ML18011B059

and placed in service the

"B" charging/safety

injection

pump

(CSIP) without properly

testing it.

The "A" and

"C" CSIPs

were removed

from service

and declared

inoperable to satisfy

LTOP requirements

contained

in TS 3. 1.2. 1 (Boration Systems

Flowpath)

and

TS 3.5.3

(ECCS Subsystems)

with RCS temperature

less

than

325

'F.

The "C" pump's electrical

breaker

was racked out and

the "A" pump's

manual

discharge

valve

had. been

locked closed

to prevent either

pump from injecting with the plant in a

pressurized,

low temperature

condition.

Prior to this

configuration

and for much of the previous operating cycle,

the

"A" and

"C" pumps

had

been in service satisfying

Node 1-

3 TS requirements.

The following paragraphs

discuss

how the

"B" pump should not have

been declared

on September

2 since it had not been properly tested prior to placing it

in service.

~Back round

Each

CSIP has

a miniflow system that ensures

a vendor-

recommended

minimum flowrate of 60

GPN for pump protection.

The "8"- CSIP had

been out of service

and inoperable for much

of the previous operating cycle due to

a failed check valve

(1CS-193)

in its miniflow system.

A stuck disk caused

the

valve to experience significant backflow leakage

over the

cycle requiring that the "B" pump not be placed in service

concurrent with the

"A" pump.

The backflow leakage

did not

affect operability of the

"B" pump,

which only required that

the check valve pass

forward flow.

However,

a postulated

"B" train electrical failure would take out the "8" pump,

and the undesirable

check valve leak path could potentially

divert enough

"A" pump flow during

a

LOCA, thus preventing

the "A" pump from performing its safety function.

Because

of the backflow leakage

problems,

in late July

licensee

personnel

replaced

the check valve (a 2-inch

T-style globe check valve with a resilient seating

surface)

with another T-style valve minus the soft seat.

Later,

on

August 2, the inspector

observed

the newly installed check

valve fail

a forward flow test,

passing

approximately

28

gpm, vice 60 gpm.

The failure was caused

by a sticking disk

inside the valve.

After this failure,

between

August

2 and

September

2, operators

maintained

compliance with Node 1-3

Technical Specifications

by using the

"C" pump to replace

the

"B" pump

and isolating the "B" pump's miniflow leak path

from the "A" pump.

The inspector,

recalling that successful

completion of the

forward flow test

was

a prerequisite for "B" pump

operability, questioned its operability on September

2.

This information was indicated to the control

room,

The

control

room operators

were unaware of the earlier

forward flow failure.

After researching

the previous

month's test records

and the reactor operator's

logbook

entry for August 2, the operators

determined that the "8"

pump had

indeed not been successfully

tested prior to

placing it in service

on September

2.

At the time of this

discovery,

RCS temperature

was less

than

325 'F.

Operators

immediately corrected

the situation

by raising

temperature

above

325 'F to ensure

compliance with LTOP

requirements,

opening the "A" pump's discharge

isolation

valve,

and placing that

pump in service.

After securing

the

"8" pump

and racking out its breaker,'perators

continued

the plant cooldown to Mode 5,

Root Cause

Operators

improperly placed the "8" pump in service

because

they were

unaware of its inoperable status

since August 2,

Further review determined

the root cause

to be inadequate

Equipment

Inoperable

Records

(EIRs) for both valve

and the "8" CSIP.

The EIRs did not reference

the valve's

forward flow test failure.

EIRs were

used to document

inoperable

equipment,

failed surveillance tests,

and

associated

retest

requirements.

These

forms were relied

upon

by operators

to ensure that

TS

LCOs were complied with

when manipulating or testing plant equipment.

'he

EIRs associated

with the "8" CSIP

and valve

were

initiated in July because

of the previous backflow test

failure, but were not updated

by the

SCO on August

2 when

the newly replaced

valve failed the forward flow test.

Responsible

plant personnel

incorrectly assumed

on August

2

that because

the valve was already inoperable prior to the

forward flow test,

the

EIRs generated

in July were properly

annotated

with retest

requirements.

Since "8" pump miniflow

check valve backleakage

only affected

"A" pump operability,

the "8" pump

EIR only referenced

that the pump's breaker

had

to be racked

in to make it operable.

Likewise, the only

retest

requirement

referenced

on the

EIR was its

backflow leak test.

Successful

completion of this test

would be required prior to unisolating the valve from the

"A" pump to maintain that pump's operability.

On September

2,

because

of the incomplete information in the

EIRs, operators

placed the "8" CSIP in service to support

an

upcoming

18-month surveillance test without forward flow

testing the miniflow check valve,

and

made the other

pumps

inoperable.

The plant was operated

in this condition for

approximately

seven

hours before the inspector discovered

it.

During that time, operators

were cooling down the

in accordance

with operating

procedures,

thereby

adding

positive reactivity to the core with one degraded

CSIP

functional.

Operations

Management

Manual procedure

OHH-014,

Rev.

