ML17326B426

and panel indication as outlined

in Appendix

C (Paragraph

6)

50-316/88017-02

(Open Item)

Open

Correction of technical

and

human factors discrepancies

contained in the

as outlined

in Appendix

B (Paragraph

6)

50-316/88017-03

(Open Item)

Open

Upgrading two inadequate

procedures

(Paragraph

6)

50"316/88017-04

(Open Item)

Failure to maintain

a correct

procedure

and to take adequate

corrective action (Paragraph

6)

50-316/88017-05

(Open Item)

Open

Improve procedure

network control

(Paragraph

6)

50"316/88017-06

(Open Item)

Open

Review and resolve

accumulated

EOP comments

(Paragraph

8)

3.

Back round Information

Following the TMI acci dent,

the Office of Nuclear Reactor Regulation

developed

the "TMI Action Plan"

(NUREG-0660 and NUREG-0737) which

required licensees

of operating reactors

to reanalyze transients

and

accidents

and to upgrade

(Item I.C.l).

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

EOPs,

and describes

the use of a "Procedures

Generation

Package"

to prepare

The licensees

formed four vendor type owner groups

corresponding

to the four major reactor types in the United States;

Westinghouse,

General Electric, Babcock 6 Wilcox, and Combustion

Engineering.

Working with the vendor and the

NRC, these

owner groups

developed

GTGs which set forth the desired accident mitigation strategy.

These

.GTGs were to be used by the licensee in developing their PGPs.

Submittal of the

PGP to the

NRC was

made

a requirement

by Confirmatory

Order dated

June

12,

1984.

Generic Ietter 82-33,

"Supplement

1 to

NUREG-0737 - Requirement for Emergency

Response

Capability" requires

each licensee

to submit to the

NRC a

PGP which includes:

a.

Plant-specific technical guidelines with justification for

differences

from the

GTG

b.

A writer's guide

c.

A description of the program to be used for the validation and

verification of EOPs.

d.

A description of the training program for the upgraded

From this

PGP, plant specific

were to have been developed that

would provide the operator with directions to mitigate the consequences

of a broad

range of accidents

and multiple equipment failures.

Due to various circumstances,

there

were long delays in achieving

NRC

approval of many of the

PGPs.

Nevertheless,

the licensees

have all

implemented their EOPs.

To determine

the success

of the implementation,

a series

of NRC inspections

were performed to examine the final

product of the program;

the EOPs.

The objective

was to perform table

top reviews, simulator exercises

where possible,

and inplant walkthroughs

of the

EOPs with licensed operators

to verify their adequacy.

The EOPs

were considered

to be adequate

for use if they could be understood

and

performed successfully

by the operators

and they incorporate

the accident

mitigation strategy

developed

by the appropriate

vendor specific owner

group.

This inspection report represents

findings, observations,

and conclusions

regarding the adequacy of the EOPs.

It did not,

as

a matter of intent,

review whether the

EOPs thus prepared

conformed to the

NRC staff's

long-term program for upgrading

and whether those

had been

properly prepared

using

a PGP.

The success

level of licensees

in following the

PGP submitted to NRC

is

a regulatory issue that will be dealt with on a case-by-case

basis.

Although some licensee's

EOPs strayed far from their PGP, that issue is

of secondary

importance to this inspection effort.

The purpose of this

inspection is to verify adequacy of the

EOPs for continued safe operation

of the facility.

EOP/GTG

Com arison

The

NRC compared

the D.C.

Cook EOPs to Revision

1 of the Westinghouse

Owners

Group ERGs.

The

ERGs were used

as the basis for the D.C. Cook

Plant Specific Technical Guidelines.

Deviations between the

NRC approved

and the D.C. Cook plant specific technical guidelines

were identified,

justified, and documented

by the licensee in the

SDD.

The D.C.

Cook ERG background

document

served

as the basis

from which

the D.C.

Cook EOPs

and their changes

were developed.

The D.C. Cook

EOPs closely parallel the generic

ERGs.

The licensee

uses plant specific

emergency

procedures

and abnormal operating procedures

to supplement

the

ERG based

The D.C.

Cook EOPs,

based

on the ERGs, together with

abnormal operating procedures

(4022 and 4023 series)

comprise the

licensee's

emergency operating procedures.

I

(C

The

NRC reviewed the emergencies

and other significant events

covered

by

the D.C.

Cook EOPs

and

AOPs

as indicated by Appendix A.

Taken together,

the

NRC judged that the

and

AOPs cover the broad range of emergencies

and other significant events

necessary.

With respect to

QA involvement in the

EOP development,

a review of all

Revision

0 EOPs

was performed.

The scope of the

QA reviews consisted

of programmatic

assessments

such

as adherence

to D.C.

Cook procedure

for writing procedures

(PMI-2010, Plant Manager

and Department

Heads

Instruction, Procedures,

and Associated Index's, Revision 4),

and operator

training on the

new procedures.

In addition, although not procedurally

required,

the technical

adequacy of the Revision

0 EOPs

as assessed

in

a table top review.

The major deficiency in this

QA process

was that the

technical

adequacy

was not reviewed by a physical hands

on walkthrough,

resulting in numerous

discrepancies

not being identified such

as those

enumerated

in Appendix B.

There were

no violations or deviations

noted in this area.

Inde endent Technical

Ade uac

Review of the

EOP

The licensee

used Revision

1 of the

WOG ERGs

as the generic technical

guidelines for that portion of the

covered by the

ERG'evision

0 of the D.C.

Cook

PGP

was submitted

on April 15,

1983.

It included Revision

0 of the writers guide and

a sample of the

EOP

background

documentation

forms which collectively comprise the

SDD used

to document

EOP deviations

from the generic technical guidelines.

The

NRC issued

a draft SER on September

12,

1985, in response

to the licensee's

submittal of PGP Revision 0.

The licensee

submitted

PGP Revision

1 on

May 16,

1986.

Updated

sample

documentation

forms and Revision

1 of the

writer's guide were included.

No SER has been issued

on the D.C.

Cook

PGP.

This inspection

was based

upon the effective Unit 2 EOPs listed in

Appendix A, Revision

0 of the Writer's Guide and Revision

1 of the

The

NRC determined that

ERG Revision

1 generic technical guideline step

sequence

and placekeeping

requirements

were met and that entry and exit

points were correct except

as noted in the enclosed

Appendix B.

Revision

1 of the Writer's Guide has not been applied to the EOPs,

but is scheduled for September

1988 when an EOP upgrade will incorporate

Revision lA of the

Transfers within the

EOPs were well defined

and appropriate

except

as noted in Appendix B.

The general priority of treatment

and order

of steps

was maintained.

I

Because of the self contained nature of the

EOPs it was not generally

necessary

for the operators

to remove pages.

For this reason,

placekeeping

was not a significant problem.

I

The

NRC verified that procedure entry and exit points were generally

correct, properly and clearly identified,

and could be easily followed

by the operators.

The licensee's

use of notes,

cautions,

and transfer instructions

was

clear

and consistent with the

ERGs except

as noted in Appendix B.

The

NRC verified that the priority of accident mitigation was maintained

in the

EOPs except

as noted in Appendix B.

Major identified deviations

between

the plant specific

and the

generic technical guidelines

appeared

to be based

upon adequate

technical

justification.

Safety significant deviations

had been reported to the

NRC.

As noted in Appendix B, the

NRC identified some deviations

which

were not included in the

SDD; none were considered

safety significant.

Plant unique operator action setpoints

were contained in the setpoint

document.

Many parameters

were selected

from the

and traced to the

SPD with generally satisfactory results

except in the case of adverse

containment.

There were several

instances'where

the

ERG contemplated

adverse

values

and the setpoint

document either carried normal and

adverse

values

as identical or omitted adverse

values entirely.

These deficiencies

are documented in the attached

appendices.

Control room drawings

were inspected

to verify that management

controls

were effective and that plant changes

were reflected in interim and final

drawings in a timely manner.

Twelve drawings were inspected; all were

up-to-date.

The licensee

has

an onsite drawing production capability

and does not use interim drawings.

Final installation drawings are

issued

when the change

package installation is complete.

There were no violations or deviations

noted in this area.

Review of the

b

In lant and Control Room Walkthrou hs

Inplant and control room walkthroughs of the emergency

and abnormal

procedures

listed in Appendix A were conducted.

When strictly compared,

the instrumentation

and control labeling on the control board

and the

nomenclature

used in the procedures

was inconsistent.

However, the

majority of the discrepancies

observed

were minor in nature

and only

those discrepancies

which the

NRC felt were significant have been

identified in Appendix C.

The licensee

should review and resolve

not only "those discrepancies

identified in Appendix C, but also perform

a procedure/control

board labeling review and evaluate all discrepancies.

Resolution of this issue will be identified as

an Open Item (316/88017-01).

Indicators,

annunciators

and controls referenced in the

EOPs were found

to be available to the operators.

There

was one set of ERG based

maintained in the control room at all times.

These procedures

were

verified to be of the latest revision and free of any handwritten changes.

While the result of these walkthroughs

was generally positive,

discrepancies

in the areas of technical

adequacy,

writer's guide

adherence

and

human factors were noted.

These discrepancies

are

identified in Appendix B.

The licensee

committed to review and resolve

the discrepancies

identified in the aforementioned

appendix.

Appendix

B

discrepancies will be identified as

an Open Item (316/88017-02).

As a result of inplant and control room walkthroughs,

two procedures

reviewed by the

NRC were determined

to be inadequate.

