ML18038B486

Walkdown Observations

On August 22,

1995,

an inspector

accompanied

licensee

personnel

during the

performance of the SSP-12.55

Unit 3 Phase

I SPOC walkdown of the

HPCI system.

The inspector attended

the walkdown pre-brief and observed

the. HPCI walkdown

in the drywell, torus area,

main steam valve room and the

HPCI

pump room.

The

system

walkdown was led by .the system engineer.

Numerous minor maintenance

deficiencies

were noted

by the walkdown team.

These deficiencies

included

missing bolts from Limitorque valve actuator

covers

(valve testing

was still

incomplete),

bent instrumentation

tubing, loose conduit'ittings at junction

boxes,

and general

housekeeping.

The main steam valve room was particularly

noted

as needing

housekeeping

attention.

Maintenance activities,

including

painting,

were in progress

in the

HPCI pump room during the walkdown which

made it difficult to assess

the extent of housekeeping

attention

needed

in

that area.

No major deficiencies,

however,

were noted during the walkdown by

either the walkdown team or the inspector.

The inspector

concluded that the

walkdown was adequate

and met the requirements

of SSP-12.55.

During the walkdown of the

HPCI

pump room, the inspector

observed

a small

puddle of water which had developed

from a leaking

hose connection

on

a drain

hose attached

to

a catch basket

which was positioned

beneath

a steam line trap

bypass

valve.

The catch basket'had

a radcon tag attached

which indicated that

leakage

from the valve had

been

surveyed

on June

5,

1995

and

on that date

.indicated less

than

1000

cpm smearable.

However, during the

HPCI

pump room

walkdown, the inspector

observed

several

individuals walk through the puddle

without questioning its source or whether it was potentially contaminated.

A

radcon technician

was subsequently

requested

to survey the area

and again it

measured

less

than

1000

cpm smearable.

The inspector

concluded that, in this

instance,

licensee

personnel

were not sensitive to

a potential radiological

condition which could have resulted in'the spread of contamination.

On August 24,

1995,

the inspector

accompanied

licensee

personnel

on

a Unit 3

Phase

I SPOC walkdown of the

RCIC system.

At the walkdown pre-brief, the

system engineer

provided

each

walkdown team

member with an itinerary which

l.isted the various locations

and system

components

to .be walked down.

Also

given to each

team member

was

a copy of SSP-12.55,

Appendix D,

Malkdown

Instruction.

The inspector

observed that the itinerary was

a useful aid for

team

members

.and helped to,keep the team focused

on what needed to be

accomplished.

The walkdown team documented

numerous

minor deficiencies

during

the walkdown and

was thorough in inspecting electrical

boards,

breakers

and

instrument panels,

as well

as various mechanical

components of the

RCIC

system.

The walkdown team noted,

and the inspector

agreed,

that the

RCIC pump

room, including the turbine,

pump,

and associated

equipment,

was still

undergoing

maintenance

to the extent that it was inappropriate

at that time to

conduct

a

Phase

1 walkdown of those

components.

Because of the

disassembled

condition of the

RCIC pump/turbine,

the

Phase

1 walkdown for the

RCIC pump

room was rescheduled

to

a later date.

The inspector concluded, that

the

SPOC walkdown of the

RCIC system

was well planned,

was timely (with the

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exception of the

RCIC pump room),

and

was well executed

and met the

requirements

of SSP-12.55.

On September

8,

an inspector

accompanied

licensee

personnel

on

a

phase I

Hain Steam

(HS) system walkdown.

A pre-walkdown meeting

was held

and the

walkdown leader,*the

assigned

system engineer,

highlighted SSP-12.55,

"Unit 3

SPOC",

Appendix 0,

"SPOC Walkdown Guidelines"

and conducted

a brief of

previously identified

HS system discrepancies.

The test

and system engineers

provided'etails of what had

been previously discovered

on

a "pre-SPOC"

walkdown performed in August.

About two hours into the walkdown, the licensee test engineer

found that many

of the previously discovered

system discrepancies

which had

been

observed

in

the

"pre-SPOC"

walkdown were still present.

The walkdown was stopped

and,

after conferring with the plant system engineer,

the test engineer

presented

his concerns

to licensee

management.

The walkdown itself was performed

by the

team in

a direct/methodical

and straight-forward

manner

and in accordance

with

SSP-12.55,

Appendix D, guidelines.

Although this walkdown was postponed;

pending completion of previously-identified deficiencies,

a post-walkdown

meeting

was held.

This meeting

was thorough

and met SSP-12.55

guidelines.

This walkdown is to be rescheduled

and is to be conducted

during the riext

.

reporting period.

Another

NRC inspector

reviewed the two Phase

I SPOC packages

to ensure

they

complied with SSP 12.55, Unit 3 System Pre-Operability Checklist,

Revision

13.

The inspector

noted that the walkdown teams

had identified

a substantial

number

(60 to over 90 items per system) of deficiencies,

during the system

walkdowns.

The list of the items identified during the walkdown reflected the

thoroughness

of the inspection effort.

Items ranged

from missing equipment

identification labels,

damaged

valve hand wheels,

improperly mounted Hotor

Operated

Valve

(HOV) limit switch brackets, lifted wire leads,

and

indications'f

system leaks.

The inspector

noted that the walkdown teams

paid particular

attention to the condition of HOVs, labeling, piping supports,

hangers

and re-

straints,

and general

housekeeping

and material conditions of the systems.

The inspector returned to portions of the

HPCI system previously reviewed,

conducted

an independent

partial walk-down of the system with the associated

CCD Flow and Control

Diagrams

3-47E812-1,

Revision

28 and 3-47E610-73-1,

revision

15 to verify the as-constructed

configuration with the drawings.

The inspector

concluded that the

HPCI system configuration

was in agreement

with the flow and control diagrams,

and could not'ind any other system defi-

ciencies

not already identified by the

SPOC walk down team.

The inspector

concluded that the system

walkdown process

was effective in id'entifying

problems

and issues

which need to be corrected 'prior to system operability.

The 'inspections

indicated that the quality of (POC

1 walkdowns continued to be

high.

Deficiencies

were identified and listed for correction.

The cognizant

engineers

made appropriate

recommendations

to management

regarding delay of

some portions of the walkdowns

when it became clear that the effectiveness

would be limited due to remaining work activities.

I

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12

4.3

Unit 2/3 Safe

Shutdown Instructions

On September

7,

1995,

two of the inspectors

accompanied

operations

personnel

on

a walk through of a simulated

Appendix

R fire in fire area

16 (control bay,

including control room).

This effort was intended to be training on the

combined

U2/U3 SSIs

as well as

a enhancement

of the procedures.

This area is

regarded

as the most chall'enging

safe

shutdown scenario

due the extensive

number of in-plant activities required.

Operators

simulated

performance of

plant activities

on Units

2 and 3'hile the simulator was shutdown

as the

"non

fire" unit.

The inspectors

(and operators)

noted

numerous differences

between

the labels

on the installed equipment

and the procedures.

The procedures

had

been through validation.

The inspectors

discussed

with management their

conclusions that the exercise

involved more procedural

validation effort

rather than operator training and verification of time requirements.

These

observations

were

made in response

to an Inspector

Followup Item (296/95-37-

02),

Performance of Simulated

Shutdown for an Appendix

R Event,

opened during

review of the U2/U3 Appendix

R program.