4,

Operation of the Work Control Center,

Step 5.3.6 required

that the

SCO annotate all applicable

EIRs when equipment

failed surveillance testing or portions of the test which

were not completed.

Procedure

OHH-014 further required that

the

SCO do this by entering all pertinent information in the

Remarks section of the EIR, which was Attachment

4 to the

'rocedure.

Procedure

OMM-007, Rev.

4, Operations

Surveillance,

Periodic

and Reliability Tests,

required that

the Shift Supervisor

ensure that

an

EIR was completed

when

an

OST failed to meet its acceptance

criteria.

The failure

to complete the "B" CSIP

and valve

EIRs with forward

flow test information resulted

in the plant operating in

Mode

4 for over

7 hours8.101852e-5 days <br />0.00194 hours <br />1.157407e-5 weeks <br />2.6635e-6 months <br /> with one degraded

CSIP.

The failure

to follow procedures

OMH-007 and

OMH-014 was contrary to the

requirements

of TS 6.8. Ia and Regulatory

Guide 1.33,

Rev.

2,

Appendix A which required procedures

for equipment control.

This is identified as Violation 400/95-15-01,

Failure to

Properly Annotate Surveillance

Test Requirement for an

Inoperable

CSIP.

Safet

Si nificance

Although this violation resulted

in the

"B" CSIP being

placed in service without testing its miniflow system,

the

safety consequences

were minimal.

At the time of the

discovery,

the inspector verified that at least

a 60

gpm

flowrate existed via the normal charging/seal

injection

flowpath.

Additionally, the licensee initiated

ESR 9500752

to show that the

"B" pump never operated

below its minimum

flow limit and that it could have performed its safety

function with the plant in Mode

4 and

RCS pressure

reduced

to 350 psig.

The licensee's

evaluation is further discussed

in paragraph

5.a.4 of this report.

While the event's

safety

significance

was minor, the problem could have resulted

in a

substantial

safety hazard

under different plant operating

conditions

(Modes

1,

2 or 3).

Corrective Actions

To correct the valve problem,

the licensee

replaced

the T-

style globe check valve with a Y-type valve.

The

new valve

had

a disk arrangement

designed

to operate better under

higher system pressures.

The valve subsequently

passed

both

forward flow and backflow leakage tests.

To correct the

EIR

documentation

problem, operations

management

issued night

orders describing

the event

and discussing

the

need for more

attention to detail in documenting surveillance test

results.

The licensee

documented this event in LER 95-08 which is

closed in paragraph 3.f.(2) of this report.

The licensee

also reported

the check valve deficiency in accordance

with

10 CFR 21.21.

The inspectors

found the logs

and other facility records to

be legibl'e

and well organized,

and to provide sufficient

information on plant status

and events.

The inspectors

found clearance

tagouts

to be properly implemented.

The

inspectors

identified one violation in this area.

(2)

Facility Tours

and Observations

Throughout the inspection period,

the inspectors

toured the

facility to observe activities in progress,

and attended

several

licensee

meetings

to observe

planning

and management

activities.

Inspectors

made

some of these

observations

during backshifts.

During these tours,

the inspectors

observed

monitoring

instrumentation

and equipment operation.

The inspectors

also verified that operating shift staffing met

TS

requirements

and that the licensee

was conducting control

room operations

in an orderly and professional

manner.

The

inspectors

additional,ly observed

several shift turnovers to

verify continuity of plant status,

operational

problems,

and

other pertinent plant information.

Licensee

performance

in

these

areas

was satisfactory.

The inspectors

identified no violations or deviations

in the

facility tours

and observations

area.

Effectiveness

of Licensee

Control in Identifying, Resolving,

and

Preventing

Problems

(40500)

Condition Reports

(CRs) were reviewed to verify that

TS were

complied with, corrective actions

and generic

items were

identified,

and items were reported

as required

by 10 CFR 50.73.

Several

CRs documenting

personnel

or process

errors

were generated

during the refueling outage.

While the numerous

CRs indicated

that the licensee's

threshold for documenting

nonconformances

was

relatively low,

some of these

CRs described

incidents that

warranted additional

management

attention in the area of work

performance

and clearances.

The following incidents

documented

in

CRs were noteworthy:

Operator error in conducting the Loss of Offsite Power/LOCA

sequencing

test resulted

in the "A" RHR pump starting twice

in 20 seconds,

as discussed

in paragraph

4.b.(2) of this

report.

Due to

a process error, operators

inadvertently placed

SG

PORVs

"A" and

"C" under clearance.

Per the licensee's

shutdown risk assessment,

the valves were

assumed

to be part

of a key safety function available during cold shutdown,,

maintaining the

SGs

as

a diverse

decay heat

removal

method.

When operators

realized the error, the "A" and

"C" SG

PORVs

were returned to functional status.

Fortunately,

defense

in

depth

was not compromised

as the

RHR pumps were both

NRC Generic Letter 88-17,

and in service at the time.

Upon installing an inappropriate

clearance,

operators

isolated

instrument air to the containment building, thereby

isolating the normal

CVCS letdown flowpath.

