ML16343A311

and associated

tenting installed .in

EOG radiator

exhaust

rooms is considered

strong performance.

As

a result,

the

amount of

and tenting

was limited in order to ensure

adequate

airflow

(Section 3,1.1).

~

Contrary to management

expectations,

the results of a surface

contamination

area

(SCA) survey performed to allow maintenance

without

the use of protective clothing was not documented

(Section

6. 1).

Summar

of Ins ection Findin s:

~

Violation 275/9508-01

was identified (Section

3. 1.5).

~

A noncited violation was identified (Section 4.3.3).

LERs 275/95-02,

Revision 0,

and 323/94-013,

Revision 0, were closed

(Section 7).

Attachments:

I

Attachment

1 - Persons

Contacted

and Exit Heeting

Attachment

2

Acronyms

DETAILS

1

PLANT STATUS

(71707)

1.1

Unit

1

Unit

1 began

the report period at

100 percent

power.

On April 21,

1995,

power

was reduced to 50 percent to perform scraping of marine growth from the

circulating water system conduits.

The unit returned to

100 percent

power on

April 24,

1995, following completion of the tunnel

scraping

and operated

at

100 percent for the remainder of the report period.

1.2

Unit

2

Unit

2 began

the report period at

100 percent

power.

On Hay 8,

1995,

power

was reduced for 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to approximately

60 percent at the request of the

system dispatcher.

During the period that power was reduced,

corrective

maintenance

was performed

on Inverter P2000,

which supplies

power to the main

turbine digital electrohydraulic control

system.

Unit 2 operated

at

100 percent for the remainder of the report period.

1.3

Re uest for Notice of Enforcement Discretion

NOED

Due to

Ex iration of

Reactor

Coolant

S stem Heatu

and

Cooldown Limits

~Back round

The licensee's

reactor coolant

heatup

and

cooldown limitations

were developed

based

on

a projected

fluence equivalent to 8 effective full

power years

(EFPYs).

On April 11,

1995,

the licensee

discovered

a

calculational error in the

EFPY calculation which revealed that Unit

1

exceeded

8

EFPYs of operation

on April 8,

1995,

11 days before the previously

predicted date.

Technical Specification

(TS) 3/4.4.9. 1, "Reactor Coolant

System - Pressure/Temperature

Limits," Figures 3.4-2,

"Reactor Coolant

System

Heatup Limitations

Applicable

Up to 8 EFPY,"

and 3-4.3,

"Reactor Coolant

System

Cooldown Limitations

Applicable

Up to 8 EFPY," were

no longer

applicable

when Unit

1 exceeded

8

EFPYs

~

The licensee

had previously submitted

License

Amendment

Request

(LAR) 94-09 to

revise

TS 3/4.4.9.

1 applicability beyond

8 EFPYs,

but the

LAR submittal

had

not been

approved

by the

NRC.

On April 12,

1995,

the licensee

performed

an

operability evaluation

which determined that the existing heatup

and cooldown

limits specified in TS 3/4.4.9.

1 were applicable

up to

12

EFPYs.

The licensee

then requested

enforcement discretion until

1200

PDT on April 21,

1995,

not to

en'force compliance with TS 3/4.4.9.

1 and to allow continued

use of the current

TS figures until revised figures were approved

as

a part of LAR 94-09.

1.3. 1

EFPY Calculation Error

Plant Engineering

Procedure

R-5, Revision 0,

"Burnup Tracking," is used to

calculate effective full power days

(EFPDs)

and is normally performed

on

a

monthly basis.

Using the data

from this procedure

Reactor

Engineering

had

~

~, ~

projected that

8

EFPYs would be exceeded

on April 19,

1995.

The cumulative

calculation

had,

in error,

not included

12 days of coastdown

at the

end of

Unit 1's Cycle 5, which added

another

10

EFPDs to the total.

When the

10

EFPDs were included in the

EFPY calculation

on April 11,

1995, it was noted

that Unit

1 had exceeded

8 EFPYs of operation

on April 8,

1995.

1.3.2

NRC Review

The

NRC evaluated

the licensee's

safety justification assertions

as

a part of

the review of LAR 94-09

and concluded that the

use of the existing heatup

and

cooldown figures

was acceptable

until termination of the Notice of Enforcement

Discretion

(NOED).

The

NRC granted

the enforcement discretion verbally on

April 12,

1995,

at 2:58 p.m.

EST.

On April 13,

1995, at 4:35 a.m.

EST,

LAR 94-09 was issued

approving the licensee's

submittal.

The licensee

formally exited the

NOED on April 14,

1995,

at 9:08 a.m.

PDT after receiving

a

copy of the approval.

1.3.3

Safety Significance

Due to fast neutron irradiation of the reactor vessel

beltline, the nil-

ductility-transition temperature

changes

over the life of the reactor vessel.

Due to implementation of very low leakage

core loading patterns,

the reactor

vessel

peak flux had

been

reduced.

Reactor

vessel

neutron irradiation

measurements,

which utilized two surveillance

capsules,

confirmed irradiation

levels to be less

than projected.

As

a result,

the nil-ductility-transition

temperature

projections for 12

EFPYs were lower than those previously

submitted for 8 EFPYs.

