ML16342D397

pump

(MFP) suction flow and heater drain

pump discharge

flow.

The

indications,

which were inputs into control circuits,

caused

the

MFP

recirculation valves to open which led to the automatic start of the third

condensate

and booster

pump set.

Following replacement

of the power supply,

the unit was returned to 100 percent

power.

01

Conduct of

Operations'1,1

General

Comments

71707

I.

0 erations

Using Inspection

Procedure

71707,

the inspectors

conducted

frequent

reviews of ongoing plant operations.

In general,

the conduct of

operations

was professional

and safety-conscious;

however,

there

were

several

instances

where control

room personnel

did not exhibit

a

questioning attitude

and failed to recognize that equipment required

by

TS was inoperable.

Specific events

and noteworthy observations

are

detailed

in the sections

below.

01.2

S stem

Ino erable

Due to Coincident Maintenance

and Testin

of

Redundant

Trains

Unit I

a.

Ins ection

Sco

e

71707

On June

13,

1996,

the licensee

discovered

that both trains of the

system

were inoperable

due to coincident maintenance

and surveillance

testing.

The inspectors

reviewed the sequence

of events

leading

up to

the discovery,

the work planning

schedule

for Unit 1,

and

Procedure

STP 1-38-B. 1, Revision

2,

"SSPS Train

B Actuation Logic Test

in Modes

1,

2,

3 or 4."

b.

Observations

and Findin

s

Initial work planning for Unit

1

had scheduled

SSPS Train

8 logic

testing for June

11.

However,

due to

a forced outage

on Unit

1

on

June

10,

the

SSPS logic testing

was rescheduled

for June

13, following

Pump

1-2 maintenance.

On June

12, operators

removed

RHR Pump 1-2 from service for scheduled

preventive maintenance

and declared

the

pump inoperable.

Removing the

pump from service

prevented its automatic start

from an engineered

safety feature actuation signal

(ESFAS) from Train A of the

SSPS.

The

maintenance

was scheduled

for. two shifts (approximately

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months ).

On June

13, at I:21 p.m,, operators

and technical

maintenance

personnel

removed

SSPS Train

B from service for the performance of

Procedure

STP I-38-B. 1,

"SSPS Train

B Actuation Logic Test in Modes

1,

2,

3 or 4."

During the testing of SSPS Train B,

an

ESFAS was blocked to

those

components

associated

with SSPS Train B.

Since automatic

actuation of RHR

Pump

1-1 is provided

by SSPS Train 8, the

pump would

not have started

had

an

ESFAS

been received during the Train

B logic

testing.

However, capability to manually start the

pump was still

available to the operators

using the manual start switch

on the main

control

panel

in the control

room.

Although the maintenance

on

Pump

1-2 was scheduled

to be completed

prior to the performance of Procedure

STP I-38-B.I, some minor delays

were encountered

and

SSPS testing

was started while

Pump

1-2 was

still cleared

awaiting postmaintenance

testing.

These conditions

resulted

in both

RHR pumps being inoperable

in that neither

pump would

have started

on

an

ESFAS.

This violated the

LCO for TS 3.5.2

and placed

the plant in TS 3.0.3.

Operators

identified the condition after

returning

SSPS Train

B to service.

Both

RHR pumps were inoperable for

approximately

53 minutes.

If a loss-of-coolant

accident

had occurred

during the t',me when both

pumps were inoperable,

plant emergency

operating

procedures

(EOPs)

would have directed the operators

to start

the available

RHR Pump

1-1 within a short period of time.

It is

reasonable

to expect that this would occur within several

minutes of

entering

the

EOPs.

Following discovery,

the licensee

made

a 4-hour

nonemergency

report in accordance

with '10 CFR 50.72.

Although delays

in the

RHR Pump

1-2 maintenance

led to

a scheduling

conflict between

the

two activities, administrative controls

were

contained

both in Procedure

STP I-38-B. I, and in Operating

Procedure

(OP) 1.DC17,

Revision

2A, "Control of Equipment

Required

By the

Plant TS," that should

have precluded entering into the procedure with

Pump

1-2 inoperable.

Step 7.2 of Procedure

STP I-38-B. 1 requires

that ".

. .if any engineered

safety feature

equipment

in Train

A is

known to be inoperable,

then

do not perform this test unless it is

known

TS

LCOs will not

be violated."

Additionally, Step 5.6 of

Procedure

OPI.DC17 requires

a review of SSPS train related

inoperable

equipment prior to authorizing work or testing

on either

SSPS train.

Operators

failed to follow these

precautions

when performing

SSPS

testing.

0

Conclusions

The failure of both the

SFH and

CO to: (1) properly assess

the effect of

maintenance

and testing

on

TS requirements,

and

(2) comply with the

requirements

of Procedures

STP I-38-B. 1 and

OP1.DC17,

resulted

in both

RHR trains being inoperable for just under

one hour.

This is considered

to represent

a failure in the control of maintenance

and surveillance

activities

and

was identified as

a violation of TS 6.8.