The clearance

also caused

a service water header

discharge

isolation valve

to unexpectedly

close, essentially

removing

one train of

ESW

from service,

Fortunately,

RCS letdown was aligned to the

RHR system at the time which eliminated the potential for

unexpected

RCS heatup.

Operators

promptly restored

the

service water header

by placing the normal service water

system in service,

The above incidents,

including the inoperable

CSIP event discussed

in section 3.a.(1), all occurred during the first few days of the

outage.

While errors like these

were reduced

as the outage

continued,

other performance deficiencies

surfaced

(improperly

restored

clearances,

poor

FME controls) which warranted

increased

management

attention in this area.

Refueling Activities (71707)

The inspector

observed

fuel offload and reload activities in

accordance

with fuel handling procedures

FHP-014,

Rev.6,

Fuel

and

Insert Shuffle Sequence,

and

FHP-020,

Rev. 7/3, Refueling

Operations.

Fuel handling equipment,

including the refueling

bridge crane,

hoist,

and load cell

had

been properly tested,

inspected

and calibrated prior to fuel movement,

as required

by

plant procedures.

The fuel handling equipment

performed well

during the evolutions.

Operators

mairitained the refueling cavity

water level at

23 feet

above the reactor vessel

flange during fuel

movement.

The licensee's

FME program

was in effect, with areas

around

and

above the refueling cavity properly controlled

as

FME

boundaries.

An

FME coordinator signed

people

and equipmeht in and

out of the

FME zone

as required

by plant procedures.

Potentially

loose articles

were properly tied off.

The inspector

observed

that the fuel movement

was directly supervised

by

a licensed

senior reactor operator,

as required

by TS 6.2.2d.

Licensee

and

'ontractor personnel

performed these

core manipulations

in

a

skilled and professional

manner.

Midloop Operations

(71707)

Due to continuing work in the steam generators,

the plant

had to

go into midloop operations after core reload during the weekend of

September

30.

The inspectors verified that midloop and reduced

inventory activities were conducted

in accordance

with

expectations

contained

in

"Loss of Decay

Heat Removal."

Specifically, the inspectors verified that

procedural

controls were in place

and certain

systems

were

available throughout the operation.

Additionally, the inspectors

ascertained

that operators

were trained

and pre-briefed

on the

evolution;

and were

aware of associated

risks.

Operators

received control

room training on midloop operations

just days prior to the evolution.

Additionally, pre-job briefings

were conducted for each

involved shift.

Procedures

covering the

evolution included General

Procedure

GP-08,

Draining the Reactor

Coolant System;

and

OMP-004, Control of Plant Activities During

Reduced

Inventory Conditions.

These

procedures

required at least

two independent

core exit temperature

indications,

two independent

reactor

vessel

water level indications,

and

two additional

means

of adding.,inventory to the

be available.

Containment closure

requirements

were conta'ined

in OST-1091,

Containment

Closure Test,

Weekly Interval;

and OST-1034,

Containment

Penetrations

Test,

Weekly.

The inspectors verified that all system availability and

containment closure requirements

were met prior to and during

reduced

inventory operations.

Additionally, only two of the three

steam generators

had nozzle

dams installed,

so the reactor vessel

was adequately

vented.

The inspector

concluded that the licensee's

controls for midloop

operations

were adequate.

Additionally, operators

performed

draindown activities well.

Plant

Response

to .Fire Announcement

(71707)

The inspectors

observed

plant response

to

a perceived

switchgear

fire..

On September

29, during

a containment

spray actuation test

procedure,

an Asea

Brown Boveri Model

LK-16 breaker failed to trip

open

as required.

This breaker,

located

in non-safety related

switchgear cubicle

1D1-4C,

served

a containment pre-entry

purge

fan,

E-5B, which was

supposed

to trip on low flow following the

containment

spray actuation.

Personnel

observed

smoke

coming from

the breaker cubicle

and communicated this to the main control

room.

After control

room personnel

sounded

the plant fire alarm,

the shift supervisor

announced

the location of the "fire" and

requested fire brigade

response.

When the inspector arrived at

the switchgear,

there

was

no fire and personnel

had racked out the

breaker.

There

was

a burning smell

and personnel

explained that

there

had

been

no fire, but the trip coil in the breaker

had

overheated

and released

smoke into the area.

This had

been

a

recurring problem over the years with 480 volt LK-16 breaker trip

coils.

Over the last two refueling outages,

the licensee

replaced

all LK-16 safety-related

breakers

and frequently cycled non-safety

with a Siemens

model.

This breaker

was not

considered

a frequently cycled breaker

and

was not replaced.

The plant fire brigade

responded

to the control

room announcement

in a timely manner,

The inspector

concluded that the control

room's

prompt response

and cautious

actions regarding the

perceived "fire" was excellent.

Review of LERs (92700)

'(1)

(Open)

LER 95-007-00,

Inadvertent Start of the Turbine

Driven

AFW Pump/Unplanned

ESF Actuation and Identification

of an Additional Related Test Deficiency.