The licensee

stated

they will perform

additional walk through demonstrations

of the SSIs during the next several

weeks.

The inspectors will monitor the licensee's

efforts in this'area.

4.4

Phase

I Process

Deficiency

During review of an open

USI

(USI A-48),

an inspector

noted that the drywell

control air system valve position checklist

was not complete.

The

SPOC I

checklist for the system

(the point in the Unit 3 recovery process

where plant

technical

support

recommends

that the system is ready for return to service

testing)

'had

been previously

signed off.which requires operations

to: have

system status control.

Nore specifically,

SSP-12.55,

Unit 3

SPOC,

requires

that Operations

establish

status

control of systems

at

Phase

I by

completion of the valve position checklists.

The Phase

I SPOC

was signed

without completion of the list.

This matter

was brought to the attention of

operations

management.

An audit by operations

management

revealed

two

additional

phase

I SPOCed

systems

which did not have completed valve position

checklists.

Operations

management

stated that the personnel

completing the

checklist were under the impression that the valve position checklists

could

be in progress

rather than being complete

when making the signoff.

Operations

personnel

involved in future

Phase

I signoffs have

been briefed

on

management

expectation that system status files be completed prior to

completion of the

Phase

I process.

The inspectors will continue to

monitor the results of the licensee's

corrective actions in this area.

4.5

RHRSW System Restoration Activities and Testing Observations

Several

inspectors

reviewed

and witnessed

RHRSW system recovery activities,

including restart testing

and followup of deficiencies identified durin'g the

testing.

The inspectors

reviewed the status of the

RHRSW restart test

program

and related

maintenance

activities to determine

whether the

RHRSW system

was

ready to support fuel load

and

power ascension

testing.

Inspection activities

included interviews with engineers

and operations

personnel,

field walkdowns

of system

components,

direct observation of system

performance testing,

and

various document reviews.

II

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13

The

RHRSW system

serves

as the plant's ultimate heat sink to support certain

ECCS functions.

Several

major design

changes

were implemented during the

extended

outage to improve

RHRSW system performance.

DCN W17620A replaced all

RHRSW piping within the Unit 3 reactor building because

of excessive

MIC

corrosion

and pipe wall thinning.

DCN T35994, modified all four

HX

outlet valves to reduce flow resistance

and increase

the

SW flow rate which

could

be achieved

through the

HX.

Additional modifications replaced

the

pump Bl impeller,

upgraded

MOV actuators

to meet

NRC GL 89-10 requirements,

and

added

RHRSW temperature

monitoring.

Site engineers

evaluated

the status

of all system

DCNs as part of the

RHRSW SPAE.

The inspectors

reviewed

DCN

status with the system restart test engineer.

All DCN action items required

for SPOC

Phase II closeout

were complete.

Pending

DCN action items which

affected fuel load

and plant restart

were clearly identified in the

SPAE.

The

inspectors

concluded that

DCN status tracking was thorough.

Post modification test 3-PMT-BF-023.038,

RHRSW Flow Test,

was written and

performed, to:

Demonstrate

that the

RHRSW pumps

can deliver 4500

gpm of raw water

at the discharge of each associated

Unit 2 and Unit 3 heat

exchanger.

Verify the pressure

boundary integrity for the. Process

Radiation

Monitoring System.

Verify that the interlock for the emergency transfer switch

and the

RHRSW pumps functions.

Verify that temperature

elements

3-TE-23-4100

and

4101 are connected

to

~

the correct points.

The inspector

reviewed the

PMT and considered it adequate.

The procedure

contained

enhancements

intended to reduce errors involving procedural

compliance.

The required actions

such

as; verify, check,

open, etc.

were

highlighted by larger

and bold type.

The inspector

concluded that these

highlights improved the procedure effectiveness.

The Baseline Test

Requirement

Document,

2/3-BFN-BTRD-023, for the

RHRSW System

was reviewed.

This document identifies the test which is required prior to restart to

demonstrate

the

RHRSW system's

capability to support safe

shutdown

and satisfy

design baseline

requirements

for combined Unit 2/3 operation.

The testing

specified in the

PMT satisfied the testing requirements

of Attachments

A, B,

E,

F,

and

H of the baseline test requirement.

On August 29,

1995,

the inspector

observed

the performance of portions of 3-

PMT-BF,-023.038.

The licensee

deferred testing of the

"C" loop because

of

discrepancies

with its flow transmitter which will performed

upon the

completion of maintenance.

The prejob brief was thorough

and the test

provided

an ample opportunity for questions

from the test participants.

The

test director also

asked

questions

to verify that the craft and operators

were

familiar with the test.

The inspector

observed that

a flow of 4500

gpm was

obtained

as required.

The transfer switch logic functioned

as designed.

The

test director

had

a copy of the procedure with him and gave specific

direction.

The operators

repeated

back instructions for both face to face

and

telephonic

communications.

The inspector considered

that this testing

was

well planned

and executed.

4I

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14

During the

RHRSW pipe replacement

(DCN W17620A) engineers

observed

a

significant amount of loose

MIC corrosion pipe scale

in portions of RHRSW

supply piping.

This piping, located outside of the reactor building, had

been

isolated

in dry layup

and

was not replaced during the extended

Unit 3 outage.

MIC buildup typically adheres tightly to wet piping.

Engineers

postulated

that the prolonged period of dry layup caused

the

MIC scale layer to exfoliate

and collect at the bottom portion of the

RHRSW supply header piping.

The

licensee

performed extensive

piping flushes at rated flow, 4500

gpm, to clear

the loose debris prior to reconnecting

RHRSW system piping for operation.

On August 22,

1995,

procedure 3-SI-4.5.C. 1(3),

Pump

and Header

Operability and

Flow Test, revision

4 was successfully

completed to verify

that service water flow to each

HX satisfied

TS requirements.

On

August 26, preventive

maintenance

procedure

O-TI-63,

RHRSW Flow Blockage

Monitoring, revision II was performed to establish

a baseline for RHR

HX

performance

trending.

Abnormally high differential pressure

(dp)

and slightly

reduced

flow were observed

on the

C

RHR HX.

Engineers initially attributed

the low HX flow and high tube sheet

dp to

a faulty flow instrument.

The

instrument

was recalibrated and'-TI-63

was repeated

twice more with similar

results.

Mechanics

removed the

HX .head for inspection

and found

a large

amount of corroded

pipe scale buildup fouling the tube sheet.

Engineel s

determined that the scale

was residue left over in'he pipe from the earlier

flushes discussed

above.

'The inspectors

noted that the scale

removed

from the

HX tubesheet

was identical to that photographed

during the

RHRSW piping

replacement

project.

All four

HX were. promptly cleaned

to remove scale

debris.

The

C

RHR HX continued to indicate fouling on the subsequent

retest.

The,inspectors

questioned

whether the

RHRSW supply piping integrity had

been

degraded

and whether.

pipe wall thickness

was adequate.

The inspector

reviewed

design calculation MD-f2023-870104 for the

ASME Class

3

RHRSW piping and noted

that

RHRSW supply header piping was required to be at least 0. 178 inches

thick.

Engineers

informed the inspectors

that pipe wall thickness

had

been

evaluated, prior to system restqration

and was determined to be acceptable.

The minimum measured

pipe wal.l thickness

was 0.26 inches.