The procedures

were 2-0HP-4023.001.011,

Reactor

Shutdown from Hot Standby Panel

due

to Control Room Inaccessibility,

Revision

2 and 2-0HP-4023.001.006,

Loss

of Control Air, Revision 1.

The licensee

committed to review and resolve

the inadequacies

in these

procedures

as described

below.

Resolution of

this issue will be identified as

an Open Item (316/88017"03).

The first of these

inadequate

procedures;

reactor

shutdown from

the hot standby panel procedure

contained insufficient direction in

that the majority of the procedure

appeared

to be an inventory of the

instrumentation

and controls available to the operator at the hot standby

panel.

Little guidance

on the control of the unit following a reactor

trip when evacuation of the control room is required

was provided.

Discussion with the licensee

indicated that'his

procedure

was to be

implemented in conjunction with existing plant procedures.

However,

no reference

was

made to existing normal,

abnormal or emergency procedures

within the hot standby panel procedure.

In response

to this concern,

the

licensee

informed the operators

that until the procedure is revised,

the

guidance for control from the hot standby panel is dictated by the

procedure that applies at that time, e.g.,

E-O, Reactor Trip or Safety

Injection, etc.

The second

inadequate

procedure;

loss of control air did not identify the

instrumentation that would be inoperative following a loss of control air.

The licensee

should revise the procedure

to include

a listing of those

instruments

which would be inoperative following a loss of control air.

As a result of recent revisions to E-O, Reactor Trip or Safety Injection,

Attachments

A and

B were also revised to correct several errors in the

listings of. valves.

Attachments

A and

B are used in E-O to verify that

the'applicable

valves close

on either

a Phase

A or Phase

B containment

isolation signal.

The

same attachments

are also used in ECA-O.O, Loss

of All AC Power and FR-Z.l, Response

to High High Containment Pressure.

At the time that E-0 was revised,

the other two procedures

containing

these

attachments

were not revised.

The licensee

could not provide the

NRC with a reasonable justification as to why the two remaining procedures

were not revised.

The fact that ECA-O.O and FR-Z.1 were not revised

resulted in both missing

and erroneous

information in Attachments

A and

B.

The valves missing from Attachment

A were erroneously listed under

Attachment

B as

Phase

B isolation valves.

They were 2-NCR-252, Primary

Water to Containment,

2-GCR-301, Nitrogen to PZR Relief Tank,,2-QCR-919,

Demineralized water to Containment,

and 2-QCR-920, Demineralized

Water

to Containment.

Valves missing from Attachment

B were 2-CCM-459,

CCW

l

II'

to RCP Coolers;

2-CCM-452,

CCW from RCP oil Coolers;

2-CCM-454,

CCW from

RCP thermal barriers;

2-ECR-33,

Lower Containment Air Sample to RMS/PASS;

and 2-ECR-32,

Lower Containment Air Sample to ERS-1300.

Furthermore, after

the licensee

had been informed of and had corrected

these discrepancies,

a

control room walkthrough of 2-OHP 4022.034.003,

Recovery from Containment

Phase

A, Revision 3,

was performed.

From this walkthrough it was

determined that Phase

A isolation Valve 2-GCR-314

was not labeled

on the

safety injection/accumulator

panel

as

a Phase

A isolation valve nor was

it included

on Attachment A, Revision

0 or 1.

2-GCR-314 is identified

as

a Phase

A isolation valve in Unit 2 TS 3.6.3.1,

Table 3.6-1,

Item 50,

and on print OP-1-98283-6

Emergency

Core Cooling (Safety Injection)

~

Sheet

3.

Consequently,

the control room operators

have not had

a complete

list of containment isolation valves for at least

two years.

This issue

is identified as

an Open Item (316/88-17-04).

The

NRC is concerned with the present controls for the review and revision

process for the EOPs.

A QA review,

one of the current management

controls

in the review process,

requires

only a programmatic

review and does not

include

a technical review.

Prior to final approval

and implementation

of the EOPs neither

QA nor the other management

control groups performed

an adequate

detailed technical

review.

The

NRC recognizes

that,

when

developed,

the procedures

received

a table top review and

some procedures

received

a task analysis

review and walkthrough during the

DCRDR.

Nevertheless,

many technical problems

were discovered

during this

inspection.

Timely and thorough review and revision of EOPs is

discussed

further in Paragraph

8.

Discussion with the licensee indicated that they intend for their QA

reviews to become

more performance

based

by examining the

EOPs during

simulator exercises.

While this will improve the technical content of

the EOPs,

the

NRC cautions that the errors identified above, specifically

with 2-GCR-314 would not have been found during simulator exercises

in

that there

was

no indication to lead operators

to believe that the valve

belonged

on the attachment.

It is recommended

that the licensee:

a.

Conduct walkthroughs of the procedures

in the control room

and in the plant.

b.

c ~

Conduct

a verification of technical specification requirements.

Conduct

a evaluation of the review and revision process

as it

applies to EOPs.

'

Resolution of this issue will be identified as

an Open Item (316/88017-05).

7.

Simulator Observations

The

NRC observed

an operating

crew performing the following eight

scenarios

on the

D AC. Cook simulator:

l

a

b.

C ~

d.

e.f.

g"

h.

Loss of Offsite Power with One

EDG Inoperative

RCS Leak Causing

ECCS Actuation

Loss of All Feedwater

Steam Line Break Outside Containment/Inside

the MSIV

SG Tube Rupture

Station Blackout

Anticipated Transient Without Scram

RCP Trip/Verification of Natural Circulation

The procedures

provided operators, with sufficient guidance to

fulfilltheir responsibilities

and required actions during the

emergencies,

both individually and as

a team.

The procedures

did not cause

the operators

to physically interfere

with each other while performing the

and AOPs.

The procedures

did not duplicate operator actions unless

required

(e.g., for independent verification).

When

a transition from an

EOP to an

AOP or other procedure

was required,

precautions

were taken to ensure that all necessary

steps,

prerequisites,

and initial conditions

were met.

Operators

were found to be generally

knowledgeable

about where to enter

and exit the procedures.

Activities that should occur outside the control room were initiated

by the operators

and proper confirmation of their completion was given.

These actions

were inspected

during inplant walkthroughs of the procedures.

The

EOP lesson plans

cover both the technical basis

behind the procedures

and their structure

and format.

The training scenarios

provide sufficient

coverage of the EOPs (with the exceptions

noted below), including multiple

malfunctions.

In addition, operators

were trained on significant revisions

of the

EOPs prior to their implementation.

The training simulations

should duplicate actual plant operations

whenever

possible.

The extent of simulation should be such that the operator is

required to take the

same action on the simulator to conduct

an evolution

as

on the reference plant'sing the

same procedure.

It was noted during

the simulator exercises

and procedure

walkthroughs that in one case,

pertaining to BIT isolation and the restoration of seal injection flow,

the operators

were being trained'to perform the steps

out of sequence

with the procedure.

Discussion with the licensee

indicated that they

intend to revise the procedure

to reflect this improved method of system

operation.

The

NRC encourages

improvements in plant operation wherever

identified and expects that the improvements to be incorporated,

through

temporary revision and procedure revision; however, until such actions

are taken adherence

to existing procedures

is expected.

No violations or deviations

were noted in this area.

I t

On oin

Evaluation of the

Procedures

and records

were reviewed

and licensee

personnel

were

interviewed to determine

whether the licensee

has

an acceptable

program

for long-term continuing evaluation of the EOPs.

The

NRC found that

Plant Manager's Instruction,

PMI-4020 Operating Procedures,

Revision 6,

established

administrative controls for preparation,

review and approval

of revisions to the

NUREG/CR-1977,

"Guidelines for Preparing

Emergency Procedures

for Nuclear Power Plants,"

NUREG-0899, "Guidelines

for the Preparation

of Emergency Operating Procedures,"

and the

licensee's letter

(AEP:NRC:00773Q)

"Response for Draft Safety Evaluation

on D.C.

Cook Procedures

Generation

Package,"

were all specifically

referenced in PMI-4020.

The procedure

required that "significant"

revisions to the

EOPs must comply with the guidelines'stablished

by

the

PGP - which was the process

used to develop'lant specific procedures

from the

Proposed

revisions to EOPs could be initiated from many sources,

but

operations

and training department

proposals

were predominant.

"Comments"

had arisen

from simulator exercises,

plant and control room walkthroughs,

individual studies

or observations,

biennial reviews,

a

QA surveillance,

and the

DCRDR effort.

In addition, industry experience is evaluated

through Operations

Department

review of semiannual

WOG updates,

and

by Safety and Assessment

Department

by review of NRC correspondence

(Bulletins, Notices

and Generic Letters)

and

INPO information (SERs,

SENs,

SOERs

and other information from the SEE-IN program).

The licensee

stated that all but "minor" EOP revisions will be subjected

to V and

V on the plant simulator.

This intent is not formalized, nor

were the criteria for segregating

and/or prioritizing proposed

EOP

revisions.

At the time of the inspection,

there

was

no formal mechanism

describing

and controlling the process for handling

EOP "comments."

An

Operations

Department procedure

was being developed

which the licensee

indicated would address prioritization, feedback,

and means for

inter-department

communications - e.g.,

from training to operations.

The existing informal process

was found to be fairly uniformly used

and

understood.

Proposed

EOP changes

had been submitted to a procedure

group

within the Operations

Department.

This group had only a single individual

working part time on EOPs.