This

LER discussed

a procedural

deficiency that, during

an

"A" train safety

bus undervoltage

relay logic test,

caused

an ina'dvertent start of the turbine driven

AFW pump

and

resultant

feeding of the steam generators.

During the

investigation of the

pump actuation,

the licensee

discovered

another reportable

procedural

deficiency related to testing

of undervoltage

relays.

Both items were reported

on

LER

95-07

and are discussed

below.

On September

1, plant personnel

performed procedure

HST-E0034,

6.9KV Emergency

Bus,

1A-SA Under Voltage

(Loss of

Voltage)

Channel Calibration.

The plant was in Mode

1 at

approximately

75% reactor

power and the procedure

was

a post

maintenance

test following calibrations

on each of three

6.9kV bus

1A-SA undervoltage

relays.

The procedure called

for depressing

a test push-button

which caused

actuation of

both the undervoltage

lockout relay

86UV and the test

lockout relay 86T.

The 86T test relay blocked signals

from

the

86UV relay

and its associated

relays except for a signal

from relay

86UVX to the

TDAFW pump steam

supply valve,

1HS-

70.

Since that signal

was not blocked,

and the logic for

opening the valve

on

a bus undervoltage

was satisfied,

the

valve stroked

open

and provided

steam to the Terry turbine.

During an investigation into the above event,

licensee

personnel

discovered

another

TDAFW pump testing deficiency

related to the

86UVX relay.

Specifically,

TS 4.3.2. 1 and

TS

Table 4.3-2 contained

monthly Trip Actuating Device

Operational

Test

(TADOT) requirements

applicable to both the

motor driven

AFW pumps

and the

TDAFW pump.

The motor driven

pump requirement

was covered

by procedure

OST-1124,

6.9kV

Emergency

Bus Undervoltage Trip Actuating Device Operational

Test Monthly Interval

Modes 1-2-3-4, which had personnel

visually verify that the

86UV relay rolled during testing.

Plant procedure writers incorrectly assumed

that the turbine

driven

pump was also covered

by visual observation of the

10

86UV relay,

and did not understand

that the associated

86UVX

relay was also in the starting circuit.

Thus, the monthly

test procedure

did not contain directions to verify

actuation of the

86UVX relay,

and the monthly TS requirement

was never covered.

Licensee

personnel

determined that the root cause of both

events

was procedural

error.

Related to the inadvertent

pump actuation,

plant surveillance

procedures

generally

contained

mode restrictions

and statements

cautioning

personnel

on plant conditions which may affect test

performance.

The bus undervoltage test procedure

HST-E0034

allowed the test to be performed in Hodes

1 through 6,

inclusive,

and contained

no precautions

describing

what

would happen if the test

was performed in Hodes

1 though

4

with steam available to the turbine.

The test

was normally

performed in Hodes

5 and

6 with no plant steam

such that

when valve IHS-70 opened,

the

TDAFW pump would not start.

Because of the procedural

omissions,

personnel

performing

the procedure

on September

1 were unaware of the potential

pump start.

The safety significance of both issues

was minimal.

There

were

no adverse

affects

on safe plant operation,

no

pump

damage,

and

no resultant inoperability of safety

systems

following the inadvertent

TDAFW pump start.

Operators

in

the control .room secured

AFW flow to the steam generators

in

a timely manner.

Although the

86UVX relay was never

verified on

a monthly basis

as required

by TS, its actuation

on bus undervoltage

was verified every

18 months

by

deenergizing

the safety

bus during the TS-required

EDG

operability tests.

The licensee's

corrective actions will include revising the

procedures

to correct the surveillance test deficiencies.

This

LER will remain

open pending licensee

completion

and

inspector review of corrective actions.

(Closed)

LER 95-008-00,

"B" Charging/Safety

Injection

Pump

was Returned to Service Prior to Required

Acceptance

Testing,

Resulting in Technical Specification Violation.

This inspector identified violation was discussed

in

paragraph 3.a.(l) of this report.

The

LER is closed

and the

licensee's

corrective actions will be tracked with Violation

400/95-15-01.

11

g.

Followup

Operations

(92901)

(Closed)

IFI 95-11-01,

guestionable

Position Indication for

Containment Isolation Valve 1SP-209.

The inspector consulted

NUREG-1482, Guidelines for Inservice

Testing at Nuclear

Power Plants,

to determine

the

need for

verifying both the

open

and closed positions for valves having

one

safety function.

In this case,

valve

1SP-209

gave dual

(mid-

position) indication in the control

room on Hay

11 when operators

took its control switch to the open position.

The valve in

question

was

a small

sealed

solenoid valve for which only remote

position indication was available.

The valve's safety function

was to close

on

a containment isolation signal.

Licensee

management

determined that,

since the closed position was never in

question,

the valve remained

from Hay

11 until the

valve's next inservice test

became

due.

At that time both the

open

and closed positions

would need verification for stroke

timing as required

by ASHE Section

XI Inservice Testing

Requirements,

and

implemented

by the licensee's

program procedure

ISI-203,

ASME Section

XI Pump

and Valve Program Plan.

