ML17310B470

Insp Repts 50-528/94-12,50-529/94-12 & 50-530/94-12 on 940425-0527.Violations Noted.Major Areas Inspected:Testing, Including post-mod testing,post-maint Testing,Ts Surveillance & Preventive Maint Testing

ML17310B470
Person / Time
Site:	Palo Verde
Issue date:	07/24/1994
From:	Ang W, Johnson P NRC OFFICE OF INSPECTION & ENFORCEMENT (IE REGION IV)
To:
Shared Package
ML17310B468	List: ML17310B467 ML17310B469 ML17310B470
References
50-528-94-12, 50-529-94-12, 50-530-94-12, NUDOCS 9407280033
Download: ML17310B470 (88)

See also: IR 05000528/1994012

Text

APPENDIX

U.S.

NUCLEAR REGULATORY COMMISSION

REGION IV

Inspection

Report:

50-528/94-12

50-529/94-12

50-530/94-12

Licenses:

NPF-41

NPF-51

NPF-74

Licensee:

Arizona Public Service

Company

P.O.

Box 53999

Phoenix,

Arizona 85072-3999

Inspection

Conducted:

April 25 through

Hay 27,

1994

(

Team Leader:

/~

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2.'I

o nson,

am

a er

Division of Rea

or

af ty

a

Team

Hem

rs:

J.

B. Jacobson,

Assistant

Team Leader

Senior Operations

Engineer,

Special

Inspection

Branch

Office of Nuclear Reactor Regulation

a

e

C. A. Clark, Reactor Inspector,

Plant Support

Branch

Division of Reactor Safety

F. S.

Gee,

Reactor Inspector,

Plant Support

Branch

Division of Reactor Safety

M. H. HcNeill, Reactor Inspector,

Engineering

Branch

Division of Reactor Safety

D.

C. Prevatte,

Consultant,

Parameter

Corporation

Facility Name:

Palo Verde Nuclear Generating Station,

Units 1, 2,

and

3

Inspection At:

Palo Verde Site,

Haricopa County, Arizona

Approved:

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Division of React, r SA, e

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TABLE OF CONTENTS

F

EXECUTIVE SUMMARY .

1V

DETAILS

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INTRODUCTION .

1.1

Inspection

Scope

.

1.2

Sample Selection

.

2. 1

Test

Program Description

.

2.2

Mechanical

Design Validation

2.3

Electrical

Design Validation

2.4

Instrumentation

and Controls

2.5

Conclusions

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Testing

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Testing

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Design Val

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Testing

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POST-MAINTENANCE TESTING

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3. 1

Test

Program Description

.

3.2

Mechanical

Post-Maintenance

Testing

3.3

Electrical

Post-Maintenance

Testing

3.4

Instrumentation

and Controls Post-Maintenance

Testing

3.5

Conclusions

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SURVEILLANCE AND PM TESTING

4. 1

Test

Program Description

.

4.2

Mechanical

Surveillance

and

PM Testing

.

4.3

Electrical Surveillance

and

PM Testing

.

4,4

Instrumentation

and Controls Surveillance

and

PM

4.5

Conclusions

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5.3

5.4

5.5

5

INSERVICE TESTING

5. 1

Test

Program Description

.

5.2

Purpose

and Scope for Inspection

Program

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Inservice Testing

Program

Review

Observation of Inservice Testing

Conclusions

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6

PREDICTIVE MAINTENANCE TESTING

.

6:1

Test

Program Description

.

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6.2

Predictive Maintenance

Testing

Review

6.3

Conclusions

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7

DESIGN BASIS VERIFICATION IN TESTING

.

7. I

Objectives

.

7.2

Sampling

and Criteria

7.3

Inspection

Findings Related to Design

7.4

Conclusions

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Basis Verificati

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8

LICENSEE SELF-ASSESSMENT

OF TESTING

PROGRAMS

8. 1

Recent

Self-Assessments

8.2

Conclusions

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ATTACHHENT'

EXIT HEETING AND PERSONS

CONTACTED

ATTACHHENT 2

INSPECTION FINDINGS INDEX

ATTACHHENT 3

DOCUHENTS REVIEWED

f

EXECUTIVE SUNNARY

A team of NRC staff members

and

an accompanying

consultant

conducted

an

inspection of testing

programs at Palo Verde Nuclear Generating Station.

The

inspection

was conducted

from April 25 through

Hay 27,

1994.

In conducting this inspection,

the

NRC team utilized the guidance

provided in

the Palo Verde Nuclear Generating Station Technical Specifications

and in the

Code of Federal

Regulations, Title 10 Part 50, Appendix B, particularly in

Criteria III, V, XI, and XVI.

The team also

used amplifying or implementing

'equirqments

specified in the licensee's

administrative controls

and other

.

procedures.

The inspection

team examined

the various types of testing conducted

by the

licensee,

including post-modification testing,

post-maintenance

testing,

Technical Specification surveillance

and preventive maintenance

testing,

ASHE

inservice testing,

and predictive maintenance

testing.

In each area,

the team

evaluated

the licensee's

testing

programs to determine if they met regulatory

requirements

and were effectively used to confirm system conditions.

The team observed

strengths

involving the licensee's

overall definition of

programs

and administrative control procedures;

the conduct of recent self-

assessments;

the staff's thoroughness

in identifying and documenting

issues;

the preparation of corrective maintenance

work orders;

and the application of

the licensee's

individual plant evaluation results.

The inspection

team identified weaknesses

involving:

Acceptance criteria for test procedures

which did not verify that

intended modification or maintenance activities were actually completed

as intended,

which did not establish

system operability as intended,

or

which were otherwise inappropriate for the test's

specified objectives;

Untimely or insufficiently thorough resolution of licensee-identified

issues

(e.g.,

atmospheric

dump valve accumulator

pressure

requirements,

initially identified in 1989,

and

an auxiliary feedwater

system

steam

isolation valve issue, initially identified in 1990);

Screening of proposed

design

changes

pursuant to

10 CFR 50.59,

a weak-

ness identified by previous

and recent licensee

self-assessments,

and

an

apparent

reluctance

among

some licensee staff personnel

to conclude that

an unreviewed safety question

was involved;

and

Inter-organizational

communications

and definition of responsibility, or

"ownership" of issues

(e.g.,

poor communication

between design

and

inservice testing personnel

about rebaselining

valve stroke-time data,

and uncertainty regarding responsibility for diesel

generator

load

verification issues).

The team recognized that the ongoing,

reengineering

process

and accompanying

organizational

changes

could address

some of these

concerns,

but noted that

licensee

management

should consider additional attention to communications,

inter-organizational

interface, definition of responsibilities,

and the

implementation of existing program requirements.

The team identified four violations (please

see Attachment 2), involving

failure to declare

a low pressure

safety injection pump inoperable,

inappropriate test acceptance

criteria,

an inadequate

post-maintenance

test,

and weaknesses

in 10 CFR 50.59 design

change

reviews.

In addition,

two non-

cited violations were identified.

Overall, the team observed that licensee

programs

appeared

to be well defined,

and that concerns identified by the team resulted principally from weaknesses

in program implementation.

The team recognized

a strong positive attitude

among the licensee's

management

and staff,

as indicated

by the level of

support

and cooperation

provided to the inspection

team

and

by a commonly

expr essed

desire to strive for continuing improvement in licensee

performance.

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DETAILS

1

INTRODUCTION

Testing demonstrates

that plant systems

or components

meet required

performance

parameters.

Proper testing is one of the principles of the

assurance

of quality, along with proper design,

construction,

operation,

and maintenance.

This systematic test performance

team inspection

was

a

comprehensive

performance-based

evaluation of the adequacy of the licensee's

testing programs.

1. 1

Ins ection

Sco

e

Areas

examined

included post-modification testing,

post-maintenance

testing,

Technical Specification surveillance

and

PM testing,

American Society of

Mechanical

Engineers

(ASME) inservice testing,

and predictive maintenance

testing.

Important systems

and components

were selected for examination,

based,

in part,

on consideration

of generic

and plant-specific probabilistic

risk, assessment

data.

The tests

associated

with those

components

were then

examined.

This inspection

evaluated

the licensee's

testing

programs to determine if they

met regulatory requirements

and were effectively used to confirm system

conditions.

The inspection

assessed

whether

the licensee

programs tested

the

proper items at the proper frequency

and for the proper attributes, utilizing

adequate

methods

and measurements,

and whether discrepant test results

were

appropriately dispositioned.

The inspection

also determined

whether the tests

demonstrated

that the system design basis

was met or maintained.

In addition,

the inspection verified that the purpose of testing,

as defined

by the

Technical Specifications

or licensee

procedures,

was fulfilled by the details

of the test.

The inspection

included observation of field testing or observation of as-left

equipment

when possible.

The team also reviewed records of completed testing

in most cases.

The inspection

included

samples

from the mechanical,

electrical,

and instrumentation

and control areas.

1.2

Sam le Selection

The inspectors

selected their inspection "samples to. ensure that important

risk-significant systems

and components

were examined.

In doing this, the

inspectors

considered

the probabilistic risk information described

in the

licensee's

individual plant evaluation,

provided to the

HRC in response

to

Generic Letter 88-20, April 1993.

Specifically considered

were the licensee's

Critical Systems List (Palo Verde Sensitive

Issues

Manual, Appendix A) and the

licensee's

"Top 100 List," a licensee listing of the

100 components

with the

most potential

safety

impact based

on probabilistic risk assessment

considerations.

I

e

2

POST-NODIFICATION TESTING (DESIGN VALIDATIONTESTING) (37550

and 37700)

When licensees

make design

changes

or modifications to plant systems

or

components,

an important aspect of the modification process

is to ensure that

the modified system or component will function as designed

and will meet all

design

bases

requirements.

Post-modification testing is performed to,verify

key attributes of the design

change

and also to verify that the design

change

has not resulted in any unforeseen

interactions

between

systems

or components.

Post-modification testing

should generally

be performed after completion of

the modification, but prior to declaring the associated

equipment

operable.

2. 1

Test

Pro r

m Descri tion

At Palo Verde, post-modification testing requirements

are delineated

in

Procedure

81PR-ODC02,

"Plant Design

Change

Program," Revision 4,

and more

specifically in Procedure

81DP-OCC23,

"Design Validation Testing," Revision 2.

Post-modification,

or design validation testing requirements,

as they are

called at Palo Verde,

are specified

by the design organization responsible for

the associated

plant design

change.

The modification process

at Palo Verde

was in a transitional

phase

at the time of this inspection,

the ultimate goal

being that

a design

team comprised of engineering,

maintenance,

and other

organizations

would participate jointly in the formulation of design

validation test requirements.

The licensee's

program required that revisions

to design validation tests

be approved

by the

same level

as approved

the

original design validation tests.

Maintenance

planners

incorporate

the design validation test requirements

into

specific work instructions for the organization responsible for performing the

test.

No review of the specific work instructions

by the design validation

test originators is required.

However, the licensee

plans to eliminate the

need for the specific work instructions

once the team preparation

concept is

implemented.

Licensee

Procedure

70DP-ODC02,

"System Turnover," Revision 5,

established

requirements

for the implementation of design validation tests

and

for system turnover to operations.

This procedure

also contains instructions

for performing partial

(incremental)

system turnovers.

The team noted that

the procedures

in place provided adequate

guidance for the generation of post-

modification testing requirements

and that proposed

changes

should

augment the

program's effectiveness.

2.2

Mechanical

Desi

n Validation Testin

The team reviewed

a sample of five design

change

packages

and supporting

documents,

including the Design Basis Manual, piping and instrumentation

diagrams,

and installation

and test work orders.

In some cases,

the vendor

information manual

was also reviewed.

Design

change

packages

and limited design

change

packages

(LDCPs) were

examined

as listed in Attachment 3.

The team's findings from review of these

documents

and the associated

design validation tests

are discussed

below.

I

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2.2. 1

Design Validation Testing for Changes

in Motor-Operated

Valve

(MOV)

Gear Ratios

Limited Modification LDCP 1/2/3LM-AF-102 was initiated to decrease

the stroke

time of Auxiliary Feedwater

(AFW) Discharge Isolation Valves

JAFBUV0034 and

JAFBUV0035,

and

had

been

completed in Units

1 and 3.

These Train

B isolation

valves

are the second valve in the

AFW discharge

piping flow path to each

steam generator.

The Limitorque motor operators

had

been previously modified

(Design

Change

Package

I/2/3-FJ-AF-091) in response

to

NRC Bulletin 85-03, to

change

the operators

from Model SMB-00-25,to Model SMB-1-60.

That change

was

made

bqcause

the original operators

could not generate

enough thrust to close

the valves if the plant was in abnormal or transient conditions.

The more

recent modification reviewed

by the team changed

the gear ratio in each

operator

from 45.29-to-l to 42.5-to-l to decrease

the closing stroke time from

14.5 to 13.5 seconds.

The work orders for this

LDCP specified (in Section 6.2) that acceptance

testing

be accomplished

pursuant to Inservice Testing Procedure

73ST-3XI05.

Section 8.3.8.5.

1 of the inservice testing procedure

required the closing time

to be less

than

15 seconds,

the

same closing time criterion as

was

used before

the modification.