1

(VIO 50-275/96014-01).

v

Unit

1 Startu

Observations

Ins ection

Sco

e

71707

On June

11, Unit

1 operators

returned

the reactor to Mode

2 following a

forced outage

on June

9.

The inspectors

observed

the operating

crew

performing Procedure

OP L-2, Revision

23,

"Hot Standby to Startup trode."

Observations

and Findin

s

A thorough preevolution brief was conducted

by the senior control

operator.

In attendance

were the

SFN,

COs, reactor engineer

and

auxiliary operators.

During the startup,

evolutions

in the control

room

were restricted

and duties

among the control

room staff were divided

such that

one

CO was dedicated

to the control of reactivity.

Good

coordination

between

COs

and good direction of the

OP L-2'procedure

by

the senior control operator

were noted.

The reactor engineer

who reviewed the estimated critical position

(ECP)

calculations with the operators,

determined

that the

ECP should

be

recalculated

based

on minor delays

in the startup that

impacted

the

estimated critical xenon concentration.

Although the reactor engineer

estimated

the current

ECP calculation would have met the procedural

requirement of being within 100 steps of the actual critical rod height,

the operators

elected

to further delay the restart while the

ECP was

recalculated.

The startup

was

commenced

using the

new

ECP

and

criticality was achieved

at the

ECP predicted

rod height.

During the startup,

the bank demand position indicator (counter) for

Bank C,

G. oup

2 failed to track properly.

The Bank C,

Group

1 demand

position indicator and the digital rod position indicators

remained

functional

and rods were within TS limits.

TS allow operation with one

failed bank

demand position indicator provided the

LCO actions

are

taken.

The failure of the

demand position indicator was not announced

to the control

room operators

at the time of the failure, but the

SFfl

noted the failure during the logging of the critical rod height data.

Subsequently,

the inspectors

questioned

the

CO regarding

the

TS

requirements

for operating with the failed demand position indicator.

At that time,

the

CO determined

that

a

TS

LCO applied

and contacted

the

SFM to enter the

LCO into the tracking system.

The

SFM stated

that

he

was

aware of the

LCO requirements,

but as of several

hours after the

startup

had not yet entered

the

LCO into the computer.

Even though

operator

response

was considered

untimely and communications

were weak,

the

LCO requirements

were met. and

no violation of NRC requirements

occurred.

0

c.

Conclusions

The performance of the

mode change

was well coordinated

and the overall

startup

was performed effectively.

The recalculation of the

ECP

demonstrated

a sensitivity to the effects of xenon

on the

ECP and the

desire to estimate critical rod height

as accurately

as possible.

The failure of the

CO to recognize that

an inoperable

demand position

indicator required entry into

a

TS

LCO action statement until questioned

by the inspectors

is considered

to be

a negative finding.

Further,

the

SFM,

who was

aware that

an

LCO action statement

was applicable,

did not

take timely action to inform watchstanders

and ensure that the

conditional surveillance

actions

were initiated.

01.4

0 erator Awareness

of

E ui ment Status

a.

Ins ection

Sco

e

71707

Routine walkdowns of the Units

1

and

2 control boards

were conducted

during the inspection period to determine,

among other things,

operator

awareness

of plant equipment conditions.

b.

Observations

and Findin

s

On June

21, the insp'ectors

noted that Unit 2 annunciator

PK05-09,

"RVLIS

LO/LO-LO LVL ALARM," was lit.

However,

when questioned,

the

CO was

unaware that the alarm

had

come in.

The annunciator typewriter printout

showed that the alarm had

come in approximately

15 minutes earlier.

It

was apparent

that the alarm

had

been

acknowledged,

but the annunciator

panels

had not been

adequately

scanned

and the annunciator typewriter

printout had not been thoroughly reviewed

by the

CO.

These actions

were

not in accordance

with the guidance

provided in Procedure

OPI.DC12,

Revision 3,

"Conduct of Routine Operations,"

which specifies that

when

an alarm is received it should

be acknowledged

and the annunciator

CRT

or typewriter should

be checked to determine

the alarm input.

During the

same time period, technical

maintenance

personnel

were

performing

a calibration

on power range nuclear instrument NI-43.

During the calibration,

several

expected

alarms with annunciator lights

in the vicinity of PK05-09 were received.

Following recognition of the alarm condition,

the operators

investigated

the cause of the alarm

and determined

that the compensating

resistance

temperature

detectors for the

RVLIS Train A sensing line had failed low.

RVLIS Train A was then declared

inoperable

and technical

maintenance

was

contacted

to initiate troubleshooting.

RVLIS Train A was returned

to

service

on June

24 within the

7 ~day period required

by TS 3.3.3.6.

Conclusions

The CO's failure to follow the procedural

guidance in responding

to

annunciators

resulted

in the failure to promptly investigate

RVLIS

Train

A operability and subsequently

enter the associated

TS

LCO action

statement.