A large number of comments

(well over

a hundred

items of various kinds) had been accumulated for which final action had not

been taken.

The

NRC viewed the failure to make timely and thorough

revisions to EOPs concerning certain

known deficiencies,

to be

a significant

weakness.

The licensee

should review and resolve these procedural

comments

in a timely fashion.

This issue will be identified as

an Open Item

(316/88017-06).

The

QA organization

was found to be involved in both the original and

the ongoing

EOP development process.

Three

QA staff members,

who had

been licensed at the

SRO level, reviewed all the current-generation

for various attributes'arious

communications illustrated that

QA and

10

the operations

procedure

group had continued working together

on an

upcoming major EOP revision to owner's

group

ERG Revision

1A.

The

QA

group had

a representative

on the plant subcommittee

on procedures,

as

mandated

by PMI-1040, "Plant Nuclear Safety Review Committee."

All

procedure

revisions require

QA review and concurrence.

The

QA group

also performed audits (routine)

and

a surveillance

(nonroutine) in the

EOP area.

NRC Information Notice No. 86"64, "Deficiencies in Upgrade

Programs for Plant Emergency Operating Procedures"

(and its Supplement

1)

had resulted in the licensee

obtaining and reviewing documents

describing

industry deficiencies,

and

QA Surveillance

12-88-23

was specifically

focused

on checking

a sample of the D.C.

Cook EOPs for similar

deficiencies.

QA did not subject the entire body of EOPs to

a

line-by-line comparison to ERG requirements.

While the procedure

comment/suggestion

process

needed formalization,

and

the number of accumulated

comments

was rather large,

as described

above,

the

NRC determined that the licensee

had an acceptable

program

for continuing evaluation of the EOPs.

No violations or deviations

were noted in this area.

9.

EOP User Interviews

Ten interviews were conducted

by the

NRC and it was determined that

the current

EOPs satisfy the needs of the operational personnel.

The

operators felt the

EOPs were adequate

and compatible with the level of

knowledge of the typical operator

and the operations staff was confident

that the

EOPs would function effectively during an actual event.

The

operators

expressed

concern over the double negative

aspects

of some of

the steps in the EOPs.

These

steps

require

a negative finding to remain

in the

AER column and not "kick out" to the

RNO column.

This is contrary

to normal convention which would "kick out" to the

RNO column on a negative

response.

This was also noted to be an item which caused

confusion in

the simulator exercises.

The licensee

has previously identified this

item to the

WOG.

However, the

WOG has taken no action to correct this

deficiency.

The licensee

should consider revising their procedures

to

remove the double negatives

found in the

During interviews, operators

expressed

a concern over the lack of

timely incorporation of comments or proposed

changes

into the procedures.

It should be noted that

a number of items identified by the

NRC had

previously been identified by licensee

personnel.

This lack of

timeliness in incorporating procedure

changes

has

caused

the operators

to be less than enthusiastic

about making comments

on procedures.

Examples of procedure

changes

submitted,

but not yet acted

on include:

ECA-O.O:

On Page 5, the last entry in the

RNO column references

the

wrong procedure

and unit (should be 1, not 2).

Comment sheet

submitted

6-17-87 .,

ECA-O.O:

Step 9.a refers to closing

a non-existent valve (2-C-141).

Comment sheets

submitted 9-9-86 and 11-1-86.

ECA-0.1:

Step 3.d, to start

NESW, should be performed before Step 3.a,

to start

an air compressor,

because

either the compressor

would not

start

(NESW pressure

interlock) or it could be damaged.

Comment

sheets

submitted

10-31-86,

12-1-86,

and 12-26-86.

ECA-O.O:

Step 2.a instructs that Procedure

2 OHP 4022.001.003

be

used.

This is not an appropriate

procedure for emergency

use.

A

deficiency was recognized in the Revision

1 to E-0 and

was corrected

in E-0.

ECA-O.O remains uncorrected.

There were no violations or deviations

noted in this

arear'0.

~ee Items

Open items are matters

which have been discussed

with the licensee

which

will be reviewed further by the inspectors,

and which involves

some action

on the part of the

NRC or licensee,

or both.

Open items disclosed during

this inspection are discussed

in Paragraphs

6 and

8 of this report.

12

APPENDIX A

PROCEDURES

REVIEWED

NUMBER

TITLE

REV-DATED

E-0

ES-O.O

ECA"0 ~ 0

ECA-0.1

'CA-0.2

E-1

ES-1. 1

ES-1.2

ES"1.3

ES-1.4

ECA-1.1

ECA"1.2

E-2

ECA-2.1

E-3

ES-3.1

ES-3.2

ES-3.3

ECA-3.1

ECA-3.2

ECA"3.3

Reactor Trip or Safety Injection

Rediagnosis

Reactor Trip Response

Natural Circulation Cooldown

Natural Circulation Cooldown with

Steam Void in Vessel (with RVLIS)

Natural Circulation Cooldown with

Steam Void in Vessel (without

RVLIS)

Ioss of All AC Power

Ioss of All AC Power without SI

Required

Loss of All AC Power with SI

Required

Loss of Reactor or Secondary

Coolant

SI Termination

Post

LOCA Cooldown and

Depressurization

Transfer to Cold Leg

Recirculation

Transfer to Hot Leg Recirculation

Loss of Emergency Coolant

Recirculation

LOCA Outside Containment

Faulted

Steam Generator

Uncontrolled Depressurization

of all Steam Generators

Steam Generator

Tube Rupture

Post-SGTR

Cooldown Using Backfill

Post-SGTR

Cooldown Using Blowdown

Post-SGTR

Cooldown Using Steamdump

SGTR with Loss of Reactor Coolant-

Subcooled

Recovery Desired

SGTR with Loss of Reactor Coolant-

Saturated

Recovery Desired

SGTR without Pressurizer

Pressure

Control

1-07/01/88

0-05/25/86

0-06/06/86

0-05/30/86

0-06/06/86

0-06/11/86

0-05/30/86

0-05/28/86

1-06/23/88

0-05/28/86

1-04/07/88

0-05/30/86

0-05/25/86

0-05/28/86

0-05/25/86

0-05/30/86

0-05/25/86

0-06/06/86

0-05/30/86

0-05/28/86

0-05/30/86

0-06/06/86

0-06/11/86

F-0.1

F-0.5

F.0.6

Subcriticality

Core Cooling

Heat, Sink

Integrity

Containment

Inventory

0-05/30/86

FR-S.1

FR-S. 2

FR-C. 1

FR-C.2

FR"C.3

FR-H.1

FR-H. 2

FR"H. 3

FR-H. 4

FR-P. 1

FR-P. 2

FR"Z. 1

FR-Z.2

FR-2 '

Response

to Nuclear Power Generation/

ATWS

Response

to Loss of Core Shutdown

Response

to Inadequate

Core

Cooling

Response

to Degraded

Core

Cooling

Response

to Saturated

Core

Cooling

Response

to Loss of Secondary

Heat Sink

Response

to Steam Generator

Overpressurization

Response

to Steam Generator

High I,evel

Response

to Ioss of Normal Steam

Release

Capabilities

Response

to Steam Generator

Low Level

Response

to Imminent Pressurized

Thermal Shock Conditions

Response

to Anticipated Pressurized

Thermal Shock Conditions

Response

to High-High Containment

Pressure

Response

to Containment Flooding

Response

to Containment Radiation

Level

0-04/21/88

0-05/25/86

1-06/23/88

0-05/25/86

0"05/25/86

0-05/30/86

0-05/25/86

0-05/30/86

0"05/25/86

0-05/25/86

FR-I.1

FR-I.2

FR-I.3

Response

to High Pressurizer

Level

Response

to Low Pressurizer

Level

Response

to Voids in Reactor

Vessel

0-05/25/86

0-06/06/86

2-OHP 4022.001.003

2-OHP 4022.005.002

UNIT SHUTDOWN WITH A FAILED

TURBINE VALVE

EMERGENCY BORATION

2-0HP-4023.019.001

2-OHP 4023.020.001

2-OHP 4023.001.001

LOSS

OF ESSENTIAL SERVICE WATER

LOSS

OF NON-ESSENTIAL SERVICE

WATER

'REMOTE SHUTDOWN PROCEDURE-

ATTACHMENT LS-4

APPENDIX B

TECHNICAL AND WRITER'S GUIDE COMMENTS

This appendix contains technical

and writer's guide

comments,

observations

and

suggestions

for EOP improvements

made by the

NRC.

Unless specifically stated,

these

comments

are not regulatory requirements'owever,

the licensee

agreed

in each

case to evaluate

the

comment

and take appropriate action.

These

items

will be reviewed during a future

NRC inspection

as noted in Paragraph

6.

General

Generally,

there

was apparent

lack of adverse

containment values applied

to RCS subcooling within the majority of the procedures.

This is not

consistent with the

WOG guidelines

and there

appears

to be very little

documentation within the licensee's

SDD to support this deviation.

The licensee

should evaluate this deviation and resolve appropriately.

2 ~

E-0 Reactor Tri

or Safet

In ection

a

~

~S

atoms:

The listing of conditions which require

a reactor trip is

incomplete.

Although RPS initiated trips are listed, manual trips

required by other procedures

are not (e.g.,

2-OHP 4022.002.001,

Reactor Coolant

Pump Malfunction, requirement to manually trip the

reactor

and then trip the affected

RCS pump).

The licensee

should

revise E-0 symptoms to include "manual reactor trip" and "manual

safety injection" as conditions.

b.