The licensee

performed

an analysis

which established

that the heatup

and cooldown limitations applicable

up to 8

EFPYs were

applicable

and conservative

through

12

EFPYs.

This

NOED involved no

violations of regulatory requirements.

1.3.4

Conclusion

The

NRC concluded that the exercise of enforcement discretion

was warranted

since this action involved no effect on safe plant operation

and,

as

a result,

had

no adverse

impact

on public health

and safety.

2

OPERATIONAL SAFETY VERIFICATION

(71707)

2. 1

Auxiliar

Feedwater

AFW

Safet

S stem Walkdown

During

a routine walkdown of portions of the

AFW system,

the inspector

noted

that

a pipe cap installed

on

a vent installed

on the steam supply to the steam

driven

AFW pump was different from the type of pipe cap typically used

on

steam lines.

The connection

appeared

to have

a swagelock

type test connection

fitting installed

on the cap.

e

0

2. F 1

AFW System Configuration Requirements

After the inspector identified this configuration to the licensee, it was

determined that the reference

piping Drawing 063930,

"Vents, Drains,

and Test

Connections,

Two Inches

and Smaller," Revision 7, contained

the applicable

requirements

and did not allow for the installed configuration.

The licensee

initiated

an action request

(AR) to document the problem.

The inspector

had

noted several

similar deficiencies with other systems

during the previous

inspection period.

The licensee

had acknowledged

the inspector's

observations,

but had not fully implemented

actions to identify additional

areas

that

may have this problem.

2. 1.2

Safety Significance

The licensee

concluded that this configuration resulted

in no operability

concerns

since the cap

was installed

downstream of the code break boundary.

The licensee's

evaluation

appeared

to have considered

the appropriate factors.

2. 1.3

Conclusion

The installed pipe cap

was not in accordance

with the applicable

drawing

requirements.

The licensee

has initiated actions to resolve this

and other

discrepancies

of this nature.

The licensee's

evaluation

indicated that,

although this installation

was not specifically authorized

by drawing, it was

acceptable.

The licensee

is revising the drawing to allow this type of cap to

be used

and plans to further investigate

the cause of this configuration

control problem.

The licensee's

actions to investigate

and resolve this issue

appear to be adequate.

3

PLANT MAINTENANCE

(62703)

During the inspection period,

the inspector

observed

and reviewed selected

documentation

associated

with the maintenance

and problem investigation

activities listed below to verify compliance with regulatory requirements,

compliance with administrative

and maintenance

procedures,

required quality

assurance/quality

control department

involvement,

proper

use of safety tags,

proper equipment

alignment

and

use of jumpers,

personnel

qualifications,

and

proper retesting.

Specifically, the inspector

reviewed the work documentation

or witnessed

portions of the following maintenance

activities:

Unit

1

AFW Pump 1-1; Repair

FW-1-115 leak

Battery Charger

1-2 Capacitor

Change-out

Replace

Coupling

Hub on Spent

Fuel

Pool

Pump

1-1

EDG 1-1 Starting Air Compressor

Maintenance

Repair of Pyrocrete

in

EDG Radiator

Exhaust

Area

0

Unit 2

~

Repair of Pyrocrete

in

EDG Radiator

Exhaust

Area

3. 1

P rocrete

Re airs in

EDG Radiator

Exhaust

Rooms

~Back round

Pyrocrete fire barrier material installed in the

common exhaust

plenum of the

EDG radiator

fan exhaust

area,

for both Units

1

and 2,

was noted

to have

been

damaged

following a recent

storm.

The damage

was evaluated

by

the licensee

to potentially effect the design function of the pyrocrete

and,

therefore,

required repair.

A roving firewatch was in effect for the areas

with the damaged

pyrocrete at the time the water

damage

was discovered.

The

licensee

concluded that

no additional

compensatory

actions

were required for

the degraded fire barriers.

Prior to commencing

the repairs,

the pyrocrete

was

sampled

and determined

to contain asbestos.

The installation of

and tenting

was required for the removal of pyrocrete containing

asbestos.

t

3. 1. 1

Evaluation of Unit

1 Scaffolding

and Tenting Installation

On March 8,

1995, prior to installation of the scaffolding

and tenting,

System

Engineering

was requested

to evaluate its effect

on

EDG air flow.

During

operation,

radiator exhaust air discharges

through separate

fan rooms

on the

107 foot elevation

and into

a

common discharge

room open

down to the

85 foot

elevation.

The

common discharge

room opens to the outside through screened

and louvered vents

in the side of the turbine building.

System Engineering

initially provided verbal

assurance,

followed later by

a written response

that

the installation of the scaffolding would not significantly reduce the

radiator exhaust air flow.

After a portion of the work was completed,

the

tenting was

removed

and the scaffolding

was left installed for the remaining

repair work.

The basis for System Engineering's

evaluation

was questioned

by an

ISEG

engineer.

As

a result of the

ISEG engineer's

questions,

System Engineering

and Nuclear Engineering

Services

performed further reviews of the installed

and determined that there

was

a potential for a significant

reduction of

EDG radiator exhaust air flow.

