NUREG/CR-5693

BNL-NUREG-52283

Aging Assessment of Component

iCooling Water Systems in

'Pressurized Water Reactors

~Prepared b

R. Lofaro, W. Gunther, M. Subudhi B. Lee 1~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~

lrohae NainlLbrt:

iPrepared for

U.S. Nuclear Regulatory Commission
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NUREG/CR-5693

BNL-NUREG-52283

RV

Aging Assessment of Con

Cooling Water Systems in

Pressurized Water Reacto

tponent

rs

Manuscript Completed: March 1991

Date Published: June 1992

Prepared by

R. Lofaro, W. Gunther, M. Subudhi B. Lee

S. K. Aggarwal, NRC Program Manager

Brookhaven National Laboratory

Upton, NY 11973

Prepared for

Division of Engineering

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission

Washington, DC 20555

NRC FIN A3270

0
Previous Related Work:

NUREG/CR-5052, "Operating Experience and Aging Assessment of

Component Cooling Water Systems in Pressurized Water Reactors,"

July 1988.

ii
ABSTRACT

A two-phase aging analysis of component cooling water (CCW) systems in

pressurized water reactors (PWRs) was performed. In phase I, which was published

separately as NUREG/CR-5052, the effects of aging on the CCW system were

characterized, and the predominant failure modes, aging mechanisms, and

components susceptible to aging degradation were identified. Failure rate trends

were examined, and their effect on time-dependent system unavailability was

investigated.

In phase II, which is the subject of this report, the methods used to

manage aging degradation in the CCW system were studied. Information was

collected and analyzed on inspection, surveillance, monitoring, and maintenance

techniques from a survey of operating MsR. The results are presented herein.

Advanced techniques that may help detect and mitigate aging degradation also are

included. A detailed examination of the materials of construction and their

relationship to various aging mechanisms is discussed.

In addition, the various industry standards, codes, and regulatory

requirements that govern the design, construction, and operation of the CCW

system were investigated. Recommendations to better manage aging degradation in

component cooling water system are discussed.