The inspectors

questioned

why, after identifying the corrosive scaling,

the pipe wall

thickness

measurements

and evaluation

had not been

documented.

Engineers

responded

that the evaluation

was not required

by

DCN W17620A and that pipe

integrity was subsequently

verified by code required ISI testing.

The

inspectors

reviewed 3-SI-3.3. 13,

ASME Section

XI Hydrostatic System

Pressure

Test of the

RHRSW System,

revision 0/TN-03 and confirmed that system integrity

was properly verified.

Minor test documentation

'errors

were identified and

promptly corrected.

The inspectors

concluded that the licensee

adequately

confirmed

RHRSW piping wall thickness

and integrity to meet

code requirements.

The licensee

performed 0-TI-63 approximately ten additional

times to flush

pipe scale

from the system

and evaluate

HX flow performance.

The inspectors

observed

performance of O-TI-63 and resultant

RHR HX cleaning

on several

occasions.

Test equipment

was in calibration

and foreign material

exclusion

controls were appropriate.

Procedure

0-TI-63 was modified to maximize

SW flow

through the

C

HX to enhance

the system flush.

The restart

engineer

briefed operators

on the modified test

and operators

established

the intended

lineup.

However, during

a post test review, the inspector

noted that

0

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15

procedure

O-TI-63, revision ll/UIC-14 was not properly modified to reflect how

the test

was run.

The inspectors

determined that the procedure

issue

had

minimal safety significance.

The inspector discussed

this observation with

engineering

management

for correction prior to the next 0-TI-63 performance.

The last three 0-TI-63 flow tests

were performed at

a 5400

gpm flowrate which

is twenty percent

above the flow required

by TS.

The inspectors

confirmed

that flow remained within the maximum flow recommended

by the

HX manufacturer

in service information letter No. 337, Flushing of Heat Exchangers.

The

duration of the last test

was extended to simulate the use the system would

experience

during

a six month interval.

Observed

HX fouling was minor.

Procedure 3-SI-4.5.C.l(3)

was subsequently

performed to confirm TS required

flowrate.

Engineers

concluded that the

RHR HX was operable,

RHRSW flowrate

met

TS requirements,

and periodically scheduled

0-TI-63 (six month intervals)

would provide sufficient information to identify fouling prior to significant

HX performance

degradation.

Additionally, design modifications to monitor and

inhibit corrosion

are nearing completion.

The inspectors

concluded that the

RHRSW piping/HX fouling evaluation

and actions to address

future corrosion

concerns. were technically sound.

The inspectors

closely observed

licensee activities

and the process

used to

resolve the

RHR HX fouling issue.

The system restart testing engineer

was the

lead person responsible for issue resolution.

The inspector

noted that the

restart

engineer

worked closely with maintenance,

operations,

and, other

engineers

and tracked the issue to closure.

However,

the inspector questioned

how the information learned

would be captured for future reference

and similar

issue resolution.

According to SSP-3.4,

Corrective Action, revision

14, the

issue

met the criteria for a level

C

PER,

although

a

PER for this issue

was

not established.

The Balance of Plant engineering

supervisor

subsequently

informed the inspector that

a Level

C

PER was appropriate

and would be

established

to document the issue.

The inspectors

determined that this action

was consistent

with the licensee

corrective action program.

The inspectors

reviewed the following records,

performed

system walkdowns,

and

discussed

SW system restart

assessment

with various licensee

engineers.

The review included:

RTP test requirements

and results,

Phase

I SPOC

walkdown report,

SPAE,

SNPL,

and the

Phase II checklist.

The inspectors

confirmed that

Phase

I was complete.

All open work was

properly prioritized and tracked

on the

SHPL.

The

RTP properly addressed

all

RHRSW related

TS and

UFSAR requirements.

All RHRSW

Phase II activities

(includes entire

RTP)

have

been sat'isfactorily completed or scheduled for

completion coincident with testing of other systems.

Specifically the

following two tests

have

been

scheduled

with other systems to eliminate

duplicate testing:

Verify any Unit 3 Core Spray

pump start will start the

(EECW and swing)

RHRSW pumps A3, Bl, C3, Dl, and Verify both Unit 3

common

accident signals

A and

B will start

RHRSW pumps Al, A3, Bl, B3, Cl,

C3, Dl and

D3.

This testing is tracked in 3-STS-057-5.

The inspectors

walked down portions of the

RHRSW system within the Unit 3

reactor building during system operation.

System integrity was good.

No

indication of leakage,

excessive

vibration, or material degradation

were

HL

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16

identified with the exception of limited RHR HX blockage described

above.

This condition was properly resolved.

Through the extensive

review and observations

discussed

above

and in previous

IRs, the inspectors

concluded that the

RHRSW system restoration

was being

completed in a controlled

and thorough manner.

Management tools for tracking

system material

and test condition were comprehensive.

Actions to resolve

emergent

issues

were appropriate.

The licensee

was completing the last

portion of the

Phase II SPOC at the close of the report period.

The

inspectors

concluded that appropriate

programs

were established

and were being

properly implemented to support

RHRSW system restoration

in accordance

with TS

requirements.

4.6 Control Air System

and Restart

Test Program

Review

The inspectors

reviewed the

DCN listing for System 32, Control Air System,

and

System

33,. Service Air System,

to determine i.f all the system

DCNs were

included in the site master

punch list (SMPL).

The Browns Ferry Design

Schedule,

from August 6,

1990 through October

1,

1999,

dated August 23,

1995

was reviewed against

the historical

SMPL for Systems

32 and

33 dated

August

24,

1995.

The inspectors

noted that all

DCNs in the

Browns Ferry Design

Schedule for Systems

32 and

33 were include'd in the .SMPL.

The inspectors

performed

a review of the Control Air and Drywell Control Air

System

Design Criteria,

BFN-50-7032,

Revision 3,

and

FSAR Section

10. 14 to

determine

the system safety functions.

The Control Air System Baseline Test

Requirements

Document

(BTRD), 3-BFN-BTRD-032, Revision 0,

Change Notice No.

1,

was reviewed.

The

BTRD adequately

included the system safety .functions.

The

inspectors

reviewed the Control Air System Test Specification

(STS),

3-STS-

032,

Revision 00,

and verified

that the testing specified

met the safety

related functions outlined in the Control Air BTRD.

The Control Air STS also identified testing, required to verify adequacy of

system plant modifications.

The following DCNs were reviewed:

DCN

DESCRIPTION

W17185 Sl

and

S3

Conceptual

Design For Primary Containment

Isolation System Modifications

W17044

S2

W18703

Control

Room Design

Review Modifications

Valve Operability 3-FCV-32-62

and 3'-FCV-32-63

W21917

S7

Replace Electrical

Breakage

Components

The post modification testing

(PMT) specified for these

4 modifications

was 3-

PMT-BF-032.043,

Drywell Air SyStem Valves Functional Testing,

Revision 0.

The

inspectors

reviewed the

PMT and concluded that it adequately verified the

functions specified in the

above listed modifications.

The completed testing

package for modification W33292 S2, Unit 2-3 Crosstie

2-PCV-032-3901

was

reviewed.

The test

package,

3-PMT-BF-032.037,

Revision 0, Control Air Cross

0

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17

Tie Valve Functional Test,

documented satisfactory

performance of the auto

isolation functions identified in

DCN W33292 S7.