~Sn~toms:

There are two subparagraphs

numbered

2.

Recommend

deleting the "2)" on Page

1; no other change is required.

C.

Ste

3a

AER and

RNO:

The intent of this step is to verify power

available to at least

one train of equipment.

This requires

power

to either Buses

T21A and

B or T21C and

D or to both bus pairs.

Existing

EOP terminology is confusing

due to the use of "at least

one energized"

and "one

AC emergency

bus" when referring to four

buses;

two bus pairs.

The licensee

should revise the wording to

eliminate this confusion.

d.

Ste

s

14 and 15:

The licensee

should revise the procedure

to eliminate Step

15.

Since these valves are included in

Attachment A, they are properly positioned in Step

14.

e.

Ste

18a

AER and

RNO:

The licensee

inserted the word "remained"

which did not appear in the

ERG.

Use of the word "remained" implies

that containment

spray should be reinitiated if pressure

has ever

been

above 2.9 PSIG,

even if it is currently below 2.9 as it might

be following ice condenser

suppression

of a pressure

spike from a

leak which has

been isolated.

There is no technical justification

I

for reinitiation under these

circumstances.

The licensee

should

review and resolve this condition.

~gte

30:

The note before

Step

24 applies

to Step

30 also.

The licensee

should revise the procedure

to include the note

before Step 30.

Attachment

A

Pa

e 19:

The 2-CRV-445 valve is

CCW from south spent

fuel pit HX, not from the "North."

The licensee

should correct the

noun name of this valve.

h.

Attachment

A

Pa

e 19:

The 2-CRV-485 valve noun name omits the word

South in this attachment.

In order to be consistent with the valve

label, the noun name in this attachment

should read

"CCW to South

Boric Acid Evap."

The licensee

should correct the noun

name of this

valve in Attachment A.

1 ~

Attachment

A

Pa

e 21:

The Containment Auxiliary Subpanel

(CAS)

which is physically located in the auxiliary building, Elevation 633,

does not have the Phase

A labels adjacent

to the indicator lights.

In order to be consistent with the control room labeling,

the

licensee

should

add the Phase

A tags to the

CAS panel switches.

Attachment

A

Pa

e 21:

The

"VC panel" is actually the

"VS Panel."

The licensee

should correct this error.

k.

Attachment

A

Pa

e 21:

The eight

VS panel

HV switches

are designated

with only the switch numbers not the noun names.

In order to be

consistent with the rest of Attachment A, the licensee

should

add

the noun names for the

HV switches.

Attachment

A

Pa

e 22:

The licensee

should revise the procedure

to insert the "Attachment A" heading

as found on Pages

18-21.

3.

ES-O.O Redia nosis

~gte

3:

The licensee

should evaluate

the need to revise the procedure

to more clearly define "High radiation."

4.

ES-O.l Re'actor Tri

Res

onse

a

~

Ste

1

RNOs

a and c:

The licensee

should revise the procedure

to be consistent with the terminology used by the operators, i.e.,

"SG PORVs" vs procedural

and control board usage of "SG steam

reliefs."

b.

operation of Valve 2-QRV-301.

Ca

~gte

da:

This step is identical with that of the

WOG guidelines,

"check

SG levels:

a. Narrow range level greater

than x g."

Neither

the

WOG guidelines nor the

EOP indicate whether it refers to one or

more or all steam generators.

The background

document indicates it

applies to one or more.

The licensee

should revise this step to

"a. Narrow range level in at least

one

SG greater

than 6g."

d.

The procedural

process

of electrical power restoration varies

from excellent (e.g.,

ES-0.1

Step

7 and

7

RNO with Attachment A)

to inadequate

(e.g.,

E-0 Step

19

RNO, "Try to restore offsite

power," unamplified).

The problem is complicated

by the existence

of 2-OHP 4023.001.021,

Restoration of Power From Blackout,

and the

belief of at least three licensed operators

that loss of offsite

power with successful

sequencing

of the diesel generators

onto

.

their busses

is an entry condition to ECA 0.0 (because

of the

transient loss of all AC while the

DGs are sequencing).

It is

recommended

that:

(1)

be reviewed to assure

that power restoration

requirements

are adequately specified.

(2)

The need for and application of 2-OHP 4023.001.021

be

reviewed.

(3)

Operator training provide increased

emphasis

on,

(1) the difference between blackout and total loss

of AC power and (2) the entry conditions of ECA 0.0.

5.

ES-0.2 Natural Circulation Cooldown

a

~

~gte

1:

This step contains

a check for plant status

"Containment-

Accessible."

If the containment

were not accessible

the operator

may resort to the

RNO which would direct him to the next step

and

preclude starting

a RCP.

The licensee

should revise this step to

clarify the desired action.

b.

~gte

6:

The note preceding this step

has

been

added by the licensee

and is not contained in the

WOG guidelines,

but no deviation document

was generated.

The licensee

should generate

a step deviation

document for this note.

Ca

~Ste

15:

The caution preceding this step

has been

added by

the licensee

and is not contained in the

WOG guidelines;

however,

no. deviation document

was generated

by the licensee.

The licensee

should generate

a step deviation document for the caution.

6.

ES-0.3 Natural Circulation Cooldown With Steam Void in Vessel (with RVLIS)

a

~

~Ste

2:

Same

comment

as noted in ES-0.2,

Step

1 above.

b.,

~Ste

7:

Same

comment

as noted in ES-0.2,

Step

15 above.

Cs

~gte

13:

This step under the

EEO contains

an incorrect refereace

to Step 8.

The licensee

should revise this step to reference

the

correct step.

a

~

~gte

2:

Same

comment

as noted in ES-0.2,

Step

1 above.

7.

ES-0.4 Natural Circulation Cooldown With Steam Void in Vessel (without

RVLIS)

b.

~gte

2.

This step requires

the operators

to hand rotate the

to be started.

Other procedures

(ES-0.2

and ES-0.3)

make this step

conditional with the words "ifpractical."

The licensee

should

revise this step to be uniform with the other procedures.

c.

~Ste

11:

Same

comment

as noted in ES-0.2,

Step

15 above.

d.

~gte

23:

This step

under the

RNO contains

an incorrect reference

to Step

23'he

licensee

should revise this step to reference

the

correct step.

e.

Foldout:

The foldout page

does not contain the adverse

containment

values for RCS pressure

under the

RCP trip criteria or RCS subcooling

under the SI actuation criteria.

The licensee

should revise the

foldout page to include these values or provide documentation in

the

SDD.

8.

ECA-O.O I,oss of All AC Power

a

~

The last entry in the

RNO column on Page

5 should be "Unit One

D/Gs per

1-OHP 4023.001.020."

The licensee

should evaluate

this discrepancy

and revise

as appropriate.

b.

~gte

S.a:

This instruction cannot

be accomplished

as stated

because

the referenced

valve (2-C-141)

no longer exists.

An alternate valve

for accomplishing

the intended objective should be identified.

The

licensee

should evaluate this discrepancy

and revise

as appropriate.

c ~

~gte

14:

Design changes

to both the

CRID and the

TDAPP latching

solenoid

may make this step unnecessary.

If it remains desirable,

I and

C (not

C and I as stated)

should disconnect

the

TDAFP electrical

overspeed trip without waiting for an attempted

emergency

fan hookup.

The licensee

should evaluate this discrepancy

and revise

as

appropriate.

d.

~gte

16:

The

RNO column should read If Un"it one's

CST

The licensee

should evaluate this discrepancy

and revise

as

appropriate.

e.

~gte

21: It appears

inappropriate

to give instructions to

stop fans

as necessary"

in the Response

Not Obtained

column,

when the procedure is at a point where no fans

have

power.

The licensee

should evaluate this discrepancy

and

revise

as appropriate.

~gte

29a:

There is no

SUPPLEMENT FOR ADVERSE CONTAINMENT attached

to this procedure

as indicated.

The Unit

1 procedure

(Unit 1 was

in operation during the inspection) did contain the Supplement.

The licensee

should evaluate this discrepancy

and revise

as

appropriate.

go

~Ste

10.c:

Some brief instructions for locating Valve 2-MS-141

should be provided at this step.

It is both rarely operated

and

not easy to locate.

The licensee

should evaluate this discrepancy

and revise

as appropriate.

~gte

17:

A cross-reference

should be

made at this step to existing,

.

approved

methods to "locally dump steam using

SG steam relief

e.g.,

Attachment IS-4, Section IS-4-3 to Procedure

2-OHP 4023.001.001,

"Remote

Shutdown Procedure."

The licensee

should evaluate this

discrepancy

and revise

as appropriate.

the

WOG guidelines,

should be clarified or deleted.

It may be

either ill-advised or impossible to "bleed and feed with demineralized

water" through the BIT and the

BAST in the condition in which no

AC

busses

are energized.

The licensee

should evaluate this discrepancy

and revise

as appropriate.

9.

ECA"0.1 Loss of AC Without SI Re uired

a

~gte

3:

The specificity of this step should be improved to:

~

identify the instrument

number

and pressure

for instrument

air AVAILABLE (Step 3.a)

~

identify valves to be checked

by valve number

(Step 3.b)

~

provide the flow/ratio to achieve the desired

VCT makeup

concentration

(Step 3.c)

The licensee

should evaluate

these

discrepancies

and revise

as

appropriate.

b.

~gte

3.d:

Since this step (restoring

NESW) is

a precondition to

Step 3.a (restoring

a control air compressor)

the sequence

needs

to be revised.

