ML17291A829

Public Power Supply System

3000 George

Way

P.O.

Box 968,

MD 1023

Richland,

Facility Name:

Nuclear Project-2

(WNP-2)

Inspection At:

WNP-2 site near Richland,

Operability determinations

Inspection

Conducted:

March 6-27,

1995, with further inspection

in the

NRC

offices through

June I,

1995

Inspectors:

W.

D. Johnson,

Chief, Project

Branch

A

J.

F. Ringwald, Senior Resident

Inspector

W.

C. Walker, Resident

Inspector

Approved:

wig t

.

C

am er ain,

C ie

,

roJect

Branc

Date

Ins ection

Summar

Areas

Ins ected:

Special,

announced

inspection of recent operational

events,

control

room operations,

and various operational

areas.

In addition", followup

of Augmented

Inspection

Team Report 50-397/95-13

was performed in the

NRC

offices.

Results:

Teamwork between

departments

was lacking'perations

was not

a

demanding

customer,

but more of a service organization.

Information

exchange

between

departments

was ineffective in some

cases

and

inefficient in other cases.

Teamwork within operations

was inconsistent.

Operators

performed

actions without informing other crew members.

Communications

in the

control

room were complicated

by the background

noise level.

Crew

briefings prior to plant evolutions

were

used inconsistently

by

different crews.

9506i200i8 950602

PDR

ADQCK 05000397

8

PDR

0

~

The control

room supervisor

was unable to devote his full attention to

oversight of operators.

His desk faced

away from the reactor operators

He was overburdened

with maintenance

coordination

and other

administrative duties during the day shift.

~

Attention to detail, self-checking,

and

independent verification all

need significant improvement,

as indicated

by numerous

examples.

~

Implementation of the clearance

order program

needs

immediate

improvement.

Corrective actions for incidents

have

sometimes

been

narrowly focused.

Repetitive errors

have not been

taken seriously

by

the plant staff or by management,

leading to the chance of more errors,

possibly resulting in personnel

injury or equipment

damage.

~

Some events

have not been thoroughly evaluated.

Examples

include the

lock seal

which was missing

from a service water valve, repetitive

clearance

order problems,

and the failure to initiate

a problem

evaluation

request for the half-scram of February

23.

~

Schedule

pressure

may have contributed to certain events,

such

as the

failure by instrumentation

and control personnel

to properly restore

the

main steam

leakage control

system

instruments

and the

mode change with

an inoperable

vacuum breaker.

~

need

improvement.

The improper operability

determination for an intermediate

range monitor had

no sound technical

basis

and indicated

a lack of a questioning attitude

by operators,

engineers,

and management.

~

The work control process

did not properly support operations.

The

process

did not adequately

control the status

of the main steam

leakage

control

system.

During the spent fuel pool cooling system outage,

operations

was in the position of expediting maintenance

work.

The many

control

room deficiencies

and operator work-arounds

indicate

a lack of

priority on these

items.

Summar

of Ins ection Findin s:

Ten apparent

v'iolations were opened:

397/9507-01

(Section 3.1)

397/9507-02

(Section 3.3)

397/9507-03

(Section 3.4)

397/9507-04

(Section 3.5. 1)

397/9507-05

(Section 3.5.3)

397/9507-06

(Section 3.6)

397/9507-07

(Section 3.7.1)

397/9507-08

(Section 3.7.2)

397/9507-09

(Section 3.8)

397/9507-10

(Section 3.8).

Attachment:

Attachment

Persons

Contacted

and fxit Meeting

DETAILS

1

PLANT STATUS

The plant'was

operating

at power during the March 6-14,

1995, on-site

phase of

this inspection..

2

BACKGROUND

A number of events

occurred during the first 2 months of 1995 at

WNP-2

involving operators

and plant operation.

Since the

NRC staff places

very high

importance

on the proper conduct of operations,

this reactive inspection

reviewed

a number of these

events

in detail,

in order to determine if common

causes

existed

and, if so,

what that meant with regard to the proper conduct

of operations

at WNP-2.

In addition, this inspection

evaluated

operations

and

operational

interfaces.

After the on-site

phase of this inspection,

an

operational

event occurred

on April 9,

1995.

An Augmented

Inspection

Team was

dispatched

to review the facts surrounding

the improper operation of the

reactor water cleanup

system

by

a control

room supervisor.

The

NRC Office of

Investigations

also conducted

an investigation of the event

because

of the

potential willful nature of the apparent

procedure violation involved.

3

FOLLOWUP OF

EVENTS

3. 1

Im ro er 0 eration of Reactor

Water Cleanu

S

salem

On April 9,

1995,

the

WNP-2 plant staff were conducting operations

to prepare

the facility for restart following a plant trip which had occurred

on April 5.

At approximately

1:45 a.m.,

the control

room supervisor

opened

Valve RWCU-V-31,

a bypass

valve around

the reactor water cleanup

system

letdown line flow restricting orifice.

The valve was operated

in such

a way

that the valve position indication indicated that the valve was closed.

The

valve was

open sufficiently to allow approximately

10-20 gallons per minute

flow through the valve to help control reactor vessel

level.