As

a result;

the

amount of

scaffold planking was limited to,three

planks.

This required

removal of

five planks since,

at the time, there

were eight planks installed

on the

scaffolding.

The basis for the decision to reduce

the

amount of planking was

engineering

judgement.

At that time,

a detailed analysis

had not been

performed.

Subsequently,

the licensee

conducted

a meeting to discuss

the

EDG air flow

concerns.

During the meeting,

the licensee identified that there

was margin

for radiator cooling based

on ambient temperature,

but there

was

no margin in

the

EDG radiator air flow.

At this point, the licensee

removed the remaining

planks

from the scaffolding until

a detailed analysis

could

be performed to

evaluate

the effect of the scaffolding

and tenting

on

EDG radiator exhaust air

0

flow.

Analysis results

revealed that, with the existing ambient temperature

and wind conditions during the period,

the scaffolding

and tenting were

installed

such that the

EDGs would not have overheated.

In the calculations

for determining operability, the outside

ambient temperature

was required to

be less

than 69'F for the

EDGs to have

been considered

operable.

3. 1.2

Unit 2 Pyrocrete

Repairs

Following the repairs to the Unit I pyrocrete,

similar repair work was

commenced

in Unit 2.

In order to ensure that Unit 2

EDGs remained

operable

during the repairs,

a calculation

was performed prior to commencing

the work

to determine limitations for the scaffolding

and tenting.

The scaffold

planking was limited to three planks

(49 square feet).

The tented

area

used

in the analysis

was

25 square feet.

The tented

area of 25 square

feet

was not

included

as

a limitation in the work package.

Initially, during preparation

for the pyrocrete repairs,

the scaffolding

and

tenting were installed within the limits determined

by the engineering

calculation.

Later, additional tenting

was installed which blocked

approximately

85 percent of the entire area for EDG 2-2 air flow to the lower

vents.

This configuration

was observed

by the

EDG system engineer

who

questioned

the blockage of EDG radiator exhaust air flow.

During

a review of

the installed scaffolding

and tenting, it was noted that the tented

area

exceeded

the

25 square

feet included in the calculation.

At that point, the

licensee

removed the additional tenting.

3. 1.3

Procedural

Controls for Scaffolding Installation

The procedure

which describes

the methods for requesting

and controlling the

staging,

erection,

dismantling,

and modification of elevated

work structures

is Procedure

AD7. ID5, Revision 0, "Elevated

Work Structures."

The procedure

was designed

to minimize the potential for damage to safety-related

equipment

caused

by falling structures

and interference with the operation of such

equipment

caused

by the structure during normal conditions

and seismic events.

The precautions

and the instructions require review of the scaffolding

installation for seismic interactions

which could possibly render safety-

inoperable

and a,check for interferences

which could prevent

access

for operation of components.

The inspector

reviewed the elevated

work structure

requests

which were

used to

authorize

the installation of the scaffolding

and the work orders for the

pyrocrete repairs.

The inspector

noted that these

documents

did not contain

instructions to limit the amount of tenting or scaffold planking.

The

specific size of the scaffolding structure

was listed;

however,

the option to

modify the structure without additional

Engineering

concurrence

was allowed.

3. 1.4

Safety Significance

The licensee

performed calculations

to determine

the operability of EDGs

during the periods that

EDG radiator exhaust

flow was obstructed.

The results

0

indicated that the

EDGs were never inoperable

due to the scaffolding

and

tenting restricting air flow through the radiators..

Due to the lack of proper

planning

and adequate

work instructions,

the potential

existed

under certain

elevated

outside

temperatures

and adverse

wind conditions for the

EDGs to have

been

inoperable.

3. 1.5

Conclusion

The failure to adequately

evaluate

the impact of the pyrocrete repairs

on

operability when preplanning

the work and the failure to provide written

procedures

and documented

instructions

which limited the obstruction of

radiator exhaust air flow is

a weakness.

TS 6.8. 1, states,

in part, that

written procedures

shall

be established,

implemented,

and maintained

covering

applicable

procedures

recommended

in Appendix

A of Regulatory

Guide 1.33,

Revision

2, dated

February

1978.

Appendix

A of Regulatory

Guide 1.33,

Revision

2,

recommends

that procedures

for performing maintenance

which can

affect the performance of safety-related

equipment

should

be properly

preplanned

and performed

in accordance

with written procedures,

documented

instructions,

or drawings appropriate

to the circumstance.

Contrary to these

requirements,

during the period of March

3 through April 5,

1995, for Unit 1,

and April 26 though

May 2,

1995, for Unit 2, pyrocrete repairs

were performed

which affected

the performance of the

EDGs without adequate

preplanning

and

without procedures

and documented

work instructions which were appropriate

to

the circumstance.

This was identified as

a violation of TS 6.8. 1 (275/9508-

01).

4

SURVEILLANCE OBSERVATIONS

(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;

(?)

a technically adequate

procedure

existed for 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.