The team noted that this acceptance

criterion was

inappropriate,

in that the test result would have

been satisfactory

even if

the modification were not performed (i.e., the design validation test

acceptance

criterion did not verify that the desired reduction in stroke time

had

been achieved).

This inappropriate

acceptance

criterion was identified as

an example of a violation of Criterion XI of 10 CFR 50, Appendix

B

(528;529;530/9412-01).

The team also noted that Condition Report/Disposition'equest

(CRDR) 2-4-0116

had been

issued recently to document the failure of Valve SIAUV0627 to stroke

closed during dynamic testing

(HOVATS).

This is an isolation valve in the

high pressure

cold-leg injection header to Reactor Coolant

Loop 2B, which

failed because

the actuator motor pinion and spur

gears

were improperly

reassembled

in April 1993.

Inservice stroke time testing

was performed

four times after that reassembly,

with an observed

decrease

of about

50 percent

in valve stroke time.

Kowever,

no problem was identified at that

time.

This also indicated the inappropriateness

of using inservice test

stroke times

as acceptance

criteria for post-maintenance

or post-modification

testing.

The team questioned

how the inservice testing group was notified of

LDCP 1/2/3LM-AF-102.

The

LDCP did not indicate that the inser vice testing

group

had

been notified of the change in gear ratio and stroke time so that

the baseline

inservice testing for these

valves could be adjusted.

The

licensee

noted that the "Impact Process"

procedure did not address

this

situation.

CRDR 9-4-0295

was written to address

this concern.

Procedure

01AC-OCC01,

"Impact Process,"

was also revised to add the inservice

test department

to the review process

when valve performance characteristics

are changed.

i

2.2.2

Modification of Spray

Pond

Bypass

and Return Valves

The ultimate heat sink is comprised of two spray

ponds for each unit.

The

spray

pond system return line to each

pond has

branches

leading to

a bypass

valve

(JSPAHV0049B

and

JSPAHVOOSOB)

and to the spray header

valve

(DSPAHV0049A

and

JSPBHVOOSOA).

A modification,

LDCP I/2/3LE-SP-067,

ended the provision

for remote operation of these

valves

(from the control

room) by removing power

to the four motor operators

(in each unit), allowing for only local

manual

manipulation of these

valves using the existing handwheels.

This

LDCP

provided that the cables

and wires to the valves

be de-terminated,

spared,

and

'bandoned

in place.

This modification was accomplished

to remove these

valves

from the dynamic

(MOVATS) testing

program because

these

valves are not

required to change position during

a design basis

event.

The design validation test provided in the modification package for this

LDCP

stated that "the assistance

of the Reactor Operator is required to determine

if the flow in the system is adequate."

This flow testing

was done to ensure

that the inlet valve was

open

and the bypass

valve was closed.

However, the

design validation test did not identify any quantitative

acceptance

criteria

for this test.

The team questioned

the licensee

about the absence

of

quantitative

acceptance

criteria for a flow test,

and the licensee

revised the

design validation test criteria.

The failure to specify appropriate

acceptance

criteria for this design validation test

was contrary to the

requirements

of Criterion XI of 10 CFR 50, Appendix B.

This problem was

recorded

in the licensee's

corrective action system,

and corrective actions

were implemented.

Since the criteria of Section VII.B(l) of the

NRC

Enforcement Policy were satisfied, this violation was not cited.

2.3

lectrical Des'

alidation Testin

The team selected

a sample of a dozen modifications completed during the past

2 years for review in the electrical

area.

Included in this sample

were

modifications performed under previous versions of the design

program (prior

to December

1993), modifications associated

with the top 100 safety

components,

and modifications where changes

to the originally specified design

validation tests

were required.

The team identified that, generally,

the

post-modification tests sufficiently validated the important aspects

of the

design

change.

Often, the specified design validation test

was

an a'lready

issued surveillance test,

such that the adequacy of the design validation test

was dependent

on the thoroughness of the surveillance -test.

The team

.

expressed

a concern that surveillance tests

sometimes

do not address

important

design considerations

that should

be va'lidated after making plant

modifications,

and that the licensee

should ensure that all testing necessary

to validate the proper implementation of plant modifications is accomplished

regardless, of whether it is specified in a corresponding

surveillance test.

Specific findings by the team,

based

on its review of electrical

design

validation test,

were

as follows:

'

2.3. I

Degraded

Grid Voltage Relays

The team reviewed Design

Change

Package

(DCP) I/2/3XE-PB-024, which replaced

the mechanically-operated

second level undervoltage

(degraded grid voltage)

relays

and associated

Agastat timers with more accurate

solid state relays.

The modification was performed to minimize relay drift, which could inhibit

the relays

from ensuring that adequate

voltage is available to support all

Class

lE loads under worst-case

design basis conditions.

The design

validation test specified for this modification was the associated

Technical

Specification surveillance test for the relays.

Technical Specification 3.3.2

requirqs these

relays to be set

between

2930

and 3744 volts.

The licensee

had

previously noted that this Technical Specification setpoint is inconsistent

with the

FSAR, which states

that the degraded grid voltage relays will actuate

when voltage drops

below 90 percent

(3744 volts) of design voltage.

At

settings significantly less

than 3744 volts, the relays might not assure that

adequate

voltage is provided to all Class

lE equipment.

The licensee

had

recently submitted

a Technical Specification

amendment

request

to provide for

setting the relays at 3744 volts or greater.

However,

the team noted that

there

appeared

to be

an undue delay (approximately

3 years)

between the

identification of this concern

and the submission of a Technical Specification

amendment

request.

To ensure

component operability, the licensee's

practice

has

been to set the

degraded grid voltage relays at the upper end of the allowable Technical

Specification range.

With these settings,

the licensee

has determined that

all Class

IE equipment is operable,

although operability margins

have

been

significantly reduced for some components.

However, this practice

was not

proceduralized.

The team noted that the applicable surveillance

procedure

specified that the relays

be set

anywhere within the range of 3150 to

3744 volts,

and that settings

at the lower end of this range would be

inappropriate,

resulting in potential

load voltages well below the operability

requirements

for many components.

The inappropriate

acceptance

criteria in

the surveillance

procedure

were identified as

an example of a violation of

Criterion XI of 10 CFR 50, Appendix 8 (528;529;530/9412-01).

Setting the relays higher than

3744 volts presents

a possibility of spurious

relay actuations if the grid voltage should fluctuate from nominal levels.

An

ideal setting that would assure

desired voltage margins to all Class

lE loads,

and also avoid the possibility of spurious actuations,

is currently not

achievable without modifying the electrical- distribution system.=

The .licensee

was pursuing various options to improve ac voltage regulation

and to restore

some of the operational flexibilitythat

has

been lost as

a result of this

issue.

2.4

Instrumentation

and Controls Desi

n Validation Testin

The team reviewed selected

modifications which had

been

implemented during the

past

5 years

in the instrumentation

and controls area.

The team selected

packages

for review based

on safety

and potentially quality-related

impacts of

the modifications.

The modification packages

reviewed are listed in

Attachment 3.

The modifications reviewed in the instrumentation

and control

area

and the associated

post-modification testing

appeared

to have

been

appropriately performed.

2.4. 1

Nitrogen-16

(N-16) Monitors

On March 14,

1993,

a steam generator

tube ruptured in Palo Verde Vnit 2 Steam

Generator

No.

2 while -the unit was at 98 percent

power.

One of the licensee's

subsequent

responses

to the event

was to install

a Nitrogen-16

(N-16) monitor

on each of the main steam lines to enhance

the monitoring and alarm functions

available in the event of a steam generator

tube rupture or significant

leakage.

The team noted that the licensee

had committed to install the N-16

monitors

as

a qualitative indication of tube leakage

which would enhance

the

operators'bility to quickly diagnose

a tube rupture

or significant leak.

As

specified

in the licensee's

design

change

package,

the alarm setting for each

N-16 monitor was set at three-times

background,

with an alert setpoint at

70 percent of that value.

Supporting information for the design

change

package

also stated that the licensee

would continue to pursue the possibility

of quantitatively correlating the N-16 monitor indications to primary-to-

secondary

leak rate

as operational

experience

on the steam generators

used at

Palo Verde makes that possible.

2.5

Conclusions

In general,

the team found the program

and procedures

which specify

and

control design validation testing to be adequate.

The team's findings in this

area,

attributed principally to weaknesses

in the implementation of program

and procedure

requirements,

included three instances

wherein the specified

testing (generally,

an existing surveillance test) did not include appropriate

acceptance

criteria.

It appeared

that inadequate

attention

was, at times,

given to evaluating the purpose of the design validation test

and ensuring

that the specified test actually verified accomplishment

of the intended

design

change.

The team also identified instances

wherein poor communication

resulted

in design information not being appropriately disseminated

to

responsible

organizations

(e.g.,

degraded grid relay setpoints,

MOV stroke

times).

3

POST-MAINTENANCE TESTING (62703)

Post-maintenance

testing is that testing usually expected

and accomplished

following maintenance activities to confirm that (1) the maintenance

was

accomplished

as intended,

(2) no unexpected

adverse

impacts resulted during

the performance of maintenance activities,

and (3) the equipment maintained is

operational

and ready to be restored

to service.

3. 1

Test

Pro ram Descri tion

Maintenance activities at Palo Verde are controlled by the work order process,

as prescribed

in several

licensee

procedures,

including 30AC-9ZZOl,

"Work

Control Process,"

Revision

18;

30DP-9WP02,

"Work Order Development,"

Revision 7;

and

30DP-9WP04,

"Post Maintenance

Retest

Development,"

Revision 5.

,

f

I

f

1

A work request

is generated,

based

on

a modification, scheduled

maintenance,

or an identified deficiency.

The work request starts

the planning process,

and usually results

in the generation of a work order.

The maintenance

planner develops

the instructions

needed for rework or replacement.

Model

work orders

are

used for standard

operations

such

as valve gland re-packing.

Some preapproved

maintenance

instructions

are also used,

such

as for the

performance of

PM activities.

Post-maintenance

testing requirements

are provided

by the work planner.

Interviews with work planners

indicated that they usually specify

an

appropriate,

existing surveillance test procedure,

as licensee

procedures

encourage

them to do.

The planners

may consult with engineering

personnel, if

necessary,

in establishing

post-maintenance

testing requirements,

although it

appeared

that this was

uncommon except in the instrumentation

and controls

area.

Each work order is approved

by a supervisor,

and other reviews are

provided

as established

by the planner.

3.2

Hechanica

Post-Haintenance

Testin

The inspectors

accompanied

licensee

personnel

during the performance of

selected

corrective maintenance activities

and witnessed

the performance of

associated

post-maintenance

testing.

The records of any similar corrective

maintenance

on like components

during the previous year were also reviewed.

Post-maintenance

testing

was observed for the following corrective maintenance

activities:

Work Order 00662004,

"Troubleshoot

Leakage of Nitrogen Accumulator,"

performed

Hay 24,

1994;

Work Order 00640201,

"Y Strainer Plug Is Leaking Causing

Excessive

Corrosion of the Strainer,

Plug,

and Surrounding Pipe," performed

April 27,

1994;

~

Work Order 00658281,

"Fix Body to Bonnet Leak," performed

May 12,

1994;

and

~

Work Order 00660155,

"Replace Motor Pinion Gear

and

Worm Shaft Gear to

Match Operator Bill of Materials for 3JSGAUV0134," performed

May 13,

1994.

Specific findings by the team,

based

on its review and observation of

mechanical

post-maintenance

testing,

are discussed

below.

3.2. 1

HOV Gear Ratio Changes

Maintenance activity pursuant to Work Order 00660155

was conducted to replace

the gears

in Limitorque operators

to match the overall gear ratio as described

on the bill of materials.

In this case,

the change

increased

the valve

opening time from approximately 3.5 seconds

to 4.5 seconds.

This work order

was

one of a set of five work orders for valves in all

3 Units.

The team

noted that the post-maintenance

testing which was specified

and performed

was

l

l

t

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f

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I

Inservice Testing Procedures

73ST-3XI01 for the JSGAUV0134-type valves

and

73ST-3XI02 for the JSGAUV0138-type valves, with a'cceptance criteria of

6.75 seconds

(paragraph 8.3.7.3.2)

and 7.5 seconds

(paragraph 8.3.7.3.2),

respectively.

These

were the

same

acceptance

criteria

as were in use before

the maintenance activity, and would not have confirmed that the desired

gear

ratio change

was actually accomplished.

The team also noted four other work orders

(00653367,

00653513,

00653521,

and

00653523) for gear ratio changes.

These

work orders

were for four reactor

coolant

pump controlled bleedoff valves, to increase their closing time

changed

from 6.5 to ll seconds.

In this case,

the post-maintenance

testing

specified in the work instructions

was to verify a closing stroke time of less

than

12 seconds

(there

was

no existing inservice test for these valves,

so

existing inservice testing

acceptance criteria could not be used).

Since this

criterion would have

been satisfied before the maintenance

was performed, it

also did not appear to clearly confirm proper completion of the specified

maintenance.