iff
CONTENTS

Page

ABSTRACT . . . . . . . . . . . . . . . . . .iii

LIST OF FIGURES . . . . . . . . viii

LIST OF TABLES ................. ...... ix

EXECUTIVE SUMMARY ..................... .. xi

ACKNOWLEDGEMENTS . . . . . . . . . . . . . . .-. . . . . . . . xvi

1. INTRODUCTION . ... . . . . . . . . . . . . . . . . . . . . . . . 1-1

1.1 Background . . . . . . . . ... . .. .. . . . . . . . . . 1-1

1.2 Summary of Phase I CCW Study . . . . ... . . ... . . . . 1-1

1.3 Update of Phase I Data Analysis. . .. . . 1-4

1.3.1 Analysis of heat exchanger data.. . . . 1-5

1.3.2 Analysis of pump data . . . . . , . . . . . . . . . . 1-6

1.3.3 Analysis of valve data .. .. . . . . . . 1-7

1.4 Objectives and Approach of Phase II Study . . .1-11

2. EVALUATION OF PLANT SPECIFIC DATA . . . . . . . . . . . . . . . . 2-1

2.1 Survey of PWRs . . . . . .-. . . . . . . . . . .-. ... . . 2-1

2.1.1 CCW testing practices . . . . . . . . . . ... . . . . 2-1

2.1.2 CCW inspection and monitoring practices . ... . . . . 2-3

2.1.3 CCW preventive maintenance practices . ... . . . . . 2-7

2.1.4 Summary -of findings . . . .-. . . . . . . ... . . . 2-9

2.2 Plant A Data Evaluation . .. . . . . . . . . . 2-11

2.2.1 Plant A CCW system design . . . . . . . . . . ... . 2-11

2.2.2 Plant A inspection, surveillance and

monitoring practices . .-. . . . . . . . . . . . . 2-12

2.2.3 Plant A preventive maintenance practices . . . . . . 2-15

2.2.4 Plant A corrective maintenance events . . . . . . . . 2-17

2.2.5 Summary of plant A findings .... . . . . . . . ... . 2-25

2.3 Plant B Data Evaluation . . . . . . . . . . . . . ... . . . 2-27

2.3.1 Plant B CCW system design . . .. . . . . . .... . . .2-28

2.3.2 Plant B inspection, surveillance and

monitoring practices. . ... . . . . . . . . . . 2-28

2.3.3 Plant B preventive maintenance practices . . . 2-30

2.3.4 Plant B corrective maintenance events . . . ... . . . 2-33

2.3.5 Summary of plant B findings . . . . . . . . . . . . 2-36

3. EVALUATION OF COMPONENT MATERIALS . . . . . . 3-1

3.1 Heat Exchangers . . . . . . . . . . . . . . . . . . . . . . 3-1

3.1.1 Description . .. . . . . . . . . . . . . . . . . . . . 3-1

3.1.2 Heat exchanger materials . . . . . . . ... . . . . . 3-1

3.1.3 Heat exchanger aging mechanisms . . . . . . . . . . . 3-5

3.1.4 Failure prevention and mitigation . . . . . . . . . . 3-7

3.1.5 Findings for heat exchangers . . . . . . . . . . . . 3-9

3.2 Valves. .. . . . . . . . . . . . . . . . 3-9

3.2.1 Description of valves .3-10

3.2.2 Valve materials and aging susceptibility . . . . . . 3-10

3.2.3 Findings for valves .3-14

v
Page

3.3 Valve Operator . . . . . . . . . . . . . . . . . . . . . . 3-15

3.3.1 Description of valve operators ... . . . . . . . . . 3-15

3.3.2 Valve operator materials . . . . . . . . . . . . . . 3-15

3.3.3 Valve operator aging mechanisms . . . . . . . . . . . 3-17

3.3.4 Finding for Valve Operators . . . . . . . . . . . . . 3-19

3.4 Pumps . . . . . . . . . . . . . . . . . . . . . . . . . . 3-19

3.4.1 Description of pumps .. 3-20

3.4.2 Pump construction materials . . . . . . . . . . . . . 3-22

3.4.3 Findings for pumps . . . . . . . . . . . . . . . . . 3-27

4. SAFETY SYSTEM FUNCTIONAL INSPECTIONS OF CCW . . . . . . . . . . . 4-1

4.1 SSFI Structure and Methodology . . . . . . . . . . . . . . 4-1

4.2 CCW SSFI Findings Related to Aging . . . . . . . . . . . . 4-3

4.2.1 Increasing system leakage leads to potential

inoperability . . . . . . . . . . . . . . . . . . . . 4-4

4.2.2 Design change potentially increases component

aging rate .4-4

4.2.3 Potential for stress corrosion cracking identified 4-5

4.2.4 Causes for calibration discrepancies not determined 4-5

4.2.5 Untested check valves added to design . . . . . . . . 4-5

4.2.6 Incomplete procedure for motor operation . . . . . . 4-6

4.2.7 Throttling of valves causes accelerated aging of

seats . . . . . . . . . . . . . . . . . . . . . . . . 4-6

4.2.8 Insights from a utility self-assessment SSFI . . . . 4-6

4.2.9 Summary of SSFI findings . . . . . . . ... . . . . . 4-7

4.3 Recommended Additions to the SSFI Methodology . . . . . . . 4-8

5. ASSESSMENT OF REGULATORY AND INDUSTRY REQUIREMENTS . . . . . . . 5-1

5.1 CCW System Design Requirements . . . . . . . . . . . . . . 5-1

5.1.1 General design criteria . . . . . . . . . . . . . . . 5-1

5.1.2 Generic and unresolved safety issues on RCP seal

cooling . . . . . . . . . . . . . ... . . . . . . . . 5-3

5.1.3 IN 89-54: Potential Over Pressurization of CCW

system .... ' ..... 5-4

5.2 System Inservice Inspection and Testing Requirements . . . 5-5

5.2.1 Preoperational test requirements . . . . . . . . . . 5-5

5.2.2 Inservice inspection requirements . . . . . . . . . . 5-6

5.2.3 Inservice testing requirements . . . . . . . . . . . 5-6

5.2.4 Generic Leter 89-13 on Service

Water System Problems .5-7

5.3 System Maintenance Requirements . . . . . . . . . . . . . . 5-8

5.3.1 Industry maintenance standards . . . . . . . . . . . 5-8

5.3.2 Generic letter 89-13 on service water system

problems . . . . . . . . . . . . . . . . . . . . . . 5-8

5.4 Summary of Findings . . . . . . . . . . . . . . . . . . . . 5-9

vi
Pare

6. ADVANCED ISK&H PRACTICES . . . . . . . . . . . . . . . .

6.1 Ultrasonic Testing . . . . . . . . . . . . . . . .

6.1.1 Detecting heat exchanger tube leaks . .

6.1.2 Detecting valve internal leaks .. . . . . .

6.1.3 Detecting bearing degradation . . . . . . . .

6.1.4 Detecting pump degradation . . . . . . . . .

6.2 Eddy Current Testing . . . ... . . . . . . . . . .

6.3 Remote Field Technique . . . . . . . . . . . . . .

6.4 Vibration Monitoring . ... . . . . . . . . . .

6.5 Tracer Technology . . . . . . ... . . . . . . . . .

. . . 6-1

. . . 6-1

. . . 6-2

. . . 6-2

. . . 6-2 . . . 6-3

. . . -6-3

. . . 6-4

. . . 6-5

. . . 6-8

. . . 7-1

. . . 7-1

* . . 7-2

7. UTILIZATION OF RESEARCH RESULTS . . . . . . . ... . . .

7.1 CCW System Performance Assessment . . . . . . . . .

7.2 Evaluation of ISM&K Practices . . . . . . . . . . .

8. RESULTS AND CONCLUSIONS . . ... .

8.1 Conclusions from the Review of ISM&M Practices

8.2 Conclusions from the Review of Component Materials

8.3 Conclusions from the Review of SSFIs . . . . . . .

8.4 Conclusions from the Review of SSFIs

8.5 Recommendations . . . . . . . . . . . . . . . . ...

.

.

8-1

8-1

8-1

8-2

8-3

8-4

9. REFERENCES . . . . . . . , . . . . .- . . .

APPENDIX A: SURVEY OF PWRs . . . . . . . . . .... . ... . . . . . . .

9-1

A-1

vii
LIST OF FIGURES

No. Title

1.1 Phase II research approach . . . . . . . . . . .

1.2 CCW failure causes versus system age . . . . . .

1.3 CCW component failures and aging fraction . . . .

1.4 CCW pump failure rate versus age . . . . . . . .

1.5 CCW system unavailability versus time . . . . . .

1.6 CCW component importance versus time . . . . . .

1.7 Heat exchanger failures (NPRDS 1/99 to 6/90) . .

1.8 CCW pump failures (NPRDS 1/88 to 6/90) . . . . .

1.9 Valve failure mechanisms (NPRDS 1/88 to 6/90) . .

1.10 Valve subcomponent failures (NPRDS 1/88 to 6/90)

Page

. 1-2

. 1-3

. 1-4

. 1-5

. 1-6

. 1-7

. 1-8

. 1-9

. 1-9

1-10

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

2.10

2.11

2.12

2.13

2.14

2.15

2.16

2.17

2.18

2.19

2.20

Routine CCW parameters monitored . . .

Plant A CCW system design . . . . . . .

Plant A corrective maintenance events

Plant A valve types requiring CM

Plant A manual valve failure modes

Plant A AOV and MOV failure modes

Plant A I&C components requiring CH

Plant A I&C component failure modes

Plant A pump failure modes . . . . . .

Plant A manual valve time-line history

Plant A MOV time-line history . . . . .

Plant A CCW pump time-line history . .

Plant B CCW system design . . . . . . .

Plant B corrective maintenance events

Plant B valve types requiring CM . . .

Plant B manual valve failure modes . .

Plant B AOV and MOV failure modes . . .

Plant B I&C components requiring CH

Plant B I&C component failure modes

Plant B pump failure modes . . . . . .

. . . . . . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. . . .

. 2-6

2-11

2-18

2-19

2-20

2-21

2-22

2-23

2-24

2-25

2-26

2-27

2-28

2-34

2-35

2-36

2-37

2-38

2-38

2-39

3.1 Typical shell and tube heat exchanger . . . . . . .

3.2 Heat exchanger tube and tubesheet materials

(NPRDS 1974 to 1987) . . . . . . . . . . . . .

3.3 Typical valve subcomponents . . . . . . . . . . . .

3.4 Typical valve packing requirements . . . . . . . .

3.5 Life expectancy of packing materials . . . . . . .

3.6 Temperature range of elastomer materials . . . . .

3.7 Typical horizontal single-stage double suction pump

3.8 Subcomponents of a mechanical seal . . . . . . . .

. . . . . . . 3-2

. . . . . . . 3-2

. . . . . . 3-10

. . . . . . 3-13

. . . . . . 3-14

. . . . . . 3-16

. . . . . . 3-21

. . . . . . 3-22

6.1 Remote field technique concept . . . . . . . . . .

6.2 Sample calibration standard used for RFT . . . . .

6.3 Sample vibration patterns . . . . . . . . . . . . .

. 6-5

. 6-6

. 6-7

viii
HNo..

1.1

2.1

2.2

2.3

2.4

2.5

2.6

2.7

2.8

2.9

2.10

2.11

2.12

2.13

2.14

2.15

2.16

2.17

2.18

2.19

2.20

2.21

2.22

2.23

2.24

2.25

LIST OF TABLES

Title

*Valve subcomponent failure modes . . . . . . . . . . . . .

Pump tests performed on CCW pumps . . .. . .. . .

Valve tests performed on CCW valves . . ... . . . .

Miscellaneous CCW system tests . . . . . . . . . . . . .

CCW pump inspection/monitoring practices . . . . . . .

CCW valve inspection/monitoring practices . . . . . . ... .

CCW heat exchanger inspection/monitoring practices -.

CCW electrical component inspection/monitoring practices.

CCW pump preventive maintenance practices . . . . . . . . .

CCW valve preventive maintenance practices . . . . . . . .

CCW electrical component preventive maintenance actions . .

CCW instrumentation/control preventive maintenance actions

CCW operational activities to mitigate degradation . . . .

CCW parameters monitored daily for plant A . . . . . . . .

Plant A CCW pump ISM practices . . . . . . . . . . . . . .

Plant A CCW valve ISM&M practice . . . . . . . . . . . . .

Plant A CCW heat exchanger ISM practices . . . . . . . . .

Plant A CCW pump preventive maintenance practices . . . . .

Plant A CCW heat exchanger preventive maintenance practices

CCW parameters monitored daily for plant B . . . . . . . .

Plant B COW pump ISM practices . . . . . . . . . . . . . .

Plant B CCW valve ISM&O practices . . . . . . . . . . . . .

Plant.B CCW heat exchanger ISM practices . . . . . . . . .

Plant B CCW pump PM activities . . . . . . . . . ... . . .

Plant B CCW valve PM actions . . . . . . . . . . . . . . .

Plant B CCW heat exchanger PM activities . . . . . . . . .

Page

1-10

. 2-2

. 2-3

.2-4

. 2-4

. 2-5

. 2-5

. 2-5

.2-7

.2-8

. 2-8

2-10

2-10

2-12

2-13

2-14

2-15

2-15

2-17

2-29

2-30

2-31

2-32

2-32

2-33

2-33

3.1 Typical CCW heat exchanger design conditions . . . .

3.2 Performance ratings of heat exchanger materials . . .

3.3 Prevention/mitigation measures for heat exchanger

aging mechanisms . . . . . . . . . . . . . .

3.4 Valve trim materials . . . . . . . . . . . . . .

3.5 Characteristics of elastomer liners . . . . . . . . .

3.6 Relative performance of common elastomers . . . . . .

3.7 Life expectancy during storage of various elastomers

3.8 Typical pump construction materials . . . . . . . . .

3.9 Materials used in mechanical primary seals . . . . .

3.10 Materials used in mechanical secondary seals . . . .

3.11 Pump seal aging mechanisms and causes.

3.12 Pump bearing aging mechanisms and causes . . . . . .

.. . . . . 3-3

.. . . . . 3-5

. 3-9

3-11

3-12

3-18

3-19

3-24

3-25

3-25

3-26

3-27

4.1

4.2

4.3

4.4

SSFI inspection areas and subtasks related to aging .

Sections of NRC SSFI manual related to aging . . . .

Areas where SSFIs provide useful aging information

Recommended additions to SSFIs . . . . . . . . . . .