Reactor coolant

system pressure

was approximately

215 psig when the valve was initially

opened.

The system operating

procedure

contained

a caution that prohibited

opening

Valve RWCU-V-31 when reactor coolant

system pressure

was

above

125 psig.

This statement,

in

a box before Section 5.7,

Step

10, of

Procedure

2.2.3,

"Reactor Water Cleanup

System,"

Revision

20, stated

"CAUTION:

RWCU-V-31 shall not

be

open with Reactor pressure

GT [greater than]

125 psig,

to prevent overpressurization

of the

RWCU blow down piping."

A reactor

operator questioned

the control

room supervisor

regarding this action for two

reasons.

First.,

the operator felt that the supervisor manipulating the

controls

was contrary to management

expectations

regarding

supervisory

responsibilities.

Second,

he pointed out that operation of this valve was in

violation of the procedure

caution statement.

A second on-shift reactor operator

became

involved in the discussions

regarding

the plant conditions for operation of the bypass

valve.

Following a

discussion

between

both operators

and the supervisor,

the control

room

supervisor

twice consulted with the shift manager.

The supervisor

returned to

the control panels

and stated that the bypass

valve would remain open.

The

action

was not logged in the Control

Room Operator's

Log by any of the control

room operators.

Contrary to operations

program processes

and controls,

a

procedure'deviation

was not written, nor was

a problem evaluation

request

(PER) generated

by any of the control

room operators

to identify the

nonconformance

with procedures.

One of the operators

contacted

both the Nuclear Safety

Issues

Program

(employee

concerns

program)

and the assistant

operations

manager

on April 10,

1995,

about the apparent

procedure violation.

The licensee

started

an

investigation of the event

on April 10,

1995, after the assistant

operations

manager initiated

a

PER.

Following its initial investigation,

the licensee

removed

both the control

room supervisor

and the shift manager

from licensed

duties

and requested

in

a letter dated April 20,

1995, that the

NRC withdraw

the operator licenses for both individuals.

After reviewing the findings of the Augmented

Inspection

Team

and the

investigation report

(Case

Number 4-95-018) of the

NRC Office of

Investigations,

the inspectors

confirmed that action of the control

room

supervisor

in allowing Valve RWCU-V-31 to remain

open contrary to the caution

statement

before Section 5.7,

Step

10, of Procedure

2.2.3,

"Reactor Water

Cleanup

System,"

Revision

20,

was

an apparent deliberate violation

(397/9507-01).

3.2

Reactor

Over ower Event

On January

26,

1995, at 2:55

pm,

a reactor operator discovered

that reactor

power reached

3333 megawatts

thermal, slightly greater

than the licensed

power

limit of 3323 megawatts

thermal.

The licensee

determined

the cause of the

overpower excursion

to be the failure of licensee

personnel

to manually

initiate the Eight-Hour Average Calculation

Program following scheduled

maintenance

on the advanced

neutron noise analysis

(ANNA) backup computer.

At

the conclusion of the maintenance,

technicians initially failed to properly

restart

the

ANNA backup computer.

This caused

the

ANNA computer to stop

functioning at approximately 9:40 a.m.

The technicians

subsequently

succeeded

in restarting

both computers;

however,

they did not

know that the restart

process

failed to restart

the Eight-Hour Average Calculation

Program.

This

caused

the date/time

stamp

and certain portions of the overview display to

display outdated

information from the time the

ANNA computer

stopped.

The

overview display presented

more than

70 pieces of information related to

reactor operations.

The top left section of the display contained six columns

of data representing

the 1-minute,

15-minute, l-hour, 4-hour, 6-hour,

and

8-hour displays of core power,

percent

power,

core flow, percent

core flow,

generator

output,

and the begin time for the averaging interval.

While the

1-minute average

power display continued to provide accurate

information, the

15-minute,

I-hour, 4-hour, 6-hour,

and 8-hour columns displayed

outdated

information

A second

computer display of reactor

power, called the real

time graphic

display of power level,

was located at the shift engineer's

desk.

This

display presented

a trend line of instantaneous

reactor

power in green lines

when reactor

power was below,

and in red lines

when above,

100 percent

power.

This display,

including the date/time

stamp,

also stopped

updating

when the

ANNA and

ANNA backup

computers

stopped.

After shift turnover,

the reactor operator

noted that the 1-minute average

power indication indicated

a higher power level than normal.

The operator

initiated

a computer

power trend display different than the display most other

reactor operators

used.

This display indicated that the reactor

was operating

at above

100 percent

power.

The operator

immediately initiated

a

recirculation

pump flow reduction to reduce

power.

During interviews with the

operator,

the inspectors

learned that this immediate action occurred prior to

the reactor operator notifying the control

room supervisor or anyone else in

the control

room of the problem.

The inspectors

concluded, that the operator's

action without informing other crew members

was

an example of weak operations

crew communications

and teamwork.

The licensee initiated

PER 295-052

and

formed

an incident review board to

evaluate

the event.

The licensee

determined that this event

stemmed

from two

root causes.

The first was the failure of the overview display to clearly

indicate

when

a partial loss of operability exists.

The second

was the

failure of operators

to recognize that the expected

response

was not obtained

following recirculation flow changes

intended to increase

reactor

power.