The licensee

should evaluate this discrepancy

and

revise

as appropriate.

c ~

~Ste

11:

The current laaguage

of this step

caused

confusion regarding

whether all three

RCP seal injection valves are supposed

to be

opened - an unusual condition.

The licensee

should evaluate this

discrepancy

and revise

as appropriate.

10.

ECA-0.2 Loss of AC With SI Re uired

~Ste

10:

Same

comment

aa noted

above in ECA-0.1, Item c; Step

11.

E-1 Loss of Reactor or Secondar

Coolant

Pa

e

1

S

toms or Entr

Conditions:

Entry condition number five,

refers to Step

28 of Procedure

ES-1.1,

SI Termination, but, it should

refer to ES-l,l Step

31.

The licensee

should correct the entry

conditions in E-l.

b.

Pa

e

1

S

toms or Ent

Conditions:

Entry condition number

seven,

refers to Step

10 of Procedure

ECA-0.2, Loss of All AC

Power - Recovery Without SI Required, but, it should refer to

ECA-0.2, Step ll.

The licensee

should correct the entry condition

in E-l.

Pa

e

3

Ste

3.a:

This procedure lists auxiliary feedwater

flow units in "1b/hr" but the meter face units are "PPH."

The

abbreviation

PPH is not in the approved writer's guide list of

abbreviations.

The licensee

should establish

parameter unit

consistency

between procedures

and panels.

d.

Pa

e

8

Ste

14.a:

This step

uses

"RHX" instead of "RHR HX."

The licensee

should correct this abbreviation.

e".

Su

lement

Pa

e 1:

The scale graduations

on Graph A

(300-700-1100-1500-1900-2300)

PSIG are inconsistent with

scale

graduations

on the wide range

RCS pressure

chart

recorder

(0-500-1000-1500-2000-2500-3000)

PSIG.

The inconsistent

scales

and graduations

on Graph A, make it difficult for the

operator to use.

- The licensee

should revise

Graph A to be

consistent with the chart recorder scale.

Su

lement

Caution

rior to Ste

9:

This caution states

the

RHR

pumps must be manually restarted if RCS pressure

decreases

to

less

than 300 psig.

However, the caution does not include the

RCS pressure

of 590 psig for an adverse

containment condition.

The licensee

should include the

RCS pressure

reading for adverse

containment or provide documentation in the

SDD.

12.

ES-1.1 SI Termination

a

~

Pa

e

1

S

toms or Ent

Conditions:

The entry conditions,

Item 1,

states

that the procedure is entered

from E-O, Reactor Trip or Safety

Injection, Step 26.

However, this procedure is actually entered

from

E-O, Step 29.

The licensee

should correct the Item

1 entry conditions

in ES-1.1.

b.

Pa

e

1

S

toms or Ent

Conditions:

The entry conditions,

Item 2,

states

that this procedure is entered

from FR-H.l, Response

to Loss

of Secondary

Heat Sink, Step 29.

However, this procedure is actually

entered

from FR"H.l, Step 30.

The licensee

should correct the Item 2

entry conditions in ES-l.l.

c

~

and outlet BIT isolation valves.

However, the operator is not given

the valve numbers.

In order to be consistent with the previous steps

and the writer's guide,

the licensee

should revise this step to

include:

2-IMO-255

2"IMO-256

2-ICM-250

2"ICM"251

d.

Pa

e

12

Ste

25:

This step instructs

the operator to transfer

NR-45 to the source

range scale.

However, the NR-45 chart recorder

has been replaced

by the 2-SG-12 chart recorder.

The licensee

should

change all steps

referencing

NR-45 to 2-SG-12.

e.

Pa

e 21

Attachment

B Action Statements:

"Control removed" at the

end of this statement

should read "control power removed" to make

it consistent with the panel label.

13.

ES>>1.2 Post

IOCA Cooldown and

De ressurization

Pa

e 4

Caution

rior to Ste

7:

This caution instructs

the operator

to evaluate

steam flow rates in "LB/HR."

The vertical steam flow meters

indicate

steam flow in "PPH."

The safety parameter

display system

indicates

steam flow in "KBH." Furthermore,

the D.C.

Cook list of

abbreviations

does not include

"PPH" or "KBH." This

same

comment applies

to feedwater

and other meters

on the steam generator

and feed

pump panels.

The licensee

should apply parameter units consistently

and in agreement

with the writer's guide.

See

DCRDR Human Engineering Discrepancy, Vl-5.-

14.

ES-1.3 Transfer to Cold Ie

Recirculation

~Ste

3:

The

RNO coatains

a reference

to ECS-1.1.

The correct

reference is ECA-1.1.

The licensee

should revise this step to

correct the reference.

15.

ECA 1.1 Loss of Emer enc

Coolant Recirculation

a

~

h

should evaluate

whether

some qualification should be placed

on

water transfer from the spent fuel pool to RWST.

b.

S~te

dc:

The licensee

should revise the procedure

to emphasize

the fact that this is not a transfer to ES-1.3.

c

~

S~te

21a:

No adverse

containment value is provided for RCS pressure

This is not consistent with the

WOG guidelines

which indicate that an

I a

adverse

containment value is applicable.

The licensee

should revise

the procedure

to include the adverse

containment value if applicable

or provide the necessary

documentation in the

SDD.

16.

ECA-1.2 LOCA Outside Containment

Pa

e

1

S

toms or Ent

Conditions:

The entry conditions state that

this procedure is entered

from E-O, Reactor Trip or Safety Injection,

Step 30.

However, this procedure is actually entered

from E-O, Step 31.

The licensee

should correct the entry conditions in ECA-1.2.

17.

E-2 Faulted

Steam Generator Isolation

a

~

~Ste

B.1:

This step contains

an incorrect reference

to Step

22 of

an E-0 entry condition.

The licensee

should revise the procedure

to correct, this reference.

b.

~gte

5:

This step under the

RNO contains

a reference

to the

CST

crosstie

Valve 2-CRV-51.

The correct valve number is 12-CRV-51.

The licensee

should revise this step to reference

the correct

valve designation.

18.

ECA"2.1 Uncontrolled

De ressurization of All Steam Generators

a

~

~gte

S.a:

This step

does not contain the adverse

containment

value for RCS pressure

as contained in the

WOG guidelines.

The

licensee

should revise this step to include this value or provide

documentation in the

SDD.

b.

~gte

4:

This step

under the

RNO contains

a reference

to the

CST

crosstie

Valve 1-CRV-51.

The correct valve number is 12-CRV-51.

The licensee

should revise this step to reference

the correct

valve designation.

C ~

~Ste

6:

The caution

does not contain the

contained in the

WOG

step to include this

preceding this step concerning the

RHR pumps

adverse

containment value for RCS pressure

as

guidelines.

The licensee

should revise this

value.

d.

Ste

s 38

39

and 40:

These

steps

do not contain the adverse

containment values for RCS hot leg temperatures

and pressures

as contained in the

WOG guidelines.

The licensee

should revise

these

steps

to include these values.

e.

~gte

9:

The note preceding this step

concerning

the start of

an RCP with a noncondensible

bubble is not contained in the

WOG

guidelines

and

a step deviation document

does not exist.

The

licensee

should generate

a step deviation document for this note.

S~te

17:

This step

energizes

the hydrogen igniters.

It is not

contained in the

WOG guidelines nor has

a deviation document

been

generated.

The licensee

should generate

a deviation document for

this step.

Ia

19.

E-3 Steam Generator

Tube

Ru ture

a

~

The entry. conditions

from E-O, listed on Page

1, from Step

23 and

Step

30 appear

to be out of sequence.

The licensee

should revise

the procedure to include the correct step

numbers.

b.

and containment isolation Phase

A and B.

In the

WOG guidelines

these

steps

do not occur until Steps

8 and 9.

The licensee

has

not provided documentation of this difference in their SDD.

~Ste

12:

The caution prior to this step

does not include the

adverse

containment value for RCS pressure.

The licensee

should

revise the procedure

to include this value or provide the necessary

documentation in the

SDD.

d.

~Ste

27:

The value for adverse

containment

conditions

on

pressurizer

level in the

AER column is 47 percent while the value

in the

RNO column is 50 percent.

The licensee

should review and

resolve this apparent

discrepancy.

e.

~Ste

35:

Same

comment

as noted in ES-3.2,

Step

12.

20.

ES-3.1 Post

SGTR Cooldown Usia

Backfill

a

~

~Ste

4:

The caution prior to Step

4 informs the operator that

it will be necessary

to line up alternate

water sources if the

CST level decreases

to less

than

13 percent.

The licensee

should

consider revising the procedure to include the applicable procedure

through which this task would be accomplished.

b.

~Ste

5:

The direction provided for the operator in this step to

dump steam to the condenser

from the intact steam generator is not

consistent with other steps

completing the

same action.

The

licensee

should revise the step.

c ~

~Ste

8:

This step directs

the operator to establish auxiliary

spray if letdown is in service.

However, this step

does not

direct the operator

on the specific valves to be used.

This

is not consistent with other steps

completing the

same action.

The licensee

should revise the step.

d.

General

Comment:

Same

comment

as noted in ES-3.2,

Step

12, below.

21.

ES-3.2 Post

SGTR Cooldown Usin

Blowdown

a ~

~Ste

4:

The caution prior to Step

4 informs the operator that

it will be necessary

to line up alternate

water sources if the

CST level decreases

to less

than

13 percent.