Specifically, portions of the following surveillances

were observed

by the

inspector during this inspection period:

Unit

1

Surveillance

Test Procedure

(STP) P-AFW-ll, "Routine Surveillance

Test

of Turbine Driven Auxiliary Feedwater

Pump 1-1"

STP

SP S-312S,

"Security System

Emergency

Power Source

and

Load

Transferring

System Test"

STP I-38-A. 1,

"SSPS Train A Actuation Logic Test in Modes

1,

2, 3, or 4"

Unit

2

STP I-36-S4EPT,

"Protection

Set

IV Eagle

21 Partial Trip Board Actuation

Test"

4. 1

AFW Pum

1-1 Surveillance

~Back round

The surveillance

accomplished

a remote

manual

warm start of

turbine-driven

AFW Pump 1-1.

4. 1.1

Equipment Observations

Steam traps

were verified to be properly aligned

and appeared

to be

functioning properly.

A minor packing leak was noted

on

a valve associated

with one of the

steam traps.

An AR was written to document

the leakage.

The

surveillance verified operation of the

steam

admission trip throttle valve.

The trip lever, trip mechanism,

and associated

linkage were noted to operate

freely.

After remotely starting the turbine,

the as-found

speed

was slightly

greater

than the reference

speed

but within that allowed by the surveillance.

The steam supply valves

(FCV-37 and

FCV-38) were stroked

one at

a time and

verified not to affect the turbine

speed (i.e.,

adequate

steam flow through

one supply line was verified).

Steam generator

AFW control valve operation

was also verified during the surveillance.

4. 1.2

Conclusion

The surveillance test verified the capability to perform

a remote

manual

warm

start of turbine-driven

AFW Pump 1-1.

Operators

closely followed procedural

requirements.

4.2

Securit

S stem

Emer enc

Power Source

and

Load Transferrin

S stem Test

~Back round

On April 28,

1995, the inspector

observed

the monthly test of the

security diesel

generator

in accordance

with STP

SP S-312S,

Revision

7C,

"Security System

Emergency

Power Source

and

Load Transferring

System Test."

The inspector

attended

the pretest briefing and accompanied

operators

to the

diesel

generator

room to observe

the performance of the test.

4.2. 1

Security Inverter Display Panel

Deficiency

While observing

the operators verify the system alignment for STP

SP S-312S,

the inspector

noted that, during Step 11.3.2.g,

the operators

stopped

to

obtain direction from the shift foreman prior to continuing with the

procedure.

The step required that the security inverter panel display

indicate that the maintenance

bypass

switch is normal (i.eis the associated

alarm message

LED is off).

This step could not

be completed

as written since

the display panel

had

been previously noted not to illuminate when the

maintenance

switch was placed

in the bypass position.

This problem had

been

documented

on

an

AR.

After the discussion

with the shift foreman,

the

0

-10-

i

operators verified the position of the maintenance

bypass

switch.

The

operators

then annotated

the procedure to indicate the actions

taken.

These

actions

appeared

to be appropriate

and in keeping with management

expectations.

The inspector

questioned

the operators

as to how Step

11.3.

1 had

been

performed,

which required

v rifying that all display messages

were

functioning.

The maintenance

LED had

been

covered

in March 1995,

when

a

nameplate

was installed which referenced

the

AR written on the display panel

deficiency.

The operators

acknowledged

that the maintenance

bypass

LED could

not

be verified as required

by Step

11.3. 1.

Contrary to management

expectations,

the operators

did not stop to evaluate their inability to

perform this procedure

step

as written.

4.2.2

Safety Significance

The operators

were able to adequately verify that the maintenance

bypass

switch was in the proper position for testing the security diesel

generator

with the display panel deficiency.

The security diesel

started

and operated

within the specified limits of the procedure.

4.2.3

Conclusions

The security inverter panel display deficiency

had existed for over

6 months.

The surveillance

procedure

had not been revised to provide instructions

on

how

to accomplish the test with the deficiency.

Each time the surveillance

was

performed,

operators

were left to determine

the appropriate

actions.

While

performing this surveillance,

the operators

were slow to exhibit

a questioning

attitude

when they could not strictly adhere to the

STP.

The licensee

has

since

issued

a change to the procedure

which provides

more specific

instructions regarding

the verification of display panel

indications.

The

licensee's

ultimate actions,

while not particularly timely, appear to have

resolved

the procedural

work around created

by the status

panel deficiency.

4.3

Emer enc

Airlock Interlock Verification

Backcaround

STP II-BE2, "Emergency Airlock Door Interlock Verification," was

performed for Unit

2 on

May 4,

1995.

Following performance of the interlock

verification, the emergency airlock door seals

are required to be demonstrated

operable within 72 hours8.333333e-4 days 0.02 hours 1.190476e-4 weeks 2.7396e-5 months .

On May 10,

1995, during

a review of STP M-8E2 test

results,

the licensee

determined that the testing of the door seals

had not

been

accomplished.

The interlock verification procedure,

STP M-8E2, contained

three specific

steps,

11.2. 16,

11.2. 17,

and 11.2. 18, which referred to the testing of the

airlock seals.

These

steps

had

been

signed

as complete.

No other

documentation

existed that

showed that the test

had

been

completed.

STP

M-

8E2,

Step

11.2. 16, requires that Engineering

be notified to complete testing

of the door seals within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of closing the doors,

or prior to mode 4.