. 4-2

. 4-3

. 4-8

4-10

ix
LIST OF TABLES

No. Title

5.1

7.1

7.2

7.3

7.4

7.5

7.6

7.7

Regulatory and industry documents related to the CCW system . . . 5-2

Reference of component material information . . . . . . . . . . . 7-1

Reference of ISH&MI information .... . . .. . . . .. . . . . 7-2

Recommended basic ISM&M practices for the CCW system . . . . . . 7-4

Pump ISM&M practices versus aging mechanisms . . . . . . . . . . 7-5

Valve ISMhM practices versus aging mechanisms . . . . . . . . . . 7-6

Heat exchanger ISHM& practices versus aging mechanisms . . . . . 7-7

Advanced monitoring practices .... .. . .. . . .. . .. . . 7-8

K
-EXECUTIVE SUMMARY

''In thi "phase I aging analysis of component cooling water (COW) systems,

failure data from the nuclear plant reliability data system (NPRDS), licensee

event reports (LERs), and actual plant data from an operating pressurized water

reactor (PWR) were analyzed to characterize the effects of aging.' The results

showed that the CCV system' is vulnerable to aging de'radatLon. The majority iof

failures in'the 'CWC, system are related to aging,' and the number of aging related

failures increases with time. 'If this trend continues, component failure rates

are likely to increase with time, and the availability of the system will

decrease. The CCV system-provides cooling water to several important loads

throughout the plant under all plant operating conditions. Consequently, a

decrease in CCW system availability could lead to increased plant risk. The

phase I study provided an understanding of the effects of aging in the COW

system, and showed that these effects must be mitigated to ensure reliable system

operation.

The goal of the phase II CCW aging analysis is to'study methods that can

be employed to better manage the effects of aging. These methods include ways

to detect incipient aging degradation, before failures occur, as well as

maintenance practices to mitigate the effects of aging. To achieve this goal,

the research strategy for this study' followed four separate paths; 1) an

examination of current inspection, surveillance, monitoring, and maintenance

(ISK&H) practices, 2) an investigation of the materials used in the construction

of components, 3) a review of industry standards and codes reLated to inspection,

testing, and maintenance requirements, and 4) a review of regulatory practices

and how they can be used to evaluate the effectiveness of ISM&M programs for

managing aging.

To review current ISH&M practices, a survey of operating PWRs and two site

visits to operating PWRs were made to obtain information on the types of

practices used, along with their frequency. The results showed that there are

two categories of practices performed on a routine basis; basic practices that

all plants perform, and supplemental practices that vary from plant to plant,

depending on various factors. The basic practices are typically required by

plant technical specifications or codes, and include such items as measuring pump

head and vibration, or stroking motor operated valves. Additional discussion on

these activities is presented in Section 2, and research results are summarized

in Section 7.

The supplemental activities are selected by the plant based on

manufacturers' recommendations or past plant experience, and typically are used

to address specific plant operating conditions or past problems. These

supplemental activities include such items as thermography examination of pumps

to detect hot spots, and eddy current testing of heat exchanger tubes to detect

cracks or flaws. While most plants may use these techniques when a problem is

suspected, the survey shows that some plants use them regularly as part of their

routine maintenance and monitoring program.

id
r

To aid in the evaluation of current ISM&M programs for managing aging, each

of the basic and supplemental practices was correlated with the aging mechanisms

they can detect or mitigate. The resulting charts, presented as Figures 7.1,

7.2, and 7.3, can be used by utilities to review their ISM&M practices. Current

ISM6N programs are discussed in detail in Section 2.

In addition to the routine practices used in plants, several advanced

practices were investigated, including ultrasonic testing, eddy current testing,

remote field technique, internal rotary inspection system, vibration monitoring,

and tracer technology. Each of these techniques can detect some form of aging

degradation, including internal component leakage, material flaws, and wall loss.

Section 6 gives a detailed discussion of these practices, and a summary is

presented in Table 7.2.

The following findings were also obtained from the ISM&M review:

- In general, no specific actions are taken to address long term aging

of the CCW components. For example, no routine measures are in

place to monitor wall loss of heat exchanger shells, piping, pump

casings, or valve bodies. Although the data do not indicate any

failures related to wall loss in the CCW system, this is a potential

concern for extended life operation. Over many years of operation,

wall thinning may occur which could weaken these components.

- A standardized maintenance or monitoring program which requires all

plants to perform the same actions would not be practical because of

differences in plant designs, operating conditions, and environment.

An optimum program should include the basic practices now performed

by most plants, along with supplemental and advanced practices

specifically chosen to address particular problems or weaknesses in

the plant's ISM&M program. A discussion of recommended basic and

supplemental practices is presented in Section 7.

In addition to ISM&H practices, the materials of construction were

investigated. The results indicate that several different materials are used in

the construction of various components, each of which is susceptible to certain

types of aging degradation. In most cases, knowledge of the material used will

help to identify the aging mechanisms that should be monitored for and protected

against. Therefore, a maintenance and monitoring program should include the

identification of materials used. Other findings from the review of component

materials include the following:

- The majority of heat exchanger failures are caused by corrosion and

wear of the tubes, which is directly related to the materials used

and the operating environment. Because all tubes in the tube bundle

typically are made of the same material and are exposed to the same

environment, once tube failure begins, the number of failures can

increase dramatically in a short time.

- There are several methods to extend the life of heat exchangers,

including the use of cathodic protection, and protective coatings or

xii
liners. If the material selected for construction is incompatible

with the operating conditions or environment, aging degradation will

proceed rapidly. In these cases, the material should be replaced

with one more suitable for the service conditions.

A valve subcomponent that is extremely susceptible to aging is the

packing. Several different materials are available for packing,

however, installation can also be important. Using combinations of

different materials can increase the life expectancy of the packing.

Two other valve subcomponents that are susceptible to aging are the

diaphragm and O-rings used in pneumatic valve operators. The

materials most commonly used are neoprene and buna-N. These

components should be inspected regularly and replaced periodically

to prevent failures during operation. These materials degrade even

while in storage, therefore, proper storage conditions should be

maintained and shelf life tracked.

An additional area that can contribute to the proper management of aging

involves the various industry codes, standards, and regulations that govern the

design, inspection, testing, and maintenance of the CCW system. A review of

these items resulted in the following findings:

The design of the CCW system is governed by the General Design

Criteria in the Code of Federal Regulations. Although the criteria

address safe operation of the systems, there are no specific

requirements addressing the issue of aging.

Inservice inspection requirements for the CCW system are governed by

ASHE Section XI, and are included in the' plant's technical

specifications. The inspection requirements of Section XI are to

pressure test the system and inspect for leakage periodically, and

to visually inspect any snubbers in the system. Inspections to

specifically address aging degradation are not required.

Inservice testing requirements of -the CCW system are governed by

ASME Section XI, which references ASME Operation and Maintenance

(O&M) standards. The testing requirements address pumps (ASME OM6), valves (ASME OM-10) and snubbers (ASHE O-4). ASME standard OM2 addresses performance testing of the CCW system as a whole,

however, this standard is not a mandatory requirement. The 0M-2

standard includes guidance on evaluating aging degradation which can

be useful for evaluating the long-term effects of aging on system

performance. It is recommended that this information be trended and

used as an aging indicator.

Additional testing requirements have been imposed by generic letters

issued by the NRC in response to various problems detected during

operation. Generic letter 89-10 requires licensees to implement a

program for testing, inspecting and maintaining motor-operated

valves (MOVs) in safety-related systems. Generic letter 89-13

xii
requires licensees to establish a test program to verify the heat

transfer capability of all safety-related heat exchangers cooled by

service water.

- The General Design Criteria require that the CCW system be

maintained throughout the life of the plant; however, there is no

specific guidance on how to accomplish this. Codes or standards on

system maintenance do not exist, although standards on good

maintenance practices for various components are available.

Based on the findings of the phase 1 CCW system study, it was observed that

the various codes and standards provide a means of detecting degradation caused

by many aging mechanisms. However, they are not comprehensive enough to

completely control all aging degradation. In order to effectively control aging,

ISM&H programs should include a combination of basic practices, as required by

codes and standards, along with supplemental practices chosen specifically to

address any unique plant operating conditions or past problems.

Another important method of managing the effects of aging is to evaluate

how effective a plant's practices are at detecting and mitigating aging

degradation. To identify ways of doing this, current regulatory practices were

reviewed. One practice was found to have the elements necessary for effectively

assessing plant practices, namely the Safety System Functional Inspection (SSFI).

These inspections are currently performed by the NRC to determine if safety

systems can perform their design functions, if called upon. However, the

structure of the SSFI also lends itself to obtaining information relevant in

assessing aging management. This could be a useful tool for the NRC to use for

evaluating how effectively a plant is managing aging degradation. Table 4.4

gives several additions to the SSFI format which would make it more suitable for

this purpose. The types of information which can be obtained from an SSFI and

used for aging management are demonstrated in the following examples, which were

obtained from a review of previously performed SSFIs.

