

EPG step RC/g-7.2 which de-energizes

the scram solenoids

during attempts

to insert the control rods during an

ATWS.

However, Caution

No.

7 concerns

the simultaneous

operation of

drywell and suppression

pool sprays

and is unrelated

to this actions of

this

EPG step.

The inspection

team identified this as item CAV-18 during the inspec-

tion,

Because

the licensee

had not identified this deviation, it was

not identified,. nor justified,

as

a deviation.

However,

the inspection

team verified that this

new caution reference

was not incorporated into

the

The following discrepancy

between

the deviation

document

and the

was also

identified:

12,

Addition of

a

New Caution into the

EPGs - The deviation

document

had

a

new,

unnumbered

page

ocated

etween

pages

13 and

14 that indicated that

EPG Caution

No,

8 concerning

operation of HPCI or RCIC turbines with

suction temperatures

above

225 degrees

F or above the

NPSH limit,

whichever is more limiting, may result in equipment

damage.

Although

the deviation

document indicated that this Caution is not incorporated

into WNP-2's

the inspection

team noted that Caution

No.

8 does

not

exist in Revision

4 of the

I'

'

A9

The inspection

team identified this

as item CAY-4 during the inspection.

Because

the caution

v.as not incorporated, it did not represent

a

deviation,

However,

the inspection

team

was concerned

that its inclusi.on

in the

EPGs indicated that further unidentified deletions

or inclusions

into the

EPGs might exist.

~,i

j'

ATTACHMENT

B

The inspection identified the following EOP/PSTG differences,:

PSTG step

C2-1,1

(pa'ge

234) of Contingency

No.

2 (Emergency

RPV Depress-

urization) required preventing injection of the low pressure

(LPCS) system

and those residual

heat

removal

(RHR) systems

not needed

for ensuring

adequate

core cooling if a high drywell pressure

emergency

core cooling system

(ECCS) signal is present.

These

emergency

depressu-

rization actions

were accomplished

in

EOP 5. 1,.3 (Emergency

RPV Depressu-

rization)

and

EOP 5, 1,5

(Emergency

RPV Depressurization-ATWS),

EOP'.

1.3 incorporated this step

as the first decision block; however,

5.1.5 did not incorporate

the

PSTG step.

(The inspection

team identi-

fied this item as

CAV-36 during the inspection.)

2)

3)

PSTG step

C2-2 (page

241) of Contingency

No,

2 (Emergency

RPV Depressur-

ization) required entering

the pressure

control actions of PSTG step

RC/P-4

when the reactor is shutdown.

However,

EOP 5. 1.5

(Emergency

Depressurization-ATWS)

incorrectly directed

the operator to transition

point 48 in

EOP 5. 1.2

(RPV Control-ATWS).

This transition to the

ATWS

procedure after the operator

has determined

the reactor is shutdown

was

confusing.

(The inspection

team identified this item as

CAV-36A during

the inspection.)

PSTG step Cl-3 (page

222) of Contingency

No.

1 (Alternate

Level Control)

required

emergency

depressurization if any system,

injection-subsystem,

or alternate

injection system is lined up to the

RPY with at least

one

pump running,

However, in the

second

path of,level control in EOP. 5. 1. 1

(RPY Control) the operator

was directed

by the "emergency depressurizat-

ion required" contingency action to refer to the active

"emergency

depressurization"

override statement

in the pressure

control path.

Before the transition to the emergency depressurization

actions of

either

EOP 5. 1.3

(Emergency

RPV Depressurization)

or

EOP 5, 1.5 (Emergen-

cy

RPV Depressurization-ATWS),

EOP 5. 1. 1 had

an additional decision step

to determine if seven

SRVs are open.

This additional

step

was not in

the

PSTG,

and delayed

or prevented

going directly to the emergency

depressurization

actions.

(The inspection

team identified this item as

CAV-35 during the inspection,)

The override prior to

PSTG step

RC/P-2

(page

82) required

opening the

HSIYs to re-establish

the main condenser

as

a heat sink.

However,

5. 1.2

(RPV Control-ATWS) had incorporated this action in

a different

location than specified in the

PSTG,

The

PSTG

had this override

directly preceding

step

RC/P-2;

the.EOP

has this override

two steps

ear-

lier before the verification that the suppression

pool's heat capacity

temperature limit and the safety relief valve tail pipe level limit are

exceeded,

(The inspection

team .identified this item as

CAY-38 during

.the inspection.)

