ML17290B060

In addition, the inspectors

assessed

the

'perators'nowledge

of, and ability to implement the

The assessment

included

a review of licensee

programmatic controls.

During this inspection

Procedure

42001 was used.

Safet

Issues

Mana ement

S stem

SIMS

Items:

None.

Results:

The inspectors

concluded that the licensee's

EOPs were satisfactory to

mitigate events

and appeared

much improved from previous versions

examined

by

the

NRC in 1991.

The inspectors

also concluded that

some of the support

procedures

that assisted

the operators in performing the

EOP flow-charts

required further attention.

A summary of the most significant findings is

provided in the Executive

Summary.

One

NRC Open Item involving licensee

corrective actions

from previous

EOP inspections

was closed

(paragraph 8.a).

94033l0092

940318

PDR

ADOCK. 05000397"

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TABLE OF CONTENTS

TABLE OF CONTENTS...................................................)

EXECUTIVE SUMMARY.......................................

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1.

PERSONS CONTACTED..............'..................................1

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BACKGROUND~ ~ ~ o

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SCOPEo

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3

4.

COMPARISON OF EOPS,'OWNERS'ROUP

GUIDANCE, AND THE PSTG.........2

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USE

OF

EOPS

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5

6.

KNOWLEDGE AND PERFORMANCE

OF DUTIES..............................9

7.

EMERGENCY OPERATING PROCEDURE

PROGRAMMATIC CONTROLS.............. 12

8 o

FOLLOWUP OF CORRECTIVE ACTIONS...................................

14

. CONCLUSION.......................................................16

9

10.

EXIT MEETING...........................,.............

ATTACHMENT 1 Documents

Reviewed

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ATTACHMENT 2 Deficiencies

Observed

EXECUTIVE SUMMARY

From February

7 through

18,

1994, inspectors

from Region

V conducted

an

emergency operating

procedures

(EOPs) inspection at the Region

V offices and

at Washington Public Power Supply System's

Unit 2 (WNP-2).

The inspectors

reviewed the

EOPs to determine if: (1) the

EOPs, the

BWR Owners'roup

guidance,

and the licensee's

deviation document were consistent

and deviations

adequately justified; (2) evaluated

operator

use of the

EOPs to determine if

they could be implemented;

(3) evaluated operators'nowledge

and performance

of the

EOPs;

(4) evaluated

the licensee's

programmatic controls;

and (5)

evaluated

licensee corrective actions

from previous

EOP inspections

in 1991.

The inspector s concluded that the

EOPs (flow-charts) were satisfactory to

mitigate events

and appeared

much improved over previous versions.

The

inspectors

also concluded that

some

Emergency Support Procedures

(ESPs),

although adequate,

required further management

attention.

During comparison of the

EOPs, the Owners'roup

guidance,

and the deviation

document,

the inspectors

found

a few weak justifications for deviations

and

some questionable

set-points in the

During evaluation of the operators'sing

the

EOPs, the inspectors

observed

that (1)

some equipment

needed to perform the

ESPs

was not readily available,

(2)

some control

room instrumentation

had inconsistent labelling or was not

fully available,

and (3) that

some procedural

steps

could have complicated

plant recovery.

During inspection of the operators'nowledge

of and performance of the

EOPs,

the inspectors

found that the operators

made

a few errors which were self-

corrected.

Overall operator

performance

was adequate

in implementing the

and the operators

demonstrated

an acceptable

level of training.

The

inspectors

found command

and control displayed

by one operating

crew a notable

strength.

In evaluating the licensee's

EOP programmatic controls the inspectors

concluded that the licensee's

program was adequate

with one exception;

the

licensee failed to fully update the graphics display system

when the phase II

EOPs were implemented.

The errors in the graphics display system did not

appear to affect proper implementation of EOPs.

During review of licensee corrective actions following the

NRC

EOP inspection

in 1991, the inspectors

observed that, with a few exceptions,

the licensee

had

taken actions consistent with their response

to the

NRC.

Two issues,

for

which a regulatory position has not been developed,

were in the process

of

being resolved with the

BWR Owners'roup.

The inspectors

also observed that

some planned actions described to the

NRC following the

1991

EOP inspection

had

been modified.

These actions generally involved instances

where the

licensee stated that they would maintain deviations

from .the Owners'roup

guidance,

but had subsequently

changed the

EOPs to conform with the

Owners'roup.

DETAILS

Persons

Contacted

G. Smith, Acting Plant Nanager

H. Kook, Licensing Nanager

D. Williams, Nuclear Engineer

N. Harm, Acting Operations

Nanager

D. King, Operations Training Division Hanager

J. Baker, Technical Training Nanager

N. Baird, Operations Training Hanager

0. Brooks,

EOP Coordinator

P. Bettis, Technical

Programs

Hanager

"B. Twitty, guality Assurance

Engineer

K. Pisarcik,

Licensing Engineer

R. Vosburgh,

Nuclear Engineer

J. Parrish, Assistant

managing Director for Operations

S. Davison, guality Assurance

Engineer

D. Larkin, Manager Engineering Services

J. Swailes,

Plant Nanager

The inspectors

also interviewed various control

room operators, shift

supervisors

and shift managers,

maintenance,

engineering,

quality

assurance,

and management

personnel.

Attended the Exit Meeting on February

18,

1994.

Backcaround

In July and August 1991,

a revision of EOPs

was inspected

by Nuclear

Regulatory Commission

(NRC) inspectors

before that revision was

implemented.

Inspection

Report 50-397/91-27

documents

the conclusion

that numerous deviations

from the Owners'roup

guidance

were not

properly justified by the licensee.

In August 1991, the licensee

met

with the

NRC to further discuss

the issues

associated

with the

1991

On November 21,

1991, the licensee

provided

a written response

to

NRC Inspection

Report 50-397/91-27.

In April 1993, after the licensee's

response

was evaluated

by the

NRC,

a

letter was sent to the licensee

requesting

additional information.

In

August 1993, the licensee

responded to the

NRC request for information.

The licensee's

response

appeared

to resolve the significant outstanding

issues,

but the

NRC staff recognized the need for follow-up of

corrective actions.

The licensee

implemented the current

Emergency Operating

Procedures

(EOPs) that the inspectors

reviewed

(phase II EOPs) in April, 1993.

These

EOPs utilized the Boiling Water Reactor Owners'roup

(BWROG)

Emergency

Procedure

Guidelines

(EPGs),

Revision 4.

These

EOPs were

reportedly the product of the licensee's

corrective actions

from the

1991

EOP inspection.

3.

The inspectors

reviewed the results of the previous inspection activity,

with particular attention to previous concerns identified.

The

inspectors

observed that the licensee

had

made significant changes

to

the

and the deviation document since the

1991 inspection

and prior

to implementation of the phase II EOPs.