The post-maintenance

testing for the above gear ration changes

indicated

an

inadequacy

at times,

as discussed

earlier in Section 2.2. I of this report, in

using existing inservice testing criteria

as acceptance criteria for post-

maintenance

or post-modification testing.

This specification of inappropriate

acceptance

criteria was identified as

an example of a violation of 10 CFR 50,

Appendix B, Criterion XI (528;529;530/9412-01).

During review of Work Order 00562760, written for refurbishment of

Valve CHA-HV-524 in Unit 3, the team identified

a question regarding the

normal lineup for this valve in each unit.

This valve, in the chemical

and

volume control

system,

is the regenerative

heat

exchanger outlet to Reactor

Coolant

Loop 2A.

In the original design

(Combustion Engineering

Standard

Safety Analysis Report) it was

a charging line containment isolation valve.

The licensee's

Updated Safety Analysis Report described this valve as

an

isolation valve for Penetration

41 which was to have Type

C leakage testing

(Table 6.2.4).

The Type

C leakage testing

appears

to be the only time the

valve has

been closed.

As indicated in the Updated Safety Analysis Report

(Section 6.2.4.2. 1), this valve is locked open by removing the power supply

and by removing

and locking the local handwheel.

Table 3.6-1 of the Technical

Specifications

also lists Valve CHA-HV-524 as

a containment isolation valve,

stating that it is required to be open during accident conditions.

Supplement

4 of the Safety Evaluation Report

{SER) accepted

the-licensee's

position on .

compliance with Regulatory

Guide 1. 141

on containment isolation in regard to

Valve CHA-HV-524 with the requirement that the valve have emergency

power.

However,

Supplement

9 of the

SER accepted

as corrective action for loss-of-

load testing failures the licensee's

plan to lock this valve open.

The team

questioned

whether this valve should

be locked open,

in view of the apparent

conflict between

Supplements

4 and

9 of the

SER.

This issue

was discussed

with Office of Nuclear Reactor Regulation,

and will remain

open pending

further

NRC review (Followup Item 528;529;530/9412-02).

,

J

3.2.2

Repair of Fire Protection Strainer

Cap Leak

Maintenance activity pursuant to Work Order 00640201

was conductea

to rework

a

leaking strainer

cap,

located outside the high pressure

safety injection

pump

room, in the trim piping to

a fire protection preaction

deluge valve.

Maintenance

personnel

noted

as they began this activity that the stainer

cap

did not appear to be tight.

In observing this maintenance activity, the team

noted that

no controls were'placed

on the number of times the compressible

metal gasket

could be re-used.

Available vendor information for this part was

limited to a drawing symbol.

The licensee

stated that the gasket

could not be

procured separately,

and that the strainer

assembly

would be replaced if

continued strainer

cap leakage

was encountered.

The pressure test of the

strainer

cap following replacement

was satisfactory.

3.3

Electrical

Post-Maintenance

Testin

0

The team reviewed approximately

20 corrective maintenance

work documents

in

the electrical

area,

including several

in which changes

to the retest

requirements

were

made after the work order

had

been issued.

The documents

reviewed were generally well prepared

and adequately

indicated post-

maintenance

test requirements.

In most cases,

the specified post-maintenance

test

was

an existing surveillance test.

Discussions

with two maintenance

planners

indicated that the specified surveillances

are

assumed

to envelope

the design basis

requirements

for the system

and that no attempt is made to

evaluate

whether the retest actually verifies design

bases

requirements.

For

the examples

reviewed this did not seem to be

a problem;

however,

the team

noted that occasions will exist wherein

an existing surveillance test will not

adequately verify key design basis attributes of a system following

maintenance.

3.4

nstrument tion and Controls Post-Maintenance

Testin

The team reviewed

a sampling

(see Attachment 3) of corrective maintenance

work

orders

performed in the last

3 years

associated

with the following:

reactor

protection

system,

engineered

safety features

actuation

systems,

control

room

ventilation control, feedwater control

system,

and steam

bypass control

system.

From these

areas,

the team selected

18 corrective maintenance

work

documents

in the instrumentation

and controls area for review.

The documents

reviewed were from all three units at Palo Verde.

The team found that the

work documents

reviewed adequately

addressed

post-maintenance

test

requirements.

Additionally, the team recognized that the instrumentation

and control

corrective maintenance

work orders

reviewed for Unit I had adequate

attributes

in the work procedure

regarding clear maintenance

objective; pre-job

verification of system alignment, plant conditions,

and correct procedure

revision;

communication

requirements

with control

room staff on pending work

and annunciations;

measuring

and test

equipment

usage control; identification

of out-of-tolerance

readings;

engineering participation;

and instructions for

contingencies.

,

(I

1

3.5

Conclusions

In review of post-maintenance

activities the inspectors

found that work orders

were generally well prepared

and adequate

in regards to post-maintenance

test

requirements.

However, the team found

some instances,

similar to those

discussed

under post-modification testing

(Section

2 of this report), wherein

the use of an existing surveillance or inservice test

was not adequate

to

demonstrate

acceptable

completion of maintenance activities.

The team noted

other recent

instances

outside the scope of this team inspection (e.g., diesel

generator

(DG) rocker arm replacement,

NRC Inspection

Report

No. 50-.530/94-16),

wherein the use of an existing surveillance test did not

appropriately verify the acceptability of maintenance

work which had

been

performed.

The licensee's

self-assessment

of testing activities also

identified other examples.

Additional licensee

review of this issue is

encouraged.

4

SURVEILLANCE AND PN TESTING (61725 and 61726)

Surveillance

and

PM testing involves scheduled

periodic test activities

performed

on systems

or components

to ensure that their performance will meet

the operational

requirements

defined in the facility's Technical

Specifications

or the plant's design basis.

4. I

Test

Pro ram Descri tion

At Palo Verde,

Procedure

73AC-9ZZ04, "Surveillance Testing," Revision ll,

describes

the methodology

and responsibilities for administration

and

implementation of the Palo Verde Technical Specification Surveillance

Testing

(ST) program.

The procedure

defines requirements for the development,

scheduling

and tracking,

and performance of ST.

The procedure

also defines

responses

to contingencies

such

as failed steps,

out-of-tolerance

data,

and

the process

for reviewing and approving the deferral of STs.

Responsibilities

for acceptance

review of ST results

were adequately

defined for operations

and

the respective

work groups.

The procedure

appeared

to provide proper controls

for the scheduling

and accomplishment of STs.

Procedure

30DP-9HP09,

"Preventive Maintenance

Processes

and Activities,"

Revision 1.00, provides guidelines for the use

and processing of PH tasks

and

work orders

by site organizations.

The licensee

uses

PH work orders to

collect trendable

data

and failure modes.

Based

on this history of equipment

performance,

the licensee

performed periodic evaluations of established

PH

frequencies.

The procedure appropriately defines the responsibilities of

individual line supervisors

for scheduling control,

acceptance

review,

and

identification of adverse quality impacts.

4.2

Mechanical

Surveillance

and

PH Testin

Team members

accompanied

licensee

personnel

to witness the performance of

surveillance testing

and

PH activities.

In addition, the team reviewed

records,

for each unit, of the last three performances

of selected

10

surveillance tests

and

PM activities.

Surveillance tests

and

PH activities

observed

by the team were

as follows:

~

40ST-9GR01,

"Waste

Gas

Decay Tank Curie Content Surveillance Test,"

performed

Hay 10,

1994;

~

41ST-IDF01, "Diesel/Fuel Oil Transfer

Pump Operability 4.0.5," performed

May 25,

1994;

~

41ST-2EC01,

"Essential

Chilled Water

Valve Verification 4.7.6. 1,"

performed

May 11,

1994;

~

73ST-9CL08, "100'mergency Airlock Seal

Leak Test," performed

Hay 23,

1994;

Work Order 00638032,

"Sample

and

Change Oil in LPSI Hotor Bearing,"

performed

May 23,

1994;

Work Order 00645050,

"Inspect

and Clean Cooling Coil," performed

May 12,

1994;

and

~

Work Order 00647994,

"Inspect

and Clean Air Line Lubricator for FWIV

Air/Oil Pump," performed

May 24,

1994.

The team's

review and observation of mechanical

surveillance

and

PM records

led to the following observations:

4.2. 1

Use of Inservice Testing Criteria for Surveillance Tests

The team reviewed several

mechanical

surveillance test procedures.

Generally,

they were well written and contained

an appropriate

level of detail.

However,

it was noted that for some safety-related

pumps,

the design/operational

performance limits had not been specified in the Technical Specifications,

and

that in those cases,

these limits also

had not been

included in the acceptance

criteria for the surveillance test procedures.

The Technical Specifications

(Section 4.0.5) specified that these

pumps

be tested

as required

by the

ASHE

Section

XI Inservice Testing program.

However, the inservice testing

acceptance criteria were provided to monitor for degradation

of pump

performance

from nominal values,

and did not necessarily verify the ability of

the

pumps or systems

to satisfy their design performance requirements.

The

references

section of the procedures

also did not include reference

to the

calculations

which established

these

performance

requirements.

Examples

reviewed

by the team were Procedures

43ST-3SP02,

"Essential

Spray

Pond

Pump

Operability 4.0.5," Revision 3,

and

43ST-3SW02,

"Essential

Cooling Water

Pump

Operability 4.0.5," Revision 2.

The team noted that these

procedures

also did

not incorporate

instrument error allowances

in their acceptance

criteria.

The licensee

pointed out that even though the acceptance criteria in these

procedures

did not by themselves

demonstrate

system operability, the

procedures

did provide for the establishment

of initial flow rates

which

confirmed the systems'bility to meet design basis

heat transfer

11

,

1

I

f

l

requirements.

In the case of,the spray

pond

pumps,

the procedure

contained

a

note to contact the inservice testing engineer if the specified flow rate

could not be established.

However, the procedures

contained

no notation

concerning the operability significance of failing to establish

these

flows,

and in the essential

cooling water

pump surveillance

procedure,

there

was

no

note to contact the inservice testing engineer if the specified flow could not

be provided.

The team noted that these surveillance

procedures

inappropriately

used inservice testing criteria to verify system operability,

and that this represented

an example of inappropriate test criteria, in

violation of Criterion XI of 10 CFR 50, Appendix 8 (528;529;530/9412-01).

In

'esponse

to this finding, the licensee

committed to incorporate appropriate

design/operational

performance limits and instrument error considerations

into

the surveillance test acceptance

criteria for all safety-related

pumps.

It should

be noted that,

even in cases

where the acceptance criteria were

inadequate

to confirm system operability,

no system or component operability

concerns

were identified, since the related surveillance tests

were being

routinely and successfully

performed, with the minimum required flow having

been established.

The team also noted that

pumps for which design or

operational

performance limits were specified in the Technical Specifications

(e.g.,

the

AFW pumps,

Technical Specification 4.7.1.2.c)

did have these limits

incorporated into acceptance

criteria for corresponding

surveillance test

procedures,

with appropriate

adjustments

for instrument error.

4.2.2

Essential

Chilled Mater System Valve Position Verification

Surveillance

Procedure

41ST-2ECOl is conducted to verify that each valve in

the essential

chilled water system is in its correct position and not locked.

This monthly surveillance

was performed for Unit 2 under Mork Order

00656623

on Nay Il, 1994.

The team noted that system valves were labeled with both large plastic tags

and small metal tags.

Several

valves

{EC-V071, EC-V201,

and

EC-V202) were

noted to be missing plastic tags.

The auxiliary operator reported that only

the metal tags were to be used for identification.

However,

one valve

(EC-V049) was found which had

no metal tag,

and the plastic tag was

used for

identification.

The auxiliary operator

completed

a label request

form to have

the valve re-tagged with a metal tag.

The team noted that one'odel

93 ITT Barton control valve

{EC-. TV-.29) had a.

plastic cover plate over the stem assembly with moisture

on the inside of the

cover plate.

The auxiliary operator stated that this was not leakage,

but was

condensation

resulting from the low temperature

operation of the chiller

system.

Upon further examination the inspector

observed crystal

growth on the

packing bolting.

Further investigation

by the licensee

confirmed

a small

packing leak.

CRDR 1-4-0160

was written to document this observation,

including the impression

by auxiliary operators that the condensation

was

normal.

12

,

f

I

I

4.3

Electrical Surveillance

and

PM Testin

The team reviewed related

procedures

and watched the performance of selected

portions of two electrical surveillance tests,

both in Unit 3.

The tests

reviewed were for the 7-day surveillance of the station batteries

and for

performance of the 18-month integrated

safeguards

test.

The team also toured

the electrical

shop area

and briefly reviewed licensee

procedures

for

performing circuit breaker testing.

The team's

examination of surveillance testing activities resulted

in the

following findings:

4.3. 1

Integrated

Safeguards

Surveillance Test

The team identified concerns

during observation of Surveillance

Procedure

73ST-3DGOl,

"Class

lE Diesel Generator

and Integrated

Safeguards

Surveillance Test," Revision 5.

To prevent

pump starts while performing

Section 8.3 of the procedure,

operators

racked out to the test position the

circuit breaker for the Train A low pressure

safety injection (LPSI)

pump.

However, the

pump was not declared

inoperable.