Although the procedural

guidance

was not

a requirement,

the

failure to take appropriate

actions

in response

to annunciators

is

considered

a negative finding.

Unit

1 Hanual

Reactor Tri

Ins ection

Sco

e

71.707

On June

10, at 1:06 a.m.

POT, Unit

1 operators initiated

a manual reactor trip after the loss of both HFPs.

The plant response

following

the trip was uncomplicated.

The inspectors

reviewed operator

response

to the event,

the associated

procedures utilized,

and licensee

corrective actions prior to the return to power.

Observations

and Findin

s

Earlier on June

9, the control

room received

an Eagle

21 digital plant

protection

system

channel

set failure alarm that was determined

to be

associated

with Protection

Set

2,

Rack 8.

Following receipt of the

alarm,

the associated

protection bistables

were tripped

and technical

maintenance

personnel

were notified to initiate troubleshooting.

Investigation revealed that the channel failure was caused

by

a

"lock-up" of the loop calculation processor

(LCP) which performs

calculations for protection

channel

functions,

data

comparison

to

setpoint values,

and initiates trip signals.

0 erator Assessment

of the

LCP Failure

on Control Functions

Operators

referred to

OP Abnormal

Procedure

(AP) 5,

Halfunction of

Protection or Control Channel," to determine

the instrument

channels

affected

by the failure and instituted

a conditional surveillance to

monitor the status of the unaffected

racks in Protection

Set

2 while

Rack

8 was in alarm.

The

LCP failure froze the outputs of Rack

8 at the values at the time of

the failure.

Therefore,

the

steam generator

(SG) level signals that

provide input into control circuits for two of the four auxiliary

(AFW) level control valves

(LCVs) associated

with the

HOAFW

pumps

were inoperable.

As

a result,

in the event of a demand for AFW

flow, while the

LCP was locked up,

Valves

LCVs 110 and

113 would have

closed

since

SG levels at the time of the

LCP failure were

above

the

level maintained

by the

LCVs in automatic following shutdown.

OP AP-5

failed to note,

and operators failed to recognize,

the affect of the

LCP

failure on the operability of the

HDAFW pumps

by the

LCVs in automatic

control.

Attachment 4. 1 of OP AP-5 only noted that the

MDAFW pumps

associated

with AFW SG

LCV 110

and

113 would be inoperable if placed

in

manual

due to the loss of pump runout protection.

Despite these

problems,

the

TDAFW pump and the remaining

two

LCVs associated

with the

MDAFW pumps were not affected

by the failure and, if needed,

would have

responded

to provide the required

AFW flow.

Operators

judged the affect of the

LCP failure on control

systems

incorrectly when assessing

failure.

Furthermore,

operators failed to

recognize

that the

OP AP-5, Attachment

4.1 note,

regarding

the impact of

the. channel failure on

AFW operability, did not address

the impact

on

operability with the

LCVs in automatic.

As

a result,

operators

did not

enter the

TS 3,7. 1.2. action statement

for both

MDAFW pumps being

inoperable

which required that the unit be in hot shutdown within the

following 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months .

Reset of the

LCP with Control

In uts

In Service

After initial troubleshooting

indicated that the

LCP was the cause of

the protection set malfunction, the decision

was

made to reset

the

LCP

without removing the control inputs from service.

Resetting

the

LCP

caused all rack associated

"deenergize

to trip" bistables

to trip and

analog outputs (indicators,

control inputs, etc..) to go to zero for

approximately

10 seconds,

This caused

the turbine first stage

pressure

(PT-506) indication to fail low which initiated

a condensate

system

load

transient

bypass

(LTB) signal that

was not anticipated

by operators.

The

LTB signal realigned

the condensate

system to eliminate condensate

rejection

and recirculation flow through gland seal

and

steam jet air

ejector condensers

and provide

a higher suction pressure

to the

HFPs

by

bypassing

the condensate

polishers

and feedwater heaters

and starting

the standby

condensate

and booster

pump set.

Upon receipt of the

LTB signal,

operators

reduced

power output

by 50

HWe

in order to limit the power increase

due to the increased

flow.

Following the

LTB automatic realignment

operators

followed the

actions

prescribed

in

OP AP-2, Revision

7, "Full Load Rejection,"

to

reset

the

LTB signal

and realign the condensate

system to normal.

The

actions

taken

by operators

resulted

in

a significant reduction in HFP

suction pressure.

In response,

operators

reduced

power at

a rate of

25 MW/min; however,

HFP 1-1 tripped

on overspeed

due to the inability to

maintain the required

feedwater flow with the lower HFP suction

pressure.

In response

to the

HFP trip, operators

started all three

AFW

pumps

and initiated

a rapid

ramp to 600

HWe.

After reducing

power

and

during operator

feedwater flow adjustments,

HFP 1-2 tripped due to high

discharge

pressure.

After the loss of the second

MFP, operators

initiated

a manual

reactor trip.