The licensee

should

consider revising the procedure

to include the applicable procedure

through which this task would be accomplished.

b.

~Ste

5:

The direction provided for the operator in this step to

dump steam to the condenser

from the intact steam generator is not

consistent with other steps

completing the

same action.

The

licensee

should revise the step.

c

~

spray if letdown is in service.

However this step

does not direct

the operator

on the specific valves to be used.

This is not

consistent with other steps

completing the

same action.

The

licensee

should revise the step.

d.

~Ste

9:

The note prior to this step is not in the

and

is not documented in the licensee's

SDD.

The licensee

should

review and resolve this discrepancy.

e.

~Ste

9:

Same

comment

as noted in ES-3.2,

Step 4.

ga

~Ste

12:

This step directs

the operator to check if RCPs

must

be stopped.

The criteria used for stopping the

RCPs is less

than

210 psid on the number

one seal or number

one seal leakoff flow

less

than 0.4 gpm.

This criteria is not consistent with the starting

values of greater

than 200 psid or 0.2

gpm leakoff flow.

Discussion

with the licensee

indicated that they intend to revise the steps

to

include the latter set of values to avoid operator confusion.

22.

ES-3.3 Post

SGTR Cooldown Usin

Steam

D

~

b.

~Ste

12:

Same

comment

as noted in ES-3.2,

Step

12.

c ~

~Ste

'14:

Same

comment

as noted in ES-3.2,

Step 5.

23.

ECA-3.1

SGTR With loss of Reactor Coolant-Subcooled

Recove

Desired

a.

'S~te

9:

The caution prior to this step is not in the

and

is not documented in the licensee's

SDD.

The licensee

should

review and resolve this discrepancy.

b.

S~te

15b:

The adverse

containment values in the expected

response

and

RNO columns differ.

The licensee

should review and resolve this

discrepancy.

c

Ste

s

16

23 and 35:

Same

comment

as noted in ES-3.2,

Step

12.

d.

Ste

s

17

18 and 19:

The note concerning the use of the supplement

for determining subcooling criteria during adverse

containment

conditions

does not appear in the

and the licensee

has not

provided documentation in their SDD.

The licensee

should review

and resolve this discrepancy.

10

e.

~Ste

29b:

This step directs the operator to transfer auxiliary steam

loads to Unit 2.

The reference

to Unit 2 is incorrect.

The licensee

should revise the procedure

to include the correct reference.

step is incorrect.

This equipment

has

been

removed

and is no longer

in service.

The licensee

should revise the procedure

to remove the

incorrect reference.

ga

~Ste

29:

This step directs

the operator to minimize secondary

system contamination.

This step is not consistent with other steps

completing the

same action in that it fails to direct the operator

to separate

miscellaneous

drain tanks if necessary

and close the

turbine

room sump

pump discharge

valve as necessary.

If applicable,

the licensee

should revise the procedure

to include these actions

such that steps

completing the

same action are consistent with each

other.

24.

ECA-3.2

SGTR With Loss of Reactor Coolant-Saturated

Recover

Desired

a

~

should evaluate

whether

some qualification should be placed

on water

transfer

from the spent fuel pool to the

RWST.

b.

~Ste

4:

The caution prior to Step

4 informs the operator that

it will be necessary

to line up alternate

water sources if the

CST level decreases

to less

than

13 percent.

The licensee

should

consider revising the procedure

to include the applicable procedure

through which this task would be accomplished.

Ca

~Ste

10:

Same

comment

as noted in ES-3.2,

Step

12.

d.

Ste

s ll

12 and 13:

The note concerning

the use of the supplement

to determine

subcooling criteria during adverse

containment conditions

is not included in the

and the licensee

has not provided the

necessary

documentation in their SDD.

The licensee

should review

and resolve this discrepancy.

e.

loads to the backup plant heating boiler if the plant heating boiler

is not available.

The backup heating boiler has

been

removed.

The

licensee

should revise the procedure

to correct this outdated

reference.

~Ste

23e:

This step directs the operator to close turbine

r'oom

sump pumps discharge

Valve 2-DRV-710 as necessary.

Discussion with

the licensee

indicated that this valve is

common to both Unit 1 and

Unit 2.

The licensee

should revise the procedure to change

the

reference

to 12-DRV-710.

25.

ECA-3.3'GTR Without Pressurizer

Control

a

~

~gte

4:

Beginning with step four, the procedure

establishes

a

series of RNO actions which, if followed through by the operator,

would result in an incorrect operator action or expected

response.

The licensee

should review and resolve the step

sequence

problem

in this procedure.

b.

~gte

6:

Beginning with Step

6, the procedure

establishes

a series

of RNO actions which if followed through by the operator would result

in an incorrect operator action or expected

response.

The licensee

should review and resolve the step

sequence

problem in this

procedure.

c.

~gte

30:

This step directs

the operator to depressurize

the

RCS and

ruptured

SG to less

than 425 psig.

There are

no adverse

containment

values applied to this pressure.

This is inconsistent with the

WOG

guidelines.

The licensee

should review and resolve this discrepancy.

d.

~gte

31:

The note

and caution before this step

are in conflict

with the

WOG guidelines.

In the

WOG guidelines

they appear before

Step

30.

The licensee

should review and resolve this discrepancy.

26.

F-0.2 Core Coolin

Status

Tree

The operators

are appropriately trained to use five core exit thermocouples

when evaluating

core exit thermocouple

temperature,

but the instructions in

this safety function tree

do not specify the number of thermocouples

that

should be used.

The licensee

should specify in this safety function tree

the number of thermocouples

to be used

when assessing

core exit temperature.

27.

F-0.3 Heat Sink Status

Tree

The brace following the safety function tree (Total AFW flow to

SGs greater

than 200X10 LB/HR and

NR level in at least

one

SG greater

than 22/) is

confusing.

The proposed Revision

1 bracket to replace

the brace

does

not eliminate the logic flaw.

The licensee

should correct the tree

logic.

28e

F-0.4 Inte rit

Status

Tree

a

The logic in the bottom half of this status tree is incorrect.

The operator is instructed to go to Procedures

FR-P.l or FR-P.2

based

on RCS cold leg temperatures

of 242oF.

The operator could

only be in this branch if any

RCS cold leg temperature

was less

than

152 F.

The licensee

should correct this logic.

b.

This Integrity status tree is not colored in Unit 2 and should be.

The licensee

should correct this.

12

c ~

Fi ure F-0.4.1

Inte rit

0 erational Limits:

This figure lists the

colors red, orange,

yellow and green,

but is presented

in black and

white.

In order to be consistent with Unit

1 and the

WOG guideline

and to enhance

the usability of Figure F-0.4.1, it should be colored.

The licensee

should correct this.

29.

F-0.5 Containment Status

Tree

One path indicates that the containment critical safety function is

satisfied

when containment radiation is less

than 200 R/HR.

The basis

for this setpoint is not clear.

The concern is that 200 R/HR represents

neither habitability limits or equipment limits'he licensee

should

reassess

the objectives of the containment critical safety function,

and modify this setpoint

and the setpoint

document

as needed.

30.

F-Oe6 Inventor

Status

Tree

The statement

"RVLIS Indicates

Upper Plenum not Full 100/'s

confusingly

stated.

It could be clarified by stating "Upper Plenum RVLIS indicates

less

than

100$ ."

The licensee

should modify all four statements

referring

to Upper Plenum RVLIS.

While this step is in agreement with the ERG, the

statement is confusing.

31.

FR-S.1

Res

onse to Nuclear Power Generation/ATWS

s a

~

Ste

2

RNO a.2:

This step

uses

the term "trip" as applied to the

SG stop valves.

It does not meet the action verb definition in the

writer's guide.

The operators

indicated that it meant to close the

stop valve using the fast trip circuitry.

The licensee

should revise the

writer's guide to include this definition.

b.

path alignment

and that shown in Procedure

2-OHP 4022.005 '02

Emergency Boration.

Step 4.2.3 closure of the recirc. valve

is not included in the

EOP version.

The licensee

should review

this discrepancy

and revise procedures

as appropriate.

c ~

to verify the

PORV closed after pressure

has

decreased

and to

shut the block if the

PORV is not closed.

The licensee

should

add the guidance

from the

ERG or document the discrepancy in

the

SDD.

d.

~Ete

12:

The

ERG AER does not verify mein feed pumps tripped nor

does the

RNO manually trip these

pumps.

The licensee

should verify

applicability of this step and/or provide documentation in the

SDD.

32.

FR-S.2

Res

onse to Loss of Core Shutdown

a.

Ste

s la

RNO and

2

RNO:

The licensee

should revise these

steps

to specify whether normal or emergency boration is to be used.

13

's

b.

~gte

3:

The

WOG guidelines

caution concerning the need to continue

boration until shutdown margin is achieved

has

been omitted.

The

licensee

should revise the procedure

to include the caution before

Step 3, if applicable,

or provide the necessary

documentation in the

SDD.

C..

Ste

12

last bullet on Pa

e 7:

Although this step is technically

accurate

as written it could result in closure of both TDAFP valves

in error.

The licensee

should revise this step to emphasize

that

only the steam supply valve from the faulted generator

should be

closed.

33.

FR-C.1 Inade uate

Core Coolin

a

~

Ste

s

17 and 24:

The licensee

should revise the procedure

to repeat

the second

"CAUTION" (Page

2 of 13) at these

steps

as

a reminder.

b.

~gte

5.a:

The reading

sequence

of this step for three instrument

flow checks is not the

same

sequence

as the left-to-right arrangement

of the instruments.