5)

PSTG step

RC/L-2 (page

68) required preventing

automatic

RPV depressuri-

zation

by resetting

the automatic depressurization

system

(ADS) timer if

RPV water level

can

be maintained

above the

TAF and the

ADS timer has

initiated.

However,

EOP 5. 1. 1

(RPV Control)

had incorporated this step

in

a different location.

The fourth block in the level control actions

~,

.1

li'

I

B2

had the operator reset

the

ADS timer before the water level cannot

be

maintained

above the TAF.

(The inspection

team identified this item as

CAY-34 during the inspection,)

PSTG Caution

No.

3 (page

45)

showed

a reactor

core 'isolation coolino

(RC1C) turbine

speed limit of 2100 rpm,

However,'Caution

No.

3 in

5,0,,0

(EOP Cautions)

had

a speed limit of 1000 rpm,

(The inspection

team identified this item as

CAV-2 during the inspection,)

The first bullet of the first override statement prior to

PSTG step

C4-1

of Contingency

No.

4

(RPV Flooding) directed the operator to Contingency

No,

5 (Level/Power Control)

and RC/P-4, if the

RPV water level

can

be

determined while performing the

RPV Flooding actions

and the reactor is

not shutdown.

However,

the

EOPs did not properly implement this step

because -the-first override step of EOP 5. 1,4

(RPV Flooding) referenced

transitions

points

82 and

13 of

EOP 5, 1. 1

(RPV Control).

Upon entering

EOP 5, 1, 1, the first override step required entering

the first steps of

EOP 5. 1.2

(RPY Control-ATWS).

This transition would result in the

operator

being in the. correct location in

EOP 5. 1.2 for level control

(i.e., transition point C7), but the incorrect location in

EOP 5. 1.2 for

power control (i,e,, the beginning of power control vice transition

point 48).

A similar, but converse,

problem existed

when the operator

would transition

between

EOP 5, 1.6

(RPV Flooding-ATWS) and

EOP 5. 1.2

(RPY Control-ATWS) when the reactor

becomes

shutdown.

(The inspection

team identified this item as

CAV-37 during the inspection'.)

r

e

Oj

J!

ATTACHY>ENT C

The following is

a partial list of the

WNP-2

EOP deviations,

Each item

includes

a description of the deviation,

the licensee's justification for the

deviation,

and the

NRC concerns

related to the deviation.

Omission from this

list does

not imply NRC approval of the deviation,

The items are designated

using the licensee's list of deviations for ease of reference,

The page

numbers refer to the documentation for the deviation in the '"deviation

document."

Desi

n Deviation 41:

Deletion of ECCS

Pum

NPSH Limits

The

BWROG EPGs specify application of net positive suction

head

(NPSH)

and

vortex limits for operation of the

ECCS

pumps.

WNP-2 has taken

a deviation to

delete

the

NPSH limits for the

ECCS

pumps

(pages

8, .123,

177,

and 198).

The

basis for this deviation provided

was that the vortex limits are always

more

restrictive than the

NPSH limits.

The justification in the deviation document

was not technically adequate

to

support this deviation.

The additional

documentation

provided clarification

that the

NPSH limits were deleted

because

the vortex limits for the

pumps

bound the

NPSH limits.

This deviation is

an example of the poor quality

justification documentation

developed

by the licensee.

(See also Section

3.c.3

and 3.c.4 of this report for further discussion.)

Desi

n Deviation 04:

Deletion of Emer enc

De ressurization

Antici ation

The

BWROG EPGs for RPV pressure

control include

an override that directs rapid

depressurization

of the

RPV with the main turbine bypass

valves

(BPVs) if

emergency

depressurization

(ED) is anticipated,

the reactor is shutdown,

and

.the main condenser

is available,

WNP-2 has deleted

the override for anticipa-

tion of ED from the

(page 30).

The basis

provided for this deviation

was

that it was difficult to provide clear guidance to the operators

as to when to

anticipate

ED or how fast to "rapidly" depressurize,

WNP-2's. position was that

it was inappropriate

to allow exceeding

Technical Specification

(TS) limits

while the plant may still be within its licensing basis,

The basis in the

BMROG EPGs for rapidly depressurizing

using the

BPVs when

ED

is anticipated is to reject heat to the main condenser

rather than to the

suppression

pool, thus minimizing the challenge

to primary containment.