The inspectors

selected

the

ADSRV accumulator safety function for testing

review.

The

PHT specified

was MSI-0-001-TST-001, Testing of Air Supply

Systems

For Hain Steam Isolation Valves (HSIVs), Revision 0.

The specified

PHT measured

the leak rate from the accumulators

to be

< 10 psi/hour.

The

inspectors

reviewed calculation,

MD-(0032-870288,

Control Air Volume and Wall

Thickness of Accumulators,

Revision

3 and verified that the

ADSRV accumulator

sizing calculation 'incorporated

a'eakage

of 10 psi/hour

and required five

ADSRV actuations.

The inspectors

concluded that this

PHT was adequate

to

verify the

ADSRV accumulator safety function.

The Control

Rod Drive (CRD) Scram Pilot Air Header

Low Pressure

Scram function

was not listed in System

32 STS.

The licensee

indicated that this fun'ction

will be tested

as part of System

85

CRD Technical Specification

(TS) required

testing.

The inspectors

reviewed several

non-safety related

Control Air System

functions to determine if the licensee

had verified that non-safety related

functions were operational.

The Control Air and Drywell Control Air

compressor

function and the Service Air backup function were reviewed.

The inspectors

determined that the Service Air automatic

backup to Control Air

was not tested

as part of the Unit 3 Control Air Restart Testing.

Review of

the Unit 2

STS indicated that the Service Air backup function was not tested

as part of the Unit 2 restart testing.

The Service Air system provides, an

alarm

and automatically connects

Service Air to the Control Air System at

a

low control air pressure

of 85 psig.

Coincidently,

on September

7,

1995,

during the implementation of modification W33292 Stage

8 on Control Air

Compressor

C, low control air, header .pressure

occurred with only one Control

Air Compressor

loaded to the system.

The service air backup function operated

and the alarm was received indicating that this function was operational.

The status of the Control Air and Drywell Control Air compressors

was

reviewed.

The Control Air System

was maintained

operational

through 'the

extended

outage,

however the Drywell Control Air system

was secured.

The

Drywell Control Air System

was exposed

to atmosphere

during the extended

outage.

The resident. inspectors

had previously questioned

the potential for

drywell air piping corrosion

and contamination with the licensee.

The

licensee

prepared

work orders to perform flushing of the drywell air piping

and accumulators.

The outboard

HSIV accumulators

and control air piping was

also flushed.

The work orders

were performed to. procedure

3-TI-337 and the acceptance

.

criteria was from HSI-0-000-PR-0001,

Cleanliness

of Fluid Systems.

The

flushing was performed using air from a portable breathing air compressor

.

The acceptance

criteria required

2 successiv'e

flushes of 2 minutes duration

with no hydrocarbons

and

no visible particulates.

The inspectors

witnessed

the flushing of Drywell Air Compressor

(DAC) 3B,

flush path no.

5,

OAC 3B through the

DAC 3B air dryer,

and flush path no.

6,

li

I.Il

~

il~

18

DAC 3B through the

DAC 3B air dryer and air receiver.

Visible particles

were

noted during the initial flushes.

The final flushes

met the acceptance

criteria of no visible particulate.

The flushing evolution was performed

according to procedure

and

was considered

acceptable.

Upon completion of all

flushing the licensee

planned to place the drywell air system in service

and

perform an air quality sample of the drywell control air system.

The Control Air System

was maintained operational

through the extended outage.

The control

and service air compressors

receive quarterly flow capacity tests,

and control air dryer dewpoint checks

were performed monthly.

Control Air

System air quality tests

were performed

once every

6 months.

The inspectors

reviewed the database

printout of closed, work orders

and verified that the

control air dryer dewpoint checks

had

been performed.

The recent control air

quality test results

were reviewed

and the inspectors

noted that the results

met the acceptance

criteria of <

1

ppm hydrocarbon

and

<

1 particle

~ 5

microns.

The latest Control Air System air quality sample results

had not

been received

from the sample laboratory.

The last air. quality sample data

showed

one sample point at 4.3 particles

~ 5 microns,

however,

the average

was

g

1 particulate for a background

value of 0.3 particulate.

The inspectors

performed

an independent

walkdown of the control air and

drywell control air, to determine if the licensee's

threshold for identifying

system

problems

was adequate.

A small air leak was noted at the packing gland

for service air backup valve 0-PCV-33-1

bypass

valve.

A work request

was

written for this minor air leak:

DAC 3B local control station handswitch,

3-

HS-032-0067,

was found in the auto position while the tagout

(Tag 3-91-0325-8)

required it to be in the Off position.

The switch was discovered

at

1530 on

August 24,

1995.

Licensee shift management

was informed and action

was

initiated to reposition the switch.

The inspectors verified that the circuit

breaker for compressor

3B was tagged

open.

This was similar to

a previous

finding by the resi'dent

inspectors.

The switch is located at shoulder height

on

a route frequently used

by personnel.

The inspectors

noted that the switch

for DAC 3A had

been

equipped with a guard to prevent inadvertent

repositioning.

PER BFPER950600

had

been initiated on the

DAC 3B local control

handswitch

and requested

a guard

be built over the switch.

The inspectors

concluded that the switch had

been inadvertently

bumped out of position.

The

breaker

being tagged

open resulted

in the safety significance of the issue

being'mall.

The Control Air Compressor

Control Panel,

O-LPNL-925-0118,

was inspected.

The

panel

was very dirty and foreign material

was noted in the panel.

Pieces of

wire trays,

terminal lugs

and screws

were noted loose

on or near terminal

blocks.

Wire markers

were noted

on top of several

open type relays

near the

relay contacts.

The licensee

was informed and licensee

management

initiated

corrective. action

and the panel

was cleaned.

The inspectors

noted

an oily

residue'hich

appeared

to be exuding from some of the cables

in this panel.

The licensee

was informed of a similar occurrence

at Sequoyah

Nuclear Plant

where Polyvinylchloride

(PVC) cable jackets

had experienced

a release

of

plasticizer

compound

from the

PVC which had exuded

from the cables.

No

significant amount of the material

had collected near

any relay contacts

or

other equipment.

The Control Air Compressor

Control

Panel

had

been

included

in the Unit 2

SPOC walkdowns but not in the Unit 3

SPOC walkdowns.

The

0,

ii

]5~,

l9

inspectors

concluded that the licensee

was adequately

identifying and

resolving system deficiencies..

As stated earlier,

on September

7,

1995, the licensee

experienced

a

Low

'Control Air Pressure

Event.

The control air header

pressure

dropped to

approximately

82 psig

and the service air backup alarm was received.

PER

BFPER950990

was initiated for resolution.

The low control air header

pressure

occurred during implementation of DCN W33292 Stage

8 on the control air

compressor

control circuit.

This

DCN was considered

non-outage

work.

The

inspectors

witnessed

the troubleshooting activities which were conducted

according to work order

WO 95-14644-05.

The troubleshooting activity involved personnel

from Technical

Support,

Nuclear Engineering,

Modifications, Instrument Maintenance,

and Operations.

The troubleshooting

was coordinated

as

a high risk activity.

At the time of

the .low control air header

pressure

only control air compressor

A was loaded.

Compressors

B and

D were running unloaded

and compressor

C was off.

The

control air compressors

had not tripped.

The service air backup function and

alarm worked during the event.