~Sco

e

During a desk-top review of the

EOPs from February .7-10,

1994, at Region

V, and during an on-site inspection

from February

14-18,

1994, the

inspectors

performed inspection activities in the following five areas.

Review the

EOPs, the licensee

generated

deviation document (Plant

Specific Technical

Guideline (PSTG)),

and the Owners'roup

guidance to ensure consistency

between all three documents.

Verify that deviations. were adequately justified, and that the

EOPs were technically adequate.

Evaluate the use of the

and Emergency Support Procedures

(ESPs) to determine whether the

EOPs could be implemented with

available equipment

and instrumentation.

Evaluate the operators'nowledge

of the

and performance of

actions required

by the

EOPs to determine the adequacy of

training.

Review the licensee's

EOP programmatic controls to identify any

programmatic weaknesses.

Conduct

an evaluation of the licensee's

corrective actions for the

EOPs to verify completeness

and technical

adequacy.

The on-site inspection included walk-downs using portions of the

and

ESPs in the plant, the control room,

and the plant referenced

simulator.

The on-site inspection also included evaluations of licensee

performance of simulator scenarios

and interviews with operators

and

other members of the licensee staff.

The inspectors

also reviewed

samples of pertinent procedures

and calculations

as listed in Attachment

(1).

4.

Com arison of EOPs

Owners'rou

Guidance

and the

PSTG

The inspectors

reviewed portions of the

and compared

them to the

most recent Owners'roup

guidance

(BMROG EPGs,

Revision 4) and the

plant specific technical

guideline.

The inspectors

evaluated

deviations

from the Owners'roup

guidance for adequate justification and

incorporation into the

and evaluated

whether the portions of the

EOPs reviewed were technically correct.

The inspectors

concluded that,

while generally satisfactory,

some justifications of deviations

appeared

weak and

some

EOP set-points

appeared

less than optimal.

Overall, the

comparison

checks

demonstrated

that the

EOP flow-charts were adequate to

mitigate events

and that the phase II EOPs adequately

implemented the

provisions of the Owners'roup

guidance.

Weak Justifications

The inspectors

noted eight examples of justifications of

deviations in the

PSTG from the Owners'roup

guidance which were

weak or absent.

The three most significant examples

are listed

below. and the remaining five are described in Attachment

(2) of

this report.

H dro en Concentration

The entry condition for EOP 5.2. 1, "Primary Containment Control,"

for hydrogen concentration

in containment

was 3.56%.

The

licensee's justification was that the Owners'roup

guidance

bracketed

value was the high hydrogen alarm setpoint,

which for

the licensee

was the annunciation setpoint of 3.56%.

However, the

Owners'roup

guidance also stated that the setpoint should

be

such that the alarm was low enough to allow the operators

time to

react before

a hazardous

situation resulted.

The inspector

reviewed the calculation that the setpoint

was

based

on, E/I-02-

91-1067, "Setting Range Determination for Instrument

Loop CNS-H2E-

1301," Rev. 0,

and noted that the setpoint

used

was the flammable

concentration of hydrogen

(given the presence

of oxygen,

minus

instrument uncertainties).

The inspector

concluded that the

containment could be at flammable levels of hydrogen at the time

that annunciation

occurred.

The

EOP entry condition appeared

non-

conservative

when compared to the Owners'roup

guidance of

providing time for operator action.

The inspector did note,

however that the most probable

cause for hydrogen in containment

would be

a loss of coolant accident

(LOCA), with a loss of core

cooling and resultant

hydrogen generation

from zircalloy water

reaction.

The inspectors

concluded that in this instance

5.2. 1 would have

been entered

due to the

LOCA and the hydrogen

threshold of 0.5% for starting recombiners

would have given

operators

time to act.

The safety significance

appeared

low, but

since hydrogen

was

a separate

EOP entry condition, there

was

an

obvious inconsistency.

The licensee

agreed to evaluate the 3.56%

setpoint

and it's justification.

Haximum Safe

0 eratin

Radiation Levels

EPG Table 1, "Secondary

Containment Control," listed Naximum Safe

Operating Values

as

1250 mR/hr (1.25 Rem/hr) for emer gency

activities monitored by the Reactor Building .Area Radiation

Instruments.

Naximum Safe Operating Values were subsequently

used

as criteria for deciding to conduct

a normal reactor

shutdown.

The

PSTG and

EOP 5.3.1,

"Secondary

Containment Control," Table 24,

listed Naximum Safe Operating 'Values

as

10

mR/hr (10,000 mR/hr).

0'

I

The justification in the

PSTG stated that the meter range

(except

for high range instruments)

of area monitors

was

10" mR/hr.

No

evaluation of expected radiation levels versus

operator tasks

and

stay times was performed

by the licensee to evaluate the

acceptability of 10

mR/hr (10 Rem/hr)

dose rates.

The inspectors

were concerned that operator

access

in the plant

may be very limited if area levels are

10 Rem/hr versus

1.25

Rem/hr,

and that

a safe shutdown

may be complicated.

The licensee

agreed to re-evaluate this radiation level

and revise

procedures

accordingly.

Lowerin

Wetwell Level

The inspectors

noted that when responding to a high wetwell level,

EOP 5.2. 1 directed that wetwell level

be lowered to meet three

different requirements

in EOP steps

L-9, L-14, and L-18.

The

Owner's

Group guidance required that steps

L-9

(maintain wetwell

level below the safety relief valve tailpipe), L-14 (maintain

wetwell level below 51 feet),

and step L-18 (maintain wetwell

level below the maximum primary containment water level limit

(NPCWLL)) be done concurrently.

The licensee's

EOP required step

L-18 to be done after step L-14.

The inspector noted that the

licensee's justification was that the L-14 level limit had to be

achieved

before the L-18 level, limits could be attained.

The

inspector

observed that for wetwell pressures

above

85 psig this

was not necessarily true.

Level could be below 51 feet and still

out of the safe operating

area for NPCWLL.

The licensee

agreed to

evaluate this concern.

uestionable

EOP Set- pints

The inspectors

observed the two following questionable

EOP set-

points in the

Standb

Li uid Control Tank Level

EPG step RC/g-6 stated, "Ifwhile executing the following steps,

SLC tank water level drops to

[0% (low SLC tank water level

trip)], confirm auto trip of or manually trip the

SLC pumps."

In

the event standby liquid control

(SLC) initiation was in progress,

this step

was required in order to stop the

SLC pumps, prior to

pump damage.

PSTG step

RC/g-5 stated, "Ifwhile ....

drops to 0

gal (low SLC tank water level trip), stop both

SLC pumps."

The

justification in the

PSTG stated that plant design did not include

a low water level trip, and potential

pump damage

would occur if

the tank level were reduced to zero,

The inspectors

were concerned that neither the

PSTG nor the

required stopping the

SLC pumps before the tank was empty

(0%

0

dl

n,

indicated).

Although the

PSTG stated that the concern

was

mechanical

damage to the

SLC pumps,

the

EOPs did not require

any

action before

0% level occurred.