During the

PER investigation,

the licensee

determined that the reactor

operator

attempted

to increase

reactor

power slightly and noted the expected

change

in the 1-minute average

display but no change

in the other longer time

averages

of reactor

power.

The operator discussed

this concern with the shift

engineer

who looked at the "frozen" indications

on both the real time graphic

display of power level

on the shift engineer's

desk

and the overview display

at the reactor operator's

desk

and assured

the reactor operator that the

indications

were satisfactory.

The only completed corrective action

as of

March 13,

1995,

was

an operations

manager briefing regarding plant inputs

and

responses.

The licensee

scheduled

the remaining corrective actions to be

complete

by June

1,

1995.

These

included

a modification to the overview

display

and system health display, revision to the shift engineer

qualification to include more computer training, additional evaluations,

completion of Minor Modification 93-0273 to add additional monitoring at the

control

room supervisor station,

requiring the printing and verification of

the overview display

as part of the daily status

package

and shift turnover,

formalization of responsibilities

and procedures

to shutdown

and reboot the

ANNA computers,

and replacing

memos

and other informal instructions to the

shift engineer with official instructions.

The i'nspectors

concluded that the magnitude of the overpower event represented

no safety concern.

The inspectors

further concluded that the reactor operator

and shift engineer

were inattentive to the computer displays

at their

operating stations.

The inspectors finally concluded that the licensee's

PER

investigation

and corrective actions

were adequate.

3.3

Service

Water Valve Not Pro erl

Lock-Sealed

On February

7,

1995,

the inspectors

found that SW-V-128A,

a throttle valve in

the service water line to the containment air cooling aftercooler,

was not

lock-sealed

in the throttled position

as required

by licensee

procedures.

The

inspectors

noted the broken lockwire seal

near the valve handwheel.

The

inspectors notified the shift manager,

who initiated

PER 295-0087.

Following notification of this deficiency,

the licensee

took immediate

corrective action to return to full compliance.

The licensee

placed

a

new

lock seal

on the valve.

The licensee

performed

Sur'vei llance

PPM 7.4.7. 1. 1. 1,

"Standby Service

Water Loop A Valve Position Verification," Revision

18,

verified Valve SW-V-128A to be locked-sealed

in its throttled position

and

found no additional discrepancies.

To attempt to quickly identify the

apparent

root cause of this event,

the licensee

checked

clearance

orders

and

work orders

and found no documented

evidence that the valve had

been

repositioned

or the lockseal

cut.

The licensee

performed

no further

investigative actions

by the

end of the inspection period.

Surveillance

PPM 2.4.5,

"Standby Service

Water System,"

Revision 26,

Attachment 6. 1 required the position of Valve SW-V-128A to be throttled per

Surveillance

PPM 7.4.7. 1. 1. 1.

Paragraph

7.2,

Step

7, of this procedure

required personnel

to verify that Valve SW-V-128A was 'sealed

in the throttled

position foll'owing final flow adjustment.

The failure to maintain Valve

SW-V-128A lock-sealed

in its throttled position is

an apparent violation of

Technical Specification 6.8. 1

(397/9507-02).

On January

30,

1995,

the inspectors

noted that the licensee initiated

a

troubleshooting

plan

on Valve CAC-TCV-4A, downstream of Valve SW-V-128A.

Following the troubleshooting

plan,

the licensee

repaired

Valve CAC-TCV-4A,

per Work Order Task

(WOT) TF9101.

When the maintenance

was complete,

the

licensee

performed surveillance

procedures

to verify proper operation of the

containment air cooling system,

including service water flows through the

system.

The inspectors

also noted that the licensee

had not interviewed

any

of the personnel

involved in performance of the troubleshooting,

repair,

or

retesting of Valve CAC-TCV-4A.

The inspectors

concluded that the likely cause of the event

was improper

restoration

from maintenance

or testing of Valve CAC-TCV-4A.

The inspectors

also concluded that the licensee

had not performed

a sufficiently thorough

investigation into the root cause of the event.

Since this valve was in the

immediate vicinity of maintenance activities, the inspectors

further concluded

that operations failed to ensure that the system

was properly restored

following extensive

maintenance.

The inspectors finally concluded that, while

this event

had minor technical

safety significance, it was considered

potentially significant because it indicated t hat the licensee

did not

adequately

evaluate

the root ca'use

and, therefore,

could not effectively take

corrective actions to prevent recurrence.

3.4

Valve Not in Position

Re uired

b

Clearance

Order

On February .8,

1995,

the resident

inspectors

noted that the control

room

handswitch for Containment Air Cooling Valve CAC-FCV-4A was in the

AUTO

position.

At the time, Clearance

Order 95-02-0005

was in effect.

Tag

1 of

this danger clearance

authorization

required

the valve handswitch to be in the

closed position

and

was attached

to the handswitch.

A licensed operator

had

attached

the clearance

tag to the handswitch.

An equipment operator

had

independently verified that the operator properly attached

the tag

and that

the handswitch

was positioned

as required

by the clearance

order.

The

operators'ailure

to position the handswitch

as required

by the clearance

order is

an apparent violation of Technical Specification 6.8. 1 (397/9507-03).