- One SSFI determined that CCW system design leakage may be

underestimated in several plant designs. For instance, one plant

did not design the makeup portion of the system as safety-related

because zero leakage was expected. However, experience has shown

that as valves, pumps, and heat exchangers age, leakage will

increase. This aging process should have been considered in the

system design.

- One SSFI determined that the expected ambient temperature in the CCW

pump area during an accident was not accurately represented. A

review indicated that the ventilation system would not be operable

in a postulated accident, which would expose the CCW pump motors to

higher temperatures than they had been designed and tested for. The

long-term performance of CCW at this plant was essential for

removing decay heat. The SSFI report indicated that the operating

stresses which could affect operation of the CCW system had not been

addressed adequately. The high temperature could impose aging

mechanisms on the equipment, resulting in premature wear and

Av
failure. The equipment should have been designed and tested to

operate under these conditions.

The results of the phase I and phase II aging studies show that the

Component Cooling Water system is susceptible to aging degradation. As the

system ages, the likelihood of failures increases, which can adversely affect'the

reliability of the system. However, the results of this phase II study show that

there are measures that can be taken to monitor and mitigate the effects of

aging. The following recommendations will help ensure that plants have the most

effective maintenance and monitoring programs to manage aging of CCW systems.

- ' Personnel cognizant of the CCW system performance should understand

the characteristics of aging degradation 'presented in the phase I

study. 'This knowledge will provide them with insights into what

should be monitored, and'what aging mechanisms may be present in

their particular system.

Cognizant utility personnel should review past-operating experience

and failure data to determine if any aging trends are evident, such

as increasing failure rates. This will help to identify the extent

and magnitude of aging mechanisms present, along with any weaknesses

in their maintenance program.

Maintenance and monitoring programs should be reviewed in relation

to the aging mechanisms identified for a particular CCW system. The

review should ensure that effective techniques are in place to

detect and/or correct any aging conditions. The ISM&K information

presented in this phase II study can be used for this purpose.

Consideration should be given to incorporating techniques to detect

and monitor the effects of long-term aging, such as pipe wall

thinning, and degradation of pump or valve bodies. Such degradation

takes many years to manifest itself, and is a potential concern for

extended life operation.

xv
ACKNOW LED GEMENTS

The authors wish to thank the NRC Program Manager, Mr. Satish K. Aggarwal

for his technical direction on this work. We would also like to thank the

personnel at the various utilities supplying information for this study for their

assistance and cooperation, and Messrs. Gary Toman and Terry White of ERC

Environmental and Energy Services Company for their assistance in reviewing the

NRC Safety System Functional Inspection reports.

We are grateful to various members of the Engineering Technology Division

of Brookhaven National Laboratory, including Mr. Robert Hall, Dr. John Boccio,

Dr. Pranab Samanta, Dr. Ali Azarm, Mr. Jim Higgins, and Mr. John Taylor for their

technical assistance in the review of this report.

We also wish to thank Ms. Ann Fort and Mrs. Alice Costantini for their help

in preparing this manuscript.

xvi
1. INTRODUCTION

1.1 Background

The component cooling water (CCW) system is one of many systems that are

:vital for the safe operation of nuclear power plants. Many safety factors are

incorporated into its design to ensure the system will- perform its design

function when needed. However, as plants age, the effects of accumulated wear

and tear on the CCW components could degrade the safety factors, if the aging

effects are not properly detected and mitigated. As plants age it becomes

important to understand and control the effects of aging to maintain plant safety

at its original design level. To address this concern, the U.S. Nuclear

Regulatory Commission, Office of Nuclear Regulatory Research, Division of

Engineering instituted the Nuclear Plant Aging Research Program (NPAR).

Work under the NPAR program has included various aging studies at the

component, and system levell8. The studies are typically performed in two

phases. The effects of aging are characterized in phase I, while the methods of

detecting and mitigating aging effects are evaluated in phase II. The phase I

CCW study is completed, and the results, which are summarized in the following

section, are documented in Reference 9. The structure of the NPAR program is

discussed in more detail in Reference 10.

The goal of the phase II study is to identify methods of better managing

the effects of aging in CCW systems. To accomplish this goal, the approach taken

was to identify and research several different areaslrelated to aging detection

and/or mitigation. The resulting tasks performed include an evaluation of

current and advanced inspection, surveillance, monitoring and maintenance

techniques, an analysis of the materials used in constructing components, the

identification of existing regulatory practices that may be useful to assess a

plant's aging management program, and an evaluation of how well industry

standards address aging. 'This approach is-summarized-in Figure 1.l.

1.2 Summary of Phase I CCW Study

The goal of the Phase I CCW study was to identify and characterize the

effects of aging in'COW systems. To achieve this goal, operating e'perience'and

failure data from various national data bases were reviewed and analyzed. Actual

plant data also were obtained and analyzed to supplement and validate the database results. To make the study manageable, CCW systems in pressurized water

reactors (PWRs) were focussed on.

Evaluation of the data shows that approximately 721 of the failures in CCW'

systems are related to aging. As defined in Reference 10,' aging is the

cumulative degradation that occurs with the passage of time. Aging degradation

can be caused by material degradation mechanisms, such as erosion, corrosion, and

embrittlement; by stressors imposed due to improper storage, operating

environment, or external environment; by service wear; by excessive testing; or

by improper installation, application, or maintenance. The dominant cause of CCW

component failures is "normal service', while the major mechanism is "wear".

1-1
SPEIF PIC

DATA

ND~USTRY

SURVEY

Figure 1.1 Phase II research approach

Examination of failure causes indicates that failures due to normal service

increase with the system's age (Figure 1.2). Figure 1.2 also shows a decrease

with age in failures caused by human error and other causes, which include

failures of other components and/or systems, and failures for which the cause was

unknown. These findings show that aging degradation occurring in CCW systems

leads to failures, and that such failures increase with age.

The _CCW components that fail *most often are valves (including valve

operators), followed by pumps, instrumentation, and heat exchangers (Figure 1.3).

For all components, a large fraction of the failures are due to aging. Timedependent component failure rates calculated from the data indicate an increasing

trend with time; for example, in Figure 1.4 for CCW pumps. This increase is

attributed to the accumulation of aging effects. To ensure proper system

function and plant safety, these aging effects must be detected and mitigated in

an incipient stage before the component fails.

1-2
FAILURES

100%

60%

50%

40%

100% ~~~~~. W............ .......... ................g

20%

.0%

0 TO 5 6 TO 10 11. TO 15 16 TO 20

SYSTEM AGE CYEARS)

NORMAL SERVICE OTHER HUMAN ERROR

Figure 1.2 CCV failure causes versus system age

To investigate the effect of increasing failure rates on system

performance, & typical CCW system was modeled to perform probabilistic risk

assessment (PRA) calculations. Using time-dependent failure rates in the PRA

analysis, two significant findings were obtained; 1) CCW system unavailability

increases with time (Figure 1.5), and 2) the relative importance of the CCW

components changes with time (Figure 1.6). From these findings it is clear that

aging degradation must be controlled to maintain system unavailability at an

acceptable level. It should be noted that this simplified analysis does not

represent a quantitative evaluation of CCG system unavailability in general, and

is presented here only to show the potential effects of increasing component

failure rates.

Based on the phase I analysis, it is concluded that aging degradation in

CCW systems is a concern which must be addressed to ensure acceptable system

performance in later years. The effects of aging must be detected and mitigated

through effective inspection, surveillance, monitoring (ISM), and maintenance.

The identification of ISM and maintenance methods that are effective at detecting

and mitigating aging effects is the focus of the phase II study discussed in this

report.

1-3
FAILURES

50%

4%L.............. ...............

......... ..... . . . . . . . . . .. . . 40%

30%

20%

2C66 ffi ~~~~. ..... . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

10%6ti

0o%

VALVES PUMPS INSTRUMENTS KXs BREAKERS MOTORS SUPPORTS OTHER PIPES

= TOTAL FAILURES M AGING RELATED

Figure 1.3 CCV component failures and aging fraction

1.3 Update of Phase I Data Analysis

The phase I aging analysis examined data on operating experience and

failures from 1976 through 1987, and concluded that three of the main

contributors So CCW system failures are valves, pumps, and heat exchangers (HXs).

Since a significant period of time has elapsed since the phase I study was

completed, the data were updated. The purpose of this update is to verify that

the results of the previous work are still valid, and to determine if any new

insights can be obtained from the new data. Accordingly, NPRDS records on CCV

systems were obtained for January 1988 through May 1990. These data were

reviewed and an analysis similar to that used in the phase I study was performed.

As was found in the phase I study, pumps and valves are still among the

most frequent components to fail in the CCW system; consequently, they were

focused on more closely in this data analysis. In addition, heat exchangers have

a high potential for aging degradation in later years of operation, thus, they

were also given increased attention.