The inspectors

concluded the

pumps should

be stopped after the required

boron has

been

injected,

but above

0% level (before potential

damage

occurs to

the

SLC pumps).

The licensee

agreed to consider

an

EOP revision to eliminate the

potential for

SLC pump damage.

Primar

Containment

Pressure

Limit Curve

The inspectors

noted that the graph of the primary containment

pressure limit (PCPL) curve shown in calculation no. NE-02-89-27,

dated

March 24,

1990, differed from the

PCPL curve in EOP 5.2.1.

The point in the curve marked

as

52 feet in the calculation

was

marked

as

51 feet in the

EOP.

The inspector

noted that the

provided

a slightly larger area for safe operation than the

calculated

curve did and concluded that the error was non-

conservative.

However, since the level difference

was minimal,

reading points this close together in the

was very difficult,

and there were significant margins in the calculation, the

inspectors

concluded the safety significance

was low.

The

licensee

agreed to evaluate the difference

between the curves

and

adjust either the

EOP curve or the calculated

curve,

as

appropriate; to reconcile the difference.

The inspectors

concluded overall that the

EOP flow-charts were

satisfactory to mitigate events

and that the phase II EOPs adequately

implemented Owners'roup

guidance.

A few weak justifications

and

some

set-points

which were questionable

were identified.

EOP Evaluation

and Ins ection

The inspectors

walked-down selected

portions of the

EOP flow-charts,

emergency

support procedures,

and the station blackout procedure.

These

walk-downs were performed in the plant, the control room,

and the

simulator.

The inspectors

observed that occasionally not all materials

for Emergency Support Procedures

(ESPs)

were readily available, that

some control

room instrumentation

had inconsistent

nomenclature

or

labelling or was not fully available,

and that

some procedural

steps

could have complicated plant recovery.

The most significant examples of

each of these

observations

are listed below with the remainder listed in

attachment

(2).

Overall the inspectors

concluded that the flow charts

were adequate,

but that

some of the

ESPs required further review and

correction.

Further management

attention

may be warranted to ensure the

ESPs deficiencies

are eliminated.

Materi al Availabi1 it

H dro en Bottle

PPM 5.5. 16,

"Emergency Drywell and Wetwell Purging," Rev. 4, step

6, required

(low flow purge) that

a pressure

regulator

assembly

be

obtained

from the tool crib operations

locker and

a pressurized

nitrogen bottle

be obtained

from the Reactor Building (RB)

522'evel

and moved to the 501'evel.

The inspector noted that the

bottle cart to be'used

in this evolution was normally on the

RB

441'evel.

Other similar support procedures

required that air or

water hoses

be run from the source to the need,

rather than moving

pressurized

nitrogen bottles through

a potentially high radiation

area.

The inspector

was concerned that the alternate nitrogen supply for

valve operation

was not readily available to execute the

procedure.

The licensee

stated at the time of the exit meeting that they were

developing

an additional

method of providing the alternate

nitrogen supply.

Control

Room Instrumentation

Gra hic Dis la

S stem

The inspectors

noted that the Graphic Display System

(GDS) used to

implement the

was not fully updated to reflect the new phase

II EOPs.

The

GDS at WNP-2 was the system

used to meet the Safety

Parameter

Display System

(SPDS) requirement of NUREG-0737,

Supplement

1, "Clarification of TMI Action Plan Requirements."

Following implementation of EOPs, the Shift Technical Advisor

should monitor the

GDS to assist the crew in event mitigation.

I

The inspectors

noted that references

to the old phase I EOPs

remained

on the display screens.

For example,

references

from old

5.1. 1 and 5. 1.2

EOPs were displayed

above the Drywell Spray

Initiation Limit curve.

This curve was not referenced

in either

of the new 5. 1. 1 or 5. 1.2 procedures.

The inspectors verified

that the other curves

on the

GDS were correct

and based

on curves

used for the phase II EOPs.

The inspectors

noted that containment

group isolations

had not

been

updated to reflect current plant groups.

For example,

Group

9 was displayed

on the

GDS,

even though it no longer exists.

The

inspectors

observed that it was important to correct the

GDS

groups

because

containment isolation valve indication was located

throughout the control

room without any group coding.

Operator

verification of correct plant response

could be complicated

by the

errors in the

GDS.

The inspectors

noted that the software logic for emergency action

levels

(EALs) on the

GDS was not consistent with the

EAL reminders

on the

In addition, recent

changes

to EAL thresholds

in the

Radioactivity Release

procedure

were not made

on the

GDS.

The

inspectors

noted that the

EAL classifications

made duting

simulator, scenarios

described later in this report were made

correctly by plant operators

using plant

EOPs,

but were not

correctly indicated

by the

GDS.

f

The licensee

agreed to evaluate

and update the

GDS to conform to

the phase II EOPs.

Dr

ell

Tem erature

Instrumentation

The inspectors

noted the following: Control

Room Drywell

temperature

recorder

CNS-TR-5/6 was used to implement measurements

required

by Figure A,

EOP 5.1.1,

"DW Temperature

versus

Saturation

Temper ature," to determine

accuracy of reactor pressure

vessel

(RPV) level instruments.

Point A01 of this recorder,

"Average

DW Temperature-Normal

Operations,"

and Point 110,

"Average

DM Temperature-Post

Accident," were the two temperatures

used to determine

RPV level accuracy.

The

PSTG required that

the temperature to be used

was Point AOl.

After a "FAZ"'signal

(low RPV level, high

DM pressure,

or

RB ventilation exhaust

radiation) occurred,

point 110 was required to be used.

These

directions were necessary

because

the computational

averaging

performed

by the instrumentation

(due to loss of forced drywell

cooling) automatically changed

upon receipt of a

FAZ signal.

Instruments to be used before

and after

a

FAZ signal

were not

described

in the

EOPs nor indicated

by labelling of the affected

instruments.

The inspectors

were concerned that operators

could not readily

determine

from instrument labeling or the

EOPs that

DM temperature

should

be obtained

from Point A01 before

a

FAZ signal,

and Point

110 after

a FAZ signal.

The licensee

agreed to evaluate this concern

and correct the

or PSTG as appropriate,

'ontrol

Room Indications

Some control

room indications were not properly labeled or

oriented.

For example, the

RCIC turbine exhaust

pressure

instrument

(used for implementing Caution

0'4 of EOP 5. 1. 1) was

lab~led with units of "PSI (pounds

per square inch)" in the

control room,

when in fact the instrument indicates

"PSIG (pounds

per square

inch gage)" units.

Also the "Shutdown Cooling

Interlocks" lights (referenced

in EOP 5.1.1, step P-7) were

unlabeled

on the desk section of the H13-P601

panel in the control

room.

c ~

The alarm annunciator (tile 2-3) for Residual

Heat

Removal

(RHR)

Pump

A Room High Differential Temperature

was located in the P601-

A2 annunciator'anel,

which otherwise annunciated

alarms for the

RHR B and

C trains.