The licensee initiated

PER 295-090 to review this event.

The permanent

disposition of the

PER was

approved

on March 4,

1995.

The evaluation

concluded that the event

was caused

by failure to self-check

and inattention

to detail.

Corrective actions

included counseling of the involved operators

and placing letters

in their files.

The individuals were coached

on the

management

expectations

for implementing clearance

orders

and the potential

consequences

of clearance

order errors.

Although the resolution

noted that

there

was generic

impact in that self-checking errors continue to be

an issue

in the operations

department,

no generic corrective actions

were proposed

by

the licensee for this event.

In view of the fact that clearance

order errors

continued to occur at

an elevated

frequency after this event,

the team

concluded that licensee

management

missed

an opportunity to take effective

generic corrective action.

The inspectors

concluded that the failure of operators

to position the

handswitch

in the position required

by the clearance

order represented

inattention to detail.

In addition,

the failure of the equipment operator to

identify the error represented

a failure of the independent verification

process.

The inspectors

further concluded that the failure of operators

to

properly implement the clearance

order represents

a real potential for a

serious

personnel

injury or significant damage to safety-related

equipment

as

a result of a clearance

order error.

The inspectors finally concluded that

the management

response

to this error, which included rationalizing the event

as insignificant based

on duplicate protection

from fuse removal

and excluding

any generic corrective actions,

indicated

an attitude where clearance

order

errors

were not considered

seriously

and

a certain level of such errors

was

tolerated.

3.5

Loss of Wetwell to Dr well Vacuum Breaker Indication

On February

14,

1995, operators

entered

a 2-hour action statement

required

by

Technical Specification Action Statement

3.6.4. l.d.2, twice as

a result of

several

errors

associated

with the work control

and clearance

order process.

3.5.

1

Inadequacy of the Clearance

Order

On February

14,

1.995,

the clearance

order review committee provided Clearance

Order 95-02-0075 for electricians

to replace rear disk indication

Relay CVB-RLY-V/1EF/R3.

The clearance

required operators

to pull one fuse,

E-FUSE-VB2-TBBIF3.

After the electricians

accepted

the clearance

order

and

proceeded

to Relay Panel

VB-I, they noticed that the CVB-RLY-V/1EF Relays

R3,

R4,

R8,

R9,

and

R10 were all still energized.

The electricians

returned to

the control

room and informed the control

room supervisor.

The electricians

also indicated that they had lifted leads

on these

relays while energized

in

the past

and would not object to doing

so again.

After discussing this with

the shift manager

and the electrical

supervisor,

the shift manager

decided to

proceed with the relay replacement

with the relays still energized.

The clearance

order stated that the purpose of the clearance

order was to

remove

and replace

the position indication relay for front Disk CVB-V-1EF.

The inspectors

reviewed Drawing 22E042

and noted that it clearly showed this

relay getting

power from Fuse

F3 in Relay Panel

VBI and from Fuse

F31 in Relay

Panel

VB2.

Despite

a second

level review,

a control

room tagging reactor

operator review,

and

a control

room supervisor

review, the licensee

never

identified this error clearly.

Procedure

1.3.8,

"Danger Tag Clearance

Order,"

Revision 22,

Step

6. 11.2.a,

stated

"The Shift Manager

Ensures

the Clearance

Order provides

the safe conditions necessary

for the protection of personnel."

Step

6. 11.2.b.

stated

"The Shift Manager

Ensures

the clearance

order is

adequate

for the tasks

and hazards

involved."

The failure of the shift

manager to ensure that the clearance

order

was adequate

to remove

power from

Relay CVB-RLY-V/1EF/R3 is

an apparent violation of Technical Specification 6.8. 1 (397/9507-04).

The operators

and electricians failed to recognize

the significance of a

clearance

order that did not provide adequate

protection for the electricians.

The immediate

response

by the electricians,

that they had

and could perform

this work with the relays energized,

may have distracted

the operators

from

this concern.

It does not,

however,

explain why the operators,

electricians,

and electrical

supervisor all failed to consider this clearance

order error as

a significant problem to be resolved prior to continuing work.

The inspectors

asked

the electrician if this type of error had occurred previously.

The

electrician

acknowledged

being personally

involved in three prior instances

of

clearance

order errors during the past

5 years

and estimated that there

had

been

perhaps

a total of twice that

many in the

same time frame affecting all

electricians

in the shop.

The electrician stated that this number of

clearance

order errors

was "not that many."

The inspectors

considered

this to

be

a very high rate of clearance

order errors

and concluded that this failure

to take clearance

order errors seriously represents

a very real potential for

a serious

personnel

injury or significant damage to safety-related

equipment

as

a result of a clearance

order error.

-10-

3.5.2

Decision to Continue

Work - First Action Statement

Entry

After removing

Fuse

E-FUSE-VB2-TBBIF3, the control

room lost front disk

indication of wetwell to drywell Vacuum Breaker

1EF.-

After completing the

process

for approving electrical

work on energized

equipment,

the electricians

cautioned

the operators

that replacing this relay energized

would cause

them

to lose

vacuum breaker position indication for Vacuum Breaker

1EF.