Following the event, it was determined

that simulator training

on restoration

from an

LTB at

100 percent

power

had not been accurately

modeled

and

as

a result

had not previously

revealed

the problem operators

encountered

with a reduction in HFP

suction pressure

that occurred during the restoration.

Licensee

Corrective Actions Prior to Restart

Prior to restart of Unit 1, the licensee

determined that the following

corrective actions

were appropriate

to prevent recurrence

of the

problem;

(1)

a list of technical

maintenance

contacts

to call in the

event of an

LCP failure was generated;

(2) operators

were provided

instructions to remove the first stage turbine pressure

instrument prior

to resetting

the Protection

Set

2,

Rack 8 LCP;

(3) standing

orders

were

issued prescribing

the requirements

for resetting

an

LCP; and,

(4) Procedures

OP AP-2 and

OP AP-5 were committed to be revised.

During

a

PSRC conference call for approval for restart,

the inspectors

questioned

the impact of the

LCP failure on the operability of the

AFW

LCVS.

The licensee's

response

was that the only affect

on the

LCVs was

that if they were taken to manual

the associated

pumps will loose

run

out protection

and therefore

be inoperable.

This was subsequently

determined

to be both incorrect

and nonconservative.

It was later

determined

that the

LCP failure resulted

in two inoperable

AFW LCVs

which required entry into

a 6-hour

LCO.

Resetting

the

LCP,

done within

the 6-hour

LCO, resulted

in restoring the operability of Valves

LCV 110

and

113.

The licensee

has subsequently

performed

a review to identify

any other similar problems with procedures

that deal with an

LCP

failure.

The licensee

has written LER 50-275/96-008-00

on this event.

C.

Conclusions

02

02.1

Failure of operators

to adequately

assess

the affect of the

LCP failure

coupled with procedural

inadequacies

resulted

in the following;

(I) failure to recognize

the applicability, of the

TS action statement

for two inoperable

MDAFW pumps;

and

(2)

an unanticipated

LTB actuation

following the reset of the

LCP.

In addition, investigation of the issue

prior to restart failed to note the affect of the

LCP failure on

AFW

system operability.

Operational

Status of Facilities

and Equipment

Unit

1 Instrument Air S stem Walkdown

Ins ection

Sco

e

71707

The inspectors

performed

a detailed

walkdown of accessible

portions of

the Unit I instrument air (IA) system.

b.

Observations

and Findin

s

On June

5-6,

1996,

the inspectors

noted that the material condition of

system

components

and area

housekeeping

of the accessible

portions of

the IA system were generally good.

Exposed portions of the

IA piping to

the

10 percent

atmospheric

dump valves exhibited

some surface corrosion.

However,

the integrity of the copper piping appeared

good, with no leaks

or obvious signs of degradation.

A detailed

walkdown of the system

configuration

and review of the alignment verifications

(OP K-1: I,

Revisjon

17,

" IA System - Make Available and Place in Service" )

and

Operating

Valve Identification Diagrams,

106725,

Revision 40,

and

106726,

Revision

29, did not identify any discrepancies.

c.

Conclusions

The configuration of the

IA system

was in accordance

with the operating

valve identification diagram

and system alignment.

Material condition

of the

system

was generally good, with the exception

noted regarding

the

surface corrosion

on the piping to the

10 percent

atmospheric

dump

valves.

05

Operator Training and gualification

05. 1

Simulator Observations

a.

Ins ection

Sco

e

41500

The inspectors

observed

the performance of requalification simulator

evaluations of licensed operators.

Observations

covered

the

administration of three simulator scenarios

to two separate

groups of

operators.

b.

Observations

and Findin

s

The evaluations

were conducted within the'guidance

of NUREG 1021,

Operator Licensing

Examiner Standards.

The evaluation

by training

personnel

appeared

to be thorough

and critical.

Operations

management

was in attendance

and provided significant imput to the evaluations.

The two crews included

one crew undergoing routine periodic evaluation,

and the other crew of persons

undergoing

another evaluation following

remedial training for a prior failure.

Crew performance

appeared

to be

adequate

in that identified critical tasks

were performed.,

The inspectors

noted that crew communications

were adequate,

with the

observation

that crew communication skills exhibited

a lack of

formality,

Directions to crew members

were,

at times,

in jargon

and

acknowledgements

were often provided

by the

use of idiomatic expressions

(e.g.,

OK).

Although repeat

back of directions

was routine,

several

instances

were noted where

none

was given,

and the operator providing

directions

was not insistent

on receiving

a response.

C

The scenarios

used during the evaluations

met the guidance

in NUREG 1021

ES-604,

"Dynamic Simulator Requalification Examination."

The inspectors

judged the scenarios

to be challenging in exercising the use of the

EOPs.

C.

Conclusions

08

08.1

The evaluations

were performed within the guidance of the applicable

standards.

The operators

demonstrated

performance that was adequate

and

the evaluators

exhibited

good practices

in the conduct of the

examinations.

The operators

were subjected

to scenarios

that challenged

their training

and abilities.