Similarly, alarm annunciator (tile 1-6) for

RHR

B Pump. Room High Differential Temperature

was in the P601-A3

panel,

used otherwise for LPCS and

RHR train A alarms.

The inspectors

were concerned that operators

would have difficulty

locating and using indications

and alarms

due to labeling and

location inconsistencies..

The licensee

agreed to evaluate the control

room board labeling

and location concerns identified above.

Procedure

Ste

Deficiencies

Station Blackout Procedure

During one simulator scenario

(simulator scenario

1), the control

room supervisor

(CRS) ordered the control

room operator

(CRO), in

anticipation of power restoration

from a station blackout, to

place the High Pressure

Core Spray

(HPCS) control switch in "PULL

to LOCK" to prevent

an auto start of the

HPCS

pump.

The action

was ordered

because

an emergency

core cooling system

(ECCS)

initiate signal

was locked in and, since the

RPV was at pressure,

a significant pressure

reduction

may have occur

ed if the

HPCS

pump were allowed to auto re-start.

This

CRS action was not

required

by procedures.

The inspectors

concluded that it was the

correct action to take under these, circumstances.

The inspectors

were concerned that the proceduie in effect at that

time,

PPN 5.6.1, "Station Blackout," Revision 4, had no guidance

for the action described

above.

The licensee

concurred that the

operator's

action was prudent,

and should

be proceduralized.

The

licensee

was evaluating this situation since it may have affected

several

procedures

and agreed to make changes

as appropriate.

Use of Cautions

The inspectors

concluded that

PPN 5.5.11, "Alternate Control

Rod

Insertions,

Revision 2, did not contain

some cautions that would

have

been prudent to incorporate.

For example,

Step g-3,

Flowchart D, removed the instrument drain plug for CRD-PI-13.

The

void behind the plug could be pressurized

to approximately 70

psig, but no caution

was provided to the operator.

Step g-7,

Flowchart

G, stated

"remove bottom and end plugs from CRD-V-102a,

Withdraw Line Dragon Vent Valve" with no caution step concerning

the potential for the plugs to be pressurized

with contaminated

water.

0

The inspectors

were concerned that the operators

should

be al'erted

to the potential for the plug striking an operator or releasing

contaminated

water.

The licensee

agreed to insert cautions in these

support procedures

where applicable.

Residual

Heat

Removal

Procedure

The inspectors

walked down;portions of PPN 2.4.2,

"Residual. Heat

Removal

System," Revision 20,

and noted that section

5.7 (8),

"Initiating Suppression

Pool Cooling/Spray-

Loop A (B)," began

with the note "This section is

EOP related."

The inspectors

noted

that step

9 of this section stated "If necessary

to supplement

Suppression

Chamber cooling,

open

RHR-V-27A, Suppression

Pool

Spray."

Although the

EOPs did not reference this procedure,

conversations

with operators

revealed that given sufficient time

after completing steps in EOP 5.2.1 to initiate wetwell cooling,

the operators

would have referred to

PPN 2.4.2 to ensure the

adequacy of their actions.

The inspectors

were concerned that

although the

EOPs did not permit initiating wetwell spray when

only wetwell cooling was called for, the supporting procedure

allowed simultaneous

wetwell spray

and cooling.

In this instance,

the inspectors

were concerned that an operator could follow plant

procedure

PPN 2.4.2

and violate

EOP 5.2. 1.

The licensee

agreed to

change

PPN 5.2. 1 to indicate that wetwell spray was prohibited

when using section 5.7 to initiate or verify wetwell cooling while

in the

Overall the inspectors

concluded that the

EOPs (flow-charts) were

satisfactory,

but that the

ESPs required additional attention.

Knowled e and Performance of Duties

The inspectors

assessed

the operators'nowledge

of and ability to

perform the

by observing simulator scenarios,

procedure

e reviews,

operator interviews,

and

EOP walk-downs with licensed operators.

The

inspectors

concluded that the operators

knowledge of and ability to

implement the

was satisfactory.

a ~

Simulator Observations

The inspectors

observed

two crews perform two scenarios

each in

the plant referenced

simulator.

No scenarios

were repeated.

The

scenarios

were from the licensee's

scenario

bank with some

changes

requested

by the inspectors

and made by the licensee

so that

differing facets of the

EOPs could be observed.

The first crew

was

a fully licensed

crew off-shift for training.

The second

crew

consisted of two licensed senior operators

and three facility

certified, but non-licensed,

control operators.

Each crew

included

a shift technical

advisor.

I

The scenarios

that were observed

were:

Scenario

1:

A station blackout with failure of reactor coolant

isolation system

and subsequent

restoration of a diesel

generator

and off-site power.

Scenario

2:

A small break loss of coolant, accident with a failure

of one of the drywell to wetwell downcomers requiring primary

containment venting.

A concurrent fire in the reactor building

occurred with no effect on

RPV level instrumentation.

Scenario

3:

A large break loss of coolant accident with a loss of

core cooling requiring hydrogen control measures.

A concurrent

fire occurred in the reactor building with significant effect on

four level indicators (failed high due to reference

leg flashing).

Scenario

4:

A hydraulic

ATMS requiring use of level/power control.

The inspectors

observed

the following minor operator errors.

As

none of the errors

had

an effect on the mitigation strategy

or

caused

plant conditions to unnecessarily

degrade,

the inspectors

considered

them of low safety significance.

During scenario

3, the crew unnecessarily

concluded that one

channel

(MS-LR-615) of fuel zone range

RPV level

was suspect.

This conclusion

was

made

based .on an error made in the use of

attachment

7. 1 of PPM 4.12.4.1, "Fire," Revision

13.

Caution

1 of

EOP 5. 1. 1, required the use of PPM 3.12.4. 1 for evaluating the

level instrument usability.

The other fuel zone channel

(MS-LI-

610)

was correctly mar ked as suspect

(had

been failed high). The

crew thought they had no reliable indication of RPV level in the

fuel zone range.

The point was moot because

the actual

RPV level

was below indicating level for the fuel zone.

The crew correctly

commenced

primary containment flooding with all

RPV level channels

off scale low.

The inspector

was concerned that unnecessarily

concluding that level instrumentation

was unavailable could cause

a crew to unnecessarily

flood the

RPV.

The error in indicating

MS-LR-615 suspect,

by not properly implementing attachment

7.1 of

PPM 4.12.4.1,

was discussed

with the crew by the inspectors after

the scenario terminated.

During scenario

3, the control

room supervisor

(CRS) failed to

correctly observe

oxygen levels in containment.

This caused

the

CRS to erroneously

answer

"yes" for decision block H-5 for

hydrogen control in EOP 5.2.1.

Correct diagnosis

using decision

blocks H-5 and H-6 would have led to the same result, initiate

containment

atmosphere

control

{CAC).