14
FA I LURE RATE ( E- 5)

25

I

15 _ .................................................. ........ ..... ....................................... |

10 20 .. . ..... \~

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19

PUMP AGE CYEARS)

Figure 1.4 CCV pump failure rate versus age

1.3.1 Analysis of Heat Exchanger Data

Over the two-and-a-half years subsequent to January 1988, 75 entries on CCW

heat exchangers were recorded in the NPRDS data-base. The problems addressed

were predominantly related to. tube leaks (561) and plugged tubes (31X). A

complete breakdown is'shown in Figure 1.7.-

. Of the 24 PWRs reporting, eight plants contributed 49 of the 75 entries,

with one plant accounting for 13 entries,' all of which were related to plugging

of the CCW heat exchangers. 'A relatively new plant'(on-lline in 1984) reported

eight leaks within 15 months.

The-data clearly indicate that tube leaks and plugging are fairly common

problems in the industry.. The safety significance of tube plugging is that if

it is excessive, the component cooling water-temperature will increase, which

could lead to overheating of the eafety-related eqvipment it -supplies, or

limiting the rate of decay heat removal. -Tube leaks in the CCW heat exchanger

increase the potential for releasing radiation to the environment through the

open-loop service water system.

1-5
UNAVAILABILITY CE-53

s0

40 _ .............................................. ...................................... ...... / ........... _

40

0 10 20 30 40

SYSTEM AGE CYEARS)

Figure 1.5 CCW system unavailability versus time

1.3.2 Analysis of Pump Data

The data reviewed for this update include 83 entries related to CCW pumps,

reported by 44 plants. The problems addressed were dominated by failures of the

mechanical seals (43%) and bearings (26%). The remaining failures were related

to packings, gaskets, and other internal components. Each of the categories

involving subcomponent wear is related to aging degradation. Figure 1.8 shows

the complete breakdown.

These results are consistent with the findings from the phase I study. The

need to detect pump degradation before a failure occurs is evident from the

impact of pump failure on risk. The high percentage of seal and bearing

failures, which can result in pump unavailability, show that maintenance and

monitoring practices should be reviewed in these two areas.

1-6
RELATIVE I MPORTANCE

o 10 20 30 40

SYSTEM AGE CYEARS)

- CCW VALVES | SW VALVES PLtJPS - HXs

Figure 1.6 CCW component importances versus- time

1.3.3 Analysis of Valve Data

There were 75 reports of failure of CCW control valves. Many of these

failures were related to aging, and affected plant operation or safety-related

equipment. Several reports noted that degradation had increased the stroke time

of the containment isolation valves in the CCW system. Five events referred to

failures of important CCW-control valves to open- or close, affecting -the CCw

supply to the reactor coolant pumps. One event described the wear out of seals

and 0-rings, which would have allowed accumulators to bleed down on a loss of

instrument air. This would have caused the valve to close, making the decay heat

removal cooler inoperable.

As discussed previously, most of the failures are related to aging, with

many of them-involving leakage. _The predominant failure mechanism is wear and

damage of internal components, which is consistent with the findings fromnphase

I. These failures typically involve wear to valve plugs, seats, and discs,

typically caused by erosion, corrosion or fatigue. Other valve failure

mechanisms include the buildup of corrosion products or other debris on discs or

seats, which causes the valve to stick or leak internally, and wear of the

1-7
TUBE LEAKS 56%

1 TUBE THINNING 3%

OTHER 4%

GASKET LEAKS 7%

PLUGGED TUBES 31%

Figure 1.7 Heat exchanger failures (NPRDS 1/88 to 6/90)

packing, which causes the valve to leak externally. The various aging mechanisms

are shown in Figure 1.9.

The control valves are typically composed of several important

subcomponents. The data were further analyzed to determine which subeomponents

contributed the most to failure of the valves. The results showed that the

predominant number of problems with the control valve are due to the actuator.

For air-operated valves, the root cause of the actuator problems was usually

attributed to contamination of the instrument air supply by moisture or dirt.

The subcomponents contributing to valve failures are shown in Figure 1.10. Table

1.1 gives the associated failure modes for each of the subcomponents.

The results of the update confirm that the phase I analysis is still valid.

Pumps, valves, and heat exchangers remain important components in the CCW system

that are susceptible to aging degradation. Therefore, the phase II study focuses

on evaluating the inspection, monitoring, and maintenance practices for these

components.-

1-8
WORN MECHANICAL SEAL 43%

WORN BEARING 26%

WORNSLEEVE. 3%

MISALIGNMENT 3%

WORN OIL SEAL 4%

WORN GASKET 4%

WORN PACKING 7%

OTHER 9%

Figure 1.8 CCW pump failures (NPRDS 1/88 to 6/90)

WEAR OF INTERNALS 60%

GASKET DEGRADATION 3%

I r// WEAR OF PACKING 10%

OTHER 17% FOULING OF INTERNALS 11%

Figure 1.9 Valve failure mechanisms (NPRDS 1/88 to 6/90)

1-9
Table 1. 1 Valve subcomponent failure modes

Subcomponent Fallure Mode

Diaphragm - ruptured

- worn

- cracked

- dilated/stretched

- hardened

Regulator - clogged

- setpoint drift

Solenoid Operated Valve - shorted cog

(electrical) - open coil

Solenoid Operated Valve - binding

(mechanical) - sluggish

Actuator - leakage

- binding

l stiffness

Valve Body - packing leakage

- gasket/seal leakage

- wall thinning

Limit Switch - out of adjustment

- fused/degraded contacts

ACTUATOR 33%

SOV- MECHANICAL 18%

REGULATOR 14%

so

LIMIT SWITCH 5%

AIR SUPPLY 5%

V- ELECTRICAL 5%

VALVE INTERNALS 7% DIAPHRAGM 12%

Figure 1.10 Valve subcomponent failures (NPRDS 1/88 to 6/90)

1-10
1.4 Objectives and Approach of Phase II Study

With an understanding of the aging effects obtained from the phase I work,

the methods used to detect and mitigate aging degradation can be evaluated. The

specific objectives of the phase II work are the following:

- Identify the inspection, surveillance, and monitoring methods

currently used for CCW systems, and evaluate their effectiveness for

detecting aging degradation.

- Identify the maintenance methods being used for CCW systems and

evaluate their effectiveness at mitigating aging degradation.

- Recommend new methods or improvements to current methods to better

detect and mitigate aging effects.

- Review and evaluate the materials used for component construction

and their susceptibility to aging degradation.

- Review and evaluate NRC inspection programs and industry standards

to ensure that aging is properly addressed.

- Identify aging concerns that are important for plant life extension.

To achieve these objectives, two operating PWRs were visited to collect

information on their CCW systems. Engineers and maintenance personnel were

interviewed, and copies of plant procedures were obtained to determine what

practices are used to monitor and maintain the CCW system. When possible,

failure records were also obtained to help evaluate these practices. In

addition, a survey of other operating PWRs was performed to help identify current

practices.

Various industry standards and NRC inspection plans were reviewed to

identify areas where aging should be addressed, and where results from the NPAR

CCW studies would be useful. Reviews were also performed of NRq bulletins and

notices related to CCW systems, and NRC safety system functional inspections to

supplement other results.

In the following section plant specific data is discussed, including the

ISM&M practices currently in use and the failures typically experienced. Section

3 examines the various materials used to construct the components, and the

effects of aging on them. Section 4 presents the findings from the review of the

NRC safety system functional inspections, and section 5 presents findings from

the review of regulations and industry standards. Section 6 discusses advanced

detection and monitoring techniques that may be effective at detecting and

mitigating aging degradation. Section 7 discusses how the results of this

analysis can be used to better manage the effects of aging in CCW systems.

Recommendations and conclusions are given in Section 8.

1-11
2. EVALUATION OF PLANT SPECIFIC DATA

To identify the inspection, surveillance, monitoring, and maintenance

practices currently used for CCW systems, information was collected from several

operating PWR nuclear power stations using a survey developed by BNL

specifically for the NPAR program and performed by the Electric Power Research

Institute (EPRI). In addition, BNL personnel visited two plants to collect data

and interview the staff. This section discusses the findings obtained from the

plant information.

2.1 Survey of PWRs

A questionnaire was distributed to various utilities requesting information

on their CCW system. A total of 14 units responded, providing information on

COW testing, monitoring, and maintenance. Not -all units completed all sections

of the questionnaire; therefore, the number of units responding to a particular

area was not always 14. In addition, the plants remained anonymous, therefore,

the findings could not be correlated with system design, and discrepancies in

the responses could not be investigated. However, the survey provides a good

representation of current practices.