The licensee

should review and revise the step

as appropriate.

c ~

~gte

13:

The degree of detail in this step for establishing

and

operating

the steam

dump in the pressure

control mode should be

revised to be consistent with other steps

completing the

same

action.

34.

FR-C.2

De raded

Core Coolin

~

a.

~gte

S.b.3:

The reading

sequence

of this step for three flow

b.

checks differs from the panel arrangement (left-to-right) of the

instruments.

The licensee

should evaluate this discrepancy

and

revise

as appropriate.

Ste

s 6.b.2

6.b.4 and 6.b.5:

The

RCP operating support status

checks

include three items which are not used to accomplish the

same objective in Procedure

FR-C.l.

The licensee

should evaluate

this discrepancy

and revise

as appropriate.

35.

FR-C.3 Saturated

Core Coolin

~gte

2:

This procedure verifies

ECCS flow - an objective also accomplished

at Step

3 of FR-C.l and at Steps

3 and

17 of FR-C.2.

Each of the four has

minor differences in language/structure

detail from all the others.

The

licensee

should evaluate this discrepancy

and revise

as appropriate.

36.

FR"H.l Res

onse to Loss of Seconda

Heat Sink

a

~

~gte

5:

The first caution prior to this step is not in the

and has not been

documented

by the licensee in their SDD.

The

licensee

should review and resolve this discrepancy.

14

b.

~gte

7:

The second

and third cautions

as well as

the note are

not in the

and have not been

documented

by the licensee in

their SDD.

The licensee

should review and resolve this

discrepancy.

c ~

~gte

20:

This step

does not appear in the

and the licensee

has

not provided documentation in their SDD.

The licensee

should review

'nd

resolve this discrepancy.

d.

~gte

20:

The action verb "perform" used in the

RNO column of this

step

does not appear in the writer's guide.

The licensee

should

review and resolve this discrepancy.

e.

~Ste

22:

The third note in the

sequence

does not appear in the

and the licensee

has not provided documentation of the difference in

the

SDD.

The licensee

should review and'resolve

this discrepancy.

~gte

23:

Same

comment

as noted in Step

22 above.

37.

FR-H.2 Steam Generator

Ove

ressure

a

~

Ste

s

2

4

6

and 8:

This procedure

should specify valve

identifications by number in these

steps

to minimize the

potential for misidentifying or omitting an action.

b.

~gte

8:

Instructions for unisolating blowdowa address

only one of

the conditions which may be the cause of the isolation.

The other

causes

and

how to deal with them should be included

as appropriate.

38.

FR-P.1

Res

onse to Imminent. Pressurized

Thermal Shock Condition

a

~

No position indication is installed on any of the steam generator

reliefs (neither the one

PORV relief nor the five code safety relief

valves installed

on each of the four steam generators)

nor are there

any acoustic or thermal sensors.

During walkthroughs

and simulator

drills, every operator took this step to refer only to the

SG PORVs.

From the context,

the

NRC believes it requires verification that all

six valves

on each generator

are closed.

It is recommended

that the

intent be evaluated

and procedure

or training changes

be made

as

appropriate.

b.

Ste

s 5

12

15b

and 22:

These

statements

are of the form "See

supplement plus x degrees

F for adverse

containment."

The wording

is unclear.

The licensee

should revise this to read

"See supplement.

Add (or subtract)

x degrees

F for adverse

containment."

c ~

by opening:

(repeat

the four valve IDs from the

AER side)."

d.

~Ste

14a:

This step is performed outside the control room.

The licensee

should revise to read:

"a. Iocally restore

power

II

to

"if" statements

by a blank line for clarity.

~gte

19:

The licensee

should add the following:

~

2-QMO-451 and

2-QMO-452 open

~

2-IMO-910 and 2-IMO-911 closed

g ~

the

WOG ERG curve is defined to zero psig.

The licensee

should

evaluate

the need to extend the curve to lower pressures.

h.

Step

1

RNO rather than to Step l.

34.

FR-P.2

Res

onse to Antici ated Pressurized

Thermal Shock Condition

a

~

the

WOG ERG curve is defined to zero psig.

The licensee

should

evaluate

the need to extend the curve to lower pressures.

b.

is limited by the yellow path conditions of the

CSF shown in

F-0.4,

Psat for 272 degrees

or 28 psig.

Allowing for a condenser

vacuum which could be held by auxiliary steam

from the opposite

unit, the pressure differential from the

SG to the condenser is

a maximum of 43 psig.

It is doubtful that this pressure

could

lead to an uncontrolled depressurization.

It is recommended

that this be evaluated, particularly the F-0.4 plant unique

parameters.

40.

FR-Z.l Res

onse to Hi h-Hi h Containment Pressure

a

~

containment isolation Phase

A valves closed,

using Attachment A.

The existing Revision

0 version of Attachment

A has

numerous errors

and omissions.

The licensee

has corrected

many of the Revision

0

discrepancies

in the Revision

1 version of this attachment that has

been published in the new Revision

1 E-0 procedure.

All Revision

0

attachments

should be replaced

by the Revision

1 Attachment A.

containment ventilation isolation, but this has already been

accomplished in Step 2; while verifying Phase

A isolation.

The licensee

should review the applicability of Step

3 and

revise

as appropriate.

16

C ~

Pa

e 4

Ste

4.c:

This step instructs

the operator to verify

spray additive tank low-level alarm, but, this step should refer

to the "low-low" level alarm which indicates that the tank is

nearing

empty.

The licensee

should

change "low-level" to "low-low"

level.

d.

Pa

e

8

Ste

9.d:

This step instructs

the operator to verify

RHR to containment

spray flow on Meters

2-IFI-330 and 2-IFI-331.

These'meters

display invalid flows of 1000

GPM and 500

GPM

respectively during normal operation.

The licensee

should

correct the meters

(Units

1 and 2) to read

0 when there is

no RHR flow and actual flow when it exists.

e.

Pa

e

9

Ste

10:

This step instructs

the operator to check if

hydrogen igniters should be turned on.

In order to accomplish

this step,

the operator

needs

to check hydrogen monitors in service,

which he is not instructed to do until Step lla.

The licensee

should

move Step

11.1 for checking the hydrogen monitors in service,

to 10a.

This will assure

that the operator

has the indication he

needs

to make the required decisions in Step

10.

f.

Pa

e

9

Ste

11.c:

This step instructs

the operator to turn on the

hydrogen recombiner

system.

Since this is

a seldom-used

procedure,

it should be referred to in the step

as

2 OHP.4022.034.004.

41.

FR-Z.3 Res

onse to Hi h Containment Radiation Level

~dte

2a:

The licensee

should revise the procedure

to more clearly define

the "high radiation activity levels" which make it necessary

to place the

filter cleanup

system in service.

During walkthroughs,

the operators

were

uncertain what radiation level the phrase

referred to but offered several

possible values, e.g.,

the monitor alert point or the high alarm point,

and the 200 R/hr value

shown in the yellow path of F-0.5 as possible

values.

42.

FR-I.2 Res

onse to Low Pressurizer

Level

Pa

e

2

Ste

2:

This step instructs

the operator to close "2-QRV-171."

This is incorrect.

The correct valve that should be closed is 2-QRV-170,

EXS I LETDN HX OUT PRESS rather than 2-QRV-171,

EXS LETDOWN HS OUTLET

SELECT.

The licensee

should revise this step.

43.

Attachment

A (Containment Isolation Phase

A)

a

~

Pa

e ll

IV Panel:

The list of Phase

A valves is incomplete.

The missing valves are:

2-NCR-252

Primary Water to Containment

2-GCR-301

Nitrogen to PZR Relief Tk

2-QCR-919

Demin Water to Containment

2-QCR-920

Demin Water to Containment

17

Note:

These four valves are

on the Attachment

B, Phase

B

list of valves.

b.

Pa

e ll

IV Panel:

2-VCR-21 and 2-VCR-11 are reversed

on the

list of valves.

These valves

need to be switched in order to

systematically evaluate

the vertical rows of switches.

c.

Pa

e

11

IV Panel:

The noun names "in the procedure

are not

similar to the panel labels.

Procedure

Panel Label

Compartment

Fan Cooler

Ice Cond

CNTMT

Air HDLG

ICR

Note:

There are significant differences in nomenclature

on both Attachments

A and B.

d.

Pa

e

12

IV Panel:

Valve 2-CCR-441.

CCW Pm Pen Cool, is not

a Phase

A valve.

e.

Pa

e

12

IV Panel:

Valve 2-QCR-300 is not functionally grouped

with other Phase

A isolation valves.

Pa

e

12

IV Panel Status Li hts:

Valves 2-GCR-22 and 2-ECR-21

are in reverse

order on the verification list.

g ~

Pa

e

12

IV Panel Status Li hts:

Seven valves in this list have

numbers but "no description."

All of these status lights have

descriptions

on the status lights.

h.

Pa

e

14

CAS Panel:

These

switches which are located in the

auxiliary building, do not have

Phase

A labels like the control

room.

They should be labeled the

same

as the control room.

44.

Attachment

B (Containment Isolation Phase

B)'

~

Pa

e

15

IV Panel:

Five valves are missing from the Phase

B list:

2-CCM-459

-2-CCM"452

2-CCM-454

2"ECR-33

2-ECR-32

CCW to RCP Coolers

CCW from RCP Oil Coolers

CCW from RCP Therm Barriers

Iower CNTMT Air Smpl to RMS/PASS

Lower CNTMT Air Smpl to ERS-2300

b.