No change in the mitigation

strategy resulted,

and

CAC was initiated.

The error

was discussed

with the

CRS by the inspectors after the scenario terminated.

During scenarios

2 and

3 the inspectors

noted differing

interpretations

of the operability of instrumentation if Caution

1

10

of EOP 5. 1. 1 (High temperatures

in instrument line areas)

was

applicable.

Section S.a of this report discusses

this issue at

greater length.

During scenario

2, the

CRO was directed

by the

CRS to initiate

wetwell sprays at 0952,

acknowledged

the order,

but failed to

carry out the order.

At 0954, the

CRS ordered the

CRO to, "Start

drywell sprays."

The

CRO replied that wetwell sprays

had not yet

been initiated (a preparatory step),

and the previous error was

discovered.

The inspectors

also noted that, particularly the operating shift

crew,

appeared

to be strong in the area of command

and control.

This was evidenced

by good communications,

good use of shift

briefs, cross

checking of operations

where possible,

and

good

understanding

and input from all members of the crew on the

mitigative strategy.

The inspectors

pointed out the errors

described

above to pertinent licensee

personnel

and considered

them all of low safety significance for the reasons

stated.

Trainin

Evaluation

The inspectors

evaluated training of operations

personnel

for the

use of the phase II EOPs.

This evaluation consisted of three

activities:

a review of PPM 5.0.10,

"Flow Chart Training Manual,"

dated April 9,

1993 (since the

EOPs take the form of flow charts,

the licensee frequently used the term Flow Chart synonymously with

EOP), walk-downs of portions of the

EOPs with licensed operators,

and observation of simulator exercises

as described

in Section

6.a.

The inspectors

determined that the requirements

in this area were

determined

by NUREG-0737,

Supplement

1, paragraph

7. l.d which

stated that the licensee shall provide appropriate training of

operating

personnel

in the use of upgraded

The inspector

observed that the training manual

(PPM 5.0.10)

was

developed

as

an information resource for individuals tasked with

the development

and presentation

of EOP training materials

and

as

a reference for individuals responsible for EOP implementation.

This manual

served to document

WNP-2

EOP implementation policies

developed

and promulgated

by the WNP-2 operations

department.

The

inspectors

noted that the 422 page training manual

addressed

each

EOP step.

The second

element of the

EOP training evaluation consisted of

control

room walk-down of portions of the

EOP flow-charts

and

supporting procedures

with licensed operators.

Based

on these

walk-downs, the inspectors

determined that the

individual operators

possessed

the knowledge

and abilities

required to properly implement the

11

The third activity in the training assessment

was the observation

of simulator exercises

with operating

crews.

Based

on these

obsess vations, with the exceptions

noted above,

the inspectors

determined that the licensed operators

demonstrated

an acceptable

level of training on the

The inspectors

concluded that operator training on the upgraded

phase II EOPs met the requirements

of NUREG-0737,

Supplement l.

Emer enc

0 eratin

Procedure

Pro rammatic Controls

The inspectors

examined licensee

procedures,

reviewed minutes of the

biannual

EOP committee meetings,

and reviewed verification and

validation documentation.

The inspectors

concluded that the licensee

had

an adequate

program for control of the

EOPs with one exception.

This exception

was

a failure to update the Graphics Display System

(GDS)

which was the licensee's

Safety Parameter

Display System

(SPDS)

(also

see Section 5.b).

The

GDS displayed

graphs of EOP curves,

plotted real

time position on the curves,

indicated

emergency action levels,

and

provided plant process

data.

Failure to update the

GDS is discussed

below as it relates to programmatic controls.

a.

Safet

Parameter

Dis la

S stem

Based

on conversations

with the licensee,

the inspectors

determined that no individual or group was tasked to assure that

the Safety Parameter

Display System

was updated

and consistent

with the phase II EOPs.

This resulted in a system that provided

out of date

and inconsistent

information to the operators.,

There

was

no procedure or mechanism to pass

EOP update information from

the

EOP group or operations

group to the software group which

maintains the

SPDS.

b.

The inspectors

concluded that the lack of communication

between

the EOP/operations

groups

and the software

group had caused

deficiencies in the

SPDS.

The inspectors

were concerned that,

although the

SPDS problems at the time of the inspection

appeared

minor, changes to the

EOPs in the future may cause

more safety

significant problems.

The licensee

agreed to deve'lop

a system to

ensure that changes

in the

EOPs would be reflected in the

GDS.

Writer's Guide

The inspectors

evaluated

the licensee

procedures

which provided

guidance for converting the plant technical

guidelines into

symptom-oriented

EOPs for WNP-2.

The inspectors

concluded that two writer's guides were used to

develop the phase II EOP network at WNP-2.

PPN 5.0.2,

"Symptomatic Emergency Operating Procedures

Writers Guide," was

used

by the operations

department to prepat e and revise the

WNP-2

phase II EOP flow-charts.

Emergency support procedures

(ESPs)

12

0

were written using the guidance provided in

PPN 1.2.2,

"Plant

Procedure

Preparation

manual."

The inspectors

observed that NUREG-0737,

Supplement

1, paragraph

7. l.c., stated that the upgraded

EOPs shall

be consistent with an

appropriate writer's guide

and this requirement

was applicable to

this area of inspection activity.

Also, NUREG-0737,

Supplement

1,

paragraph 7.2.b.(ii) defined the need for a writer's guide that

detailed the specific methods to be used in preparing

based

on the technical

guidelines;

The inspectors

compared the writer's guides to the ten

EOP flow-

charts

and twenty-two emergency support procedures.

As a result

of the review, the inspectors

determined that the writer's guides

described

the specific 'methods

used in preparing the graphic

and

text portions of the

The,inspectors

determined that the

writer's guidance

had

been applied throughout the phase II EOP

preparation.

=-The inspectors

also concluded that the licensee

met

the NUREG-0737,'upplement

1 requirements for an

EOP writer'

guide,

and that the facility writer's guide was satisfactory.

EOP verification and validation

The inspectors

evaluated

the

EOP. verification and validation

program at WNP-2.

This evaluation consisted of:

a review of (1)

PPN 5.0.3

".Emergency Operating

Procedure

Flowchart Verification,"

dated April 9,

1993,

(2)

PPN 5.0.4.

"Emergency Operating

Procedure

Flowchart Validation," dated April 9,

1993,

(3) phase II EOP

Flowchart Verification Records,

and (4) Phase II EOP Flowchart

Validation Records,

as well as

a Control

Room Walk-down of

implemented

The inspectors

observed that the objective of the

EOP verification

procedure

(PPN 5.0.3)

was to determine that consistency

had

been

maintained

between the

EOP flow-charts, the symptomatic

writer's guide,

and the

EOP technical

document.

The results of

the verification program were presented

in the phase II EOP

Flowchart Verification Records.

The verification records

included

the resolutions of problems identified on the

10 flowchart EOPs.