Operations

personnel

manually loaded control

air compressors

to restore

system pressure.

Manual control air compressor

loading

was not included in Control Air System Operating Instruction, 0-0I-32,

Revision

28.

The licensee

was initiating a procedure

change to incorporate

this hand control

mode into the Control Air System Operating Instruction.

The

resident

inspectors verified that the procedure

change

was approved

and

reflected the manual operation'utilized to recover the air system.

The control air compressor

programmable controllers were tested

and

no

problems

were noted.

The control air compressor

control circuit voltage

and

comp'onents

were tested

and

no problems

were noted.

The control air

compressors

were operated

through all switch positions

and

no failure to load

was noted.

No definitive root cause

was noted

and the problem could not be

repeated.

The inspectors

reviewed the

PMT, used following the installation of the Control

Air System

programmable controllers

(DCN W33292).

The testing

included

comparing the contents of the controller registers

(loaded software)

against

the required software

as

shown

on Mechanical

Real

Time Data Acquisition and

Control Software Drawings.

The inspectors

concluded that the

PMT demonstrated

proper compressor

loading control

and controller operation.

The inspectors

concluded that the restoration activities

and testing of the

control air systems

were proceeding

in a controlled manner.

Testing

adequately

addressed

demonstration

of the required functions.

Emergent or

postulated

issues

were being addressed

appropriately.

4.7

Unit 3 Testing Observations

During this reporting period

a selection of routine surveillance tests

and

other testing

conducted

in preparation for the re-start of Unit 3 were

observed

and evaluated

by the inspectors.

Details are discussed

in the

following paragraphs.

0

Oi

i

20

4.7. I

Core Spray Testing

The inspector

observed

the performance of Core Spray Flow Rate

and Valve

Differential Pressure

Testing for both loops.

These

were performed using

'Procedures

3-SI-4.5.A. l.d(dp)(I) and (II).

On August 25,

1995, the licensee

performed the surveillance for Loop I.

The inspector

noted that the operators

alternately

used

a telephone

and radio to communicate with the personnel

in

the field.

Background noise

was very high which made it difficult for either

party to understand

what the other was saying.

There were numerous

requests

for repeatbacks

and clarification.

The inspector considered

the

operators'erformance

to be weak. Additional details

are discussed

in Paragraph

2.1.

When the operator started

Pump 3C, the inspector

observed that the ammeter

for CS

Pump

3A dropped

approximately

20 amps.

He noted that

Pump

3A had

previously been drawing approximately

80

amps

and leveled out at

76

amps while

Pump

3C leveled out at 84

amps.

A review of the data revealed that the

differential pressure

across

Pump

3A was less

than the acceptance

criteria

of 220-251 psi.

On August

29 the inspector

attended

a meeting which was 'held

to discuss

the cause of the low d/p for CS

Pump 3A.

An engineer,

after

reviewing the data,

concluded that low pump speed

was the cause of the

deficiency.

The inspector questioned

his conclusion

as the

pump is powered

by

a two pole induction motor and

speed is controlled

by system frequency.

Pump

binding could have

been the only other contributor and it would have

been

audible.

Several

other po'tential contributors relating to the physical

condi.tion of the

pump were discussed.

The inspector considered

that foreign

material

in the

pump was the most likely cause

since other

NRC inspectors

had

observed material

in the Unit 3 torus during the test.

The licensee

developed

an action plan which required

a new set of pump curves to be developed.

Trouble shooting/testing

revealed that the motor speed

was 3600

rpm and the

problem was in the

pump.

The licensee

believed it was

a worn wear ring.

Discussions

with the vendor revealed that the

pump

had two inspection ports

which would enable

the licensee

to inspect the

pump internals without

disassembling

the

pump.

The inspection of the

pump internals

revealed that

debris

was lodged in the

pump.

The blockage could explain the disparity in

the operating current in the two pumps.

Two of the resident

inspectors

also observed

portions of the testing in the

Foreign Material Exclusion

room and the torus area.

The inspectors

id'entified that paint

had

been

improperly applied to several

snubbers

on the test return 'line and

a room

temperature

sensor.

These observations

were discussed

with Unit 3 recovery

management

and were corrected

promptly.

The inspectors

have not identified any

Category

1 drawings - 848 (UO),

492 (Ul), 815 (U2), 863

(U3)

= 3,018

CCD

'rawings

Secondary

drawings - 5467

(UO),

1744 (Ul), 5123

(U2), 6302

(U3)

= 18,636

CCD

-drawings

Based

on this additional information, the inspectors

concluded

that the

number of identified

PDDs involving incorrect Unit 3 drawings

was less

than

1%

of the total Unit 3 CCDs.,

None of the

27

PDDs impacted nuclear safety or

operability.

(Examples

included vent valves not shown, labeling,

and contact

positions

on electrical drawings.)'he

licensee

indicated that only two of

these

PDDs addressed

issues within the Safe

Shutdown Analysis Program.

The inspectors

reviewed

an Nuclear Assur ance

and Licensing assessment

of the

Unit 3

DBVP which was performed in August 1994.

The report indicated that

Unit 3

CCDs were not as reliable

as Unit 2 CCDs.

The assessment

team

was not

able to find documentation of the process

used to develop the Unit 3 CCDs.

Numerous

drawing deficiencies

were identified during the assessment

involving

I

0

il~

(gal.

26

recently issued

CCDs.

The report stated that the

CCDs have limitations and

that these limitations are not always understood

by drawing users.

The inspectors

reviewed the actions

taken in response

to the assessment

and

held additional discussions

with licensee

personnel.

As

a result of these additional

reviews,

the inspectors

concluded'hat

although the Unit 3 configuration drawings

were not subjected

to the

same

rigorous walkdowns

as the Unit 2 drawings, virtually all of the deficiencies

identified to date

have not had

any nuclear safety or major operational

.

impacts.

A deliberate decision

was

made

by l.icensee

management

that the

potential

increase

in overall drawing quality was not worth the large effort

necessary.

Licensee

management

had recognized

and users

have

been trained

on

the limitations of the drawings.

The inspectors

reviewed previous

IRs and

correspondence

associated

with the Unit 3 drawing programs

and concluded that

specific

regulatory commitments

were being met.

While it was difficult to

obtain specific data

from the current Potential

Drawing Discrepancy trending

reports,

drawing deficiencies

are being adequately

tracked

and resolved.

The

licensee

indicated that the methodology

used for PDD trending will be changed.

The inspectors

concluded that the information reviewed indicates that while

drawing discrepancies

continue to be identified, few have contributed to

safety significant operational

problems.

A large

number of the drawing errors

were identified during the

SPAE/SPOC "roll up" process

after

DCN completion

when

DCAs are incorporated into the "as constructed"

drawings.

These

identified errors

appear to be at least partially attributed to complexities

in the drawing

and modification control processes.

Some of the less

significant drawing .issues

continue to adversely

impact the licensee.

For

example,

PER 951081 described

extensive efforts required to determine

the

material

used

on pressure

transmitter piping (from a main steam)

due to

drawing errors.

The inspectors

continue to review drawings during inspection of Unit 3

recovery activities.

Paragraph

4.2 of this report describes

some

NRC review

of installed equipment

versus

the drawings.

4.9

Foreign Material Within 3A Core Spray

Pump

On August 25,

1995, during testing of the Core Spray System,

the

3A Core Spray

pump was unable to achieve rated flow.