With the plant conditions in

effect at the time, both trains of LPSI were required to be operable for

shutdown cooling.

Specifically, Technical Specification 3.9.8.2 requires that

two independent

shutdown cooling loops

be operable

and at least

one shutdown

cooling loop be in operation

when the reactor is in Mode 6 and the water level

is less

than

23 feet above the top of the reactor pressure

vessel

flange.

With less

than two shutdown cooling loops operable,

immediate action is

required to restore

both loops to operable status.

Technical

Specification

1. 19 specifies that, for a component to be considered

operable,

all associated

supporting

equipment

must

be capable of performing its

function, including electrical

power.

With a breaker

racked into the test

position, electrical

power was not available to the

LPSI

pump

and manual

operation

from the control

room was not possible.

This was

a violation of

Technical Specification 3.9.8.2

(530/9412-03).

The team noted that the control

room handswitch for the

LPSI pump was not

tagged to indicate the current status of the equipment.

The team also noted

that no controls were in place to ensure that

an appropriate retest

was

performed to verify that'the

LPSI

pump breaker

was properly racked in.

These

observations

were communicated

to licensee

management.

The licensee

stated

that,

although they normally perform a functional test

on the-associated-

component if feasible, this is not required before declaring the component

operable.

The team noted that in this case

a functional check was performed

several

hours after the breaker

was racked in.

However, the lack of a defined

requirement for retest after racking in a breaker

appeared

inappropriate.

4.3.2

Verification of Auto-Connected

DG Loads

The team also identified an inadequacy with regard to Step 8.8.28 of

Procedure

73ST-3DG01,

which is intended to satisfy the requirement of

Technical Specification 4.8. 1. 1.2.d.9 that the auto-connected

loads to each

DG

be verified every

18 months not to exceed

the continuous rating of 5500

KW.

The team noted that during Step 8.8.28,

when this Technical Specification

13

~

I

J

L0'

verification was performed,

a number of the loads

connected

to the

DG were

operating at less

than their design

basis electrical

load.

Since several

of

the operating

pumps

were running on minimum flow recirculation,

the indicated

DG load under these

conditions should

be substantially less

than

5500

KW.

Verifying that the connected

load did not exceed

5500

KW under the test

conditions did not meet the intent of the Technical Specification,

which is to

ensure that all auto-connected

loads

have

been properly accounted for and do

not exceed the rating of the

DG in a post-accident

condition.

The team

concluded that the acceptance

criterion of ( 5500

KW was inappropriate for the

test conditions,

in that it did not recognize that

a number of the auto-

connected

components

were operating at less

than their design basis

loads.

This failure to provide appropriate

acceptance

criteria is

an example of a

violation of Criterion XI of 10 CFR 50, Appendix

B (528;529;530/9412-01).

4.3.3

Inadequate

PH Testing of DG Air Intake Valve

While the

team was observing

Step 8.5.21 of Procedure

73ST-3DG01,

the licensee

noted that the overspeed butterfly valve for the combustion air intake line to

the Train A DG did not fully close

as required.

Upon review, it was

determined that this valve had

been disconnected

on April 24,

1994, in con-

junction with a periodic diesel

disassembly

and inspection

performed pursuant

to Work Order 00632343.

Although this work order contained

work instruction

steps

which provided for retest of the butterfly valve, the applicable

step

was in the body of the work document,

and

was not included or referenced

in

the retest section.

The work instructions also stated that tasks in the body

of the work instructions could be performed out of sequence.

As a result,

although the retest

was apparently

performed,

other work instruction steps

performed after the retest

made the valve inoperable.

The licensee

indicated

they would change

the applicable

procedure writer's guides to ensure that all

retests

are either listed or referenced

in the retest

section of the procedure

and not performed until all related work is complete.

The failure to conduct

proper testing to ensure

valve operability following maintenance activities

was

a violation (530/9412-04).

4.4

Instrumentation

and Controls Surveillance

and

PH Testin

Based

on licensee activities

and the "Top 100 List," the team selected

the

following plant components for surveillance

and

PH testing review:

Control

Room Ventilation Fire Damp'ers

HJB-H25 and KJB-H14,

and Reactor Coolant System

Pressure

Transmitters

PT-102 A, 8,

C,

and-D and their associated

bistables.

The team also selected

surveillance

samples

from the following systems

based

in part

on their placement

in Appendix A, "Critical Systems List," of the Palo

Verde Sensitive

Issues

Hanual:

plant protection

system,

supplementary

protection logic assembly,

engineered

safety features

actuation

systems,

control building ventilation, feedwater control

system,

and Radiation Monitors

RU-141 through -146.

The team reviewed the two most recent sets of selected

surveillance

and

PM

tests

performed

on these

components,

including

a total of 20 document

packages.

The team also observed

the performance of a surveillance

on the

Unit 2 Plant Protection

System

36ST-9SB04,

Work Order 654824.

Based

on these

reviews

and observations,

the team concluded that, with the exception

noted

I

0

'f

'

below, the licensee

performed the surveillances

and

PH tests

in the

instrumentation

and control areas

appropriately.

In addition,

the team reviewed with system engineers

the response

time testing

procedures

associated

with Reactor Coolant Pressure

Transmitter

PT-102A.

Based

upon its review, the team concluded that the test results

obtained

were

an accurate

measurement

of the instrument

channel

response

time, including

operation of the actuating bistables.

(7

4.4.1

Inoperable

Control

Room Outside Air Intake Damper

On Hay 10,

1994, while conducting

a quarterly

PH procedure

in Unit 1, the

licensee

found that control

room outside air intake

Damper

INHJB-N03 had been

inoperable

since the previous

PN, performed

on February

15,

1994.

The

mechanical

linkage between the actuator

and the damper

was disconnected

at

that time,

as prescribed

by the

PH, to permit exercising the actuator while

avoiding unnecessary

wear of the damper seating

surfaces.

The

PH procedure

directed the technician to cycle the damper

once after the linkage was

reconnected

to confirm proper reattachment.

However, the acceptance

criteria

for the

PM test

were not sufficiently specific to ensure that the damper

was

properly reconnected.

The licensee

found that the connecting pin had

been inserted

in only one hole

of the connecting linkage, with a cotter pin inserted

and bent over.

Proper

damper operation following the previous

PH was apparently

confirmed by

observing the damper position indicating light in the control

room, rather

than

by locally observing rotation of the damper shaft to ensure that the

damper actually moved.

Since the remote indicating light is actuated

by the

actuator rather than

by the damper,

observation of the remote indicating light

will not confirm proper damper operation.

The failure to verify that the

damper linkage had

been properly reconnected

apparently resulted

from

inappropriate

acceptance

criteria for the retest.

This is an example of a

violation of Criterion XI of 10 CFR 50, Appendix

B (528/9412-01).

Before completion of this inspection,

the licensee

revised the acceptance

criteria in the'PM procedure to provide for verification of proper damper

operation

based

on direct observation of the damper shaft.

The licensee

concluded that inoperability of the damper for the previous

3 months did not

appear to significantly affect control

room habitability,

and that it was not

reportable

pursuant to 10 CFR 50.72.

However; the licensee

subsequently-

addressed

this concern in Licensee

Event Report

No. 50-528/94-04,

dated

June

9,

1994.

4.5

Conclusions

The program established

to schedule

and track the completion of periodic

surveillance tests

was found to be working effectively.

The team noted that

the number of surveillance tests

deferred into the

25 percent

grace period

had

decreased

markedly during the last few years.

15

f

l

The team also observed that the administrative procedures

which co'ntrol the

surveillance

and

PM programs

appeared

to be well defined.

However,

the

following weaknesses

indicated

a need for additional licensee attention to

program implementation:

~

Failure to declare

a LPSI

pump inoperable while its feeder breaker

was

racked into the test position (Section 4.3. 1 of this report);

Improper positioning of retest instructions in a

PN procedure

(Section 4.3.3);

Inappropriate

acceptance criteria for verifying the total auto-connected

DG load (Section 4.3.2)

and the operability of a control

room ventila-

tion damper

(Section 4.4. 1);

~

The use of inservice testing criteria to demonstrate

system or component

operability (Section 4.2. 1);

and

~

Failure to recognize

a small valve packing leak (Section 4.2.2).

5

INSERVICE TESTING (73756)

The

NRC, through

10 CFR 50.55a,

"Codes

and Standards,"

requires certain

pumps

and valves designed

and constructed

according to the

ASNE Boiler and Pressure

Vessel

Code

(Code),

Classes

1, 2, or 3, to be designed

to enable inservice

testing.

The purpose of inservice testing of pumps

and valves is to assess

operational

readiness

of these

components,

to detect degradation that might

affect their oper ation,

and to assess

safety margins, with provisions for

increased

surveillance

and corrective action

as appropriate.

The

NRC issued

Generic Letter 89-04,

"Guidance

on Developing Acceptable

Inservice Testing Programs,"

on April 3,

1989.

Generic Letter 89-04 addressed

several

generic inservice testing

program deficiencies

and provided specific

guidance

on meeting

10 CFR 50.55a(g)

provisions that require

adherence

to

Section

XI of the

ASNE Code,

"Inservice Testing of Pumps

and Valves."

The

Generic Letter 89-04 guidance

was

used

by the licensee

to develop their

current inservice testing

program.

5. 1

Test

Pro ram Descri tion

Section 4.0.5 of the Palo Verde Units 1, 2,

and

3 Technical Specifications

requires that inservice testing

be performed

on ASNE Code Class

1, 2,

and

3

pumps

and valves in accordance

with Section

XI of the

ASNE Code

and applicable

addenda.

The Code testing requirements

are the basis for inservice tests

conducted

during the initial inservice testing interval, covering the first

120 months of commercial

operation.

January

28,

1986,

was established

as

a

common start date for the initial inservice testing interval for all three

units, with July 17,

1998,

as the

common

end date for the inservice testing

interval.

The licensee's first 10-year inservice testing

program was required

to be in accordance

with Section

XI of the

ASNE Code,

1980 Edition, through

the Winter 1981

Addendum

(80W81).

16

The Palo Verde inservice testing

programs for Units 1, 2,

and

3 ASNE Code

Class

1, 2,

and

3 pumps

and valves

are described

in Nuclear Administrative and

Technical

Hanual

Procedures

73PR-.1(2,3)XI01,

"PVNGS ASHE Section

XI Pump

and

Valve Inservice Testing

Program,

Unit 1(2,3)."

5.2

Pur ose

and

Sco

e for Ins ection of the Inservice Testin

Pro

ram

This inspection

reviewed the licensee's

implementation of their inservice

testing

program for pumps

and valves.

Verification of adherence

to

NRC

regulations

and

ASNE Code Section

XI requirements

was addressed

as part of the

inspection.

In addition to the programmatic reviews, six systems

were

selected for review to assess

inservice testing requirements:

AFW, essential

spray pond, safety injection

& shutdown cooling system,

chemical

and volume

control, essential

cooling water,

and essential

chilled water.

5.3

Inservice Testin

Pro ram Review

The team reviewed

ASHE Code Class

1, 2,

and

3 pumps

and valves with safety-

rel ated functions in the selected

systems to verify that they were included in

the inservice testing program.

The team also reviewed related relief

requests,

administrative controls,

and technical

aspects

of the inservice

testing

program.

This review did not identify any applicable

components

which

had not been included, or previously identified by the licensee for inclusion,

in the inservice testing

program.

The team reviewed

a sample of recently completed test documentation

packages

for approximately

95 inservice tests

performed

on pumps

and valves in the

selected

systems.

A partial listing is included in Attachment 3.

This review

was performed to verify that the tests

met the code test method

and frequency

requirements,

except

where relief had been granted.

The team's

review found

that the reviewed testing

had

been performed satisfactorily.

5.4

Obse

v

'o

of

nserv'ce Testin

Activit'es

The team observed

and evaluated

ongoing testing,

examined procedures,

and

assessed

instrumentation to verify that

Code requirements

were met.

The team

observed testing performed pursuant to the following inservice testing

procedures:

43ST-3SI15,

Revision

1; "Section XI'S Pump. Test-- 4;0.5; " performed

April 27,

1994,

in Unit 3;

73ST-2XI10, Revision 2, "Section XI Valve Operability Hode

1 Thru 4,

CT, SI,

and

HP 'B'rain," performed

Hay ll, 1994, in Unit 2;

42ST-2CH06,

Revision 5, "Charging

Pumps Operability Test 4. 1.2.4

and

4. 1.2.3," performed

Nay 25,

1994, in Unit 2;

and

73ST-3XI01, Revision 3, "Section

XI Valve Stroke Timing & Position

Indication Verification - Mode

1 Thru 4,

Steam Generator

No.

1

Containment Isolation Valves," performed

Hay 26,

1994, in Unit 3.

17

5 '

Conclusions

Overall, the team concluded that the inservice testing

program was being

conducted

in an effective manner.

Examples

were noted wherein

MOV stroke

times were not rebaselined

after changes

in gear ratio (see Section 2.2. 1 of

this report).

6

PREDICTIVE NINTENANCE TESTING {62703)

The team reviewed three licensee

programs

associated

with predictive

maintenance

testing:

vibration monitoring, lubricant evaluation,

and infrared

thermography

inspection.