Hiscellaneous

Operations

Issues

Closed

LER 50-275 95-12-01:

TS 3.9.4 requirement for containment

closure during refueling not met

as

a result of an inadequate

evaluation.

The

LER was issued

due to inadequate

containment

closure

during core alterations for the Unit

1 refueling outage

in October

1995.

The inspectors

reviewed the licensee's

corrective actions

addressed

in

the

LER.

Independent verification of containment closure during core

alterations

for the Unit 2 refueling outage

in April 1996

was also

performed.

The licensee's

library clearance

work instruction of the

administrative

tag out and clearance

process

was revised to require the

installation of a gag device for the main steam isolation valves

(HSIVs)

when they are relied

upon to provide containment closure.

The gag

devices

were installed

on Unit 2 during its last refueling outage.

The

licensee

also replaced

the HSIV actuator pins

on both units during their

respective

refueling outages.

Corrosion of the original actuator

pins

was determined

by the licensee

to be

a contributing factor to the

failure of the HSIVs to fully seat.

A review by the licensee of other

containment isolation points did not identify any other unique

situations that would require additional

measures

to assure

containment

closure.

08.2

Closed

Violation 50-275 95017-03

Violation ID 02014

and

LER 50-275 95-19-00:

The inspectors

reviewed the licensee's

corrective

actions for control of overtime.

Procedure

OH14. ID1, "Overtime

Restrictions,"

was revised to include specific instructions that

"No

individual shall

work more than

6 consecutive

days without the written

preapproval

from the

VP&PH or VP, NTS."

Several

conditions

were

imposed

for granting the approval

to ensure

measures

of personnel ability to

adequately

perform their duties

were assessed

prior to approval

of

overtime.

The

TS limits on overtime were explicitly detailed

in the

procedure

and specific guidance

was provided to supervisory

personnel

with regard to all factors involving overtime.

The results of the

changes

were reflected in the recent

2R7 refueling outage.

While

overall

overtime rates did not change substantially,

no personnel

worked

-10-

more than

7 days without a day off.

Further,

a licensee

review of

overtime records

indicated

no TS violations occurred during the

2R7 outage.

I

08.3

Closed

LER 50-275 96-008-00:

reactor trip on loss of normal

flow due to personnel

error.

The event

documented

by this

LER is

discussed

in detail in Section 01.5 of this report.

Following the event

the licensee initiated actions to revise procedures

and Eagle

21

training to cover the effects of resetting

an

LTB and the effects of a

LCP failure.

The licensee

reviewed

an incident

summary with instrument

technicians

and operators.

In addition,

the licensee

indicated that the

simulator parameters

for feedwater

and condensate

for resetting

an

LTB

would be updated

and that operators

would be trained

on the subject.

The corrective actions discussed

in the

LER appeared

appropriate.

II. Maintenance

Hl

Conduct of Maintenance

Ml. 1

Maintenance

Observations

a.

Ins ection

Sco

e

62703

The inspectors

observed all or portions of the following work

activities:

MP M-4.18

C0145315

C0145335

C0145514

MP M-4,25

Verification of Lift Point Using Ultra Star Assist

Device for the Main Steam Safety Valves (Unit 2)

Replacement

of PS-1221,

Pressure

Switch

Investigation/Repair of Oil Leak on

PDP 2-3

Correct Failure of PS4 in Power Cabinet

2AC (Unit 1)

AFW Pump Turbine Governor Maintenance

b.

Observations

and Findin

s

The inspectors

found the work performed

under these activities to be

professional

and thorough.

All work observed

was performed with the

work package

present

and in active use.

Technicians

were experienced

and knowledgeable

of their assigned

tasks.

The inspectors

observed

system engineers

monitoring job progress

and that quality control

personnel

were present

when required

by the procedure.

When applicable,

appropriate radiation control measures

were in place.

In addition,

selected

maintenance

observations

are discussed

below.

-11-

Hl.l.l Valve CCW-1-FCV-364 Actuator

Re lacement

a.

Ins ection

Sco

e

62703

The inspectors

observed

portions of the replacement

and testing of the

actuator to component

cooling water

(CCW) Valve CCW-1-FCV-364, which

isolates

CCW return flow from

RHR Heat Exchanger

1-2.

The actuator

was

replaced

using

Work Order C0138081.

Obser ations

and Findin

s

During the review of the work package,

the inspectors

noted that the red

tag,

provided to assure

administrative control of the operations

department

man-on-line tag,

was not hung

as required

by Prerequisite

4

of the work order.

The work order step requiring the red tag

had

been

previously signed

by the mechanic

and the reinstallation of the

new

actuator

was in progress

at the time of discovery,

The safety of the

work was being controlled

by

a master clearance

and the man-on-line

tag

was

an additional

measure

for personnel

protection.

When informed of

the tag,

the mechanic

hung the tag

and continued work.

Additionally, Prerequisite

5 was signed

although not all of the actions

were complete.

The step verified that technical

maintenance

personnel,

under

a separate

work order,

had disconnected

the actuator air supply

and limit switches

and provided

a remote air supply

and gage for

testing.