The inspectors

observed that the objective of the

EOP validation

procedure

(PPN 5.0.4)

was to determine if the

EOPs provided

adequate

guidance to allow the control

room crew to correctly

manage

emergency conditions relative to reactor plant control.

The validation results

were included in the phase II EOP

validation'records.

Q

NUREG-0737,

Supplement

1, paragraph

7.2.b (iii) stated that the

licensee shall provide

a description of the program for validation

of the

The inspectors

concluded that verification and

validation program for the phase II EOPs at

WNP 2, met the

NUREG-

13

0

0737,

Supplement

1 requirement

and that the verification and

validation process

appeared

adequate.

Followu

of Corrective Actions

The inspectors

reviewed licensee

actions in response

to deficiencies

identified in the

NRC inspection

conducted in 1991

as described in the

Background section of this report.

Follow-up of these deficiencies

was

tracked

as

NRC open item 50-397/91-27-01.

-a.

Closed

0 en Item 50-397 91-27-01

The inspectors

noted that the licensee,had

significantly upgraded

the phase II EOPs since the

1991 inspection.

The inspectors

observed that the licensee

had taken actions consistent with their

reply to the

1991 inspection, with the exceptions

noted below.

The inspectors

also concluded that two issues

were not completely

resolved,

but were in progress

of resolution.

These

two issues

involved Caution

1 to

EOP 5. 1. 1 and the drywell spray initiation

limit curve in

EOP 5.2. 1.

Based

on the licensee's

completed

corrective actions

and commitments identified during this

inspection,

open item 50-397/91-27-01 is closed.

Caution

1 to

EOP 6.1.1

This caution was placed in the

EOPs to prevent taking action

on

erroneous

RPV level indication 'when abnormally high temperatures

existed near instrument sensing

and reference lines.

The licensee

had numerous

pressure

sensing lines that sensed

pressure

in the

RPV and utilized

a reference

leg to provide differential pressure

for level indication.

These lines ran outside of the primary

containment to instrument racks located in the reactor building.

The licensee

had no installed temperatur e sensors

near these lines

and the concern

was that if temperature

increased

(most probably

due to a fire or high energy line break)

above saturation

temperature

in the lines, or the temperature

at which dissolved

gas would come out of solution, then the affected level instrument

would not function properly.

This concern

was identified in the

1991 inspection

and the licensee

developed

abnormal

procedures

for

Fire and High Energy Line Break conditions.

These

procedures

contained

attached

tables that the operators

could refer to which

referenced

instrument lines

and locations.

Thus

a fire in a

certain area could be determined to effect certain specified

indications.

The licensee

also specified minimum usable

levels for each instrument.

During the simulator scenario

observations

the operators differed

in their use of instruments

when Caution

1 was applicable.

Based

on questioning,

some operators

said that if Caution

1 applied to

an instrument it was out of service,

some operators

said the

instrument

was only suspect

and could still be used

as long as it

cross, checked properly with other instrumentation,

and

some

0

operators

said it could

be used for trending,

but not for specific

level values.

The inspector

was concerned that

a uniform

implementation of the caution

was not present.

The licensee

committed to provide additional training in this area.

The .inspector also noted that different crews

used different

marking on the control boards for this instrumentation.

Some used

red tape,

some

used yellow tape,

and

some yellow "stickies."

The

inspector

was concerned that non-uniformity of marking could cause

confusion

and the licensee..agreed

to evaluate

and develop

a

standard

methodology.

The inspector

observed that to implement Caution

1, the fire

brigade or an entry team of operators

had to confirm the fire or

break location.

The inspector

concluded that, if there

was no

installed local temperature

monitoring, area entry was

an

appropriate

response.

The inspector

concluded that, with the exceptions

stated,

the

licensee

had adequately justified the plant specific deviation

and

had adequately

developed

procedures

to implement the caution.

I

Dr

ell

S ra

Initiation Limit Curve

The licensee

had deviated

from the Owners'roup

guidance in

assuming

some humidity in the drywell while developing this curve,

whereas

the Owners'roup

assumed

no humidity.

This provided

a

slightly larger safe operating

area (less conservative)

than the

Owners'roup

curve.

The inspector noted that the

NRC had

informed the licensee that the plant specific curve should

be

submitted to the Owners'roup for approval.

The inspector

reviewed the licensee

submittal for this curve which was dated

August,

1990 and found that the curve,had not been

approved

as of

this inspection period.

The licensee

informed the inspector that

the Owners'roup

had placed

a low priority on the request

and

that they would continue to attempt to have the curve approved.

Given that the licensee

seemed to be making

a good faith effort to

have the curve approved,

the inspector considered this adequate.

Res

onse to Ins ection

Re ort 50-397 91-27

The inspector reviewed Inspection Report 50-397/91-27,

NRR's

evaluation of the licensee's

response,

and the phase II EOPs.

The

inspector

concluded that, with four identified exceptions,

the

licensee

had taken appropriate

actions to either change the

or strengthen justifications.

The licensee originally planned to retain two deviations to the

Owners'roup

guidance

but later changed the

EOPs to be consistent

with the Owners'roup

guidance.

These involved the use of steam

cooling override

and criteria to be used to initiate wetwell

15

r

0

spray.

The inspector considered that these

changes

were

satisfactory.

The licensee originally indicated that they intended to add

a step

to

EOP 5.3. 1 to operate

secondary

containment

HVAC if the

HVAC

isolation signal clears.

The licensee

had not done this.

The

licensee

agreed to evaluate

adding this

step.'he

licensee

stated in their original response that the

Owners'roup

intended to continue primary containment venting, if.it was

in progress,

even if the radiation levels off-site were high while

in

EOP 5.4.1, "Radioactivity Release

Control."

The licensee

presented

the inspectors;

after the exit meeting, with EPG issue

number

8902 which proposed

a change to the Owners'roup

guidance

in this area.

EPG issues

were submitted

by various facilities to

steering

committees of the Owners'roup,

for resolution

by the

steering

committee.

The inspector noted that the resolution of

this

EPG issue

was to recommend

a change to the Owners'roup

guidance to maintain primary containment venting,

even if off-site

radioactive release

rates

were high,

as long as

a distinction was

made

between

normal venting and purge,

and venting regardless

of

off-site release

rates.

The inspectors

concluded that if the vent

was necessary

to preserve

primary containment integrity then it

should

be continued,

otherwise it should

be stopped.

The

'inspectors

noted that step

R-2 of EOP 5.4.1 appeared

to make no

distinction as to the reason the vent may be in progress.

The

inspectors

were concerned that

a vent that allowed off-site

release

rates to be high (in excess of License limits), and was

not necessary

to preserve

primary containment integrity, appeared

to be allowed by the existing

,The inspector also concluded,

however, that operator training would prevent this; but that the

clarity of'this particular procedural

step deserved further

assessment

by the licensee.