2.1.1 CCW Testing Practices

The BNL survey solicited information on testing of CCW components, including

the test performed and its frequency. The responses covered pump testing, valve

testing, and several miscellaneous tests performed by the utilities. In

general, there are several basic tests for each component that all units

perform. These are typically tests required by plant technical specifications

or by the ASME code. In addition, there are also various other tests performed

which provide supplemental information. These tests may be recommended by

component manufacturers, or they may be desirable, based-on the utility's past

experience. The frequencies of the basic tests are consistent among utilities;

however, the frequencies of the supplemental tests vary.

The results for pump testing show that virtually all units measure pump head

and vibration, typically on a quarterly basis (Table 2.1). These are basic

tests which are part of the ASME Section XI code requirements for pump testing.

Although not all units reported that they perform them, testing pump suction

pressure, pump flow rate, and bearing temperature are also basic tests which are

required by ASME Section XI. Results from these basic tests give a general

indication of the pumps condition and, if trended, could be useful as indicators

of aging degradation. It should be noted that trending of all pump parameters

may not be warranted or effective for controlling aging degradation. Each

parameter should be evaluated at the component and plant level to determine if

trending of it will be useful. It should also be noted that some units do not

perform tests at the frequency required by code since relief may have been

granted by the NRC due to special circumstances.

Several other tests performed by some of the units include vibration

acceleration, and motor voltage and current tests. Two units stated that a

2-1
"performance test" was done for the CCW pumps. Although no description was

provided, it is expected that the performance test includes measurement of pump

head and vibration, and is similar to what other units perform.

Results on valve testing indicate that most plants test MOV stroke time and

check valve seat leakage. Stroke time testing of MOVs can be used as an

indicator of aging degradation if the results are trended. Increasing stroke

times would indicate increasing wear in subcomponents of the valve and valve

operator. Check valve seat leakage measurements can only be used as an

indicator if the actual leakage flow is measured. In some plants, check valve

leakage is determined by observing whether a non-running pump upstream of the

check valve rotates when there is flow on the downstream side of the valve.

Since no measurements are taken, results from this type of test would not be

trendable. Other tests which some of the units perform are measuring check

valve flow, checking of remote position indicators, checking of relief valve set

points, measuring isolation valve seat leakage, vacuum breaker stroking, MOV

current measurements, and MOV signature analysis. These tests, along with their

frequencies, are summarized in Table 2.2.

Table 2.1 Pump tests performed on CCW pumps

Test Frequency (Hamths)

Test Performed

1 3 12 18

1. Measure Vibration Amplitude 1 unit 10 units 3 units

2. Measure Pump Read 3 units 10 units

3. Measure Suction Pressure' 3 units 8 units

4. Measure Flow Rate 2 units 4 units

5. Measure Bearing Temperature' 5units

6. Measure Lubricant Temperature 2units 2 units

7. Check Lubricant Level ' units

8. Measure Vibration Acceleration 2 unite

9. Measure Motor Voltage/Current 1 unit 1 unit

10. Performance Test of the Pump

1 unit 1 unit

*Tests required by ASME Section XI

2-2
Table 2.2 Valve tests performed on CCV valves

Test Frequency (Hmt*hs)

Test Performed

3 12 1i 24 36 54 60 12n

1. Measure mOV Stroke Tine' 10

units

2. Check Valve Leakage 5 4

units units3. Measure Check Valve Flow' 5ui

units

4. Check Remote Position 1 2 1

Indicator' unit units unit l

5. Check Relief Valve - 2 3 1

Setpoint' units units unit

6. Measure Valve Seat

Leakage unit l

7. WIV Signature Analysis =

unit

8. NDV Current, Insulation 1

Resistance. Timing Check unit:

9. Vacuum Breaker Stroke I

unit'

'Tests required by ASHE Section zI or Generic Letter 89-04.

Other tests performed on theCCW systems include hydrostatic tests, system

logic response tests, and system leakage tests. The hydrostatic tests and

system leakage tests are an ASME code requirement, and must be performed every

10 years and three to four years, respectively.- The system logic response tests

include slave relay tests and automatic actuation of components. Although these

tests are good indicators of system integrity and should be continued, they do

not provide the type of information that would be useful for trending as an

aging indicator. The units performing these tests and their frequency are

summarized in Table 2.3.

2.1.2 CCW Inspection and Monitoring Practices

The BNL survey specifically asked for information on inspecting and

monitoring CCV pumps, valves, heat exchangers, and electrical components. The

information requested included parameters which are monitored/inspected monthly,

as well as parameters which are monitored daily, typically using shift logs.

2-3
Table 2.3 Miscellaneous CCV system tests

Test Frequency (Months)

Test Performed

1 3 12 1i 24 40 120

1. Hydrostatic Test 7 units*

2. Slave Relay Test 2 units 3 units

3. Auto Component Actuation 1 unit 7 units

4. System Leakage Test 1 unit 1 unit

5. Protective Relay Test 3 umits I unit

6. X Performance Test 1 unit

7. Motor Winding Phase/

Polarization Index 2 units

2 other units did not specify frequency

In general, the inspection/monitoring (IM) practices vary from plant to

plant. Unlike the testing practices, the survey does not indicate a basic set

of IM practices which all units perform. Aside from the daily, routine readings

taken during shift watches, most units do not perform any additional inspection

or monitoring activities on the CCW system. The few additional IM activities

that were reported are not performed by all plants. This could be due to the

existence of plant specific problems with a particular component, which

necessitate giving it additional attention. The IM practices for CCW pumps,

valves, heat exchangers, and electrical components are shown in Tables 2.4

through 2.7, respectively.

Table 2.4 CCW pump inspection/monitoring practices

Frequency (Months)

Inspection/Monitoring Practice 1 3 12

1. Check lube oil level 1 unit 1 unit

2. Check lube oil temperature 1 unit 1 unit |

3. Mechanical seal inspection I l _ | 2 units

2-4
Table 2.5 CCV valve inspection/monitoring practices

-__________ tFrequency (Mooths)

In~spection/Monitoring Practice 84 Z 3 1s 48 120

1. Check valve inservice inspection 4 units 2 units 1 unit

2. AOV disassembly inspection 1 unit 1 unit

3. FOV disassembly inspection 1 unit

Table 2.6 CCW heat exchanger inspection/monitoring practices

YFrquency (Months)

Inspection/Honitoring Practice

12 18 Unspecified

1. External visual inspection 1 unit

2. Open/internal visual inspection 1 unit _

3. Eddy current tubes 1 unit

Table 2.7 CCV electrical component inspection/monitoring practices

IzpectiU -lonitoring Frequency (Hanths)

Inspecticn/Moitoring Practice -1 18 40 48 so 220

1. Check lube oil, level 1

unit

2. Motor insulation resistance check 3 2

units units

3. Motor inspection 1 2

1 unit units

4. Motor specs heater check 1 2

unit units

5. Monitor stator current 1

unit

6. Thermoscan 1

unit

7. Motor disassembly/inspection *

unit

8. Motor vibration measurement 2

units

9. EQ inspecin2

units

2-5
All plants have shift watches during which operators walk down the plant,

visually inspect the various systems and components, and take various readings

from local gauges on the equipment, and from control room gauges. Operating

equipment is observed to ensure that there are no unusual noises or operating

conditions. These routine observations are typically recorded on a daily log

sheet. Twelve units responded to this portion of the survey which identified

the most common CCW parameters monitored daily. The results show that a number

of different parameters are monitored; however, not all plants monitor all of

them. For example, of the 12 units responding to this part of the survey, 5

units monitor CCW pump discharge pressure, while 7 do not. Results for

additional parameters are shown in Figure 2.1.

PARAMETER

PUMP DISCHARGE PRESS

PUMP MOTOR AMPS

HEAT EXCHANGER FLOW

HEAT EXCHANGER OWT

SURGE TANK LEVEL

PUMP FLOW

MOTOR WINDING TEMP

HX OUTLET TEMP

HEAT EXCHANGER DP

0 2 4 6 8 10 12

NUMBER OF UNITS

MON I TORED Z NOT MONITORED

Figure 2.1 Routine CCV parameters monitored

Of the two units monitoring pump flow, one unit reported monitoring it once

per hour by computer, while the second unit reported monitoring it once per

shift. Although no units monitor heat exchanger pressure drop, two units

reported they would monitor it if fouling was suspected. Three units monitor

surge tank level once per shift. The unit monitoring heat exchanger outlet

2-6
temperature reported doing it once every four hours. For heat exchanger delta

temperature, one unit monitors it every hour by computer, while three units

monitor it once per shift. Monitoring frequencies were not supplied for the

other parameters.