The air supply was disconnected;

however,

the limit switches

had not been

removed

and the air supply

and gage were not provided.

Although it had

been determined that removal of the limit switches

was

unnecessary

for replacement

of the actuator,

this determination

was not

dispositioned

or noted

on the work order.

The air supply was

subsequently

delivered

and the gage

was later determined

not to be

required.

TS 6.8. l.a requires that written procedures

shall

be established,

implemented

and maintained

covering activities referenced

in Appendix

A

of Regulatory

Guide 1.33, "guality Assurance

Program Requirements

(Operation)",

Revision 2, February

1978.

Section

9 of Appendix

A to

Regulatory

Guide

1.33 requires that administrative

procedures

be

established

for performing maintenance.

Administrative

Procedure

AD7. ID1, Rev IA ,

"Use of PINS Work Order Nodule," requires

work to be performed in accordance

with the instruction provided

by the

work order.

Prerequisites

4 and

5 were not completed

as required,

and

the deviations

were not administratively acknowledged

as authorized

by

Procedure

AD7.ID1.

The failure to perform the steps

appeared

to be

a

failure to maintain attention to the details of'the procedure

for items

thought to be unimportant.

After the actuator

was installed

on the valve, technical

maintenance

assisted

in adjusting

the limit stops of the actuator.

An acoustic

leak

monitoring device

was

used to determine

the optimum seating position of

-12-

the valve.

This licensee

technique

was

an enhancement

to the guidance

provided in the valve technical

manual.

c.

Conclusions

The use of the acoustic leak. monitor to set the actuator position stops

indicated

a proactive effort by technical

maintenance

to maximize valve

performance.

Adherence

to the work order was poor

as demonstrated

by the failure to

comply with or change

the requirements

of the work order.

The failure

to properly perform and/or disposition prerequisite

Steps

4 and

5 is

a

violation of TS 6.8. 1.

This failure constitutes

a violation of minor

safety significance

and is being treated

as

a noncited violation

consistent

with Section

IV of the

NRC Enforcement

Polic

(NCV 50-275/96014-02).

MI.2

Surveillance

Observations

a.

Ins ection

Sco

e

61726

Selected

surveillance tests

required to be performed

by the

TS were

reviewed

on

a sampling basis to verify that:

(1) the surveillance tests

were correctly included

on the facility schedule;

(2)

a technically

adequate

procedure

existed for the performance

of the surveillance

tests;

(3) the surveillance tests

had

been

performed at

a frequency

specified

in the TS;

and (4) test results satisfied

acceptance

criteria

or were properly dispositioned.

The inspectors

observed all or portions of the following surveillance:

~

STP I-2C1, Revision

17,

"Removal of Power

Range

Channel

From

Service"

~

STP I-20, Revision 40,

"Nuclear Power

Range

Incore/Excore

Calibration"

~

STP P-AFW-II, Revision IA, "Routine Surveillance

Test of

TDAFP 1-1"

b.

Observations

and Findin

s

The inspectors

found that the surveillance

reviewed and/or observed

were

being scheduled

and performed at the required

frequency.

The procedures

governing

the surveillance tests

were technically adequate

and personnel

performing the surveillance

demonstrated

an adequate

level of knowledge.

The irspectors

also noted that test results

were appropriately

dispositioned.

M7

-13-

Quality Assurance

in Naintenance Activities

N7.1

a

~

AR Ta

s Not Removed

from Control

Room Panels

Ins ection

Sco

e

62703

b.

During the course of the inspection period,

the inspectors

walked

down

the Unit

1 main control

boards

and interviewed watchstanders

to

determine,

among other things,

the status of control

room equipment.

Observations

and Findin

s

On Hay 15,

the inspectors

noted that there

were approximately

39

AR

stickers

associated

with annunciators,

indications,

and controls

on the

Unit

1 main control boards.

Of the

39 ARs,

16 had

been initiated more

than

6 months prior to the date of the walkdown.

Review of those

16 ARs

revealed that five of them had

been taken to history (the work was

completed

or the problem otherwise resolved)

and the control

board

sticker

had

been incorrectly indicated

as having

been

removed.

Unit

1

control

room watchstanders

were informed of the discrepancies

and

removed

the tags.

AR tags

are

used

by the licensee

as

a means of alerting operators

that

a

particular annunciator,

indicator, control, or component

was either not

functioning properly or had operated

abnormally at

some time in the past

and

had

been evaluated.

AR stickers that are not current'nd

are

attached

to control

room equipment could result in confusion for

operators

to determine

the operational

status of the component.

This

issue

was discussed

with the Operations Director who expressed

concern

that the failure to remove the tags

and stickers

could result in

misinformation being provided to operators

and could affect operational

decisions

regarding

the

use of the equipment

under both normal

and

abnormal

conditions.

Review of previous

ARs that documented

additional

failures to remove

AR stickers

from control

room panels.