Step 11.2. 17 requires that

a Plant Information Management

System

TS tracking

0

-11-

sheet

be initiated for the Unit 2 emergency airlock door seal test.

Step

11.2. 18 requires verification that the emergency airlock door seals

have

been tested

by STP H-8G.

The licensee

subsequently

discovered that the

individual performing the test

signed off Steps

11.2. 16,

-17 and -18 as being

complete without performing any of the specified actions.

The administrative

reviews of the surveillance

by both the shift technical

advisor

and the shift

foreman did not provide verification that all of the steps

had actually

been

performed.

4.3.

1

Licensee

Actions

Upon Discovery of Hissed Surveillance

After discovering that the testing of the emergency airlock door seals

had not

been

accomplished,

the licensee

performed

STP H-8G, Revision

2,

"Leak Rate

Testing of the

Emergency Airlock Seals."

The test results

were within

specification

and demonstrated

the operability of the seals.

The licensee

investigation

found that the individual,

who had

been

in

containment

during the performance of the test,

signed off the procedure

steps

after he left containment

and signed off more steps

than were performed

due to

his inattention to detail.

The licensee

counseled

the individual according to

their disciplinary program.

4.3.2

Safety Significance

There is no safety significance

associated

with this problem since the testing

performed following the discovery of the problem demonstrated

that the

emergency airlock door seals

were operable

even

though they had not been

tested within the timeframe required

by TS.

4.3.3

Conclusions

The failure to test the emergency air lock door seals,

as required

by STP H-

8E2, Revision

1,

"Emergency Interlock Verification Test," is

a violation of

TS 4.6. 1.3.a which states,

in part, that each

containment air lock shall

be

demonstrated

operable

by verifying the seal

leakage.

Contrary to the

requirements,

operators

failed to perform the required actions of STP H-8E2,

which required testing the emergency air lock door seals following opening of

the air lock doors.

This violation was identified by the licensee.

Following

the discovery of the missed surveillance,

the test

was performed which

verified the operability of the door seals.

A nonconformance

report

was

initiated

on this problem.

Based

upon the licensee's

actions, this violation

is not being cited.

5

ONS ITE ENGINEERING

(37551)

5.1

Pum

2-2 0 erabi1 it

Evaluation

~Back round

Si

Pump 2-2 was replaced

during the last inspection period.

Replacement

of the

pump was performed following a period of degraded

pump

performance.

The decision to replace

the

pump was

made after it failed to

0

-12-

produce

the required total developed

head

(TDH) during periodic surveillance

testing.

Prior to failing the surveillance test,

Engineering

performed

an

analysis of the

pump performance

data

and investigated

potential

mechanisms

for the degradation

of performance

in order to evaluate

pump operability.

5. 1. I

Pump 2-2 Failure

Node Effects Analysis

The failure mode effects analysis

performed

as

a part of SI

Pump 2-2

operability evaluation prior to pump replacement,

determined that there

were

two plausible failure mechanisms

which could cause

the noted

symptoms of

degraded

performance.

The mechanisms

included failure of the 0-ring sea'.s,

which provide

a static seal

between

the

pump stage diffusers

and the

pump

casing,

and the degradation

of wear rings,

which seal

between

each impeller

stage

and it's associated

stationary diffuser.

These failure mechanisms

were

considered

plausible

as the expected

and observed

symptoms of degradation

matched.

Other failure mechanisms

considered

and evaluated

as not being

plausible included:

impeller wear,

boundary valve leakage,

pump motor

degradation,

and inadequate

suction pressure.

The SI

Pump 2-2 operability evaluation

stated that additional

data

was

required to identify a conclusive trend of pump degradation

or

a degradation

rate.

The licensee

stated

they had not performed

more frequent testing of the

pump to determine

the degradation

rate

because

the

ASNE Code Section

XI alert

value of 90 percent of the reference

pump differential pressure

(dP)

had not

been

achieved.

The inspector

noted that the

dP could

and did go below the

TS

required value prior to the licensee establishing

more frequent monitoring.

The inspector

reviewed the previous surveillance test results

and noted that

there

had

been

a degrading

trend toward the

TS value.

The licensee

replaced

the impeller and shaft (rotating assembly)

with a

new

rotating assembly that

had

been

procured

from another utility.

The licensee,

therefore,

had not verified that the impeller locknuts

had

been

coated with

Loctite.

Following the replacement

of SI

Pump 2-2, disassembly

of the

degraded

pump revealed

loosening of the impeller locknuts located at each

end

of the shaft outboard of the impeller.

Loosening of the locknuts allowed for

axial

movement of the impeller which caused

reduced

developed

head.

Industry

experience

indicated that this failure mechanism

had,

in certain instances,

resulted

in the

pump seizing during operation,

The loosening of the impeller

locknuts

had not been considered

as

a potential failure mechanism

in the

licensee's

operability evaluation.

Investigation of component history records

revealed that

an SI

pump

had

previously seized

due to loosening of the impeller locknuts at

DCPP.

Further

investigation of industry experience

revealed that

6 of 24 similar model

pumps

were

known to have failed due to the loosening of the impeller locknuts.