WNP-2

removed this option without adequate

evaluation of the negative effects of

deleting this strategy,

Difficulty in providing clear guidance for the

performance of

a step is not adequate

technical justification for deletion of

the step.

It is not possible to predict whether the plant will still be

within its design

basis

when. anticipation of

ED would be

an appropriate

action,

However, it is

assumed

that operators will not exceed

TS limits

unless

a significant challenge

to the safety of the plant exists

and it is

clear that

ED will be required.

(See also Attachment A, Item 3 for further

discussion

of this item,)

H

II

C2

Desi

n Deviation f6:

Deletion of Dr ell Coolin

Isolation

B

ass

The

EPGs provide direction to defeat drywell cooling isolation inter-

locks to mitigate high drywell temperatures,

WNP-2 deleted this direction

(page 70).

The basis

provided for the licensee's

deviation

was that symptom-

atic override of iso15tion interlocks

was technically incorrect

and might

cause

an unnecessary

radiation release.

Additionally, restoration of drywell

cool'ing would have

a negligible effect

on long term heat

removal

from the

containment.

The licensee's

justification related

the effects of drywell

cooling to suppression

pool temperature

increase,

but did not address

the

potential effects

on drywell temperature.

The intent of the

BWROG EPGs is -to provide the optimum strategy for mitigation

of emergencies

and to utilize all available equipment.

The authorization to

defeat interlocks recognizes

that concurrent

actions directed

by other

sections of the

may otherwise

preclude drywell cooler operation.

It is

not intended that isolation interlocks

be defeated if there is indication of a

leak in the drywell cooling system which could result in a radiation release.

It is also important to take all possible actions

to. lower drywell tempera-

tures

due to the effect on

RPY water level indication, not just for long term

heat removal.

The licensee

removed

an option for mitigation of high drywell

temperatures

without adequate

assessment

of the consequences

of deleting this

strategy,

(See also Attachment A, Item 6 for a related discussion.)

Desi

n Deviation f7:

Limitation on Primar

Containment

Ventin

The

BMROG EPGs direct venting of the primary containment

before suppression

chamber

pressure

reaches

the Primary Containment

Pressure

Limit (PCPL).

The

most limiting PCPL for WNP-2 is 49 psig.

WNP-2 modified this strategy

by

waiting -until drywell pressure

exceeds

39 psig before allowing the containment

to be vented

(pages

81

and 84).

The justification for this deviation was to

delay venting

and potential

release

of radioactivity until the accident

has

progressed

beyond the design

basis of the plant.

The modification made

by the licensee

addressed

only drywell pressure

for

venting conditions.

The

PSTG

and

EOPs did not address

when the primary

containment

should

be vented with respect

to wetwell pressure.

The

WNP-2

strategy

assumed

that wetwell pressure

is equal

to or below drywell pressure.

If wetwell pressure

increased

without

a corresponding

increase

in drywell

pressure,

the

MNP-2

EOPs would not allow venting of the containment

even if the

PCPL were exceeded.

The operators

could easily

be confused

on when to take

action to vent the containment if drywell and wetwell pressures

did not

respond equivalently to the event,

The licensee's

justification for this deviation did not indicate that the time

to initiate containment

venting

was considered

in the analysis for this

deviation.

If venting is delayed unti 1

39 psig, there

may not be sufficient

time to commence

venting prior to exceeding

the

PCPL.

Design Deviation f10;

Recombiner

Suction from the Wetwell Not

S ecified-

The

EPGs direct operation of hydrogen

recombiners

with suction from the

suppression

chamber for high hydrogen or oxygen concentrations

in the suppres-

t

1

C3

sion chamber,

WNP-2 does

not specify recombiner suction from the wetwell,

and

only bases

recombiner start permissive

signals

on drywell hydrogen

and oxygen

concentrations

(pages

104

arid 107).

The justification for this deviation

was

that the hydrogen

recombiner

system treats

the primary containment

as

a single

volume.

Therefore,

WNP-2 expected

that operation of the recombiners

with

suction from the drywell would control accumulation of combustible mixtures, in

either the drywell or wetwell,

The licensee's

justification did not indicate whether

an analysis

was per.-

formed to ensure that recombiner operation with suction from the drywell was

as effective

as recombiner operation with suction from the wetwell if the

source of hydrooen

was in the wetwell.