This review

determined

that the practice of closing

ARs without first removing the

sticker

has

been

a historical

problem

and the actions

taken to resolve

the problem have

been ineffective thus far.

Administrative Procedure

OH7. IDI, Revision 6,

"Problem Identification

and Resolution

ARs," Section 5.8.7,

requires that

AR stickers

in the

control

room shall

be removed after problem resolution prior to closure

of the

AR.

AR stickers

had not been

removed

as required

by. procedure

even

though initials in the block indicated that tags

had

been

removed.

It appears

that personnel

were not careFul

in removing all required

tags

when closing the

AR.

Information provided after the

end of the

inspection

period identified that data entry sequence

contributed

to the

occurrence

of this problem.

-14-

c.

Conclusions

The inspectors

concluded that the failure to remove

AR stickers

from the

control

room main control boards,

as required

by Procedure

ON7. ID1, was

a violation of 10 CFR Part 50, Appendix B, Criterion

V ( Instructions,

Procedures

and Drawings), which requires that activities affecting

quality shall

be prescribed

by documented

instructions,

procedures

or

drawings of a type appropriate

to the circumstances

and shall

be

accomplished

in accordance

with these instructions,

procedures

or

drawings

(VIO 50-275/96014-03).

H8

Miscellaneous

Maintenance

Issues

M8.1

Closed

VIO 50-275 8802-04:

At the time of the inspection,

Containment

Flow Instrument

FT-932

and both Unit

1

and

2 Condensate

Storage

Tank

Level Transmitters

LT-44, were found to have

exceeded

their 18-month

recalibration interval.

Following the inspection,

the instruments

were

recalibrated,

and placed

on the Recurring Task Scheduler.

The

inspectors verified that the instruments

have

been maintained

on the

Recurring

Task Scheduler

and

FT-932 having

been recently calibrated

on

May 16,

1996,

and both LT-44 instruments

on July 31,

1995.

III. En ineerin

El

Conduct of Engineering

El. 1

AFW Pum

Room Ventilation Path

a.

Ins ection

Sco

e

37551

The inspectors

reviewed the

AR, the associated

evaluations,

and the

4-hour nonemergency

50.72 report written to document

the blockage of

ventilation exhaust

from the Unit

1 TDAFW'ump room.

b.

Observations

and Findin

s

On Nay 13, the licensee

noted that the ventilation exhaust

path for the

TDAFW pump was blocked.

Exhaust ventilation for the

pump

room is routed

through

a floor grating that

had

been

covered

by sheet

metal plates

and

a chair.

A security watch

had laid down the metal plates

and put

a

chair over the grating,

the plates

had

been installed for a time period

of up to two weeks.

The plates

and the chair were

removed

the

same

day

they were noted to restore

the normal ventilation exhaust

flowpath.

During the time that the exhaust

flow through 'the floor grating

was

blocked, ventilation air flowed through

a normally open fire damper into

the

room containing

the two

MDAFW pumps.

The air exhausted

from the

MDAFW pump room through

a separate

ceiling grate.

-15-

An auxiliary steam line passes

through the

TOAFW pump

room which the

licensee

has postulated

a break (crack).

With the

TDAFW pump

room

exhaust grating blocked,

the

steam

would exhaust

through the fire damper

into the

MDAFW pump

room and through

a ceiling grate.

The licensee's

existing analysis

assumed

that even with normal ventilation exhaust

flow

through the unblocked grating,

operator

action

was still required to

isolate

an auxiliary steam leak

and restore

heating ventilation

and air

conditioning within an hour in order to ensure that the temperature

in

the motor-driven

pump room would not exceed

128'F.

However,

since the

TDAFW pump room exhaust

was blocked,

the licensee

determined that for

the postulated

steam leak the temperature

in the

MOAFW pump room would

exceed

128'F

and cause

the

MOAFW pumps to be outside of their design

basis.

C.

On June

11, the licensee's

technical

review group reviewed this issue

and'etermined it to be reportable.

The licensee

made

a

10 CFR 50.72

report for being outside of design basis

in the past.

The licensee

plans

on installing

a warning sign to help ensure that the floor grate

is not blocked

and is looking for similar types of problems or

vulnerabilities in other vital equipment

rooms.

Conclusions

The discovery of this problem

and the prompt actions

taken to resolve

the issue

and prevent recurrence

of the problem were considered

to be

proactive

and indicative of a concern for safety.

This issue will be

reviewed further during the review of the licensee

event report that

will be written to document this occurrence.

E2

E2.1

Engineering

Support of Facilities

and Equipment

Review of U dated

Final Safet

Anal sis

UFSAR

Commitments

E8

E8.1

A recent discovery of a licensee

operating their facility in

a manner

contrary to the

UFSAR description highlighted the need for

a special

focused

review that compares

plant practices,

procedures,

and/or

parameters

to the

UFSAR description.

During the inspection period,

the

inspectors

reviewed the applicable sections of the

UFSAR that related

to

the inspection

areas

discussed

in this reports

There were

no

inconsistencies

noted

between

the wording of the

UFSAR and the plant

practices,

procedures,

and/or parameters

observed

by the inspectors.