In

response

to the failures,

the

pump vendor revised

the vendor manual

maintenance

procedure

to require the application of Loctite to the impeller

nut threads

during

pump assembly.

Upon disassembly

there

was

no evidence that

the degraded

pump

had Loctite applied to the impeller locknuts.

The licensee

noted that they had previously incorporated

the revision to the vendor manuals

0

-13-

and revised

maintenance

procedures

to ensure

the application of Loctite to the

impeller locknuts

as

a corrective action to the previous

pump failure.

5. 1.2

Operability of the Replacement

Pump 2-2

After determining

Pump 2-2 degraded

pump performance

was

due to the

loosening of the impeller locknuts,

the licensee

attempted

to determine if

Loctite had

been applied

by the vendor

on the locknuts of the replacement

pump

by reviewing procurement

records.

Based

upon available evidence,

the licensee

concluded that Loctite had not been applied

on the locknuts of the replacement

pump.

The licensee

performed

a review of maintenance

records for the

remaining three installed

pumps for Units I and

2 and confirmed that Loctite

had

been applied

on the impeller locknuts of all three remaining

pumps during

pump assembly.

The licensee

performed

an operability evaluation for the replacement

pump due

to the potential

mechanism for loosening of the locknuts.

Due to the

increased

potential for degraded

pump performance,

the licensee instituted

compensatory

actions

associated

with SI

Pump 2-2 operation.

The compensatory

actions

were necessary

to ensure that the conclusions

in the operability

evaluation

remained valid.

The actions required that additional

pump

performance

data

be obtained during surveillance testing

and that the SI

pump

be monitored for reverse

shaft rotation during operation of the opposite train

pump.

The vendor

has identified reverse rotation of the

pump shaft

as the

mechanism for locknut loosening.

These actions

appear

to be prudent

and

necessary

to ensure early detection of SI

Pump 2-2 impeller locknut loosening.

In reference

to the monitoring for reverse

shaft rotation, the inspectors

noted that the only concern

was that

a leak in the'discharge

check valve of an

idle SI

pump could allow backflow and subsequent

reverse rotation of the idle

pump during operation of the opposite train SI pump.

Since

such

an event

had never occurred at Diablo Canyon,

the inspectors

considered

the licensee's

actions to be precautionary.

5.1.3

Safety Significance

Pump 2-2 was replaced

when surveillance testing indicated the

pump

TDH to

be less

than the specified value.

The replacement

pump has subsequently

been identified as being potentially susceptible

to the

same type of

degradation.

The licensee

has

increased

the monitoring of the

pump to ensure

early detection of any significant changes

in pump performance

during routine

surveillance testing.

5. 1.4

Conclusion

i

The licensee's initial operability evaluation of the degraded

pump

performance failed to consider the potential for the loosening of the impeller

locknuts,

a known mechanism for pump failure based

on

DCPP

and industry

experience.

As

a result,

the potential for the

pump seizing during operation

was not considered

in the evaluation.

14-

The operability evaluation of the replacement

pump,

which addressed

additional

concerns

regarding

the performance of the replacement

pump,

appeared

thorough.

The evaluation

provided the licensee

with a formal method

for assessment

of additional

pump operating

parameters.

5.2

Pum

2-2 Performance

Test Instrumentation

Backcaround

During the performance of the Sl

Pump 2-2 routine surveillance

test, prior to pump replacement,

the inspector questioned

the acceptability of

the range of the digital instruments

installed for the test.

The system

engineer incorrectly responded

that the digital instruments

met the code

requirements.

Subsequent

to the inspector questioning

the range of the

digital instruments,

an

AR was written to document that the digital

instruments

installed to monitor the SI

pump discharge

pressure

and

dP did not

meet the

ASME Code

pump requirements.

According to the licensee,

this

AR was

written independent

of the inspector's

questioning.

The licensee

is in the process

of implementing the

new requirements

of ASME

Operation

and Maintenance

(OM) Standard

OM-1987, with addenda

through

OMa-

1988.

During the transition period,

the licensee

committed to revise

pump

and

valve

STPs to the

new inservice test requirements.

Upon revision of the

surveillance

procedures,

the

new requirements

were to be placed in effect.

STP P-SIP-22,

"Routine Surveillance

Test of SI,Pump 2-2," had

been revised

and, therefore,

was required to comply with the

new inservice testing

requirements.

ASME Section

XI Part

6 Section 4.6. 1.2(b) of OMa-1988 requires that digital

instruments

shall

be selected

such that the reference

value shall not exceed

70 percent of the calibrated

range of the instrument.

For the SI

Pump 2-2

surveillance,

the expected

or reference

value for the discharge

pressure

reading

was approximately

1500 psig, which was greater

than

70 percent of the

calibrated

range of the 0-2000 psig range discharge

pressure digital

instrument.

Similarly the reference

pump

dP exceeded

70 percent of the range

of the

dP digital instruments installed for the test.

5.2. 1

Licensee Corrective Actions

I

The licensee

issued

a change

to

STP P-SIP-22 to install test instrumentation

for measuring

the

pump discharge

pressure

which was in compliance with the

ASME code requirement.