Additionally, operation of the

recombiners

with suction from the wetwell was not included

as

an option if

drywell suction

was not available,

The licensee's

justification assumed

that the vacuum breakers

would function

effectively to allow mixing of the containment

atmosphere.

The

PSTG did not

direct action to start recombiners

based

on high hydrogen or oxygen concentra-

tions in the wetwell.

This was not identified as

a deviation from the

EPGs.

The WNP-2

EOPs incorporated

the

EPG guidance

to start the

recombiners

on high hydrogen or oxygen concentrations

in the wetwell or the

drywell.

Desi

n Deviation 015:

Dela

Containment

Floodin

with

S ra

Coolin

and 2/3

Core

Submer

ence

At low RPV pressure,

the

BWROG EPGs direct Primary Containment

(PC) Flooding

if RPV water level cannot

be maintained

above the top of active fuel

(TAF)

after all attempts

to submerge

the core, with RPV injection have

been

unsuc-

cessful.

WNP-2 deviated

from this strategy

by delaying

PC Flooding if core

spray

(HPCS and/or

LPCS) is injecting it or above

6000

gpm and

RPV water level

is above 2/3 core height

(pages

148,

149,

and 150),

This is

a plant specific

analyzed condition for adequate

core cooling,

The justification for this

deviation

was to eliminate or reduce

the radiological releases

associated

with

PC Flooding.

The

(Rev. 4) do not consider

spray cooling

as

adequate

core

cooling,

This is because

of the possibility that the spray pattern

may be

affected

by the steam environment,

The

EPGs also

assume

that core

cooling in this mode is immediately threatened

due to the potential failure of

the operating

pump,

The licens'ee

did not consider this long term

operability concern for the

and

LPCS

pumps

when evaluating th'is devia-

tion.

(See also Attachment A, item 2-for

a related discussion.)

The licensee's

justification indicated that

PC Flooding would be performed if

RPV water level dropped

below 2/3 core height or spray cooling capability was

lost.

However, the

do not reflect this logic,

There is

no override nr

direction to implement

PC Flooding if spray cooling conditions

are lost.

0

~

'

C4

e

Desi

n Deviation 816:

Use of HPCS

as

an Outside the Shroud

S stem with Boron

~ln 'ection

The

BWROG EPGs specify preferential

use of systems

that inject outside

the

shroud for RPV flood or fill during

an

ATWS,

WNP-2 deviated

from this strategy

by allowing use of the

HPCS system which injects inside- the shroud if boron is

being injected with the

SLC system

(pages

169,

192,

and 198). 'he justifica-

tion for this deviation

was

based

on

a plant specific

ATWS analysis that .

supports

HPCS operation

under these

conditions.

HPCS injection is said to

provide increased

boron mixing because

boron is injected through the

spray header.

The

BMROG EPGs

do not allow use of systems

which inject inside the shroud

until systems

that inject outside

the shroud

have

been unsuccessful

in

controlling

RPV water level to prevent disruption of the steam cooling and

addition of posi tive reactivity,

The licensee cited analysis that indicated

that power excursions with borated

HPCS injection are minimal.

However, they

were unable to demonstrate

that

HPCS injection would not disrupt steam

cooling, therefore,

they decided to delete

thi.s deviation during the next

revision to the

The original analysis

performed

by the licensee

was not

adequate

to support this deviation.

(See also Attachment A, item

4 for a

related discussion,)

Strate

Deviation Ol:

Use of RCIC

Su

ression

Pool Suction

In several

situations,

the

BWROG EPGs direct use of RCIC with suction from the

Condensate

Storage

Tank (CST),

WNP-2 allowed use of RCIC with suction from the

suppression

pool in addition to suction from the

CST (paoes

22, 38,

192,

198,

and 210),

The justification for this deviation

was to increase

RCIC

availability, if the

CST was lost, or during

a Station Blackout.

The licensee's

original justification documentation

did not indicate that

CST

suction

was the preferred

source

and that suppression

pool suction

was being

allowed only if CST suction

was not available.

This was clarified in the

additional documentation,

However, the licensee

did not address

each situation

for which the suppression

pool suction option was

added separately.

To

provide adequate

technical justification for a deviation, it is necessary

to

provide specific reasons

for each

EPG step or strategy that is deviated

from.