Initial troubleshooting

and inspection

(boroscopic

inspection of the

pump bowl) of the

pump revealed that foreign

material

was lodged within the

pumps impeller.

The licensee initially

postulated that the material

most likely came from the condensate

transfer

system during torus fill.

A PER

(BFPER951168)

was generated

to document the

condition

and

an Incident Investigation

team

was formed to determine

and

correct the cause of the incident.

Attempts to retrieve the material

through

the

pumps casing

were unsuccessful

making it necessary

to remove the

motor/pump assembly.

The inspectors

observed this evolution

as well the

retrieval of the foreign material. Initially, the material

removed

was thought

.

to be

a welders sleeve,

however; after further examination,

the material

was

determined

to be

an underwater

vacuum bag. This type of vacuum

bag

was

I~

'E

~

0

27

utilized during the clean out of the

CSTs in 1985.

The vacuum

bag

was mostly

intact with a small portion missing.

The II team

recommended

that the underwater portions of the torus

as well as

the five condensate

storage

tanks

be inspected.

TVA contr acted divers to

perform these

inspections.

The first area

inspected

was the torus

and its

associated

ECCS ring header.

While inspecting this area,

the divers located

portions of the vacuum bag,

a few pieces of duct tape with plastic attached,

and

a small

snap ring (5/8" diameter)

on the torus bottom in the vicinity of

the

3A Core Spray

pump discharge.

The duct tape

and plastic were apparently

what the inspectors

observed floating in the torus

as discussed

in paragraph

4.7. 1.

and 4. 10.

Other than

some minor silt on the torus bottom,

no other

substantial

foreign material

was observed.

Inspection of the

CSTs did not

reveal

any additional material similar to that which was found in the

pump.

The licensee

determined that it was not practical to inspect

CST

2 due to

safety concerns for the divers

as the possibility existed that

HPCI could

initiate during the underwater inspection.

This

CST will be inspected

during

the next Unit 2 outage.

The II teams preliminary conclusions

are that the vacuum

bag

was left in the

CST 3 during its clean out in 1985.

The II team evaluated

the alig'nment

used

to fill the Unit 3 torus

and determined that there

was

no potential for

foreign material

from Unit 3 to have

been flushed into the Unit 2

ECCS systems

through the condensate

cross ties.

The inspectors

concurred with this

conclusion.

Additionally, the licensee II team is recommending that

a flush

of condensate

header

and condensate

suction lines to the

RHR pumps

be

performed using the

RHR drain

pumps.

The inspectors will continue to monitor

the licensee's

efforts in this area.

The deficiencies

in FHE practices

which caused this incident apparently

occurred years

ago.

The licensee's

testing

program

and review of data

resulted

in the identification of the problem.

The inspectors

concluded that

the licensee's

actions after the material

was identified were adequate

to

ensure that Unit 2

ECCS systems

were not affected

by the material.

4. 10

Foreign Material Exclusion Accountability Control

Problem

On August 28, while observing

a portion of a Unit 3 Core Spray flow test,

the

inspectors

observed

a number of what appeared

to be pieces of foreign material

floating on the surface of the torus water.

This observation

was

made

from

the outside of the torus through .the torus hatch.

At the time of the

observation,

the torus proper

was being controlled

as

a foreign material

exclusion

area in accordance

with SSP-12.8.

The torus

has

been maintained

as

a foreign material

exclusion

area

since being refilled in

April 1995.

As

a

result of these

observations,

the inspectors

entered

the torus

(on August 30)

to determine

the extent of condition of foreign material within the torus

water.

During the internal

inspection of the torus,

no foreign material

was

identified in the torus water due to low water clarity.

However, during

a

review of the

FNE accountability log for the torus,

the inspectors

noted that

the temporary light stringer located within the torus

was not documented

in

~ the log.

The inspectors

informed the licensee of this matter

and

a

PER

(BFPER951184)

was generated.

As discussed

in paragraph

4.9 above,

duct tape

0

O~

ili

28

and plastic material

were subsequently

recovered

from the torus

by divers

and

this material

was apparently

what the inspectors

had seen.

This failure to follow plant procedure

SSP-12.8,

Control, represents

a violation of 10 CFR 50, Appendix B, Criterion V.

This

matter is similar in nature to violation 50-260/94-27-01,

(example,2),

in

which equipment

being utilized within the Unit 2 torus

was not recorded

in the

FME accountability log.

The current matter represents

a continuing problem

with the control of foreign material

and will be tracked

as violation 50-

296/95-51'-01,

Failure to Properly Control Material within an

FHE Zone.

5.0

Review of Open

Items

(92700)

(92901)

(92902)

(92903)

(92904)

(TI 2515/65)

The open

items listed below were reviewed to determine if the information

provided met

NRC requirements.

The determinations

included the verification

of compliance with TS and regulatory requirements,

and addressed

the adequacy

of the event description,

the corrective actions taken,

the existence of

potential generic

problems,

compliance with reporting requirements,

and the

relative safety significance of each. event.

Additi'onal in-plant reviews

and

discussions

with plant personnel,

as appropriate,

were conducted.

5. 1.

(CLOSED)

VIO 259,

260, 296/92-09-03,

Failure

To Control Access

To

Protected

Area.

This violation occurred

when two individuals whose

employment

had

been

terminated

entered

the protected

area.

The proper procedures

for employee

check out had not been followed by the employees

nor their supervisors.

As

a

result, their access

badges

which allowed access

to the protected

area

and

vital areas

were not revoked

and were subsequently

used

by the terminated

employees

to gain access

to the protected

area.

Upon discovery of this event,

'he

licensee

removed the employees

badges

to prevent further entrance

into the

protected

area.

TVA Nuclear Business

Practice

BP-108,

Processing

Employees

In

And Out Of TVA Nuclear,

a corporate level procedure,

was revised to provide

a

clear methodology for out-processing

of employees.

In addition,

BP-308,

Browns Ferry Check-In/Check-out

Procedure,

was written to provide

a check-out

form and

a step-by-step

procedure for processing

out.

This procedure

describes

the responsibilities

and provides guidance to both the person

whose

employment is being terminated

and that employees

supervision.

Included

on

the check-out

form is

a signature

by site security indicating that protected

area

access

has

been

revoked.

This procedure

and check-out

form is required

to be completed

by all site personnel

whose

employment is terminated.

This

violation is being closed

based

on these corrective actions.

5.2

(CLOSED)

LER 260/94-013',

Unit 2 Scram

From 54 Percent

Power Caused

By

Balance

Of Plant

Equipment Failure.

This event occurred

on December

2,

1994,

when

a faulty stator water cooling

temperature

switch generated

a false high temperature

signal

and tripped the

main turbine which resulted

in a reactor

scram.

The licensee

determined that

the switch

had

been calibrated

two months earlier

and

had exhibited

an

unusually high reset

dead

band.

However, there

was

no procedural

guidance

'e

4i

4I~

~ ~

29

which described

what constituted

an unsatisfactory

setting

and the. switch was

left installed.

Following the event the licensee

developed

a procedure for

calibrating this switch and it was subsequently

replaced.

In addition, the

licensee

developed

a list of fifty-three balance of plant devices

which were

capable of individually initiating a turbine/generator trip or other major

equipment operation.