The

operators

acknowledged this

and the electricians

proceeded

to Relay

Panel

VB-1.

Prior to de-terminating

leads

from the relay,

the electricians

contacted

the control

room and again

reminded

them that,

as

soon

as they

de-terminated

this relay,

the control

room would lose indication for Vacuum

Breaker

1EF.

Operators

acknowledged this

and agreed that they should

proceed

with the work.

The electricians

began

removing the leads for

Relay CVB-RLY-V/1EF/R3 and,

as

soon

as it was disconnected,

the control

room

lost rear-disk indication for Vacuum Breaker

1EF.

This surprised

the

operators

who had expected this action to cause

the loss of front disk

indication, which was already deenergized

by the pulled fuse.

Operators

entered

the 2-hour action statement

required

by Technical Specification

Limiting Condition for Operation

(LCO) 3.6.4.

1 for loss of both front and rear

disk indications.

The shift manager directed the electricians

to restore

the

disturbed circuitry immediately.

Since the electricians

had the relay nearly

de-terminated

and would have taken approximately the

same time to re-terminate

the original relay or terminate

the

new relay, they installed the

new relay

with the shift manager's

permission.

This restored

indication to the rear

disk of Vacuum Breaker

1EF,

and operators

exited the 2-hour Technical

Specification Action Statement

3.6.4.1.

The inspectors

reviewed the

WOT SV62

01

and noted that the completed

work ord'er documentation

failed to

acknowledge that there

had

been

a clearance

order problem despite

the fact

that the clearance

order field on the first page identified that

a clearance

order was required for this work.

The inspectors

concluded that, despite

the

discovery of a -clearance

order error in the preparation for this work,

and

despite

warnings

from the electricians that indication would be lost once the

relay was disconnected,

operators still inadvertently entered

the 2-hour

Technical Specification action statement.

The inspectors

further concluded

that communication

between

operators

and electricians relied

on inaccurate

assumptions.

The inspectors finally concluded that the operations staff had

sufficient information to have anticipated

and prevented this unnecessary

entry into the 2-hour Technical Specification action statement

but failed to

evaluate this information sufficiently to understand

the impact

and failed to

request

adequate

support

from the work planning organization

to prevent the

action statement

entry.

3.5.3

Independent

Verification Error

Later the

same

day,

the clearance

order review committee provided Clearance

Order 95-02-0076,

which correctly specified

the proper fuses to deenergize

Relay CVB-RLY-V/1EF/R4.

As operators

hung this clearance,

they first removed

,

Fuse

E-FUSE-VBI-TBIAF3, which deenergized

the relays for the wetwell to

drywell Vacuum Breaker

1EF rear-disk indication.

When operators

attempted

to

remove

Fuse

E-FUSE-VB2-TBBIF31, they removed

Fuse

E-FUSE-,VB2-TBBIF3-1 instead,

0

-11-

which deenergized

the relays for the

Vacuum Breaker

1EF front-disk indication.

When the inspectors

questioned

the operator

who pulled the wrong fuse,

the

operator

said that the labeling

was poor, but they believed that they had the

right fuse

because

the labelling suggested

a pattern

not clearly marked.

The

operator also stated that,

because

of the close similarity between

F31

and

F3-1,

they assumed

that the labeling

was incorrect

and that they.had

identified the correct fuse.

Operators

again entered

the 2-hour action

statement

required

by Technical Specification

LCO 3.6.4.

1 for loss of both

front and rear-disk indications.

The shift manager

contacted

the operators

hanging the clearance,and

directed

them to restore

the fuse.

This again

restored

indication to the front disk of Vacuum Breaker

lEF,

and operators

exited the 2-hour Technical Specification Action Statement

3.6.4. 1.

The

inspectors

concluded that the failure of operators

to stop

and clarify their

questions

regarding

whether they were pulling the correct fuse represented

a

willingness to rely on conjecture

and

an unwillingness

on the part of the

operators

to take the time to resolve their questions prior to proceeding with

hanging the clearance.

Procedure

1.3.8,

Step 6. 12.2.c,

required the operators

to resolve the difference

between

the

name or label

on the clearance

order

with the equipment field label with the shift manager

before

hanging the tag.

The failure of the operators

to resolve this difference prior to removing the

fuse is an apparent violation of Technical Specification 6.8. 1 (397/9507-05).

The operations

manager,

shift manager,

and control

room supervisor

provided

similar responses

regarding mitigating factors involved in the

operators'rror.

This suggests

that operators

were not expected

to notice

and

distinguish

between

a fuse designation of F31

and F3-1.

This further suggests

that operators

were not expected

to stop

and get their confusion resolved

prior to pulling

a fuse.

The fact that operations

management

accepted

the

operators'ationalization

demonstrates

that operations

management

did not

expect operators

to perform in

a manner to prevent this occurrence.

3.5.4

Licensee

Corrective Actions

The licensee initiated

PER 295-0106

and convened

an incident review board.

The incident review board determined that the electrical

supervisor called the

control

room prior to the work to ask if the clearances

were hung.

During

this discussion,

the clearance

order reactor operator told the electrical

supervisor that the relays would be worked

one at

a time to prevent losing

front- and rear-disk indications at the

same time.