Predictive maintenance

activities are generally

considered

to be licensee initiatives at the present

time, although it appears

that they will be components of the program the licensee

is developing to

satisfy the maintenance

rule (10 CFR 50.65)

when it becomes effective.

6. 1

Test

Pro ram Descri tion

The licensee

was developing

a documented predictive maintenance

program,

including

a common computer database

for the thre

existing principal program

elements.

The Palo Verde programs

associated

with predictive maintenance

were

as described

below:

0

0

6. 1. 1

Vibration Monitoring Program

Under this program,

the Predictive Maintenance

Group of the Site Technical

Support organization initiated actions to record,

evaluate,

and trend the

results of vibration measurements

taken

on plant components.

These activities

were performed in accordance

with Procedures

32MT-9ZZ66, "Vibration

Monitoring," Revision 3,

and 73TI-9XI01, "Vibration Data'Collection for

Surveillance Tests."

Revision 00.01.

Procedure

73TI-9XIOI noted that the

resulting vibration data were stored in

a vibration processor

and later

analyzed to determine the vibration severity which,

when used with classical

analytical

mechanics,

could determine

impending component failure.

6. 1.2

Lubricant Evaluation

Program

Under this program,

evaluations

were performed to establish

whether lubricants

were acceptable

for continued

use or were unsatisfactory

and required

replacement.

These activities were performed

by the Predictive Maintenance.

Group of Site Technical

Support in accordance

with instructions

issued in

Procedures

73DP-9ZZ04,

"Lubricant Evaluation for Continued Duty," Revision

1,

and

73AC-OAP01, "Lubrication Program," Revision 2.

Procedure

73DP-9ZZ04

stated that the responsible

component

engineer

would be notified of abnormal

lubricant evaluation data, for consideration of any effect on component

operability.

6. 1.3

Infrared Thermography

Inspection

Program

This program provided for infrared thermography

inspection of plant components

to be performed to identiFy conditions which could result in potential

component/system

degradation

or failure.

These activities were performed

by

18

0

1.

0

the Predictive Maintenance

Group of Site Technical

Support pursuant to

Procedure

73TI-9ZZ74,

" Infrared Thermography

Inspection of Plant Components,"

Revision 0.

6.2

Predictive Haintenance

Testin

Review

The team reviewed the licensee's

implementation of component vibration

monitoring, lubricant sampling

and evaluation,

and infrared thermography

inspection activities.

Good engineering practices

and verification of

adherence

to procedure

requirements

were addressed

as part of the inspection.

The team observed testing activities and interviewed personnel

involved in

these activities, regarding their knowledge of the following:

~

Vibration analysis

equipment

and techniques;

Lubricant sampling equipment,

techniques,

and evaluation methodology;

and

Infrared thermography

equipment,

techniques,

and evaluation methodology.

During the team's

interviews of personnel

and observation of testing,

licensee

personnel

demonstrated

that they were well trained

and knowledgeable

in the

equipment,

techniques,

and evaluation methodologies.

6.3

Conclusions

The team concluded that predictive maintenance

testing activities were

generally effective.

The licensee

was developing state-of-the-industry

predictive maintenance

testing activities,

and

had provided

a capable

onsite

oil quality monitoring laboratory.

The licensee

was still in the process of

developing

programs characterized

as predictive maintenance,

and had not

implemented

an administrative control procedure

governing the overall

predictive maintenance

program.

Administrative control procedures

had

been

issued for activities involving vibration monitoring, oil quality monitoring,

and infrared thermography

inspection.

The test data

from these testing

activities was in the process

of being entered into a common data

base.

7

DESIGN BASIS VERIFICATION IN TESTING (37550 and 37700)

Criterion XI of 10 CFR 50; Appendix B, requires-;

in "part, that appropriate

testing

be conducted to demonstrate

that plant systems

and components

perform

satisfactorily,

and that tests

incorporate the requirements

and acceptance

criteria contained

in applicable design

documents.

Therefore,

design limits

generally form the basis for most testing performed.

19

(

I

1

f

7.1

~0b 'ectives

The objectives of this portion of the inspection

were (1) to determine whether

applicable design limits were being properly and accurately reflected in test

procedures

and verified in actual tests,

(2) to verify that the design

bases

themselves

were correct,

and (3) to determine

the level

and effectiveness

of

Engineering

involvement in testing activities.

7.2

Sam lin

and

C iteria

To achi.eve

these objectives,

samples of various types of tests

were examined,

along with corresponding

design

and licensing basis

documents.

The team also

reviewed

a sampling of the procedures

used to control design

and testing

activities at the site.

Testing samples

were identified for systems

and

components

determined

by the licensee to be of higher safety significance,

as

indicated in the licensee's

"Top 100 List" and Appendix A - Critical Systems

List, of the Palo Verde Sensitive

Issues

Manual.

The systems

selected

were

the

AFW system,

the backup nitrogen accumulators for the atmospheric

dump

valves,

the essential

spray

pond system,

and the essential

cooling water

system.

The samples

examined

included the following numbers

and types of

documents:

7

9

22

3

2

2

14

7

10

10

8

Surveillance test procedures

Modifications

Material nonconformance

reports

(MNCR)

Licensee

event reports

CRDRs

Engineering evaluation requests

Calculations

Design basis

manuals

Vendor manuals

Drawings

Technical Specifications

sections

FSAR sections

SER sections

Administrative, design control,

and work control procedures

7.3

Ins ectio

Findi

s Related to Desi

n

sis

Ve i icat'on

Generally,

the team found that design bases-were

being correctly reflected. and..

verified in testing

acceptance

criteria, except

as discussed

below; that the

design

bases

themselves

were correct;

and that engineering

personnel

were well

qualified and capable.

With minor exceptions,

the design

and testing control

procedures

were well written and appropriately detailed.

Specific findings

from the team's

review of the above

documents

were

as follows:

7.3. 1

Atmospheric

Dump Valve Backup

N, Accumulator Discrepancies

The team reviewed the design of the safety-related

atmospheric

dump valve

backup nitrogen accumulator

system.

This revi ew included

FSAR

Sections

7.4. 1.1.7,

"Atmospheric

Dump System"; 9.3. 1,

"Compressed Air System";

and 10.3.2.2.4,

"Atmospheric

Dump Valves"; the surveillance test procedure for

20

'

I

~

the nitrogen accumulators,

43ST-3SG05,

"ADV Nitrogen Accumulator Drop Test,"

Revision 5; the design basis calculation for the test

acceptance

criteria,

13-HC-SG-314,

"Nitrogen Tank Pressure

Requirements,"

Revision 2, July 23,

1992;

and Technical Specification 3/4.7. 1.6,

"Atmospheric

Dump Valves."

Two

areas

of concern

were identified during this review and are discussed

below.

7.3. 1. 1

Incorrect Technical Specification

Requirement for N, Accumulator

Pressure

Technical Specification 4.7. 1.6 requires that the atmospheric

dump valve

backup. nitrogen accumulator tank pressure

be verified daily to be

> 400 psig

for the atmospheric

dump valves to be considered

operable.

However,

as

indicated in

CRDR 92-0329,

dated

June 4,

1992, the minimum required pressure

for the accumulator

tanks

was changed

in 1992 from > 565 to > 615 psig.

In

reviewing this concern,

the team learned that the licensee first discovered

this discrepancy

in 1989

and then again in 1990.

At those times, the

operability limits were revised

from > 400 to > 550 psig

and

> 565 psig,

respectively.

Further review by the team established

that the licensee

had

performed the daily verification required

by Technical Specification 4.7.1.6

(per Procedure

40ST-9ZZ16,

"Routine Surveillance Daily Hidnight Logs,"

Revision 3) by verifying that the associated

low pressure

alarm annunciator

was not activated,

and that this alarm setpoint

had

been set at 600 + 10 psig.

The team therefore

concluded that the licensee

had

been properly verifying

system operability before

1992, notwithstanding the determination that the

initial minimum pressure

requirement of > 400 psig was nonconservative.

The last change in the operability limit from 565 to 615 psig was

made in 1992

to allow a higher leakage rate from the system in order to decrease

the

failure rate during surveillance testing.

This necessitated

a change

in the

accumulator

low pressure

alarm setpoint

from 600 + 10 psig to 630 + 10 psig.

After the close of the inspection,

the licensee

provided information

confirming that the alarm setpoint for all three units

had

been raised to

630 + 10 psig before the surveillance test

was

changed to permit an increase

in the allowed accumulator

leakage rate.

This indicated that the daily

surveillance test also would have properly verified operability of the

atmospheric

dump valves after 1992.

Although the licensee

had responded

appropriately to safety concerns

related

to minimum required accumulator

pressure,

a Technical Specification

amendment

request to correct this inaccuracy in the Technical Specification

was still

undergoing internal licensee

review at the time of this inspection.

The team

noted that this represented

an elapsed

time of approximately

5 years

since the

Technical Specification discrepancy

had

been identified.

Criterion III,

"Design Control," of 10 CFR 50, Appendix 8, XVI, requires that measures

be

established

to assure

that the design basis,

as defined in Section 50.2, is

correctly translated

into specifications.

Contrary to this requirement,

although the licensee

determined

on three occasions

in 1989,

1990,

and

1992

that the minimum accumulator

pressure

specified in the Technical Specification

was incorrect,

the licensee

had not submitted

a request to the

NRC,

as of the

time of this inspection,

to have the correct

minimum pressure

reflected in the

Technical Specification.

This is

a violation of Criterion III of 10 CFR 50,

Appendix 8.

The licensee

was reviewing

a proposed

change request,

which was

21

f

l

I

subsequently

submitted to the

NRC on June

17,

1994.

Since the critet ia of

Section VII.B(I) of the

NRC Enforcement Policy were satisfied, this violation

was not cited.

7.3. 1.2

Inadequate

Design Calculation for N, Accumulator Pressure

Drop Test

In reviewing the design basis calculation which established

the acceptance

criteria for the atmospheric

dump valve

N, accumulator pressure

drop

surveillance test (Calculation

I3-HC-SG-314,

"Nitrogen Tank Pressure

Requirements,"

Revision 2, July 23,

1992,

and Surveillance Test 43ST-3SG05,

"ADV Nitrogen Accumulator Drop Test," Revision 5) the team determined that two

factors

had not been considered:

(I) the potential reduction in temperature

of the accumulators

over the 13.3-hour duration of the event for which the

atmospheric

dump valves are required,

and (2) energy losses

due to the work

done in the valve actuators,

plus other non-reversible

energy losses.

When

these factors were considered,

using the original calculation techniques,

the

acceptance

criterion changed

from 34 psig/hour

maximum allowable pressure

'loss

to 32 psig/hour,

indicating that the original acceptance

criterion was non-

conservative.

This placed the acceptability of some previous test results in

question.

However,

by using

a more refined calculation technique,

the

licensee

was able to show that,

even considering

these factors,

a pressure

loss

as high as

35 psig per hour would be acceptable.

The licensee

committed

to formally revise this calculation,

incorporating these factors

and the

refined technique.

7.3.2

Inadequate

Resolution of AFW Design Discrepancy

In 1990,

NNCRs 90-AF-0002,

0003,

and 0004 for the three units were written to

address

a design deficiency which caused

overspeed trips of the turbine driven

AFW pumps

on startup.

The cause of the problem was identified as insufficient

time between

opening of the one-inch turbine stop 'valve bypass

solenoid

valves,

SGA-UV134A and -138A,

and opening of the corresponding

6-inch motor

operated

stop valves

SGA-UV134 and -138.

As a result of this insufficient

delay,

the governor was, in some cases,

not yet controlling the turbine when

the 6-inch stop valve opened,

and

an overspeed trip would occur.

When the

steam supply line was initially cold, the energy in the steam admitted

by the

bypass

valves

was spent heating the piping rather

than bringing the turbine

up

to speed

so the governor could take control.

The condensate

resulting from

heatup of the steam line also

appeared

to contribute to possible

overspeed,

being injected into- the turbine along with. steam

as the stop valve. opened.

The licensee

found that

when the stop valve leaked,

such that the line was

maintained hot, the energy in the steam admitted

by the bypass

valves

was

applied to rolling the turbine,

and less

condensation

was produced,

so that

an

overspeed

did not occur.

The licensee

determined that when the time delay was increased

from

6 to

10 seconds

and the steam supply line was maintained

above I93', the

turbine would not overspeed.

It was also discovered that the 6-inch stop

valves normally leaked sufficiently to maintain this temperature,

even with

their torque switches at normal settings.

With the resultant

steam cutting of

the valve seats,

the leakage rate

was at times excessive,

with continued

turbine rotation observed after closure of the steam stop valve on at least

22

'

l

I

one occasion.

However,

the licensee's

"interim" resolution of the

HNCRs was

to allow the stop valves to continue to leak and to require Operations

to

verify that the piping temperature

was

> 193'

every

6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to assure

operability.

This interim resolution

was still in effect

4 years later at the

time of this inspection.

The

HNCR resolutions,

however,

did not identify that these valves,

in addition

to their safety function to open to admit steam to the

AFW turbine,

have

a

second safety function as containment isolation valves,

as identified in

Table 6.2.4<Wof the

FSAR.