In this case

the deviation affected four different'ections

of the

The justification for use of RCIC with suction from the suppres-

sion pool varied for each situation,

(See also Attachment A, Item

1 for

a

a related discussion,)

Strate

Deviation II3:

Deletion of Primar

Containment Air Pur

e

The

EPGs specify purging the primary containment with nitrogen or air if

a flammable mixture exists,

h'NP-2

deleted

the direction to purge with air and

specified only

a nitrogen purge

(page

111).

The justification for this

deviation

was that purging with nitrogen

was more effective than purging with

air.

C5'he

licensee's

justification for this deviation did not address

any poten-

tially negative effects cf purging with air,

The WNP-2

EOPs did not include

air purge

as

an option if nitrogen

purge

was unavailable.

The licensee

deleted

an option for mitigating an emergency without adequate

analysis of the

negative

aspects

of deleting this strategy,

Strateo

Deviation <<6:

Deleticn of Low Pressure

Override for Termination of

team

Coo

sn

The

BWROG EPGs direct emergency depressurization

(ED) if RPV pressure

drops

below the shutoff head of a

l'ow quality alterna'te injection system during

alternate

level control.

This results

in termination of steam cooling

irrespective

of whether

an injection system is lined. up.

WNP-2 deleted

the

override to terminate

steam cooling

on low pressure

(pages

144

and 147),

The

justification provided for this deviation

was to prevent unnecessary

termina-

tion of steam cooling when

no injection systems

were lined up with pumps

running,

The original justification documentation

did not indicate that

an analysis

had

been

performed to verify that steam cooling is effective at low RPV pressures,

The additional

documentation

provided

by the licensee

referenced

an evaluation

performed

by

NUSCO that indicated that steam cooling was effective at low

pressures.

The effectiveness

of steam cooling at low pressures

is currently

an

open item beino evaluated

by the

BWROG.,

The licensee's justification for this deviation indicated that steam cooling

will,be terminated

and the

EPGs will be followed as

soon

as

an injection

system is lined up,

Additionally, the

WNP-2

PSTG for steam cooling contained

an override that directed

ED if an injection system is lined up while steam

cooling is in progress,

However,,the

WNP-2

EOPs did not reflect this logic,

The

EOPs did not contain

an override to direct

ED if an injection system

was

lined up while steam cooling is in progress.

(See also Attachment A, Item 2

for further discussion.)

Strate

Deviation <<8:

Deletion of Level/Power Control Strate

if SLC is

~ln 'ectin

The

EPGs direct actions to lower

RPV level to control reactor

power if

reactor

power is above the

APRYi downscale trip setpoint,

suppression

pool

temperature

is above

the Boron Injection Initiation Temperature

(BIIT), and

an

SRV is open or drywell pressure

is above

the scram setpoint.

WNP-2 has

added

an additional condition that less

than

two

SLC pumps are running or reactor

power is not decreasing

to the conditions for lowering

RPV level

(pages

18"

and 188),

The justification for this deviation

was

based

on plant specific

ATWS analysis

that indicated that reactor

power will be rapidly red'uced

when

boron is injected via the

HPCS spray header.

II

N~

j

C6

The licensee's

justification stated

that they have

chosen

the "preferred"

- method for reactor

power control.

However,

the

BWROG EPGs direct both methods

(injection of boron

and lowering

RPV level) for reactor

power control,

and

do

not indicate which method is preferred,

The licensee's

justification is based

on

an event

based

analysis

that

assumes

the

SLC pumps will continue to inject

until the reactor- i s 'shutdown,

Their analysis

does not'ddress

the potential

for additional

heat input to the suppression

pool resulting from not lowering

level, If the

SLC pumps subsequently trip; this additional

heat input results

in

a greater

challenge

to primary containment.

The licensee's

justification is based

on an analysis of the effect in

a five

minute delay in SLC injection on suppression

pool heatup.

This analysis

has

no correlation to the deviation of not lowering

RPV level.

The power reduc-

tion rate from boron injection is not equivalent to that from lowering

water level.

With the deviation,

lowering

RPV water level is not delayed for

a short period (i.e., five minutes),

but indefinitely,

while SLC is inject-

ing.

The licensee's

justification that "allowing a delay in reducing water level is

not expected

to have

any adverse

consequences

and avoids the complications

(terminating injection sources,, reducing'vessel

inventory) associated

with

reducing reactor water level" is inadequate.

The deviation

does

not result in

a delay in reducing water level, but removes

a mitigation strategy specified

by the

Removing

an action to avoid. complications is not adequate

technical justification for deviating from the

(See also Section

3.c,2 of this report for further discussion of this item.)