To document licensee

changes

in plans for the

EOPs', the licensee

agreed

to submit

a letter to the

NRC revising responses

to the

1991 inspection

as appropriate.

Conclusion

The inspectors

concluded that the licensee's

EOPs were satisfactory to

mitigate events

and appeared to be much improved from 1991.

The

inspectors

also concluded that the Emergency Support Procedures

were

adequate,

but appeared

to require further attention to eliminate

unnecessary

complications for the operators.

Mith the exception of

updating the

SPDS software, the licensee's

programmatic controls

appeared to be satisfactory.

Errors

and deviations identified did not

appear to affect proper implementation of the

EOPs,

but did reveal

a

need Nor the licensee to continue to identify and correct procedure

16

The inspectors

met with licensee

management

representatives

periodically

during the report period to discuss

inspection status.

An exit meeting

was conducted with the personnel

denoted

in Section

1 on February

18,

1994.

The scope of the inspection

and the inspectors'indings,

as

described

in this report,

were discussed

with and acknowledged

by the

licensee representatives.

The licensee

did not identify as proprietary any of the information

reviewed

by or discussed

with the inspectors

during the inspection.

17

A~AT

DOCUMENTS REVIEWED

NED0-31331,

BWROG Emergency

Procedures

Guidelines,

Rev.

4

EOP Technical

Document,

Rev. 0,

Amendment

1

EOP Technical

Memoranda,

Rev.

2

PPM 13. 1. 1, Classifying the Emergency,

Rev.

19

EOP 5.0.10,

Flowchart Training Manual,

Rev.

0

EOP 5.1.1,

RPV Control,

Rev.

9

EOP 5.1.2,

RPV Control - ATWS, Rev.

9.

EOP 5. 1.3,-

Emergency

RPV Depressurization,

Rev.

13

EOP 5.1.4,

RPV Flooding,

Rev.

2

EOP 5.1.5,

Emergency

RPV Depressurization - ATWS, Rev.

1

EOP 5.1.6,

RPV Flooding - ATWS, Rev.

1

EOP 5.1.7,

Primary Containment

Flooding,

Rev.

0

EOP 5.2.1,

Primary Containment Control

EOP 5.3. 1,

Secondary

Containment Control, Rev.

10

EOP 5.4.1,

Radioactivity Release

Control,

Rev.

8

PPM 3.3. 1,

Reactor

Sct am,

Rev.

16

PPM 2.4.2,

Residual

Heat Removal

System,

Rev.

20

ESP 5.5.3,

Fire Water to Condensate

Crosstie,

Rev.

3

ESP 5.5.5,

Overriding RCIC Low RPV Pressure

Isolation Interlocks,

Rev.

4

ESP 5.5.7,

Reopening the MSIVs to Reestablish

Main Condenser

as

a Heat Sink,

Rev.

3

ESP 5.5.8,

Alternate Boron Injection,

Rev.

4

ESP 5.5. 11, Alternate Control

Rod Insertions,

Rev.

2

ESP 5.5. 15,

Emergency Drywell Venting, Rev.

3

ESP 5.5. 16,

Emergency Drywell and Wetwell Purging,

Rev.

4

ESP 5.5.20,

Emergency Wetwell Venting with High Hydrogen

and Oxygen

Concentrations,

Rev.

3

ESP 5.5.24,

Overriding Drywell Cooling Isolation Interlocks

and Maximizing

Drywell Cooling,

Rev..

1

ESP 5.5.25, Alternate Injection Using the

SLC System,

Rev.

1

ESP 5.5.27,

RB 422 Max Safe Operating

Level Measurement,

Rev.

1

SBO 5.6. 1,

Station Blackout (SBO),

Rev.

2

Calculation No. NE-02-84-33,

Secondary

Containment Control

EOP Gale.,

Rev.

2

Calculation

No. NE-02-89-27,

Primary Containment

Pressure

and Level Limits-

EOP Gale.,

Rev.0

Calculation No. NE-02-89-23, Drywell Spray Initiation Limit-

EOP Gale.,

Rev.

1

PPM 4.12.4.1,

Fire,.Rev.

12

PPM 4.12.4.1.A,

High Energy Line Break,

Rev.

3

PPM 2.4.2,

Residual

Heat

Removal

System,

Rev.

20

~

1

0

A~EEA IIIIEAE

DEFICIENCIES OBSERVED

The inspectors

noted the following examples of inadequate

deviation

justifications.

a ~

b.

c ~

d.

A

EPG Caution ¹6 stated that cooldown rates

above

t100 deg F/hr

(RPV

C/D rate

LCO)] may be required to accomplish the associated

step.

The

PSTG discarded

the cautionary verbiage

and employed the

phrase,

"Disregard cooldown rate."

The justification was that the

EPG words were not really a

caution, rather

an instruction.

Concern - The inspectors

concluded the

EPG caution would alert

operators to potentially adverse

consequences

'to the Reactor

Pressure

Vessel,

such

as catastrophic

cracking with potential

leaking,

and should

be included in the

EOP.

The licensee

agreed to, evaluate this concern.

EPG Step RC/P-2 concerned

employing High Pressure

Coolant

Injection (HPCI) with suction from the Condensate

Storage

Tank

(CST).

The

PSTG deleted the HPCI system

{from EOP 5. 1. 1, table 4).

The justification, in the

PSTG, stated,

"MNP-2 does not utilize a

HPCI sys em.", but later stated,

"The function performed

by the

HPCI system -is achieved

by the .High Pressure

Core Spray

(HPCS)

system."

Concern - HPCS was

an

"ON/OFF" system with flow of approximately

1500

gpm only,

and was not suitable for use

as

a pressure

control

system.

The inspectors

concluded the

HPCS capability was

inconsistent with intent of the

EPGs

and it was proper 'to delete

the

HPCS system

from Table 4, but this inconsistency

was not

stated.

The licensee

agreed to clarify the justification.

The

EPG required implementation of Alternate

Rod Insertion methods

for an Anticipated Transient Mithout Scram

(ATMS) condition.

The

PSTG employed

one method if, "All Blue Scram Valve Lights

On

(Hydraulic/Air)"

The

EOP employed the same method if, "All Blue Scram Valve Lights

On {Hydraulic)"

Concern - The inspectors

noted the difference

between the

PSTG and

the

EOP concerning the potential

rod insertion problem,

and

concluded in this instance the

EOP and

PSTG were not consistent.

During the. inspection,

the licensee

determined the

EOP was correct

and agreed to revise the

PSTG accordingly.

The

EPG for Secondary

Containment Control included

an Entry

Condition,

"A floor drain sump water level

above the max normal

operating water level."

The

PSTG deleted the Entry Condition.

~ 4

1I

k

e.

The licensee justification stated,

"floor drain sumps

do not'have

max normal operating water levels.", but then went on to state,

"Each

sump has

an alarm which sounds

before the specified area

water level alarms

are reached".