This function requires

these

valves to be capable

of isolation

on demand

and to be

as leak-tight

as reasonably

achievable

(no

specific leakage limit was identified).

Requiring these

valves to leak as

a

condition of operability for the turbine-driven

AFW pump appears

contrary to

their containment isolation safety function.

This created

a nonconforming

'ondition

and,

in effect, constituted

a change to the facility as described

in

the

FSAR.

The

10 CFR 50.59 screening,

performed

on August 23,

1993, to re-

solve this

HNCR, concluded that

no change to the facility as described

in the

FSAR was involved,

so no safety evaluation

was performed.

This is

an example

of a violation of the requirements

of 10 CFR 50.59 (528;529;530/9412-05).

The licensee

pointed out that the leakage of these

valves

was enveloped

by the

FSAR Chapter

15 accident

analyses

which considered

the single failure to close

of one of these or other similar valves associated

with the steam generators

in determining that the offsite dose

consequences

of all accidents

were less

than the

10 CFR 100 limits.

However, the team noted that since leakage of

these

valves is known to already exist, this leakage

should

be considered

along with any separate

single failure associated

with the steam generator

or

containment to confirm that onsite or offsite doses

would not be greater

than

indicated in the accident

analyses.

In a letter to the

NRC dated

June 30,

1993, the licensee

proposed

an

amendment

to Technical Specification 3/4.3.2 to increase

the response

time of the

turbine-driven

AFW pump from 30 to 46 seconds,

which is consistent

with the

Technical Specification

response

time for the motor-driven

pumps.

This would

increase

the delay time between

the opening of the bypass

valves

and the stop

valves from 10 to 26 seconds,

thereby providing more warmup time for the steam

line.

The objective of this change

was to produce

a final resolution for this

concern

by allowing the requirement to maintain the pipe hot to be eliminated.

However, the licensee

had

no definitive testing results or analyses

which

showed that this .change

would resolve the -problem at the lowest credible steam

line temperature (i.e., at low ambient temperature

with a tightly seating

steam

stop valve).

7.3.3

Reduction in Essential

Spray

Pond Capacity

FSAR Section 9.2. 1.6 and the basis for Technical Specification 3/4.7.5,

"Ultimate Heat Sink," state that the spray

pond has

a 27-day cooling water

capacity,

without makeup.

However, in 1993, Calculation

13-HC-SP-307

was

performed to refine the analysis of the spray pond.

This reanalysis

revealed

that the capacity

was actually only 26 days.

Upon making this discovery,

the

licensee

changed

the design basis to indicate

a minimum required spray

pond

capacity of 26 days.

The

10 CFR 50.59 screening for this change

concluded

23

'

that

a safety evaluation

was not required.

The team noted,

however, that this

change

in design

requirements

for the ultimate heat sink reduced

the margin of

safety

as defined in the basis for the Technical Specification.

Section

10 CFR 50.59,

"Changes,

Tests,

and Experiments," of the

NRC

Regulations

states

that

a proposed

change is deemed to involve an unreviewed

safety question if the margin of safety,

as defined in the basis for any

Technical Specification,

is reduced.

This regulation also requires

a licensee

who desires

to make

such

a change to submit

an application for amendment of

his license.

The licensee's

failure to recognize this change

as

an unreviewed

'afety. question,

and to submit

an application for license

amendment,

is an

example of a violation of 10 CFR 50.59 {528;529;530/9412-05).

The original licensing justification for a 27-day capacity,

instead of the

30 days specified in Regulatory

Guide 1.27,

was

based

on the licensee's

being

able to establish

new wells in 15 days,

as described

in the

SER.

The licensee

maintained that since the newly calculated

26-day capacity

was still greater

than the 15-day drilling time, the margin of safety

had not been

reduced.

However, the

NRC noted that the margin of safety

as defined in the Technical

Specification basis

included

12 days to analyze

and evaluate

the situation,

and that this margin had in fact been

reduced

by one day.

7.3.4

Unverified Calculation Assumptions

Calculation 13-HC-IA-301, Revision 2, dated

10/26/93,

was performed to

determine

the pressure

drop in the instrument air system supply to the safety-

related

atmospheric

dump valves for normal

and transient conditions.

Procedure

81DP-OCC05,

"Design

and Technical

Document Control," Revision 5,

stated

in Section 4. 1.7 that documents

in which there are unverified

assumptions

are to be considered

"preliminary" and can not be used for

activities affecting plant operation.

The team noted that this calculation

contained five assumptions

which remained unverified at the time the

calculation

was issued

as

an approved

document.

The licensee

stated that

action would be taken to address this observation.

The team noted that the

air supply addressed

in this calculation is not safety-related,

although its

failure to perform as designed

could present

an unnecessary

challenge

to the

safety-related

backup nitrogen system.

7.3.5

Inadequate

10 CFR 50.59 Safety Evaluation Screenings

Section

10 CFR 50.59,

"Changes,

Tests,

and Experiments," of the

NRC

'egulations

allows licensees

to make changes

in the facility as described

in

the safety analysis

report without prior review and approval

by the

NRC if

they do not involve a change

in the Technical Specifications

or an unreviewed

safety question.

One of the first steps

in the evaluation

process

is

a screening to determine

if the proposed

change is indeed

a change "in the facility as described

in the

safety analysis report." If it is not,

and other criteria are satisfied

{e.g.,

a Technical Specification

change is not involved),

no safety evaluation

is required.

The team reviewed

numerous

such screening

documents

and found

that in many cases

the interpretation of "as described

in the

FSAR" appeared

24

1

I

to be too narrow; that is, unless

the particular piece of hardware

being

changed

was explicitly described

in the

FSAR,

even if it was

a component of

something

which was described,

this screening

question

was in several

cases

inappropriately

answered

"no."

As

a result,

these

changes

did not receive the

safety evaluation required

by 10 CFR 50.59,

and there

was

a potential that

an

unreviewed safety question

could go undetected.

The following are examples

wherein this weakness

in 10 CFR 50.59 screening

was observed,

in addition to

the examples cited previously in Sections

7.3.2

and 7.3.3 of this report:

~

LDCP l(2,3)LJ-SP-061,

Revision 0,

December

31,

1991,

"ECWS [essential

cooling water system)

Heat Exchanger

Thermal Relief Valve Change,"

replaced

the

150 psig thermal relief valves

on the essential

cooling

water system heat exchangers

with 100 psig relief valves to prevent

overpressurizing

the connected

system piping between

the heat

exchangers

and the closest isolation valves,

which was designed

for only 100 psig.

No safety evaluation

was performed

even though similar thermal relief

valves

on the spray

pond side of the

DG heat exchangers,

also set at

100

psig,

had lifted when the spray

pond

pumps were started.

This had

resulted

in deterioration

and sticking open of these

valves

and failure

of ASME Section

XI pressure

tests

due to their exposure to the

aggressive

chemistry of the spray

pond water.

Such sticking open could

compromise

the 26-day capacity of the spray ponds.

The essential

cooling water system heat exchangers

are described

in FSAR

Section 9.2. 1, "Station Service Water System,"

and the relief valves are

shown in FSAR Figure 9.2-1.

~

Setpoint

Change

Request

SXX-SG-002,

November 25,

1992,

changed

the

setpoint of pressure

control valves

13-J-SGA-PCV-0310

and -0317

and

13-J-SGB-PCV-0303

and -0323, which provide backup nitrogen for actuation

of the atmospheric

dump valves

(a safety-related

function) from 105 psig

to 100 psig.

The screening

judged that this was not

a change

in the

facility as described

in the

FSAR.

However, the atmospheric

dump

valves,

including their backup nitrogen supply,

are described

in

Sections

7.4. 1. 1.7 and 10.3.2.2.4 of the

FSAR.

MNCR) 92-EW-3018,

Revision 0, October 5,

1992, identified degraded

tubes

in essential

cooling water heat exchanger

3M-EWA-EOl, and

MNCR 92-EW-2021,

Revision 0,

December 8,

1992, identified degraded

tubes

in essential

cooling water system heat exchanger

2M-EWA-E01.

The

resolutions

were to plug -nine tubes

and eight tubes respectively.

The

10 CFR 50.59 safety evaluation

screenings

judged that these

were not

changes

to the facility as described

in the

FSAR.

However,

the heat

exchangers

were described

in FSAR Sections

9.2. 1, "Station Service Water

System,"

and 9.2.2. 1, "Essential

Cooling Water System."

There were indications that this was

a longstanding,

previously identified

concern.

In 1989, to address this concern,

the screening

question

was changed

to ask whether the issue

under review was

a change to the facility, regardless

of whether it is described

in the

FSAR.

In late

1992,

when this interpreta-

tion was determined to be too broad,

the stipulation "as described

in the

~

FSAR" was restored to the question.

A recent audit by the licensee's

Indepen-

25

I

l

(f

dent Safety Engineering

Group also concluded that, of the 50.59 screenings

reviewed,

a notable portion of the interpretations

of "as described

in the

FSAR" were too narrow.

Although the audit report

had not been

issued at the

time of the inspection,

a presentation

had

been

made to licensee

management

describing the concern,

and recommending that the 50.59 procedure

be

strengthened

with regard to the screening criteria and that additional

training be instituted.

Team discussions

identified a reluctance

among

some

members of the licensee's

staff to recognize

an unreviewed safety question,

since they perceived that

this would reflect adversely

on the organization.

The team

commented

during

meetings with management

and at the exit interview that the identification of

an unreviewed safety question

can indicate thoroughness

in th'e review of

licensee activities,

and that the detection of unreviewed safety questions

during the ongoing design basis

documentation

review should not be unexpected.

7.4

Conclusions

The team concluded that,

in general,

design

bases

were being correctly

reflected

and verified in testing

acceptance

criteria, with the exceptions

described

above; that the design

bases

themselves

were correct;

and that

engineering

personnel

were well qualified and capable.

With minor exceptions,

the design

and testing control procedures

were w'ell written and appropriately

detailed.

The team observed that several

of the findings indicated

a licensee

strength

in the identification and definition of discrepancies accompanied,

however,

by a licensee

weakness

in the timeliness or effectiveness

of their resolution.

Examples of untimely or ineffective resolution of problems

included the

atmospheric

dump valve accumulator pressure/leak

rate issue

(Section 7.3.1 of

this report)

and resolution of the

AFW turbine overspeed trip issue

(Section 7.3.2).

A weakness

in dealing with licensing issues

was also

apparent.

Examples

included delay in resolving errors in the Technical

Specifications

(Sections

2.3. 1 and 7.3. 1. 1) not resolving

10 CFR 50.59

screening

weaknesses

in a timely manner

(Section 7.3.5),

apparent failure to

recognize

the

AFW turbine steam stop valves

as FSAR-identified containment

isolation valves,

and

an apparent

reluctance to acknowledge

unreviewed safety

questions

due to a perception that the identification of such questions

would

reflect negatively

on the organization.

Although Engineering

appeared

to be somewhat'nvolved

in site activities,

there were indications that more involvement is needed

in the definition of

routine testing requirements

and in the timely resolution of identified

problems.

This was illustrated

by the noted examples of inappropriate testing

criteria, including the finding that design or operational

performance limits

had not been incorporated into the criteria for some surveillance tests

intended to verify equipment operability (Section 4.2. 1).

26

I

1

t1

I

8

LICENSEE SELF-ASSESSMENT

OF TESTING PROGRAMS (40500)

8. 1

Recent

Self-Assessments

The licensee

had performed three self-assessments

in the last year related to

testing.

The first assessment

was conducted

in May 1993

and consisted of a

review of 11 modifications.

The assessment

appeared

to be thorough

and

identified numerous

issues,

principally with post-modification testing.

The

issues

were documented

on several

CRDRs

and assigned

to the responsible

organizations for resolution.

The team noted that substantive

changes

had

been

made in response

to the assessment,

and that

gA had diligently tracked

each

issue to ensure that appropriate corrective actions

were taken

when

warranted.

The changes principally involved (1) the strengthening

of

procedures

regarding post-modification testing to clarify the responsibilities

assigned

to each organization

and (2) additional training for those

involved

in post-modification testing.

A followup assessment

was conducted

in

September

1993, involving the review of 17 work orders for proper post-

maintenance

testing.

Again numerous deficiencies

were identified, questioning

the effectiveness

of the corrective actions

taken

as

a result of the

May 1993

assessment.

A comprehensive

self-assessment

of licensee testing

programs

was conducted

in

February

1994 by a team of 12 licensee

individuals representing

maintenance,

engineering,

and quality assurance

to address

the effectiveness

of the

previous corrective actions.

There were

no team members

from outside of the

APS organization.

The team's

Report ¹431-00003-RBP/EAS,

"RETEST," issued

on

Harch 29,

1994, indicated that the concerns

regarding post-modification

testing

had

been largely resolved

by a new design validation testing

approach

which was implemented in December

1993.

However, inconsistencies

with post-

maintenance

test implementation

were identified.

In particular,

the

licensee's

assessment

team noted instances

in which the specified post-

maintenance

testing did not appear appropriate.