A cost benefit analysis

was performed for the items

on

the list and determined that thirty-three of the items would be modified to

alleviate the single failure vulnerability.

In the interim period, the

preventive

maintenance

and calibration procedures

for the components

on the

lis't were reviewed to determine if additional action

needed to be taken to

provide added

assurance

that the components

would not fail.

This review did

not identify any needed

changes

to the existing maintenance

schedule.

In

addition, training was provided to maintenance

and engineering

personnel

on

this event

as well as the proper

use of electronic temperature

calibrators

and

the identification of degrading

equipment.

This item is closed.

5.3

(CLOSED)

IE Bulletin 79-12 (Unit 3), Short Period

Scrams

at

BWR

Facilities.

An inspector

reviewed Bulletin 79-12;

as it pertained to Unit 3; in order to

determine

the current status of licensee efforts in addressing

the issue.

In

this review, the inspector

noted the following:

In TVA's initial response

to Bulletin 79-12;

as presented

in letters

dated

June

30,

1979

and August 19,

1981;

TVA tendered

a commitment to

perform both unit and cycle-specific analyses

of rod withdrawal

sequences

to ensure

notch worths of individual control rods were

minimized.

The bulletin was subsequently

closed

as part of USNRC

Inspection

Report '50-296/81-18.

In a .letter .dated January

4,

1990,

the licensee

requested

to use

NSSS

vendor/NRC-approved,

banked withdrawal

sequences

and reduced

notch worth

procedures

for future startups.

In the

same letter, the licensee

requested

a revision to

a commitment regarding fast period

scrams

and to

no longer require either cycle or unit specific analysis of rod notch

worths.

In an

NRC to licensee letter,

dated

January

25,

1990,

the

NRC

found the licensee's

revised

commitment to the bulletin to be

'cceptable.

Unit 3 Technical Specification

LCOs 3.3.B.3.b

8 3.3.B.3.c

and

Surveillance

Requirements

4.3.B.3.b.

1

8 4.3.B.3.b.2 appropriately

reflect TVA's current position

on withdrawal

sequences

and reduced

notch

worths.

An SI, 3-SI-4.3.B. I.a,

"Coupling Integrity Check" procedure,

(effective

September

1,

1995),

has

been

approved for use in the. Unit 3 restart.

This SI implements

an

RWH sequence

which incorporates

procedures

for

Reduced

Rod Notch Worth and

Banked Position Withdrawal

Sequences.

A

similar Unit 2 SI has

been successfully

used for previous Unit 2 start-

ups.

et

II

il~

~

>

30

Based

on this review, the inspector concluded that the,licensee's

corrective

actions properly addressed

bulletin concerns

and were acceptable

for the

upcoming Unit 3 restart.

This item is closed.

'5.4

(CLOSED) Multi-Plant Action Item (HPA) COll (Unit 3),

(TAC H08931);

RPS

Power Supply.

In an

NRC August 7,

1978 letter, the licensee

(TVA) was told of defects

identified in

BWR RPS systems.

TVA was further asked to evaluate

BFNP's design

and to commence

a heightened

surveillance of the,RPS

power supplies.

In an

NRC September

24,

1980 letter,

TVA was informed, that based

upon

NRC

evaluations,

BFNP

RPS power supply modifications should

be implemented to meet

Class

lE requirements,

single failure criteria and seismic requirements.

The

NRC also stated that appropriate

RPS power supply Technical Specification

changes

should

be implemented.

In a TVA to

NRC December

4,

1980 letter,

TVA

made

a commitment to install

such modifications,

submit

TS changes.

These

activities were completed

by March,

1985.

In the

NRC Safety Evaluation

(June,

1985),

the

NRC stated that based

upon their review of TVA's modifications

and

the specific actions taken,

TVA had satisfactorily resolved

the issue.

A

IE Bulletin 83-08

(comparable

RPS power supply modifications to

HG set output breakers)-

was closed

as part of IR 50-296/95-22.

Based

upon the

above

and the inspector's

review of the Unit 3 modifications

and related

documentation,

this issue is closed for Unit 3.

Similar work on the Unit 2

RPS power supply was noted

as complete in 1990

and

an analogous

Unit 2 issue

was closed in Inspection

Report',

50-260/90-40.

5.5

(CLOSED) THI Action Item II.K.3.57 (Unit 3), Identify Water Sources

Prior to Hanual Activation of ADS.

An inspector

reviewed

item II.K.3.57 and noted that

a TVA to

NRC letter

(December

23,

1980) stated that

TVA would ensure that related

procedures

contained verifications of low pressure

water source availability prior to

manual

actuations of the

ADS.

The inspector further reviewed the present

status of TVA's Unit 3 response

and noted the following:

In almost all cases,

any Unit 3

EOI action step which requires

manual

actuation of the

ADS is prefaced

by

a "note" or "substep".

This

EOI

"note" or "substep" highlights the need for operator verification of a

low pressure

water source

(or sources)

prior to manual

ADS actuation.

In some cases;

where

emergency

Unit 3 reactor depressurization

is

required,

but

an undesired

reactor repressurization

is

a distinct

possibility; the

EOI directs the operator in the elimination of low

pressure

water sources

which could repressurize

the reactor.

This

EOI

action step

change

has

been

made

subsequent

to the original concerns

presented

by the THI action .item.

The inspector

observed that the

above

changes

were complete

and that similar,

Unit 2 EOIs have

been

approved for use during the operation of BFP Unit 2.

NRC review of the

EOIs has

been

completed.

Based

upon the above

and the

inspector's

specific review of the Unit 3 EOIs

and related documentation,

this

THI Action Item is closed for Unit 3.

8V

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5.6

31

(Closed)

Unresolved Safety Issue A-48, Hydrogen Control Measures

and

Effects of Hydrogen Burns

on Safety Equipment.

This item in conjunction with Generic Letter 84-09

(Recombiner Capability

Requirements

of 10 CFR 50.44 (c)(3)(ii)), discusses

the potential for the

evolution

and burning of hydrogen within containment.

The burning of high

hydrogen concentrations

could lead to

a challenge of containment integrity and

the mal.function of safety equipment within the containment.

The containment

at Browns Ferry Unit 3 is

a standard

BWR Mark I containment.

To mitigate the possibility of a high hydrogen concentration

occurring

and its

associated

burn, the following actions

are in place;

TS require that within

24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months of placing the reactor in the run mode,

the containment

atmosphere

oxygen content shall

be reduced to less than

4 percent (inerted)

and

maintained

in this condition.

In addition to maintaining

an inerted

containment,

the licensee

is required to maintain two independent

trains of

the Containment Atmospheric Dilution (CAD) system in an operable status.

The

CAD system is utilized in a post

LOCA condition to prevent the containment

from reaching

a combustible mixture by diluting the containment

atmosphere

with nitrogen

and venting

as necessary.

Additionally, the pneumatic control

system for the drywell (drywel) control air) utilizes nitrogen

as its source

of air by taking

a suction

from the containment

(inerted with nitrogen).

The

air is compressed

and stored in the drywell control air system

and utilized as

necessary

for drywell pneumatic

loads.

Through

a recent modification,

a

backup supply for the drywell control air system is the

CAD system.

By a

series of manual

actions in the control

room and in the plant, operations

personnel

can align the

CAD system to supply compressed

air (nitrogen) to the

drywell.