Pa

e

15

IV Panel:

The Phase

B list contains four Phase

A

valves:

2-NCR"252

2"GCR"301

2-QCR-919

2-QCR"920

18

45.

2-OHP 4022.001.003

Shutdown With a Failed Turbine Valve

This procedure,

"entered"

from ECA-O.O Step 2.a, is inappropriate for

emergency

use.

This had been previously recognized

and entry from E.O

(REACTOR TRIP) was

removed with Revision l.

ECA-O.O should be similarly

revised.

46.

2-OHP 4022.002.001

Malfunction of a Reactor Coolant

Pum

licensee

should revise this step to reference

the correct procedure.

b.

~gte

5.2:

Same

comment

as a.

47.

2-0HP-4023.001.006

Loss of Control Air

a

~

Pa

e

3

Ste

6.1:

The pressurizer

spray valve does not have valve

position indication, therefore,

the operator will not be able to

make

a position verification of valve position on loss of control

air.

The licensee

has

a design

change

request in progress

that

will correct this concern.

b.

Pa

e

8

Ste

6.7.1-1:

This step identifies more than

40 valves

that are

now presented

in a disorganized list.

The list should

be revised

so that the user

reads

the list from top to bottom,

left to right.

48.

2-OHP 4023.001.011

Reactor

Shutdown From Hot Standb

Panel

Due to Control

~

Room Inaccessibilit

a

~

The licensee

should revise the procedure

to remove the reference

to the "folding doors" from the procedure.

The hot standby panel

enclosure is now closed off by a roll up steel door which was

installed during a modification.

b.

The licensee

should revise the procedure

to place the note which

currently follows Step 4.4.2 prior to Step 4.4.

c.

~Ste

5.5:

There is

a typographical error.

The licensee

should

revise the procedure

to change "If" to "It."

49.

2-OHP 4023.001.014

Ener izin

the Pressurizer

Heaters

From the Emer enc

Diesel Generators

a

~

by closing breaker

21PHA3 (Groups

2 and 3).

The breaker for Group

2

is 21PHA3 and the breaker for Group

3 is 21PHA5.

The licensee

should

revise this step to correct this error.

b.

Ste

5.2.6:

I

Same

comment

as Step 5.1.6 above.

19

50.

2-OHP 4023.017.001

Loss of RHR (Shutdown Coolin )

a

~

~Ste

5.5:

The last sentence

directs that the use of automatic

steam

dumps

be governed

by. secondary activity level.

The licensee

should

revise the pr'ocedure to include an operator action setpoint

above

which steam

dump use is prohibited.

The licensee

should review the

applicability of an operator action setpoint for steam

dump use

and

provide as appropriate.

b.

~Ste

5.9:

The licensee

should revise the procedure

to add steps

providing makeup

feed to the steam generator.

51.

2-OHP 4023.019.001

Ioss of ESW

"SYMPTOMS" 3.3 and Steps 4.2.1

and 4.2.3.2 appear to be out-of-date

with respect

to design

changes

which deleted certain annunciator

drops

and

removed certain "opposite Unit" indication and control (for fire

protection. separation criteria reasons)

from each Control Room.

These

should be revised.

52.

2-OHP 4023.020.001

Loss of NESW

a.

SYMPTOMS 3.2 and 3.3:

Same

comment

as above.

c ~

The sequence

at Step 5.1.3 should specify closing the

NESW crosstie

valves before tripping all NESW pumps for the Unit.

The licensee

should evaluate this step

and revise

as appropriate.

Step 4.2.2 is actually a "Note," not an Immediate Manual

Action.

This should be revised.

20

APPENDIX C

NOMENCLATURE DISCREPANCIES IDENTIFIED

BY

NRC EOP

INSPECTION TEAM

PROCEDURE

ECA 0.0

~STEP

PG

PROCEDURE

NONENCLRTURE

LABEL ON E UIPMENT

8/7

RCP seal return isolation

RCP SEAL WATER RETURN

valve

ECA 0.0

16/13

2-CRV-51

12-CRV-51 (Note: the

valve controller is

in U-1 control rm,

not U-2)

ECA 0.1

4.a/5

4.f/6

Charging line flow control

CCP DISCH FIOW CONTROL

ECA 0.1

4.b/5

Charging line header valve

HEADER PRESSURE

CONTROL VALVE

ECA 0.1

12.a/ll

letdown HX outlet valve

Pg ll,

Right

(2)

RCP seal water filter

inlet; (5) excess

letdown

HX flow ctrl

LETDOWN HX TEMP CTRL

SEAL WATER RETURN

EXS LTDN HX OUT PRESS

10.c/9

RCP seal water filter inlet

SEAL WATER RETURN

ECA 0.1

ECA 0.2

ATT.A

Pg

15

thru 23

6/5

(various breakers

are

functional described

by phrases)

AFW flow control valves

(brief names:

e.g."MAIN"

CONTROL

I

RSRV )

FEED FROM EAST MDAFP

(WEST)

ECA 0.2

7/6

(rt column)

CCW to and from hydrogen

skimmer valves

CCW TO CEQ FAN

1

MAC

tt (FROM) tt

II (2)

ECA 0.2

7/7

(rt column)

Air recirculation/hydrogen

skimmer fans

suction isolation

valves

CNTMT RECIRC FAN

1

II

tl

(2)

CNTMT RECIRC FAN 1 SUCTION

II

II (2)

II

ECA 0.2

9.c/8

RCP seal water filter inlet

SEAL WATER RETURN

ECA 0.2

FR-C.1

10.b/9

1"QRV-200

4.c/13

Air recirculation/hydrogen

skimmer fans

suction isolation

valves

2"QRV-200

CNTMT RECIRC FAN

1

II

II (2)

CNTMT RECIRC FAN

1 SUCTION

II

tl (2)

II

FR-C.2

FR-H.2

4/4

2/2

4/2

6/3

(same

as

two above)

Flow control valves

FRV isolation valves

steam supply valves to

TDAFP

TDAFP supply valves

MD AFW pump supply valves

(same

as

two above)

LEVEL CONTROL VALVES

SG(g)

FEEDWATER ISOLATION

SG(jj) MAIN STM TO AUX

FP TURBINE

SG(j/) FEED FROM TDAFP

FEED FROM EAST MDAFP

tl

(WEST)

Il

8/4

steam supply valves to

TDAFP

ES-1.4

1.1/3

RHR pump

HX bypass valve

2-OHP 4023

Symptom

2 Reactor Breaker Undervoltage

E-0

Trip A

(B)

SG(jf) MAIN STM TO AUX

FP TURBINE

PUMP DISCH XTIE

Rx Trip Bkr Train

A

(B)

2c

Alt exciter field ACB

2-OHP 4023.

017.001

2c

alt exciter field ACB

3.2

E and

W low flow

Supplement

Cabinet

2a

RNO

Panel

12/drop

Rack

Panel 212/drop

Exciter field CB 41F

loop flow low

3.3

3.6

3.13

sump alarms

RHR pump trip alarm

Hx inlet and outlet

sump high

1

W and

E

(should be plural; two

alarms per pump)

pump disch and loop

return

2-OHP 4023

2a2

RNO

SG stop valves

FR-S.1

Dump Valve 2-MRV-2xl

(2x2)

2-OHP 4023

FR-S.2

8c

1c

to normal position

NR-45

to bypass position

Neutron Flux 2SG12

2-OHP 4023

5alc

FR-P.l

RCP oil cooler

RCP bearings

14b

17

accumulator isolation

VCT makeup control

18RN02

RCP seal water inlet

10b/10g

charging line header

Up BRG CLR

CCW RETURN

LWR BRG CLR

CCW RETURN

charging

HDR PRESS

CNTRL

ACCUM OUTLET

BA Blender Feed Flows

RCP seal water return

18RN03

Splmnt

2-OHP 4023

15d

ECA-1.1

VCT

Cabinet

8 (ll)

~

0 normal

0

~

Rack

8 (ll)

BA Blender

2-OHP 4023

4c

RNO 3

excess

letdown diversion

ES-0.1

Pg.

5

EXS Letdown HX Outlet

Select

Same

VCT via seal return header

normal

ES-0.2

ES-0.3

ES-0.4

ECA-2.1

7RNO c

10c

lc/3

5/3

1b/2

2c/3

2b/3

29/12

31/14

recover

NR-45

Oil Lift Pump

CRDM

CCW FLOW RCP OIL COOLER

CCW FLOW RCP

BEARINGS

CCW FLOW RCP

THERM BAR

SAME AS 1b/2

ABOVE

SAME AS 1b/2

ABOVE

SAME AS 1b/2 ABOVE

SAME AS lb/2 ABOVE

recovery (typo)

SG-12

Bearing Lift Pump

CTRL Rod Drive Mech Fan

UP BRG CLR CCW RETURN

IWR BRG CLR

CCW RETURN

THERMAL BARRIER CCW RET

4/4

5b/4

7/5

24/9

32c/15

7/3

CST CROSSTIE

VALVE

BIOCK VAIVES

CTNMT SPRAY

TO VCT

NR-45

SG STEAMLINE RADIATION

BLOWDOWN RADIATION

SAMPLE LINE, RADIATION

UI CST TO U2 XTIE

RELIEF LINE BLOCK

CTS

NORMAL

2-SG-12

SG SAFETY RELIEF PORV

MONITOR

BLOWDOWN TREATMENT