Action items designated

as

a

result of this assessment

were documented

on

CRDR 9-4-0188.

At the time of

the inspection,

these

action items

had not yet been completed.

8.2

Conclusions

It appeared

that the licensee

had performed aggressive

assessments

in the

retest

area

and

had aggressively

monitored the implementation

and

effectiveness

of the corrective actions taken.

However; it was not- clear

whether the prescribed corrective actions

have actually corrected all

identified deficiencies.

The team encouraged

APS to evaluate

the results of

their assessments

against

those of this team

and to consider participation

by

individuals from outside the

APS organization

in future assessments.

27

TTACHNENT I

I

PERSONS

CONTACTED

icensee

Perso

nel

• W.

• J

• E

• J

R.

D.

• C

S.

D.

• Q

• J

• F

• M

R.

• W.

• Q

• S

• A.

• A

• C

• Q

• C

• S

T.

• D

P.

• p

• D

• Q

• T

R.

T.

• G

• C

• W

• F

• J

T.

• M

D.

• R.

• J

Stewart,

Executive Vice President

Levine, Vice President,

Nuclear Production

Simpson,

Vice President,

Nuclear Support

Bailey, Assistant Vice President,

Engineering

Bernier, Supervisor,

Nuclear Regulatory Affairs

Carnes,

Shift Supervisor

Connell, Supervisor,

Site Technical

Support

Coppock,

Supervisor,

Valve Services

Engineering

Fan,

Supervisor,

Pr obabilistic Risk Assessment

Garchow, Director, System Engineering

Garden, Assistant Shift Supervisor,

Unit 3 Operations

Gowers, Site Representative,

El

Paso Electric Company

Kesser,

Director, Nuclear Engineering

Hodge,

Manager, Mechanical/Civil Design

Hogstrom, Authorized Nuclear Inspector

Ide, Plant Manager,

Unit I

Kanitz, Senior Engineer,

Nuclear Regulatory Affairs

Kesler, Supervisor,

Electrical

and Instrumentation

and Contr

Khanpour, Project Manager,

Design Basis Project

Krainik, Manager,

Nuclear Regulatory Affairs

LaPeter,

Supervisor,

Unit I Work Control

Laskos,

Supervisor,

Nuclear Assurance

Lewis, Senior Engineer,

Instrumentation

and Control Design

Lopez,

APS Inspection

Core

Team

Matlock, Manager,

Nuclear Oversight

Mauldin, Director, Maintenance

Maynard, Supervisor,

System Engineering

Myers, Administrative Technician,

Nuclear

Regulatory Affairs

Oakes,

Primary Discipline Engineer,

Inservice Inspection

and

Odom, Hanager,

Document Control

Phillips, Supervisor,

Engineering

Standards

Prabhakar,

Manager,

Independent Safety/guality Engineering

Radtke, Unit'3 Operations

Supervisor

Shanker,

Department

Leader,

Engineering

Assurance

Seaman,

Director, Nuclear Assurance

Simko, Hanager,

Valve Services

Department

Swirbul, Hanager,

Electrical

and instrumentation

and control

Thompson,

Technical

Management Assistant,

Plant Support

Traylor, Supervisor,

Hechanical

Standards

Winsor, Supervisor,

Nuclear Engineering

Design

Wittas, Supervisor,

Independent

Safety

Younger, Technical

Management Assistant,

Site Maintenance

Zaghloul, Validation Lead,

Design Basis Projects

ol Design

Testing

Design

/'

1.2

Pacific

Gas

8

lectic

Com an

• J. Hjalmarson,

Power Production

Engineer,

Diablo Canyon

Power Plant

• D. Shelley,

Senior Engineer,

Diablo Canyon

Power Plant

1.3

NRC Personnel

• P. Gwynn, Director, Division of Reactor Safety

• J. Mitchell, Acting Deputy Director, Division of Reactor

Safety

• K. Johnston,

Senior Resident

Inspector,

Palo Verde

In addition to the personnel

listed above,

the inspection

team contacted

other

personnel

during this inspection period.

• Denotes personnel

who attended

the exit meeting.

2

EXIT NEETING

An exit meeting

was conducted

on Hay 27,

1994.

During this meeting,

the team

leader

reviewed the scope

and findings of the report.

The licensee did not

express

a position

on the inspection findings documented

in this report,

but

stated that they would be evaluated to determine

what additional actions

are

appropriate.

The licensee

did not identify as proprietary

any information

provided to, or reviewed by, the team.

)

1

I

CHMENT 2

INSPECTION FINDINGS INDEX

Violation 528;529;530/9412-01,

with five examples,

was

opened

(Sections

2.2. 1, 2.3. 1, 3.2. 1, 4.2. 1,

and 4.3.2).

Inspection

Followup Item 528;529;530/9412-02

was

opened

(Section 3.2.1).

Violation 530/9412-03

was

opened

(Section 4.3. 1).

Violation 530/9412-04

was opened

(Section 4.3.3).

Violation 528;529;530/9412-05,

with two examples,

was opened

(Sections 7.3.2

and 7.3.3).

Two non-cited violations were noted (Sections

2.2.2

and 7.3. 1. 1).

f

l

(

0

ATTACHMENT 3

DOCUH NTS

REVIEW D

The following is

a listing, by report section,

of the principal documents

reviewed during this inspection

which were associated

with specific testing

activities.

However, listing of a document

does not indicate that the team

reviewed all information contained

in the document.

The

tecum also reviewed

numerous

other controlling and reference

documents

which are not listed.

These

included licensee

program documents;

'administrative control procedures;

plant design or description

documents;

design basis

manuals;

piping and instrument

diagrams

and other drawings;

selected

vendor manuals;

and pertinent portions of the

FSAR, the

SER,

and the

Technical Specifications.

2.2

Mechanical

Desi

n Validation Testin

LDCP 2LM-EW-036, Sleeving of Unit 2 Trains

A 8

B

EW Heat Exchangers,

Tag Nos.

2HEWA(B) EOl, Revision 0, with Modification )

Design

Change

Package

(DCP) 1/2/3-FJ-SQ-060,

RHS Hi-Lo Fuel Building

Effluent Radiation Monitor Separation,

Revision 0, with Modifications

1

through

3

LDCP 1/2/3-LE-SP-067,

Conversion of Spray

Pond Spray

and Bypass

Valves

from Motor Actuation to Manual Actuation, Revision

0

LDCP 3LH-AF-102,

HOV Gear Set

Change for Auxiliary Feedwater

Isolation

Valves

3JFBUV0034

and

3JFBUV0035,

Revision

0

LDCP 1/2/3-LH-SG-181,

Live-loaded Valve Packing for Lower Feedwater

Con-

trol Valves

SGNFV1112

and

SGNFV1122,

Revision 0, with Modifications

1

and

2

Design Validation Testing Requirements

for LDCP 1/2/3LE-SP-067,

Revision

0

Specification

13-JM-605, Butterfly Valves. Nuclear Service; Revision

8

Specification

13-J-ZZS-220,

Motor Operated

Valve Technical

Data Files,

Revision

7

Work Orders

(WOs) 00596670,

00596671,

and 00596672,

Implement design

change

packages

01FJSQ060,

02FJSQ060,

and

03FJSQ060,

respectively,

Revision

0

Work Orders

00636099

and 00636100,

Implement

LDCP 2LH-EW-036 to Sleeve

the Tubes in the "A" and "B"

EW Heat Exchangers,

respectively,

Revision

0

J

Work Order 00647230,

Implement

LDCP 3LE-SP-067 for Train A Spray

Pound,

Revision

0

lectrical

Desi

n Validation Testin

~

DCP Unit

1 1XE-PK-037, Revision 0,

Replacement

of Existing Exide Model

"GN" Class

lE Station Batteries

EPKAFll, EPKBF12,

EPKC13,

and

EPKD14

with ATILT Hodel

KS-20472

Round Cells

~

DCP Unit

1 1PH-ZC-200,

Permanent

Reactor Cavity/Refueling

Pool

Seal

~

DCP Unit

1 1PH-DG-071,

Diesel

Generator Starting Air Upgrade

~

DCP Unit

1 1PE-SB-072,

Reactor Trip Switchgear

Upgrade

~

DCP Unit

1 1PJ-SB-071,

PPS Relay Hold Push button Replacement

~

DCP Unit

1 IXE-PB-024, Replace

Second

Level Undervoltage

Relays with

Solid State

Relays

LDCP Unit 2 2LE-GR-050,

Rewire Retork Actuators to Open Containment

ISO

Actuation Signal Circuit Upon Limit Close

LDCP Unit 2 ZLE-QD-029, Stabilized Current Shunt Installation

on Exide

Batteries for Control

Room Emergency Lighting

LDCP Unit 2 2LJ-SI-216, Installation of 'Strain

Gauges-

LDCP Unit 3 3LJ-SI-217, Installation of Strain

Gauges

LDCP Unit

1 1LE-SB-075,

Rewire Heater Junction Thermocouples

QSPDS

LDCP Unit

1 1LE-SA-023, Revision 0,

ISG Jumper Installation

~

Setpoint

Change

Requests

(SPCRs)

SXX-HP-001 and SXX-SF-004

~

Plant

Change

Packages

85-01'-SK-014-00

and 88-02-CH-030-00

~

Site Hodifications 01-SH-DG-025

and 02-SH-SG-016

~

Degraded

Voltage Plan of Action, Week of November 20,

1993

2.4

Instrumentation

and Controls

I&C

Desi

n Validation Testin

LDCP 1LJ-SQ-067

J-SQBRU-1

Flow Totalizer and Transducer

Replacement,

Unit

1 Work Order 00552374

74RH-9EF41,

Radiation Honitoring System Alarm Response,

Revision

4

DCPs

1PJ-SQ-071,

2PJ-SQ-07l,

and 3PJ-SQ-071,

Hain Steam Line N-16

Honitors, Revision

0

2

1

I

j

f

1

~

DCP 1-SH-DG-025,

DG Temperature

Controllers for Jacket

Water

and

Lube

Oil; Unit

1 Work Orders

518348

and 611741,

and Surveillance Test

(ST)

Work Orders

622375

and 628553,

February 7,

1991

DCP I-SH-Sg-028, Honitoring Containment;

corrective maintenance

Work

Orders

403405,

407760,

and 403329,

and Work Order 383155, July ll, 1989

~

SPCR S2J-SG-002,

Atmospheric

Dump Valves Nitrogen Supply Regulators;

Unit 2 Work Orders

595489,

595490,

595491,

595492

~

SPCR SlJ-SG-001,

Atmospheric

Dump Valve Limit Switch Settings;

Unit

1

Work Orders

618805,

619392,

619391,

619393,

and 619394

3.2

Hechanical

Post-Maintenance

Testin

~

Work Order 00562760,

Refurbish Actuator on 3JCHAHV0524, Revision

2 with

Amendment

B

~

Mork Orders

00619511,

00636324,

00636326,

and 00619543,

Calibrate

FW

Control Valve Loop, Revision

0

~

Work Orders

00642639

and 00642651,

Change

HOV Gear Ratio from 45.29 to

42.5 to Lower Valve Stroke Time to an Acceptable

Design Value,

Revision

0

~

Mork Orders

00653367,

00653521,

00653513,

and 00653523,

Correct

Worm

gear

on 3JRCEHV0430,

3JRCEHV0432,

3JRCEHV0431,

and 3JRCEHV0433,

respectively,

Revision

0

~

Work Orders

00657872,

00658213,

00657873,

00660155,

and 00660156,

Replace Hotor Pinion and

Worm Shaft Gears to Hatch Operators

1JSGAUV0134,

2JSGAUV0138,

1JSGAUV0138,

3JSGAUV0134,

and

3JSGAUV0138,

respectively,

to Bill of Haterials,

Revision

0

3.3

lectrical Post-Haintenance

Testin

Wor k Order 00637992,

Mork Order 00601808,

Mork Order 00648950,

Work Order 00648748,

Mork Order 00613280,

Work Order 00642097,

Work Order 00637228,

Work Order 00644477,

Work Order 00632455,

Work Order 00634329,

Work Order 00633931,

Wor k Order 00631222,

Work Order 00648950,

Reactor Trip Switchgear

Channel

C Circuit Breaker

4. 16KV Class

lE Indoor Switchgear

H2 Recombiner Control

Panel

Steam Trap SGN-H241S01

VLV

Plant Protection

System Cabloc Control

Room

Rotary Relay

ESFAS

AUX Relay Cabinet

ALOC

AT-W Pump AFA-POl Turbine

LOC

HPSI

2 Flow Control

TO

Type H26

CKTBRK for LOC 01EJD03SJ02100

Type K-6005 Circuit Breaker for LOC 04EJD025J02100

Diesel

Generator

A

HE Recombiner Control

Panel

Work Order 00621836,

4. 16

KV Class

1E Indoor Switchgear

l~

0

3.4

Instrument

and Controls Post-Haintenance

Testin

Unit

1 Corrective Maintenance

(CH) Work Order 654895,

Troubleshoot

and

Rework/ Replace

Components

to Correct

Problem

Causing

Supplementary

Protection

Logic Assembly Cabinet

1JSBAC04 to Trip, Harch 22,

1994

Unit

1

CH Work Order 636103,

Troubleshoot/Rework/Replace,

Components

as

Needed to Correct Problem of Reactor Trip Breaker

1JSBBC03

Not Opening

Mhen It Received

a Supplementary

Protection

Logic Assembly Signal,

October 28,

1993

Unit

1

CH Work Order 606235,

Troubleshoot

Flow Switch/Run Time Counter

per Engineering

Evaluation

Request

(EER) 92-HJ-008

and Engineering,

June

7,

1993

Unit

1

CH Work Order 461552,

Troubleshoot

and

Rework to Correct the

Problem(s)

causing

RCATLOOPll2HA to Indicate

5 Degrees

Lower Than Other

Channels,

January

2,

1991

Unit

1

CH Work Order 414560,

Excore Safet~

CH. A, B,

C and

D Indicated

Log Power Fluctuates

Apparently due to Various Outside Influence.