From the review of NUREG-1482,

the inspector determined that

no

additional verification was required for the valve to remain

on or after Hay 11.

Stroke time testing

on June

12,

which included timing the valve stroke from fully open to fully

closed

(based

on control

room indication)

was adequate.

Further

valve operations

did not give the

same

dual position indication.

This item is closed.

Hidloop operations,

refueling activities,

and control

room response

to

a

smoking breaker cubicle were good.

Contractor performance

during core

manipulations

was good..

Personnel

and process

errors

were noted in

other areas

which warranted

increased

licensee

management

attention.

The inspectors

identified one violation in the Operations

area which was

significant because it involved

a situation where operators

were not

aware of the inoperable

status of the "B" CSIP,

causing

them to place it

in service

on September

2 prior to it being properly tested.

MAINTENANCE

Maintenance

Observation

(62703)

The inspector

observed

the maintenance

and reviewed the work

packages

for the following maintenance

activities to verify that

correct equipment

clearances

were in effect, work requests

were

issued,

and

TS requirements

were being followed.

12

WR/JO 95-ACAYI, Remove Reactor

Head Before Core Offload

Prior to fuel offload,

on September

11 the inspector

observed

personnel

removing the integrated

reactor vessel

head

and placing it on its storage

stand located

on the

refueling floor.

This evolution was performed in accordance

with procedure

CM-M0094, Integrated

Reactor

Vessel

Head

And

Upper Internals

Removal,

by both licensee

and contractor

personnel.

Personnel

were stationed

on the refueling

operating

deck

and at the refueling cavity floor ensuring

that the head lifted smoothly without snagging

guide studs,

the currently stuck stud,

or upper internals

components.

Once the

head

was

removed

and the upper internals

exposed,

personnel

quickly evacuated

the refueling cavity in keeping

with ALARA practices.

After plant personnel

removed the

head

from the cavity and

hoisted it over the operating

deck en route to the storage

stand,

the inspector

noted that

no one verified that the

IRVH was lifted a maximum of 12 inches

above the floor as

required

by precautions

in the procedure.

It appeared

to

the inspector located

across

the refueling cavity

approximately

50 feet away, that the head

was slightly more

than

12 inches off the ground.

During the Spring

1994

refueling outage,

contractor

personnel lifted the

head

more

than

2 feet off the ground to clear

a handrail

located

on

the refueling floor.

Last year's

action

was contrary to the

procedural

precaution

and resulted

in an Adverse Condition

Feedback

Report.

Because

the

head weighs approximately

180

tons,

the 12-inch limitation was

imposed for heavy load drop

considerations.

After the September

11 head-lift, the

inspector discussed

this year's

observation with licensee

management

who documented it in

a outage-improvement

CR.

Subsequent

IRVH manipulations

were performed with plant

personnel

verifying the

head to be

no more than

12 inches

off the ground while outside the cavity.

The inspector also noted

a few occurrences

of inappropriate

industrial safety acts

such

as individuals not tying off to

safety

ropes while standing

near the cavity.

These actions

were also noted

by the licensee's

NAS inspector at the job

site.

The

NAS inspector

was aggressive

in reminding workers

of safety requirements.

Despite the industrial safety

incidents

and the 12-inch verification issue,

the inspector

concluded that the overall

head lift was

done well.

WR/JO 95-ADIS1, Replace Battery

Bank 1A-SA

The inspectors

observed activities while the licensee

changed

out the sixty-cell safety-related

emergency

battery

1A.

The shop

had previously sent personnel

to the Robinson

plant to gain experience

by participating in a similar

13

activity there.

Based

on that experience,

the shop

had set

up

a small forklift in the battery

room to move the cells

between

the rack and

a conveyer extending

from the doorway

to

an area clear of the switchgear.

Battery cells

wer e

transferred

between

the conveyer

and turbine building

mezzanine

using

a small cart.

The licensee

had found, at

the Robinson plant, that carts with a simple swivel front

axle assembly

tended to turn over,

so they procure'd carts

with tierod-type steering for the Harris changeout.

Observed activities were being performed carefully and were

well controlled.

Subsequent

testing is discussed

in

paragraph

4.b.(4) of this report.

The applicable

vendor manual

stated that, if lubrication was

needed while sliding cells across

the plastic tray rail

covers,

use plain unscented

talcum powder.

This was to

preclude

long term chemical

reactions

between

powder

ingredients

and the polycarbonate

battery cell cases.

The

inspector

observed that, during removal of the old cells

from the old rail covers,

the licensee

was using

a barber

shop type powder with a number of ingredients - including

a

fragrance.

This had

been provided

by the system engineer.

After notification, the shop

ceased

using it during the

removal

process

and did not use

powder while installing the

new cells

on top of new rail covers,

thus reducing future

operability .uncertainty.