The inspectors

concluded that

such alarms are usually associated

with exceeding

maximum normal

operating water levels.

WNP-2 used

an Alarm Response

Procedure

(ARP)

as the first level of response

before entering the 'EOPs

on

high reactor building water level

.

Concern - The inspectors

noted the

EOP entry condition for EOP

5.3. 1, "Secondary

Containment Control,"

was water level 6" above

floor level.

The inspectors

concluded that this appeared to be

inconsistent with the intent of EPGs.

The inspectors

concluded

that

WNP - 2 had not assured that the

same level of response

would

be afforded

a floor drain sump alarm with an

ARP as with the

EOP.

The licensee

agreed to evaluate this concern.

Step P-5 and P-6,

EOP 5. 1. 1, employed pressure

and temperature

icons (colored scales)

with red coloration above the set point,

but white below.

Steps I-4 and L-7 employed level icons with red

coloration:above

the set point, but green

below.

The Writer'

Guide required the latter coloration pattern in the icons on'ly.

The inspectors

noted that

EOPs should consistently

implement the

requirements of the Writer's Guide.

The licensee

agreed to correct the condition with the next

revision, currently scheduled for July 1994.

The following inspector observations

demonstrated

poor availability of

some emergency

mater ials.

PPM 5.5.8, "Alternate Boron Injection," Rev. 4, section 4.2

contained

steps for injecting boron via the Reactor Water Cleanup

System

(RWCU).

Step

3 required nine barrels of borax and nine

barrels of boric acid

be delivered to the 467 foot elevation of

the Radwaste Building next to the

RWCU precoat.tank

from Warehouse

3, Building 78,

Bay G.

The inspector

was concerned that this

delivery would have required

a lift from the 437'evel truck bay

(including opening

a door) with a non-vital

powered overhead

crane.

The licensee

agreed to consider the storage of the materials in

'he

Rad-Waste building near the intended

use.

b.

PPM 5.6.1, "Station Blackout (SBO)," Rev. 2, section 5.0, step 5,

stated,

"Maintain CN-V-65 open with a gas bottle per

PPM 2.8.2."

The inspectors

noted that

PPM 2.8.2 was not listed as

a required

material to perform

PPM 5.6.1 in the Required Material section of

PPM 5.6.1

(each

Emergency Support Procedure

had

a Required

Materials section).

The inspectors

concluded that an operator

could respond to CN-V-65 to perform this evolution and not possess

all the material

necessary

to perform this evolution because

PPM

2.8.2 was'not listed as required material.

The inspectors

noted

that another

procedure that required maintaining CN-V-65 open with

a gas,bottle,

PPN 5.5. 16,

"Emergency Drywell and Wetwell Purging,"

contained the steps to maintain CN-V-65 open with a gas bottle

directly in the body of the procedure

and did not reference

PPN

2.8.2.

Thus the inspectors

were concerned

both that

PPM 2.8.2 was

not listed

as

a required material in PPN 5.6. 1 and that

PPN 5.6. 1

was written inconsistently with PPN 5.5. 16.

The licensee

agreed to revise

PPN 5.6.1.

The. following examples

were observed

by the inspectors

where control

. room (CR) instruments

were not available,

not labelled, or had

inconsistent

nomenclature.

a ~

b.

Several

instrumentation differences

existed

between the simulator

in use at the time of this inspection

and the Control

Room (CR).

Recent modifications to the

CR instrumentation

had not been

implemented in the simulator.

The licensee

had not modified the

simulator in expectation of installation of a new simulator.

Delivery of the "new" simulator had

been delayed.

The inspectors

noted that the

same parameters

were displayed in the simulator

and

the

CR, but that the instruments

used for indication were, in many

cases,

digital in the

CR and analogue in the simulator.

The

inspector interviewed operators

who stated that they were not

confused

by the differences in displays

between the control

room

and the simulator.

The inspectors

noted that the licensee

was in

progress of installing the new simulator

and considered this

approach

adequate.

The inspectors

noted that no control

room instrumentation existed

that could measure

drywell temperature

above

400 F.

EOP 5. 1.1

"RPV Control," Caution 1, which was placed in the

EOPs to prevent

taking action

on erroneous

RPV level indication, contained

a

saturation

curve that ranged

from 200

F to 550 F.

Caution

1 of

EOP 5.1.1 disallowed the use of any

RPV level instrumentation if

drywell temperature

was above

RPV saturation

temperature.

The

inspectors

were concerned that Caution

1 of EOP 5. 1.1, with

drywell temperatures

above

400 F, would be difficult to implement

as written because

of this lack of ability to measure

drywell

temperatures

above

400 F.

This was

because

the operators

could

not utilize the portion of the saturation

curve above

400 F.

The

inspectors

considered this of low safety significance since

conversations

with operators

revealed that they would assume,

as

temperature

went off-scale high (above

400 F), that all level

instruments

were affected

by caution

1 of EOP 5.1.1.

The

inspectors

concluded that this was

a proper response.

The inspectors

observed the following examples of procedural

weaknesses

that could complicate accident mitigation or plant recovery.

a ~

A generic condition was noted in several

support procedures

that

required actions of both

CR operators

and equipment operators

3

0

(EOs).

In some cases,

the procedure listed which operator

had to

take the action; other procedures

did not.

In some procedures,

a

portion of the procedure

would identify which operator would take

the action, but later in the

same procedure,

the identification of

which operator

was to take action was not listed.

An example of

this situation

was observed

in PPN 5.5.3, "Fire Mater to

Condensate

Crosstie,"

Rev. 3.

The inspectors

noted that this inconsistency

could cause

delay in

operator response, during events

because of operator confusion

about

who would perform the action

and from where the action was

directed.

The licensee

agreed to evaluate the

ESPs for a consistent

action

direction methodology.

Steps

P-7 and P-8,

EOP 5. 1. 1, stated,

"WHEN RHR shutdown cooling

interlocks can

be reset, start shutdown cooling,

PPN 2.4.2, with

RHR pumps ... ".

The inspectors

noted that the shutdown cooling

interlocks could be reset at any

RPV pressure

less than

135 psig.

The inspectors

also noted that the "Precautions

and Limitations"

section of PPN 2.4.2,

"Residual

Heat Removal

System,"

Rev.

20,

paragraph

4. 14, required that shutdown cooling not be initiated

until

RPV pressure

decreased

to approximately

20 psig.

The

inspectors further noted that cautions in the main body of PPN

2.4.2,

such

as section

5. 13, stated

"Shutdown cooling initiation

above

48 psig may cause

damage to the

RHR heat exchanger

and pipe

supports

due to pressure/thermal

stresses."

The inspectors

were concerned that the

EOP guidance to initiate

shutdown cooling when shutdown cooling interlocks could be reset

(below 135 psig)

was not consistent with the guidance in PPN 2.4.2

that shutdown cooling should not be initiated above

an