The inspectors

determined

that, if this discussion

had

been

adequately

questioning,

the problem with the

incorrect clearance

order would have

been prevented.

The incident review

board did not address

poor communication

in their conclusions

or

recommendations.

The incident review board noted that, while it did not cause

a problem in this case,

the clearance

order preparer

used

a procedure that

was

not

a top-tier drawing in the preparation

and review of these

clearance

orders.

The incident review board noted that the clearance

order procedure

required

the

use of top-tier drawings

when available,

but did not address

this

issue

in the conclusions

or recommendations.

The incident review board noted

that the clearance

order procedure

did not address

how the control

room

tagging reactor operator

was to perform the clearance

order review.

While the

-12-

incident review board stated that the cause of the event

was the Failure of

the control

room tagging reactor operator to identify the clearance

order

error,

the incident review board

recommendation

vaguely

recommended that,

expectations

should

be communicated

regarding

how to perform the second

level

review and failed to address

the procedure

inadequacy.

The inspectors

concluded that, while the incident review board identified good issues

the issues

did not get carried forward in the incident review

board conclusions

and recommendations.

The final

PER evaluation

was not

available for the inspector's

review during this inspection.

Therefore,

the

licensee's

overall corrective actions

could not

be evaluated for this event.

3.6

Turbine-Reactor Tri

due to

Im ro er Turbine Testin

On February

18,

1995, operators

selected

and held the turbine reset lever

versus

the front standard test lever, during monthly turbine valve

surveillance testing,

causing

a turbine trip and

a subsequent

reactor trip.

Plant Procedures

Manual

"Main Turbine Generator,"

Revision 23, required

operators

to hold the front standard test lever in the test position.

When

operators

performed the auto stop solenoid trip test,

the turbine tripped

causing

a reactor trip.

The licensee initiated

PER 295-0115

and convened

an

incident review board to perform

an investigation into the event.

The

NRC

inspectors

performed

a followup assessment

of this event since previous errors

in self-checking

had

been identified in other

NRC inspections.

The assessment

consisted

of reviews of the

PER

and incident review board report

and

discussions

with selected

supply system personnel.

The supply system's

investigation of this issue identified the

following:

(I) insufficient self-checking

and communication

between

the

equipment operator

and the shift support supervisor

caused

an incorrect lever

to be selected

for turbine testing, resulting in

a turbine

and reactor trip;

(2) labeling for the two levers

on the front turbine standard

was inadequate;

and

(3) participation of the shift support supervisor

in performing

a portion

of the test

removed

him from the supervisory oversight role.

Some of the

licensee's

followup actions

included:

improving the labeling for the levers;

additional self-checking training to reemphasize

sensitivity for conditions

which are believed to be routine;

addressing

expectations

of supervisory

personnel

participating in equipment manipulations;

and review all personnel

errors over the last

6 months.

The inspectors

noted that the licensee's

efforts to evaluate

the root cause of

the, turbine trip were good.

Based

on the inspectors

review, it appeared

that

a significant contributor to the turbine trip was the failure of the

supervisor to adequately

perform

an oversight function.

The inspectors

concluded that the licensee's

failure to follow

Procedure

2.5.7, specifically Step

5 of Section 5.9. I, which directs the

operator to position the Test lever for turbine testing,

was

an apparent

violation of Technical Specification 6.S.I

(397/9507-06).

-13-

3.7

Ino erable

E ui ment Durin

Mode Chan

es

The inspectors

reviewed

two recent

instances

of mode changes

being performed

without operable

systems

required

by Technical

Specifications.

3.7.

1

Main Steam

Leakage

System

During

a Mode Change

On February

21,

1995,

the licensee

identified that certain

main steam

leakage

control

system

instruments

were valved out of service

when operators

entered

Mode

2 earlier that day at 1:54 p.m.

The licensee initiated Work

Order NF-1401

on February'9

to troubleshoot

the position indication for

Excess

Flow Check Valve PI-EFC-XISA.

To facilitate troubleshooting

on

February

20, the craft supervisor initiated

a portion of Plant

Procedure

7.4.6.3.4.1B,

"Testing Excess

Flow Check Valves For Main Steam

Leakage Control," to remove

Instruments

MSLC-PIS-7A, MSLC-PIS-70A,

MSLC-PT-6A,

and

MSLC-PT-12A, from service.

The control

room log indicated that personnel

commenced

the surveillance

procedure

at 9: 12 p.m.

Test performers

placed

test-in-progress

tags

on the affected control

room indication

and annunciator.

On February

21, the original indication problem

had not been resolved

and

management

decided to terminate

the job.

Due,to communications failures,,the

day-shift craft supervisors

were not aware that the surveillance test

procedure

had

removed

several

instruments

from service.

Workers exited the

job without restoring the instruments

to service,

leaving the main steam

leakage

control

system inoperable.

At 1:54 p.m.,

Mode

2 was entered with this

system inoperable.

Operators failed to notice the open surveillance test

entry in the control

room log and the test-in-progress

tags.

This mode change

with the main steam

leakage

control

system

inoper'able is

an apparent violation

of Technical Specification 3.0.4 (397/9507-07).