2.1.3 CCW Preventive Maintenance Practices

In addition to test and inspection practices, the BNL survey requested information on preventive maintenance (PM) practices currently used by the utilities.

The survey addressed five specific types of components; pumps, valves, heat

exchangers, electrical components, and instrumentation/controls. Twelve units

responded to this portion of the survey.

Ten units do some PM on their pumps, while two units do none, The PM performed includes oil changes, lubrication, alignment, and gasket replacement

(Table 2.8). Three units reported doing an overhaul or disassembly inspection

as part of their PM practices.

Table 2.8 CCW pump preventive maintenance practices

Fr*eqancy Months)

Hhl~erfozmed 6 E 12 18is 36 48 60 84 90

1. Luba oil system PN 2 units 2 units 2 units l

2. Bearing oil change 1 unit 1 unit

3. Coupling lubrication 1 unit 1 unit

A. Coupling alignment 1 unit l

5. Replace Gaskets (EQ) I_ 1 unit

S. Disassembly inspection 1 unit 1 unit 1unit

The number of units performing PM for valves varied with the type of valve.

Out of ten units responding, 8 reported doing PM on MOVs, while 7 reported doing

PM on AOVs. Only 5 said PM was performed on-manual valves, and only 3 units

reported doing PM on check valves. These differences can be partially

attributed to the different valve types, since MOVs and AOVs include valve

operators which add to the complexity of the valve and necessitate that they be

given more attention. The PM activities include cleaning, lubricating, and

replacement of some parts; these are listed in Table 2.9, along with their

frequency (note: some units responded with only a yes or no and did not list

specific activities).

2-7
Table 2.9 CCW valve preventive maintenance practices

Frequency (Mmnths)

Preventive Maintenance Practice

3 12 18 36 40 43 48 60

1. MV: Circuit Breaker 1 2

Maintenance unit units

2. MOV: Operator Maintenance 2 1 2

units unit units

3. NOV: Operator EQ 2 2

Maintenance units units

4. MOV: Packing Replacement 1

unit

5. DV: Motor Replacement 1

unit

6. MOV Parts Replacement 1

unit

7. AOV: Lubrication 1

unit

8. AOV: Packing Replacement u

unit

9. AOV: Diaphragm Replacement 1

unit

10. AOV: Parts Replacement 3

units

11. MAN: Clean/Lube Stem 1 2

unit units

PM activities on electrical components include cleaning of air filters and

lubrication of bearings. Several units reported doing maintenance on circuit

breakers, however, they did not specify what was included. For instrumentation

and controls, the maintenance actions reported were all calibrations. Tables

2.10 and 2.11 list the PM activities for electrical components and

instrumentation/controls, respectively.

Table 2.10 CCW electrical component preventive maintenance actions

Frequency (Months)

PM Performed

6 12 18 24

1. Clean Air Filters 1 unit

2. Lubricate Bearings 1 unit 1 unit 1 unit

3. Switchgear Circuit Brkr Maintenance 2 units 2 units

4. Pump Circuit Breaker Maintenance 1 unit 1 unit

2-8
In addition to maintenance, several operational activities are used to

mitigate excessive wear on a particular component. All of the 12 units

responding to this portion of the survey reported that they rotate their CCW

pumps to balance the operating time on each of them. This prevents any one pump

from wearing excessivley. However, a disadvantage of pump rotation is that if

all pumps wear at the same rate, there is the potential that all will fail at

the same time, although the probability is very small. - Along with pump

rotation, 5 units rotate the use of the CCW heat exchangers. Another practice

used by all units is chemical treatment, of the CCW water with chromates,

hydrazine, or nitrite borate to mitigate corrosion. Table 2.12 summarizes the

operational activities used and their frequency.

As part of the BNL survey, the units were asked whether they had a

reliability or trend analysis program in place. Ten of the 12 units responding

said they did. Four of the ten units reported that -they did not have a formal

program in place; however, they evaluate NPRDS, ISI/IST, and PM data. Two units

reported that they trend valve stroke times, pump head, pump vibration, and

bearing temperature. One unit reported trending pump flow,'- pump head, pump

vibration, and motor current. Two units only trend pump vibration.

2.1.4 Summary of Findings

The BNL survey shows that there are various basic inspection, monitoring, and

maintenance actions that all units use to mitigate failures. These include

monitoring pump head and vibration, stroking valves, and performing system

walkdowns (see also Section 7). Some basic actions are required by technical

specifications or are code requirements. In addition, there are several other

supplemental plant specific'activities. -These may be done because-of the past

experience of plant personnel, the plant's operating environment, or they may be

the result of a component's performance history. The frequency at which some

activities are performed also varies from plant to plant. Therefore, there is

probably no one set of generic test, inspection, and maintenance activities that

will satisfy the requirements of all plants. The optimum program for any

particular plant should be a combination -of activities - selected based on

specific plant conditions. - -

2-9
Table 2.11 CCV instrumentation/control preventive maintenance actions

Frequency.'_ouths)

IMKCalibrations Performed

12 18 24 36 48 so 96 120

1. Panel meter 2 units

2. Surge tank level 1 unit 6 units 1 unit 2 units

3. Flow indicators 1 unit B units 1 unit 2 units

4. HX flow loops 1 unit 1 unit 2 units

5. Header press switch 1 unit 2 units 2 units 1

unit

B. RCP return flow 1 unit 1 unit 2 units

7. RCP thermal barrier tamp. 1 unit 1 unit 2 units

8 Temp. indicators & alarms 1 unit I unit 2 units 2 units =_=

9. Cont. spray pump seal flow 1 unit =_=

10. Pump suction press 1 unit 2 units __=_=_=

11. Pump discharge press 1 unit 6 units 1

unit

12. Hx outlet temp. 1 unit 1 unit

13. RCP oil cooler flow 2 units

14. Motor stator temp. 2

units

15. Motor bearing temp. 2

units

16. Pump bearing temp. 2

units

17. RER x flow alarms 2 units

18. RTD probe 1 unit

19. Clean limit switch 1

contacts unit

Table 2.12 CCW operational activities to mitigate degradation

Frequency (Weeks)

Operational Activity

1 2 to 3 4 12 As Required

1. Rotate pumps 4 units 1 unit 3 units 2 units 2 units

2. Rotate heat exchangers 1 unit 2 units 2 units

3. Chemical injection 12 units

2-10
2.2 Plant A Data Evaluation

In addition to the survey, interviews were held and data were collected at

two operating PWR plants. Plant A has two nuclear units operating at the same

site. Each unit is approximately 17 years old and has its own CCW system. The

following subsections discuss the system's design, and plant monitoring and

maintenance practices.

2.2.1 Plant A CCW System Design

The CCW system at plant A consists of two redundant, safety-related loops and

various loops for cooling non-safety-related components (Figure 2.2). The

cooling loops are supplied by 3 CCW pumps and 3 CCW heat exchangers, each of

which can supply either or both of the safety-related cooling loops. The CCW

system is cooled by the service water system, which uses brackish salt water.

Figure 2.2 Plant A CCU system design

The system is of the closed loop design, with fluid continuously circulating.

The three pumps are each 100% capacity, and the three heat exchangers are each

50% capacity. During normal full power operation, two pumps and two heat

2-11
exchangers will accommodate the heat removal loads. The system also includes a

surge tank, and various manual valves, check valves, relief valves, air operated

valves (AOVs) and motor operated valves (MOVs).

The CCW system is considered an engineered safeguard system since it is vital

during recovery from an accident. Therefore, it consists of two independent

Seismic Category I loops (Header A and Header B), each of which serves a single

train of identical engineered safety feature (ESF) components. The redundant

loops assure cooling to at least one train of safety-related components (i.e.,

residual heat removal pumps, containment spray pumps, RHR heat exchangers,

etc.). There are also various non-ESF equipment supplied by the A and B headers

through the appropriate valving.

Tie headers are located at the suction and discharge of the CCW pumps and at

the discharge of the CCW heat exchangers. These tie headers allow any pump or

any heat exchanger to supply either or both headers. Normally, the system is

aligned to the B header.

2.2.2 Plant A Inspection, Surveillance, and Monitoring Practices

The inspection, surveillance, and monitoring (ISM) practices used at plant

A include actions which are performed periodically, on a weekly or monthly

basis, as well as actions which are performed on a daily basis, as part of the

shift watch. The daily practices include system walkdowns to check for visual

or audible abnormalities in operating equipment, and to monitor operating

parameters. No formal procedures are used and findings are recorded on log

sheets. The parameters monitored are summarized in Table 2.13.