The licensee

has

performed

a review of other

pump

surveillance

procedures

which were required to be in compliance with the

new

ASME

OM standard

requirements.

The review identified several

other

pump

surveillance

procedures

where the

same discrepancy

existed.

Revisions to the

effected

procedures

have

been

issued.

The licensee

has written

a quality

evaluation

on this problem.

5.2.2

Safety Significance

Since the implementation of revised

pump surveillance

procedures,

the only

ASME Section

XI required surveillance test performed with incorrect

instrumentation

installed

was the surveillance for SI

Pump 2-2.

The

0

-15-

surveillance test

was reperformed

using the correct

range digital instrument

following the procedure

being changed

to identify the required

instrument

range.

That test confirmed that the replacement

pump met

TS requirements

for TDH.

Prior to the implementation of the

new

ASME

ON standard

requirements,

there

was

no specific requirement for limiting the reference

value of digital

instrumentation

to 70 percent of the calibrated

range.

Surveillance testing

performed prior to the implementation of the

new requirements

utilized digital

instrumentation

which exceeded

the

70 percent limitation.

Digital instrument

calibration

was performed for these tests

which verified the accuracy of the

instrumentation prior to and after the test in the range in which the

instrument

was used.

Based

upon the licensees

actions,

the accuracy of

previous test results

is not in question.

5.2.3

Conclusion

During the transition to the

new requirements

of the

ASME OH standard,

the

licensee

did not properly implement the requirements

for the

use of digital

instrumentation

in pump surveillance

procedures.

Initially, licensee

personnel

appeared

not to exhibit

a questioning attitude with respect

to the

inspector's

questioning

on proper test equipment.

The licensee's

subsequent

actions to resolve this issue

appeared

appropriate.

5.3

Inservice Valve Stroke

Time Testin

~Back round

During the inservice stroke time testing of Unit

1 Valves

FCV-37

and

FCV-38, the motor-operated

steam

supply isolation valves for AFW Pump 1-1,

the inspector

noted that the valves

had

been operated just prior to the stroke

time testing during the performance of slave relay testing.

The inspector

questioned

the sequence

of testing since operation of valves prior to their

inservice stroke time testing did not appear to meet the intent of testing in

the as-found condition.

NUREG 1482,

"Guidelines for Inservice Testing at

Nuclear

Power Plants," describes

the condition of the valve to be as-found,

without prestroking or maintenance.

The

ASHE Code does

not specifically require testing to be performed for

components

in the as-found condition,

except for safety

and relief valves.

However, if as-found testing is not performed,

degradation

mechanisms

may not

be identified.

5.3.

1

Licensee

Procedures

for Valve Stroke

Time Testing

The licensee's

general

procedure

governing the exercising of safety-related

valves is

STP V-3, "Exercising Safety Related

Valves General

Procedure."

STP V-3 required that the first stroke of the valve, in the test direction,

be

recorded

as the official test.

A separate

detailed

procedure

is written for

each

valve to be exercised.

The individual procedures

for performance of

valve stroke timing listed

STP V-3 as

a reference

but did not include

requirements

for the operator to refer to

STP V-3 and comply with the

-16-

requirement for timing the first stroke of the valve.

In discussing

stroke

time testing with the Operations Director, the inspector

noted that it was not

management's

expectation for operators

to read

STP V-3 prior to performing

individual valve stroke time tests.

STP M-16N, Revision

11A, "Operation of Trains

A and

B Slave Relays

K632 and

K634," contained

a procedural

note which allowed the operator the option of

performing the stroke timing of Valves

FCV-37 and

FCV-38 after the valves

have

been

operated

during the performance of the slave relay test.

The sequencing

of the slave relay surveillance

and the stroke timing tests

did not meet the

licensee's

procedural

requirement for timing the first stroke of the valve in

the test direction.

In addition,

the stroke time test procedure,

STP V-3R6,

Revision 4, "Exercising

Steam Supply

FCV-37 and

FCV-38 Stroke

Time Test,"

was

written with the assumption that Valve FCV-37 and

FCV-38 were in the

open

position at the start of the test.

As

a result,

when performing the test of

Valve FCV-37 as

sequenced

in accordance

with STP M-16N, the operator

was

required to open the valve without

a specific step in the procedure

in order

to perform the stroke time test

in the closed direction.

Based

upon the inspector's

concerns for inservice valve stroke time testing,

the surveillance test group reviewed this issue

and determined that procedural

changes

were necessary

to avoid the possibility of cycling valves prior to

performing stroke time testing.

5.3.2

Safety Significance

The licensee

conducted

a review to determine

the number of times that valve

cycling occurred prior to inservice stroke time testing in the past.

The

results of the review indicated that stroking of a valve prior to inservice

testing

had previously occurred

on at least

one other occasion.

Based

upon

the results of the review, the cycling of valves prior to valve stroke time

testing

does not appear to be

a programmatic

problem.

5.3.3

Conclusion

The inspector

observed that,

in certain

instances,

the licensee

is not

performing the inservice stroke timing of valves during the first stroke in

the test direction.

The licensee

is revising surveillance test procedures

to

ensure that inservice valve stroke time testing is performed during the first

stroke of a valve wherever practical.