Review of the

EOP flowcharts indicated that the presentation

and wording of

the level/power control conditions

was very confusing.

Several

negatives

'were

used

along with

a string of "ands" and."ors" in

a table that is referred to by

a decision step,

This unclear direction could result in operator error in an

emergency situation.

Im lementation Deviation 04:

Use of Dr ell Avera

e

Tem erature

The

BWROG EPGs include

a caution that .restricts

use of RPV level'nstruments

based

on temperatures

near the instrument

runs.

. WNP-2 used

average

drywell

temperature

rather

than temperatures

near the instrument

runs in implementing

this caution

(page 3).

The justification for this deviation

was that drywell

temperatures

near the instrument

runs were not specifically monitored.

The licensee's justification for this deviation did not indicate that the

potential difference

between

local

and average

drywell temperatures

was taken

into consideration

when performing the calculations

for this caution.

It is

important to ensure

that the values specified in the caution are conservative

with respect

to drywell temperature,

The licensee's

justification was not

sufficient to ensure that this deviation is technically adequate.

C7

Im lementation Deviations (13, 414,

and

418:

Modification of Su

ression

Pool

Leve

ction Leve

s

The

BMROG EPGs specify initiation of suppression

chamber

sprays

only if

suppression

pool level is-below the elevation of the suppression

pool spray

,nozzles.

WNP-2 specified initiation of wetwell sprays

only if suppression

pool

level

was below'the

top of the indicating range for the suppression

pool level

instruments

(pages

77, 110,

and 115),

The

EPGs specify initiation of

drywell sprays only'if, suppression

pool level is below the elevation of the

bottom of the suppression

chamber to drywell vacuum breakers

less

vacuum

breaker

opening pressure,

WNP-2 has modified this action by specifying

initiation of drywell sprays

only if suppression

pool level

was below the top

of the indicating range for the suppression

pool level instruments

(pages

72,

79, 95, 112,

and 116).

The

BMROG EPGs specify venting the suppression

chamber

if suppression

pool level is below the elevation of the bottom of the suppres-

sion chamber vent.

MNP-2 has modified this action by specifying venting the

wetwell if suppression

pool level

was below the top of the indicating range

for the suppression

pool level instruments

(page

112).

The justification for

all of these deviations

was that the

maximum indicated level

was nearly the

same level

as the level specified

by the

and that it was conserva-

tive to limit the action to the

maximum indicated level,

The licensee's

claim that the maximum indicated level

was "nearly the

same

level" as that specified

by the

BMROG EPGs did not provide sufficient detai l

for

a technically adequate justification.

" Without specifying the plant

. specific value for .the level specified

by the

BMROG EPGs, it is not possible

to ensure that the deviation is conservative.

Additionally, the. licensee

did

not compare

the benefits of using alternate

means

to determine

suppression

pool level with the mitigation lost due to the limitations imposed

by

suppression

pool level indication availability.

Im lementation Deviation 419:

Deleted Start of Secondar

Containment

HVAC

The

BMROG EPGs direct action to operate

available

secondary

containment

HVAC

if radiation levels are below the isolation setpoint to control secondary.

containment

temperatures.

WNP-2 deleted

the direction to operate available

secondary

containment

HVAC (page

123),

The justification for this deviation

was that it was redundant

to previous direction given in the Secondary

Con-

tainment Control guideline.

The

EPG direction to operate

available

secondary

containment

HVAC ensures

that

ventilation is operating if it is available.

This direction was different

than the previous override which directed restart of ventilation if the system

isolated

and the isolation signal

has cleared.

The WNP-2

PSTG

and

EOPs did not

ensure that venti lation,.was operating if it was not running for any reason

other than

an isolation,

The licensee

did not perform a,thorough

technical

evaluation prior to deleting this direction.

l

lk

I

C8

l

Im lementation Deviation 826:

Multi le Level Instruments

Re uired

The

BMROG EPGs direct action to terminate

RPV Flooding when

RPV water level

instrumentation

is available,

temperature

near the instrument

runs is below

212 degrees

F,

and the Minimum RPV Flooding Pressure

(HRFP)

has

been established

for

the Yinimum Core Flooding Interval,

.MNP-2

specified that multiple

RPV level

instrunients

must

be available prior to termination of RPV Flooding (page

180).

The justification for this deviation

was that use of multiple instruments

was

the desired

and .standard

operating practice,

The