The licensee initiated

PER 295-0128

on February

21.

The resolution of this

request

was not available while the

team

was

on site.

The team reviewed the

February

28,

1995, report

on this event performed

by an Incident Review Board.

This report noted several

failures to comply with administrative

and work

control procedures.

It pointed out that previously implemented corrective

actions

were not adequate

to assure

that procedures

would be followed and

recommended

additional

management

attention for additional corrective actions.

The inspectors

concluded that operators

were inattentive to operating details

in that they did not make

an entry in the Technical Specification

Equipment

Log when the surveillance test

was initiated, they performed

a mode

change without reviewing the control

room log for open surveillance test

entries,

and they failed to review control

room panel

status

and notice the

test-in-progress

tags prior to the

mode change.

The inspectors

also concluded

that this event represents

a lack of teamwork in that operations

was not

consulted to determine

the proper

sequence

for exiting the surveillance test

procedure

and craft turnovers did not communicate

the status of the

surveillance test procedure.

Operator turnovers

were inadequate

to

communicate

the status of the main steam

leakage

control

system to subsequent

shifts.

Craft personnel

and operators

did not verify proper

system

restoration

when the job was terminated.

The inspectors

further concluded

-14-

that workers did not follow the work control process

since the

use of the

surveillance test for troubleshooting

came

from the craft supervisor,

but did

not get documented

in the work order.

3.7.2

Suppression

Chamber

Drywell Vacuum Breaker

During

a Mode

Change

During

a control

room log review on February

23,

1995,

the resident

inspectors

identified that the plant transitioned

from Mode

2 to Mode

1 at 6: 19 p.m.

on

February

22.

At the time, the position indication for the rear disk of

Containment

Vacuum Breaker

CVB-V-1LM was inoperable

as the closed indication

had

been lost and the rear disk indicated

open following a power grid

disturbance

at 5:47 p.m.

The plant operators

entered

Technical Specification

Action Statement

3.6.4. I.c. at 5:50 p.m.

when panel

walkdown identified the

open indication.

The other

vacuum breaker of the pair was promptly verified

to be closed

as required

by the Technical Specifications.

These actions

were

properly logged in the control

room operator's

log.

After the

mode change,

Procedure

7.4.6.4. 1.2,

"Suppression

Chamber - Drywell Vacuum Breaker

Operability," was

commenced

at 8: 13 p.m. to close the rear disk.

The rear

disk was closed at 9:04 p.m.

and the surveillance test

was completed at

10:02 p.m.

At this time the action statement

of Technical Specification 3.6.4.1.c

was exited.

Performance

of a mode change while relying on the

provisions of Technical Specification Action Statement

3.6.4. I.c was

an

apparent violation of Technical Specification 3.0.4,

which requires that entry

into an

OPERATIONAL CONDITION shall not be

made unless

the conditions for the

LCO are

met without reliance

upon provisions contained

in the

ACTION

requirements

(397/9507-08).

The licensee initiated

PERs

295-0132

and 295-0136

on the

vacuum breaker

indication problem

and

on the improper

mode change,

respectively.

The first

PER was closed

by reference

to

PER 294-1060,

which had generated

work orders

to replace relays for the rear disk.

The second

PER was not resolved

when the

team left the site.

The team discussed

the event with the cognizant shift

manager.

Through these discussions,

the inspectors

determined that operators

entered

Mode

1 without reviewing the control

room log or the Technical

Specification

Equipment

Log.

The inspectors

were informed that the

startup

procedure

did not require operators

to review the Technical

Specification

Equipment

Log prior to entering

Mode

1.

The

inspectors

concluded that this represented

a missed opportunity for management

to communicate

expectations

which may have prevented this event.

The

inspectors

also noted that,

immediately prior to this mode change,

the

operability concerns

with intermediate

range monitors

as discussed

in

paragraph

3.8 of this report would have required the insertion of a half-scram

by 6:38 p.m. if operators

had not entered

Mode

1 by then.

Operators

were

aware of this requirement

and this

may have inserted

some

schedule

pressure

into an otherwise very busy shift

For example,

the diesel

generators

were

still running

as

a result of the earlier grid disturbance.

The inspectors

concluded that this improper

mode

change

was caused

by

inattention to detail

by the operating

crew.

Contributing factors were the

0

-15-

rapid pace of activities,

possib'je

schedule

pressure,

and failure to include

specific checks to be performed prior to mode changes

in the startup

procedure.

The improper

mode change

discussed

in Section 3.6. 1 above

had

occurred

the previous

day and operations

had

been

informed of the

PER (the

shift manager

had reviewed

PER 295-0128 at

1: 18 a.m.

on February 22), but this

previous event did not sufficiently raise

the sensitivity of operators

to

potential

mode

change

problems

to prevent this second

occurrence.

3.8

Intermediate

Ran

e Monitor 0 erabi lit

Issues

On July 22,

1994, during the startup

from the ninth refueling outage,

operators

noted erratic indications

on Intermediate

Range Monitors

E and

H,

which required repairs prior to power ascension.

Operators

again

noted

erratic indications

on several

intermediate

range monitors following the

reactor

on February

18,

1995.