Troubleshoot/

Rework Problem w/EED, April 10,

1992

Unit

1

CH Mork Order536343,

CEAC Troubleshoot/Rework/Replace

as

Needed

to Stop Drifting RSPT 18,

54,

78,

5. 83,

February

17,

1992

Unit 2

CH Work Order 657861,

Troubleshoot,

Rework or Replace to Correct

Problems

Causing

Channel 'A'PS Trips During Bistable Select

Switch

Operation, April 15,

1994

Unit 2

CH Mork Order 509896, Troubleshoot

and Rework/Replace

Components

to Correct'he

Problems with Parameter ll (Lo SGI Press)

Setpoint

Reset

in Channel

A, August 10,

1991

Unit 2

CH Work Order 462031,

Heasure

Contact Resistance

of All Relay

Cards

and Replace

Any That Have Nore Than

2 Ohms Contact Resistance

As

Per the Attached Instructions,

October 25,

1991

Unit 3

CH Work Order 499141,

Troubleshoot/Rework/Replace

Components

to

Correct the Cause'of-Repeated

Alarms- on Window-6A05A, June. 1,

1991

Unit 3

CH Work Order 476460,

Troubleshoot/Rework/Replace

Components

to

Correct the

Cause for the Alarm Being Locked In, April 30,

1991

Unit 3

CH Work Order 524653,

Troubleshoot,

Rework and/or Replace

Components

to Correct the

Cause for PSL-231 Bringing in Continuous

Alarms

When Process

Pressure

Is Above Setpoint,

November

13,

1991

Unit 3

CH Work Order 569640, Install Thermal Barriers

Between Switches

and Their Hounting Surface

IAM the Resolution of EER 92-FM-007,

Harch

14,

1993

Unit 3

CM Work Order 602683,

Troubleshoot,

Rework and/or Replace

Components

to Restore

FWN-PSL-231 to Proper Operation,

June

28,

1993

Unit 3

CH Work Order 545873, Backfill the Listed C-Train

SG System

Transmitters

IAW the Following Instructions,

November

16, '1992

Unit 3

CH Work Order 541283,

Troubleshoot

and Rework/Replace

components,

As Per Attachments/Engineering

Direction,

To Obtain Data

and Resolve the

Low Steam

Gen Pressure

Setpoint

Problem.

See 50.59 Review,

February

27,

1992

~

Unit 3

CH Work Order 601077,

Troubleshoot

and Rework/Replace

Components,

As Per Attachments,

To Correct Problem Causing Setpoint

For

PPS

Channel

'C'arameter

12 (Lo SG ¹2 Press)

to drift, March 18,

1993

~

Unit 3

CM Work Order 550907,

In Conjunction with 36ST-9SB04 Install

a

Recorder,

As Per Engineering Instructions,

To Record Contact Traces to

Determine If Test Methodology

Can

Cause

Inconsistent

Data,

Hay 20,

1993

4.2

Mechanic l Survei lance

and

PH Testin

~

43ST-3SP02,

Essential

Spray

Pond

Pump Operability 4.0.5,

Revision

3

~

73ST-EXI101, Section

XI Valve Stroke Timing & Position Indication

Verification in Modes

1 through 4,

Steam Generator

No.

1 Containment

Isolation Valves, Revision

3

~

73ST-EXI102, Section

XI Valve Stroke Timing & Position Indication

Verification in Nodes

1 through 4,

Steam Generator

No.

2 Containment

Isolation Valves, Revision

5

~

73ST-3XI05, Section

XI Valve Stroke Timing & Position Indication

Verification - Mode

1 through

4 AF and

CT, Revision

0

~

74ST-SQI6,

RU-145 and

RU-146 Quarterly Functional

Test Procedure,

Revision

3

4.3

Electrical Surveillance

and

PM Testin

41AO-'IZZ22, Loss of Shutdown. Cooling, Revision

7

73ST-3DG01,

Class

1E Diesel

Generator

and Integrated

Safeguards

Surveillance

Test

Train A, Revision

5

70GT-OZZ01, Electrical Circuit Test,

Revision 02.00

32HT-9ZZ24, Maintenance of Low Voltage Circuit Breakers

Type K-600S and

K-BOOS, Revision

2

Unit

1

ST Procedures

32ST-92203

and 32ST-92209

4 '

Instrumentation

and Controls Surveillance

and

PH Testin

Condition Report/Disposition

Request

1-4-0158

(Reference:

Missing Damper

Linkage, Unit

1 Work Orders

00644312

and 00644311),

May 10,

1994

Unit

1 Work Order 00627316,

PM (PM) Work Description: Calibrate Pressure

Loop per Attachments,

April 27,

1994

42ST-2ZZ22,

Remote

Shutdown Instrumentation

Channel

Checks 4.3.3.5.a,

Unit 2 Work Order 00655895, April 29,

1994

36ST-95813,

Supplementary

Protection

System Functional Test, Unit 2 Work Order 00654810, April 29,

1994

36ST-9SB04,

Plant Protection

System Functional Test,

Reactor Protection

System/Engineered

Safety Features

Actuation System Logic, Unit 2 Work Order 00654824, April 26,

1994

74ST-9S(27,

Radiation Monitoring Calibration Test for RU-144; Unit

1

Mork Orders

65335

and 573889, Unit 2 Mork Order 621457,

and Unit 3 Work Order 580088

36ST-9S(IO,

RU-143/RU-144 Calibration Test; Unit 2 Mork Orders

494916

and 530923,

Unit 3 Mork Order 494916

36ST-9Sgll,

RU-145/RU-146 Calibration Test; Unit

1 Work Order 559853,

Unit 2 Work Orders

527476

and 603168,

and Unit 3 Mork Order 524728

, 74ST-9S(29,

Radiation Monitoring Calibration Test for RU-146; Unit

1

Work Order 639147

and Unit 3 Work Order 613501

Surveillance

Test Procedure

74ST-9S(28,

Radiation Monitoring Calibration

Test for RU-145; Unit

1 Work Order 639119,

Unit 2 Mork Orders

603167

and

603167,

and Unit 3 Mork Order 613483

PH Work Orders

635477 (Unit 1),

607457 (Unit 2),

and 641390 (Unit 3),

Calibrate Radiation Monitor RU-141,

Condenser

Vacuum Pump/Gland

Seal

Exhaust Monitor, per Attachments

36ST-9SB41,

PPS Transmitter

Response

Time Test Inside Containment,

Revision 04.00, July 2,

1993

36ST-9SB46,

ESF Matrix Relays to Initiation Relays

Response

Time Test,

Revision 6,

November 2,

1993

36ST-95844,

RPS Matrix Relays to Reactor Trip Response

Time Test,

Revision 6, April 21,

1994

36ST-9SB42,

Plant Protection

System Bistable

and Bistable Relay Response

Time Test,

Revision 4,

December

27,

1993

l

i

i

f

I

14FT-9FP31,

Appendix

R and Former Technical Specification Fire

Damper'urveillance;

Unit

1 Work Order 605690

and Unit 2 Work Order 411795

Unit 2

PH Work Order 646592, Calibrate Radiation Monitor Per

Attachments,

March 7,

1994

(N-16 Monitors)

Unit 3

PM Work Order 644385, Calibrate Radiation Monitor Per

Attachments,

January

4,

1994

(N-16 Monitors)

74ST-9Sg26,

Radiation Monitoring Calibration Test for RU-143; Unit

1

Work Orders

653353

and 654783,

Unit 2 Work Order 603957,

Unit 3 Work Order 580074

~

36ST-6SB21,

PPS Input Loop Calibration for Parameter

6,

Lo Pzr Press;

Unit

1 Work Orders

517901

and 591448, Unit 2 Work Orders

520024

and

572988,

and Unit 3 Work Orders

563405

and

607049

5.3

Inservice Testin

41ST-lEC02,

Essential

Chilled Water

Pump Operability 4.0.5,

Revision

4

42ST-2AF02, Auxiliary Feedwater

Pump AFA-P01 Operability Test 4.7. 1.2.a

and c, Revision

9

42ST-2CH06,

Charging

Pumps Operability Test 4. 1.2.4

and 4. 1.2.3,

Revision

5

42ST-2SI03,

Containment

Spray

Pump Operability Test - 4.6.2. l.b,

Revision

4

42ST-2SI15,

Section

XI CS

Pump Test - 4.0.5,

Revision

1

43ST-3SI03,

Containment

Spray

Pump Operability Test - 4.6.2. I.b,

Revision

4

43ST-3SI15,

Section

XI CS

Pump Test - 4.0.5,

Revision

1

73PR-3XIOl,

PVNGS

ASNE Section

XI Pump

and Valve Inservice Testing

Program,

Unit 3, Revision 00.07

73ST-2XI10, Section

XI Valve Operability - Node

1 thru

4 CT, SI,

and

HP

B Train, Revision

3

73ST-3XI01, Section

XI Valve Stroke Timing & Position Indication Verifi-

cation - Mode

1 thru 4,

SG No.

1 Containment Isolation Valves,

Revision

3

73ST-3XI10, Section

XI Valve Operability - Node

1 through

4 CT, SI,

and

HP

B Train, Revision

4

6.2

Predictive Maintenance Testin

~

32MT-9ZZ66, Vibration Monitoring, Revision

3

~

73AC-OAP01, Lubrication Program,

Revision

2

~

73DP-9ZZ04,

Lubricant Evaluation for Continued Duty, Revision

1

~

73TI-9XI01, Vibration Data Collection for Surveillance,

Revision 00.01

~

73TI-9ZZ74, Infrared Thermography

Inspection of Plant

Components,

Revision

0

0

7.3

Desi

n Basis Verification in Testin

43ST-3EW02,

Essential

Cooling Water

Pump Operability 4.0.5,

Revision

2

43ST-3AF01, Auxiliary Feedwater

Pump AFN-POl Operability 4.7. 1.2.a,

Revision

4

43ST-3AF02, Auxiliary Feedwater

Pump AFA-P01 Operability Test

4.7. 1.2.a&c, Revision

6

43ST-3AF03, Auxiliary Feedwater

Pump AFB-POl Operability Test

4.7. 1.2.abc,

Revision

6

43ST-3SG05,

atmospheric

dump valve Nitrogen Accumulator Drop Test,

Revision

5

43ST-3SP02,

Essential

Spray

Pond

Pump Operability 4.0.5,

Revision

3

Calculation

13-MC-AF-302, Auxiliary Feedwater

Pump Discharge

Pressure

Requirement,

Revision

1,

December

30,

1992

Calculation

13-MC-SP-306,

MINET Hydraulic Analysis of the

SP System,

Revision

1, March 8,

1994

Calculation

13-MC-SG-314, Nitrogen Tank Pressure

Requirements,

Revision 2, July 23,

1992

Calculation 13-MC-IA-301, Instrument Air to Atmospheric

Dump Valves

Pressure

Drop at Normal

and Transient

Flows, Revision 2, October 26,

1993

Calculation

13-MC-SP-307,

SP/EW System Thermal

Performance

Design Basis

Analysis, Revision 0,

November 3,

1993

LDCP l(2,3)LM-AF-096, Auxiliary Feedwater

Flow Orifice Replacement,

July

19,

1992

i

Si

Site Modification 1-SM-EW-001,

Change

EW Pumps

from Packing to

Mechanical

Seals,

October 9,

1987

~

LDCP 1{2,3)LJ-SP-061,

ECWS Heat Exchanger

Thermal Relief Valve Change,

Revision 0,

December

31,

1991

~

EER 889-SP-032,

Change

Stem Material Thermal Relief Valves

on Spray

Pond

System Side of Diesel

Generator

Heat Exchangers,

June

28,

1989

~

LDCP 2LM-EW-036, Sleeving of Unit 2 Trains

A 5

B Essential

Cooling Water

Heat Exchangers,

Revision 0, October 29,

1993

~

SPCR SXX-CT-001,

Change

CST Empty Alarm Setpoint,

January

24,

1993

~

DCP 85-13-ZA-021,

Redesign Auxiliary Building HVAC to Achieve Acceptable

Airflow Direction from Areas of Low Contamination to High Contamination,

Revision 0, August 18,

1989

8. 1

icensee

Se f- ssessment

~

Self-Assessment

Report 431-00003-RBP/EAS,

"Retest"

I