WR/JO 95-ABUG5, Containment

Equipment

Hatch Closure

Time

Test

The inspectors

observed

the licensee reinstall. the

containment

equipment

hatch

as

a "time test" to establish

a

baseline for future outages

when there

may be

a need to

conduct mid-loop operations

with the equipment

hatch

open.

The equipment

hatch

had not been

opened

since original

licensing

because

the personnel

hatch

was large

and

accommodated

most equipment.

During this outage,

the

equipment

hatch

was opened to pass

RCP deck plugs

and the

reactor cavity permanent

seal ring.

The hatch reinstallation

was controlled by procedure

CN-

N0100,

Rev. 3/2,

Containment

Equipment Hatch

Removal

and

Replacement,

sections

7.4 for immediate closure

and 7.3 for

normal closure'.

" Immediate closure" would result in the

hatch being closed

by 4 specific bolts (of 36).

The post-

trial assessment

was very good

and contained

many good

points for consideration,

As expected for a first-time

evolution, the test

showed that minor coordination

improvements

could

be readily made; that certain steps,

such

as platform removal, did not have

back

up provisions;

and

that using more than the TS-required

4 bolts might be

necessary

so that the remaining bolt holes would be

adequately

lined up in case additional bolts or full closure

were subsequently

necessary.

The licensee

did not have

a

need for the "immediate closure" provisions during this

outage.

The inspectors

had

no further comments

on this

test,

In general,

the performance of work was satisfactory with proper

documentation

of removed

components

and independent verification

of the reinstallation.

The inspectors identified no violations or

deviations in this area.

Surveillance

Observation

(61726)

The inspector

observed

several

surveillance tests to verify that

approved

procedures

were being used, qualified personnel

were

conducting the tests,

tests

were adequate

to verify equipment

operability, calibrated

equipment

was used,

and

TS requirements

were followed.

During the recent refueling outage,

the inspectors

observed

several

18-month

TS surveillance tests,

including the

following:

(1)

OST-1813,

Rev.

5,

Remote

Shutdown

System Operability.

This procedure partially satisfied

requirements

contained

in

TS 3/4.3.3.5,

Remote

Shutdown 'System.

The procedure

verified that transfer switches, Auxiliary Control

Panel

(ACP) controls,

and Auxiliary Transfer

Panel

controls were

operable for those

components

required

by the

SHNPP Safe

Shutdown Analysis to remove decay heat,

control

inventory through normal charging,

control

RCS pressure,

control reactivity,

and

remove decay heat via the

RHR

system.

The inspector

observed

portions of Test

C (section 7.3) of

this procedure,

which tested

the "B" train transfer panels,

TP-1BSB

and ATP-lBSB,

and associated

ACP control switches.

As directed

by the procedure,

operators

placed

each required

transfer

panel

switch in the

TRANSFER position

and later

verified that

ACP control switches

operated their respective

safe

shutdown

components.

Prior to the test performance,

as

an operator aid, plant personnel

placed

STAR placards

around

each control switch to be cycled,

ensuring that operators

cycled the right components

per the procedure.

While there

were

some unexpected

occurrences

during the procedure,

including blown-out indicating light bulbs

on the

ACP,

and

unanticipated

annunciators

and actions regarding the

ESCWS

"

chiller condenser,

the few obstacles

were easily resolved

and the test

was successfully

completed.

The inspector

noted

good personnel

performance

during this surveillance

test.

15

OST-1823,

Rev. 8,

1A-SA Emergency

Diesel

Generator

Operability Test,

18 Honth Interval, Section 7.4.

This test procedure partially satisfied

18 month

surveillance

requirements

contained

in TS 4.8. 1. 1.2f.

Steps

in section 7.4 of the procedure verified that,

on

a

simulated loss of off-site power in conjunction with a

safety injection test signal,

the "A" emergency

bus

deenergized,

load shedding

occurred,

the "A" EDG started,

emergency

busses

were reenergized

in a timely manner,

and

emergency

loads

were energized

through the sequencer.

An

- essential

element of the test

was operators

simultaneously

simulating containment

spray actuation

and SI si.gnals,

while

manually tripping the normal electrical

feed from auxiliary

bus

D to emergency

bus A-SA.

During the initial performance of this test

on September

3,

operators

erroneously

performed the simulations first, then

opened

the normal circuit breaker.

This caused

the

sequencer

to start out on the incorrect

sequence

program,

then reset

and reinitiate using the correct program.

The

"A" RHR pump started

twice in about

a twenty second

interval.

The "A" containment

spray

pump failed to start

the

second

time.

The licensee

determined that the test

performance

did not satisfy the procedure

and that starting

the

RHR pump twice in twenty seconds

was contrary to

technical

requirements

in the manufacturer's

manual.

The

licensee

suspended

the test until September

4 ~

Having suspended

the test,

the l'icensee

evaluated

the

RHR

pump condition in

ESR 9500738,

Revisions

0 and

1

and

evaluated

the test control situation in

CR 95-2012.

These

evaluations

concluded that the

RHR pump

had not been

damaged

but that the test

should

be rerun.

The inspector

reviewed

the

ESR

and concluded that it reached

correct conclusions.