Miscellaneous

Engineering

Issues

Closed

LER 50-275 95-015-00:

manual reactor trip due to loss of

due to design deficiency.

On November 28,

1995, Unit

1 plant

operators

initiated

a manual reactor trip from 50 percent

power when

flow was lost.

The unit was stabilized

in Mode

3 and the

required

4-hour nonemergency

report

was

made in accordance

with

10 CFR 50.72(b)(2)(ii).

-16-

The inservice

HFP

(HFP 1-2)

had tripped

on high discharge

pressure.

The

alpha

speed

probe,

which provides

input into the speed

control circuit,

was

found to have

been

grounded,

which caused

the sensed

HFP speed

to be

zero.

In response

to the zero

speed

signal,

the

steam supply valve

opened,

which led to the

pump tripping due to high discharge

pressure.

Investigation of the

speed

probe failure revealed that

a pinched wire

caused

the ground.

Further review of the design identified that there

were

no connectors for disconnecting

the

speed

probe wires routed

from a

junction box through flexible conduit to

a threaded

90 degree

elbow

coupling to the probe.

The probe itself is threaded

into the

HFP

bearing

cap.

In order to install the speed

probe,

technicians

"pretwisted" the probe wire in the conduit the

number of turns estimated

to be required to screw the probe into the bearing

cap.

The excess

wire

in the vicinity of the threaded

conduit coupling created

the potential

for'inching the probe signal wire.

The licensee

concluded that the

root cause of the problem was

a design deficiency that did not

facilitate routine removal

and installation of speed

probes.

The

remaining

HFP speed

probes

were inspected

to ensure similar problems did

not exist.

The licensee

indicated in the

LER that

a design

change will

be performed to install

speed

probe cable connectors.

The inspectors

concluded that the licensee

had performed

a thorough evaluation of the

problem

and

had initiated appropriate corrective actions.

V. Hang ement Heetin

s

Xl

Exit Heeting

Summary

The inspectors

presented

the inspection results

to members of licensee

management

at the conclusion of the inspection

on July 9,

1996.

The licensee

acknowledged

the findings presented.

The inspectors

asked

the licensee

whether

any materials

examined during the

inspection

should

be considered

proprietary.

No proprietary information was

identified.

Licensee

ATTACHMENT

PARTIAL LIST OF

PERSONS

CONTACTED

H.

R. Arnold, Acting Director, Mechanical

Maintenance

J.

R, Becker, Director, Operations

D. Bell, Acting Director, Nuclear guality Services

Maintenance

D.

F. Brosnan,

Director, Regulatory Services

C.

R. Groff, Director, Nuclear Secondary

Systems

D.

B. Hiklush, Manager,

Engineering

Services

H.

N. Norem, Director,

Outage Services

R.

P,

Powers,

Manager,

Vice President

DCCP and Plant Manager

D. A. Taggart, Director, Nuclear (}uality Services,

Operations

and Strategic

Programs

0.

A. Vosburg, Director, Nuclear

Steam

Supply Systems

Engineering

L.

C. Young, Director, Nuclear guality Services

Engineering

and Production

IP 37551:

IP 41500:

IP 61726:

IP 62703:

IP 71707:

IP 92901:

IP 92902:

IP 92903:

~0en ed

INSPECTION

PROCEDURES

USED

Onsite Engineering

Training and gualification Effectiveness

Surveillance

Observations

.

Haintenance

Observations

Plant Operations

Followup - Plant Operations

Followup - Haintenance

Followup - Engineering

ITEHS OPENED,

CLOSED,

AND DISCUSSED

50-275/96014-01

Unrecognized

entry into TS 3.03 during

SSPS testing

50-275/96014-02

NCV

Failure to complete

work order instructions

50-275/96014-03

AR tags not removed

from control

room panels

Closed

50-275/96004-02

50-275/88002-04

50-275/02014

50-275/95019-00

NCV

V IO

LER

50-275/95015-00

50-275/96008-00

LER

50-275/95012-01

LER

failure to complete work order instructions

instrumentation

exceeding its recalibration interval

overtime limits routinely exceeded

during outage

overtime restrictions

not met due to inadequate

overtime control

program

TS 3.9.4 requirement for containment closure during

refueling not met

manual reactor trip due to loss of feedwater

due to

personnel

error

ADHINISTRATIVE CORRECTIONS

TO PRIOR

INSPECTION

REPORT

ENTRIES

Ins ection

Re ort 50-275

323

96006

Correct 50-275/96006-03

VIO to be 50-323/96006-03

.Correct

50-275/94028-01

VIO to be 50-323/94028-01

Ins ection

Re ort 50-275

323

96009

Correct 50-275/95014-01

VIO to be 50-275/95014-02

Correct 50-275/9402.-01

VIO to be 50-275/94027-03

Correct

50-323/94027-01

VIO to be 50-323/94027-03