By utilizing the

CAD system

as

a backup to the drywell control air

system

no oxygen will be introduced into containment.

Although this

modification alleviates

the need to use plant control air as

backup to the

drywell control air system, this capability still exists.

However, if the

plant control air system is utilized in this manner,

plant

TS require the unit

to placed in cold shutdown within 24 hours2.777778e-4 days 0.00667 hours 3.968254e-5 weeks 9.132e-6 months

due to the potential of introducing

oxygen into the containment

atmosphere.

The inspector

reviewed all correspondence

related to

GL 84-09,

NUREG-1425

(Status:of Safety Issues

at Licensed

Power Plants),

and portions of DCN W17937

(Modification which provided the

CAD system

as the backup pneumatic

source for

drywell control air) to ensure all aspects

related to USI A-48 have

been

completed.

Additionally, the inspector

went to the local public document

room

to review

SECY 89-122

(SECY Paper which informed the Commission of the 'basis

for resolution of USI A-48) to verify the licensee

had completed all required

actions related to this matter.

Based

on this review of the above stated

licensee

actions

and controls,'this'matter

is closed.

5.7

(CLOSED)

DEV 259,

296/85-36-04:

Torus Flood Level Switches.

This issue

addressed

the seismic qualifications of the reactor building flood

detection

switches.

The licensee

responded

to the deviation in correspondence

dated

September

22,

1985.

The item was closed for Unit 2 in IR 89-19.

The

underlying issues

have

been

addressed

in subsequent

LERs and corrective

actions

completed.

t

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ggi

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32

The original deviation

addressed

the failure to meet

a

FSAR statement

(Section

10. 11.5) which stated that the reactor building flood switches

were

seismically qualified.

IR 89-36 also noted that the switches

were not tested.

The switches

were to be seismically mounted

and tested periodically.

Subsequent

to this,

LER 259/86-21

was issued

when the switches

and electrical

circuitry was found. to be not seismically qualified.

The

FSAR was revised to

reflect that the switches

were not seismic.

Credit was taken, for operator

actions.

This

LER was closed

in IR 90-29.

The licensee recently completed

a

Commitment Evaluation

(SSP

Form-17) which justified deleting the commitment

for seismically qualified switches

on Units

1 and 3.

The inspector

reviewed Section 4.5 of the current Fire Protection

Plan

describing the operator

actions

and level switch functions in case of a

failure of the fire protection piping in the reactor building.

Additionally,

the safety evaluation, (July 25,

1988) which justified the switches

not being

seismic

was reviewed.

The inspector verified that the assumptions

and actions

stated

in the

documents

remained valid.

The inspector. concluded that the

concerns

in the deviation

had

been

adequately

addressed.

However,

since

flooding, is

a significant risk factor in the recently completed multiple unit

operation

Plant Safety Assessment,

the inspectors

performed additional

review

of

overall flood protection issues

as described

in paragraph

2.5 of this

report.

Based

on this review, the deviation is closed for Units

1 and 3.

5 '

(CLOSED)

URI 296/95-10-01:

Inadequate

Second

Party Verification by Craft

Worker.

Extensive

NRC review of this item is documented

in IRs 94-35,

95-14,

and 95-

20.

NRC inspectors

have verified numerous re-inspections

of cables

and

splices.

It was concluded that the licensee's

investigative

and corrective

actions

were adequate

to address

potential

concerns

regarding quality control

practices.

Based

on those reviews, this item is closed.

5.9

(CLOSED)

IF.I 259,

260,

296/94-07-04:

Identification of System Test

Boundaries

This IFI was

opened to track questions

raised

regarding the identification of

system test boundaries.

In discussions

with licensee

personnel, it was noted

that procedures

did not require that

SPAE boundaries

be developed with the

concurrence

of operations

and technical. support personnel.

The inspector

was

also concerned

about the use of color-coded

drawings

used to indicate

operational

boundaries

between

the units.

The licensee

provided the inspector with a copy of BFEP PI 88-07,

"System

Plant Acceptance

Evaluation."

Subsection

4.2. 1 of this procedure,

"SPAE

Boundary,"

has

been revised to require that the cognizant

system design

engineer

determines

the

SPAE boundary with appropriate

coordination with

groups responsible

for definition of SPOC boundary

scope.

This requirement

addresses

the concerns with test boundaries.

The licensee

provided the inspector with a copy of revision

17 to SSP-12.50,

"Unit Separation

for Recovery Activities," dated

February 8,

1995.

In part,

this procedure

provides the process

for revision of color-coded

drawings

as

F

C)

~

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33

modifications

and tests

are completed

and systems

are returned to operation.

The licensee

has indicated that it does not plan to continue color-coding

drawings for systems that are fully restored

and operational.

Separation

drawings

and clearances will remain in place

as required to isolate

unqualified

BFN Unit

1 components.

This plan was discussed

in

a public

meeting

on July 20,, 1995 with NRC personnel

monitoring

BFN Unit 3 restart

activities.

The revisions to SSP-12.50

are responsive

to the concerns

expressed

in IFI 94-07-04.

The issues

raised

by IFI 94-07-04

have

been

addressed

by the licensee

as noted

above.

Therefore,

IFI 94-07-04 is closed.

The effectiveness

of the

licensee's

implementatiori of the

SPAE program

and return of systems

to service

continues

to be monitored

by igspectors.

6.0

Exit Interview (30703).

The inspection

scope

and findings were summarized

on September

19,

1995, with

those

persons

indicated in paragraph

1 above.

The inspectors

described

the

areas

inspected

and discussed

in detail the inspection findings listed below.

Although proprietary material

was reviewed during the inspection,

proprietary

information is not contained

in this report.

Dissenting

comments

were not

received

from the licensee.

Item Number

Status

Descri tion and Reference

296/95-51-01

Opened

VIO-Failure to Properly Control

Naterial within an

FHE

Zone, (paragraph

4. 10)

260/95-51-02

Opened

8 Closed

NCV-CRD Scram Air Header Valve Out

Of Position,

(paragraph

2.3)

259,260,296/92-09-03

Closed

VIO-Failure To Control Access

To

Protected

Area,

(paragraph

5.1)

260/94-013

Bulletin 79-12

HPA COll

TNI II.K.3.57

Closed

LER-Unit 2 Scram

From 54 Percent

Power

Caused

By Balance

Of Plant

Equipment Failure,

(paragraph

5.2)

Short Period

Scrams

at

BWR

Facilities (Unit 3)

(paragraph

5.3)

RPS

Power Supply (Unit 3) (paragraph

5.4)

Identify Water Sources

Prior to

Nanual Activation of ADS (Unit 3)

(paragraph

5.5)

+i0

~

/Q>

USI A-48

Closed

34

Hydrogen Control Measures

and

Effects of Hydrogen Burns

on Safety

Equipment

(paragraph

5.6)

DEV 259,296/85-36-04

Closed

Torus Flood Level Switches

(Units

153)

(paragraph

5.7)

URI 296/95-10-01

IFI 259,260,296/

94-07-04

Closed

Inadequate

Second

Party Verification

by Craft Worker (paragraph

5.8)

Identification of System Test

Boundaries

(paragraph

5.9)

7.0

Acronyms

and Initialisms

ADS

ADSRV

AOI

ASHE

BFEP

BTRD

CCD

CFR

CPH

CR

CRD