The licensee's

response

to the

inspector's

concern for the preconditioning of valves prior to performing the

periodic inservice stroke time test

appeared

adequate.

5.4

Centrifu al

Char in

CC

Pum

1-2

B

ass

Valve Seat

Leaka

e

~Back round

During the performance

of the Unit l reactor coolant

pump

(RCP)

seal

flow measurement

surveillance,

CC

Pump 1-2 Bypass

Valve CVCS-1-8387C,

was

noted to be leaking past its seat.

A flow measuring

instrument (controlatron)

was attached

to the piping, which confirmed that there

was flow past the shut

valve.

-17-

CVCS-1-8387C seat

leakage

during the

ECCS flow balance testing would effect

the flow balance results.

Since the point in time that

CVCS-1-8387C

seat

leakage

started

is unknown, it is possible that the seat

leakage

occurred

during the most recent

ECCS flow balance test.

During the

ECCS flow balance

testing,

actual

charging flow to the

RCP seals

is secured.

Charging flow to

the

RCP seals

is simulated

by establishing

80

gpm charging

header

flow as read

on the charging

pump discharge

header flow indication.

CVCS-1-8387C seat

leakage

provides

a parallel flow path during the

ECCS flow balance,

which

bypasses

the charging

pump discharge

header flow element.

As

a result,

CVCS-

1-8387C seat

leakage

would not have

been

included in

ECCS flow balance

measurements.

5.4. 1

Evaluation of CVCS-1-8387C

Impact

on

ECCS

Flow Balance

Unit

1

ECCS flow balance testing

was most recently completed during the

previous refueling outage

(IR6).

CVCS-1-8387C seat

leakage

had subsequently

been

noted

and documented

in an

AR on October

5,

1994.

At that time,

an

evaluation

was performed

by engineering

to determine

the effect of the valve

seat

leakage

on the

CC pump,

RCP seal injection,

and other surveillances for

acceptability.

The evaluation

documented

that the next performance of STP V-

15,

"ECCS Flow Balance Test,"

may not meet the test

acceptance

criteria with

the existing

CVCS-1-8387C

seat

leakage.

A prompt operability assessment

of

the leakage

on

ECCS flow rates

was not performed at that time,

On April 21,

1995, during the performance of STP M-54,

"Measurement of Reactor

Coolant

Pump Seal

Injection Flow," CVCS-1-8387C

was again noted to be leaking.

A more detailed evaluation of the effect of leakage

on

ECCS flow balance

was

performed.

The evaluation revealed that the valve seat

leakage

had the

potential to cause

the total flow for CC

Pump l-l to exceed

pump runout

limitations.

To address

this concern,

an in-depth analysis of the effects of

the valve seat

leakage

on each portion of the

ECCS flow balance

was performed.

The evaluation required

a detailed engineering

evaluation to assure

operability.

Specific parameters

which were evaluated

included:

total cold

leg injection flow rate, line-to-line flow imbalances,

the

sum of the three

lowest injection flow rates,

and total

CC pump flow.

ECCS

CC pump flow

requirements

were determined

by the licensee

to be within the

TS limits only

after instrument error uncertainties

were

removed

from the analysis

through

review of the posttest

instrument calibration data.

5.4.2

Safety Significance

The detailed analysis

performed

by the licensee

which considered

the effect of

CVCS-1-8387C seat

leakage

indicated that

ECCS flow rates

were within TS

allowed limits.

5.4.3

Conclusion

The inspector

noted that the initial evaluation of CVCS-1-8387C seat

leakage

failed to adequately

consider the impact of valve leakage

on

ECCS flow rates.

Subsequently,

over

6 months later, after failing to meet

RCP seal

injection

0

-18-

flow requirements

due to the effect of CVCS-1-8783C

seat

leakage

on measured

seal

injection flow,

a detailed evaluation

was required to assure

that

TS

requirements

were met.

6

PLANT SUPPORT ACTIVITIES

(71750)

The inspectors

evaluated

plant support activities

based

on observation of work

activities, review of records,

and facility tours.

The inspectors

noted the

following during these evaluations.

6. 1

S ent Fuel Pit

Pum

1-1

SCA Surve

s

~Back round

On

Nay 12th the inspector

observed

maintenance

being performed

on

Pump 1-1.

The area

in which the maintenance

personnel

were working was

within an area

marked with radiological

tape normally used to denote

an

SCA

boundary.

The inspector

noted that the mechanics

were not wearing

anticontamination

clothing and questioned

the mechanics

as to whether

a survey

had

been

performed to allow working in the area without SCA controls.

The

mechanics

indicated that

a radiation protection

(RP) technician

had performed

a survey of the work area

the previous

day and

had determined that it was not

contaminated.

The workers noted that the tape

had not been

removed

due to the

concern that the paint

on the floor would be marred

when the tape

was removed.

When exiting the

RCA, the inspector

reviewed the latest

survey of the

Pump

1-1 work area.

The survey indicated that only the

pump shaft

had

been

surveyed

and not the foundation

area

under the

pump shaft.

The inspector

questioned

whether the proper radiological

work practices

were being followed

for the work on