On September

4 morning, the inspector

observed

the test

being set

up again.

The prebriefing in the control

room was

well performed

and personnel

were dispatched

to stations.

The "B" RHR pump was already

stopped

and the

"A" pump was

stopped for the test,

allowing the reactor core to heat

up

at 30 'F per hour.

When the test participants did not

report to their stations

promptly, the

SCO aborted

the test,

restarted

A RHR pump to reestablish

core cooling,

and

initiated management

actions to improve personnel

performance.

The inspector

noted that the SCO's

response

was prompt

and appropriate,

Test section 7.4 was

successfully

completed later that day with all components

starting

as expected.

OST-1825,

Rev.

8, Safety Injection:

ESF Response

Time, Train

A 18 Nonth Interval

On

A Staggered

Basis,

Nodes 5-6.

16

This test procedure satisfied various

18 month

TS

surveillance

sections

requiring safety-related

equipment

response

to .test signals.

During the test,

the inspector

observed that components

actuated

as required.

The near

200-page

procedure

contained

some minor inadequacies,

and

there were

some personnel

errors

noted during its

performance.

Some of these resulted

in the procedure

having

to be temporarily revised

so that missed

elements of one

procedure

section

could be captured

in subsequent

sections.

In one case,

containment

fan cooler switches

were placed in

the wrong pretest position,

preventing the fans from

starting

on the SI signal

and requiring operators

to

reverify the fans would start in a later section.

In

another

case,

as discussed

in paragraph

4,c below,

a special

temporary procedure

(OST-9013T)

had to be developed

to

retest certain

AFW system valves.

The inspector,

however,

considered

the number of errors during OST-1825 performance

to be minimal considering

the procedure's

complexity.

Overall, licensee

performance

during this surveillance test

was adequate.

Additionally, plant equipment

responded

properly to the SI signals.

(4)

MST-E0027,

1E Battery Service Test,

[1A Battery]

MST-E0013,

1E Battery Performance

Test,

[1A Battery]

MST-E0012,

1E Battery 18-Month Test, [lA Battery]

CM-E0001, Station Battery Equalizing Charge,

[1A Battery]

These

procedures

were associated

with the installation

and

placing into service

the replacement

1A-SA battery.

The

inspectors

observed that procedures

were well run

and data

was properly collected.

During the first attempt to perform

MST-E0027,

shop personnel,

recognizing that the computerized

test

equipment

was not controlling the battery load

properly,

stopped

the test,

conferred with the test

apparatus

vendor,

and corrected

the setup.

The test

was

subsequently

performed without incident.

The inspectors

found satisfactory surveillance

procedure

performance with proper

use of calibrated test equipment,

necessary

communications

established,

notification/authorization

of control

room personnel,

and knowledgeable

personnel

having

performed the tasks.

The inspectors

observed

no violations or

deviations

in this area.

Effectiveness

of Licensee

Control in Identifying, Resolving,

and

Preventing

Problems

(40500)

Condition Report

CR 95-02534

was generated

after

an inadequate

surveillance test procedure

resulted

in

a partial safety injection

on October 5.

Temporary procedure

OST-9013T,

Temporary Procedure

for Testing the

MDAFW Pump

FCVs Auto Open Feature

From K635,

was

written to verify that the

AFW flow control valves would open

on

a

17

safety injection signal.

The valves'uto

open feature

was

originally supposed

to have

been tested earlier in the week during

the performance of safety injection test procedure

OST-1825.

However,

because

of an error in that procedure,

operators

did not

verify the valves

opened.

Specifically, the procedure

did not

take into account

the short duration (twenty seconds)

of the

valves'uto

open signal.

By the time OST-1825 directed operators

to verify the valves

opened,

the twenty second

signal

was gone

and

the valves

had reclosed.

Retest

procedure

OST-9013T

on October

5 directed

personnel

to

install jumpers

and lift leads,

ensuring all logic was satisfied

to open the valves

on

a safety injection signal.

Additionally,

the lifted leads

prevented

the signal

from actuating other safety

injection components,

such

as the emergency

safeguards

sequencer.

The procedure directed operators

to install

a switched jumper

between

two relay contacts

which,

upon closing the switch, would

initiate

a safety injection signal to the valve controllers.

Operators writing the procedure did not understand

that

a latching

r'clay in the circuit would necessitate

temporarily installing

another

jumper during test restoration

to remove the SI signal.

The procedure writers

assumed

that simply opening the switch on

the actuating

jumper would reset SI.

As directed

by the

procedure,

after the valves were satisfactorily tested

and with

the safety injection signal still present,

plant personnel

relanded

the previously lifted leads.

This action started

the

"B"

train Emergency

Safeguards

Sequencer

and sent start signals to

several

components

including the "B" RHR and

CCW pumps.

After

consulting with cognizant

engineers

and associated

drawings,

personnel

were able to remove the SI signal

and secure

the

affected

equipment.

The inspectors

noted that all equipment

started

as required following the partial SI.