Operators

used the intermediate

range

monitors to monitor and record core neutron flux levels in the intermediate

range during reactor startups

and shutdowns.

The

WNP-2 reactor design

included intermediate

range monitors to generate

a trip signal to prevent fuel

damage resulting

from abnormal

operational

transients

that

may occur while

operating

in the intermediate

power range.

The

WNP-2 reactor

design

incorporated eight intermediate

range monitors

(A

through H).

Two groups of four of the intermediate

range monitor channels

[(A, C,

E,

and

G)

and

(B, 0,

F,

and H)] provided two protection

system trip

channels,

A and

B, respectively.

WNP-2 Technical Specification 3.3. 1 applied

to the intermediate

range monitors.

The Technical Specifications

required the

reactor protection

system

(RPS) instrumentation

channels listed in

Table 3.3. 1-1 to be operable with the

RPS response

time shown in

Table 3.3.. 1-2.

Table 3.3. 1-1 required

a minimum of three operable

intermediate

range monitors per

RPS trip channel for Mode

2 and required

operators

to place

a trip channel

with fewer than three operable

intermediate

range monitors in the tripped condition within 12 hours1.388889e-4 days 0.00333 hours 1.984127e-5 weeks 4.566e-6 months .

On March 9,

1995,

the inspectors

performed

an assessment

of the licensee's

activities concerning operability and reliability of the intermediate

range

monitors.

Based

on that assessment,

the inspectors

considered

the licensee's

efforts to be less

than adequate.

After the

scram of February

18,

1995,

the licensee

performed

a followup

assessment

of operability for Intermediate

Range Monitor E,

as documented

in

PER 295-0122.

The licensee

concluded that Intermediate

Range Monitor

E was

operable

but degraded.

The licensee

reached this conclusion

because it

appeared

to operate

properly following the reactor

and passed

a channel

functional test.

On July 22,

1994,

the licensee

performed

a successful

channel

functional test

prior to the startup

from the refueling outage

because

the channel

functional

test did not check the cabling from the sensor to the preamplifier, but only

the signal

path from the preamplifier to the logic circuitry.

During the

startup,

operators

noted that all intermediate

range monitors except

E

-16-

indicated

an increasing

power level.

As

a result,

operators

declared

Intermediate

Range Monitor

E inoperable.

On July 26, the licensee

performed time-delay refractometry

on Intermediate

Range Monitor

E and located

an

open circuit at the

LEMO connector

in the

drywell.

Maintenance

personnel

had worked

on this connector during the

outage.

On July 26

and

27, the licensee

entered

the area

under the vessel

to

troubleshoot

and repair Intermediate

Range Monitors

E and

H.

After reviewing

the work scope,

the. licensee

decided

to repair Intermediate

Range Monitor H,

but decided

to not repair Intermediate

Range Monitor

E because its

LEMO

connector

was in

a high dose,

cramped, difficult-to-access

space.

Following the

on February

18,

1995,

the licensee

did not perform time-

delay refractometry

again to attempt to recharacterize

the open circuit on

Intermediate

Range Monitor E.

The licensee

considered this monitor operable

based

on engineering

judgement

(as

a result of a satisfactory

channel

functional test,

which apparently

was incapable of identifying the problem

coming out of the previous refueling outage,

and its limited operation

following the reactor

scram).

As soon

as reactor

power entered

the

intermediate

range during the startup

on February

22,

1995, operators

again

declared

Intermediate

Range Monitor

E inoperable

since it did not indicate

an

increasing

power

as did the other intermediate

range monitors.

The inspectors

questioned

the system engineers

concerning

the operability

assessment

and the basis for concluding that Intermediate

Range Monitor

E was

operable with a

known open circuit following the refueling outage.

Specifically, the inspectors

were interested

in reviewing the data the

licensee

used to support operability of Intermediate

Range Monitor E.

After

reviewing the control

room strip chart recorder traces,

the inspectors

concluded that the information provided

by the traces

would not support the

engineers'perability

determination for Intermediate

Range Monitor E.

In response

to the inspectors

questions,

the licensee

performed

a followup

review and determined that Intermediate

Range Monitor

E had

been relied

on to

meet Technical Specification

requirements

during the reactor startup

on

February

22,

1995.

The operability assessment

performed

on February

20 had

incorrectly concluded that Intermediate

Range Monitor

E was operable.

Since

another intermediate

range monitor was also inoperable

in the

same trip

system,

this was

an apparent violation of Technical Specification 3.3. 1.

(397/9507-09).

Following the

on February

26, the licensee initiated work on

Intermediate

Range Monitor

E under

WOT NF15-Ol

and discovered that the

workmanship

on the

LEMO connector

was not adequate.

The licensee

found that

the center

male electrode of the connector did not make reliable contact with

the female portion of the connector.

The licensee

concluded that this

occurred

due to the

cramped working space.'he

inspectors

noted that this

work had not been

observed

by quality control, principally because

the worked

occurred

in a high dose

area.

-17-

The inspectors

concluded that system engineering's

involvement with the

intermediate

range monitors

had

been

inadequate.

Neither of the two system

engineers

had

been

in containment to observe

any of the work during

Outage

R09.

They also

had not examined

any of the connectors

removed after

the

second