Additionally, no

components

were

damaged

following the unexpected

actuation.

During subsequent

discussions

with licensee

personnel,

the

inspector determined

the root cause of this event to be inadequate

procedures

caused

by the operators

who wrote, reviewed,

and

approved

the procedure failing to fully understand

the equipment

function.

10 CFR 50, Appendix B, Criterion V, Instructions,

Procedures,

and

Drawings, requires,

in part, that activities affecting quality

shall

be prescribed

by documented

instructions,

procedures,

or

drawings, of a type appropriate

to the circumstances.

The

licensee's

Corporate guality Assurance

Program Hanual,

which

implements

the regulatory requirement,

states

in section 6.3.6

that provisions shall

be

made for the review of procedures

required

by plant commitment

by an individual knowledgeable

in the

area affected to determine

the

need for changes.

The failure to

have fully knowledgeable

procedure writers and reviewers for

procedure

OST-9013T is contrary to the

above requirements

and

resulted

in an unplanned

and partial safety injection.

18

This is identified as Violation 400/95-15-02,

Failure to Provide

for the Review of a Safety Injection Test Procedure

by an

Individual Fully Knowledgeable

in the System Logic.

The safety significance of this event

was minor.

The

RHR pump

operated

in recirculation

mode,

ensuring

minimum flow and

preventing

pump damage.

The charging/safety

injection

pump was

already operating for normal charging

when the SI occurred.

Operators verified that all equipment started

as required

on the

SI signal,

and were later able to reset SI.

At the close of the

inspection period,

the licensee

was still developing corrective

actions.

This event

was properly reported to the

NRC in accordance

with

10 CFR 50,72 requirements.

A 30 day

LER was pending at the end of

the inspection

periods

Overall,

one violation was identified in the maintenance

and

surveillance

area.

Otherwise,

surveillance

and maintenance

procedures

were performed effectively with only minor issues

requiring resolution.

ENGINEERING

a o

Design

and Installation of Plant Modifications (37551)

ESRs involving the installation of new or modified systems

were

reviewed to verify that the changes

were reviewed

and approved

in

accordance

with 10 CFR 50.59, that the changes

were performed

in

accordance

with technically adequate

and approved

procedures,

that

subsequent

testing

and test results

met approved

acceptance

criteria or deviations

were resolved

in an acceptable

manner,

and

that appropriate

drawings

and facility procedures

were revised

as

necessary.

The licensee

was challenged with many issues

requiring

engineering resolution during the outage.

The following

engineering

evaluations,

modifications,

and/or testing in progress

were inspected.

(1)

ESR 9400013,

Permanent

Cavity Seal

Ring

This design

package

provided engineering

instructions for

installing the

new permanent refueling cavity seal ring.

For previous refueling outages,

the licensee

installed

a

temporary

seal

ring with inflatable bladders

which consumed

a lot of outage

time and personnel

dose.

The

new seal, ring,

which would be permanently

welded to the cavity and reactor

vessel,

would eliminate recurring installation

and removal

hassles.

The

new design would include several

removable

hatch covers allowing proper ventilation for RCS components

located in the reactor cavity annulus

area.

19

Due to fitup problems,

the

new seal ring project was

abandoned

and the licensee

resorted

to using the old

inflatable seal ring for cavity floodup prior to core reload

during this outage.

Specific problems

centered

around the

seal

ring not fitting properly between

the reactor vessel

seal

ledge

and the cavity liner.

Additionally, there were

problems

achieving proper clearances

between

the three major.

sections of the ring.

Proper clearances

were necessary

for

welding the three sections

together

and welding the ring to

the cavity liner and vessel

ledge.

Following the unexpected

installation delays

and eventual

project abandonment,

the

licensee initiated

a Condition Report

and

a root cause

investigation into contributing factors.

The inspectors

observed

part of the attempted installation,

reviewed portions of the design

package,

and concluded that

neither poor workmanship nor poor engineering

contributed to

the project failure.

The design

package

was adequately

detailed with specific installation instructions,

adequate

drawings,

and

a good unreviewed safety question

determination.

With a piece of equipment

as large

and

complex

as the

new cavity seal ring, which was manufactured

offsite by

a vendor, fitup problems like these

were

possible.

Licensee

management

informed the inspector that

the permanent

seal

ring installation would be attempted

again during the next refueling outage.

ESR 9500876,

Stuck Reactor

Vessel

Closure

Stud

0'40

This

ESR documented

the acceptability of a reactor vessel

head

stud

840 which became

stuck during reinstallation

on

October

2.

When the stud

became

stuck,

personnel

could not

obtain full stud

engagement

into the reactor vessel,

Actual

stud

engagement

was approximately 6.625 inches vice the

standard

of 7,375

inches for 5-13/16 inch diameter studs.

The engineering

evaluation

considered

the engagement

deviation

and the fact that the stuck stud could not be

removed for required

ASHE Section

XI inspection.

From

calculations,

engineers

determined that the stud could still

be normally tensioned

along with the remaining studs,

and

the stresses,

either

from the tensioning or the pending