Table 2.13 CCW parameters monitored daily for plant A

Parameter Frequency

1. CCW flow to/from loads 4 to 24 hours

2. CCW temp. to loads 4 to 24 hours

3. CCW surge tank level 4 hours

4. CCW pump discharge pressure 4 hours

5. CCW Hx outlet flow 8 hours

6. Check for unusual noise 4 hours

7. Check for unusual leakage 4 hours

The practices performed periodically include tests and inspections which

require formal procedures, and are done to satisfy plant technical

specifications or code requirements. However, some periodic activities are

performed as a result of past plant experience or equipment history.

2-12
CCW pump activities at plant A are performed under two procedures; an

inservice test procedure and a general inspection procedure. The test procedure

is performed quarterly to satisfy ASHE section XI pump testing requirements; it

includes measurement of'pump head, vibration, bearing temperature, seal leakage,

and motor amps. All parameters are trended using the test results. The general

inspection procedure, performed monthly, includes checks for excessive or

unusual noise, a lube oil analysis, inspection of the seals for leakage, and

inspections for corrosion and erosion on the pump externals. Disassembly

inspections and non-destructive examination (NDE) techniques are not performed

routinely. CCW pump activities are summarized in Table 2.14.

Table 2.14 Plant A CCU pump ISM practices

ISM Practice Frequency Trandin

1. Check lube oil level- Daily -o N 

2. Perform lube oil analysis Monthly No

3. Inspect for external corrosionlerosion monthly No

,. Measure vibration Quarterly Yen

5. Measure differential pressure Quarterly Yes

6. Measure bearing temperature Quarterly yes

7. Measure seal leakage Quarterly N

|. -Measure motor amperage Quarterly No

9. Perform thermography exam Quarterly Yes

10. Inspect for casingishaft cracks At Overhaul No

11. Inspect for shaft warpage At Overhaul No

12. Inspect impeller/sealstinternals At Overhaul No

ISM practices for the CCW valves are performed when preventive maintenance

is needed. During the system walkdowns, the valves are visually inspected for

gross leakage and the valve's position (open/closed) is-checked; however, no

other actions are performed. When PM is performed on the valves, which

typically occurs during cold shutdown or refueling outages, the valves are

disassembled and thoroughly inspected for wear, corrosion,' erosion, pitting,

distortion, and any other degradation. Any part found. to be unacceptable is

replaced. The parts are then cleaned and lubricated, if. applicable, and the

valve is reassembled, typically with new gaskets. Depending on the type of

valve, other checks and inspections are made. For example, on KOVs, the limit

and torque switches are inspected, cleaned,. lubricated, and calibrated. A

complete listing-of valve ISM practices is presented in Table 2.15.

CCW heat exchanger performance is monitored'by-visual inspections to detect

erosion, corrosion, and leakage, as.well as by.eddy current tests to determine

if there is excessive thinning of the tube wall, or if there are any cracks in

the tubes or shell. Tube fouling is determined, based on heat balances using

2-13
inlet and outlet temperatures and flow rates. The amount of fouling is

correlated with the service water temperature required to meet the cooling load,

and curves are plotted for use by the operators. The actual temperature of the

service water, which is used to cool the CCW heat exchangers, is monitored and

compared to these fouling curves. When the actual service water temperature

exceeds the required service water temperature, the heat exchangers are cleaned

and new gaskets are typically installed. Table 2.16 lists the heat exchanger

ISM practices.

Table 2.15 Plant A CCW valve ISM&M practice

| ala Type ISMH Practice [ Frequency

ALL Visually inspect for gross leakage Daily

MaVa Disassembly inspection and overhaul 18 Months

- Clean/inspect parts for wear/corrosion/erosion

- Lubricate moving parts

- Replace degraded parts as needed

- Check electrical connections for tightness

- Inspect, clean electrical contacts/controls

- Inspect wiring for cracks/brittleness/abrasions

- Check lube oil for water/dirt/foreign material

- Adjust torque/limit switch settings

- Measure motor current

- Measure stroke time

- Verify position indicator functioning

- Install new gaskets

MOVATS testing 5 Years or after

- Measure stem thrust Overhaul

- Measure motor current

- Check operator alignment

- Perform signature analysis

- Check stem play

hOVs Disassembly inspection and overhaul 18 Months

- Clean/inspect parts for wear/corrosion/erosion

- Replace degraded parts as needed

- Lubricate moving parts

- Adjust limit switches

- Clean air filter

- Clean and calibrate pressure regulator

- Adjust actuator spring tension

- Bench test the actuator

Manual Inspection and Lubrication 6 Months

- Clean studs/nuts/stem/reach rod

- Inspect parts for wear/corrosion/pitting/scaling

- Inspect packing for leaks

- Inspect bandwheel for cracks/loose nuts

- Inspect bonnet/body for cracks/corrosion/Leaks

- Inspect reach rods for binding/distortion

- Lubricate moving parts

Stroke Valve Open/Closed 18 Months

Relief Bench test 5 years

2-14
Table 2.16 Plant A CCV heat exchanger ISM practices

LS1 Practice Frequency

Visually inspect for gross leakage Daily

Monitor heat exchanger flow Daily

Monitor tooling water temperature at load Daily

Measure shell/tube thickness 18 Months

Check for *hall/tube cracks 18 Months

Inspect for corrosion/erosion 18 Months

2.2.3 Plant A Preventive Maintenance Practices

The maintenance practices are all performed using formal procedures. Each

component has at least one procedure specifically written to address preventive

maintenance, and is typically performed quarterly. The maintenance actions are

based on manufacturer's recommendations and past operating experience.

During every refueling outage, one of the CCW pumps is overhauled. Of the

three pumps, the one selected for overhaul is based on the number of outstanding

maintenance work requests (MWRs) on the pumps, as well as the time since the

last overhaul. As part of the overhaul, the pump is disassembled and thoroughly

inspected for signs of wear, erosion, corrosion, and degradation, and any parts

showing abnormal degradation are reworked or replaced. All moving parts within

the pump are lubricated, and a lube oil analysis is performed. A lube oil

analysis is also performed monthly by a separate procedure, and the lube oil is

changed when warranted. Table 2.17 summarizes the CCWI pump preventive

maintenance practices.

Table 2.17 Plant A CCI pump preventive maintenance practices

PM Practice | Frequency

Change lube oil As Needed

Replace gaskets As Needed

Replace seals As Needed

Replace bearings As Needed

Rework impeller As Needed

Replace wear rings As Needed

Retorque bolts Overhaul*

Lubricate moving parts Overhaul*

Check for casing/shaft cracks Overhaul*

Check for shaft warpage Overhaul*

Realign pump and motor Overhaul*

* At least 1 pump is overhauled every refueling outage.

2-15
As part of this study, the plant maintenance practices and the manufacturer's

recommended maintenance practices were compared. According to the

manufacturer's literature, maintenance on this type of pump should include

changing the bearing oil periodically, lubricating all couplings, and

overhauling the unit when performance drops off. Disassembling the pump for

inspection is not recommended unless there is evidence of internal problems.

When the pump is overhauled, the inside waterways of the casing should be

cleaned and painted to resist rust and erosion. An overhaul also should include

an inspection of wear rings for excessive wear, an examination of the shaft for

rust, pits or distortion, and an examination of the bearings for wear, cracks,

or scratches. A comparison with the plant practices indicates that all

manufacturer's recommendations are addressed, with the exception of painting the

casing waterways. This item should be considered as an addition to current

plant practices, since it would help to mitigate long term corrosion and erosion

of the casing, which is not currently addressed. Disadvantages of this practice

which should also be considered are peeling of the paint, which could clog

downstream equipment, and the additional maintenance required to repaint the

surfaces periodically.

Valve maintenance is also performed during overhaul for MOVs and AOVs, which

are overhauled every 18 months during refueling outage. Manual valves are

inspected and lubricated every 6 months, as specified in the manufacturer's

recommendations, and overhauled when necessary. No other maintenance is

recommended by the manufacturer for manual valves. During overhaul of MOVs and

AOVs, the valve and operator are disassembled and inspected for excessive wear,

erosion, or corrosion. Any parts found to be excessively degraded are reworked

or replaced. Following the overhaul of MOVs, MOVATS testing is also performed

to measure operator thrust, as well as stroke time, torque and limit switch

settings, and motor current signature during operation. The results from the

MOVATS tests are recorded and trended. Table 2.15 includes the CCW valve

maintenance practices.

The only preventive maintenance performed on the CCW heat exchangers is to

clean the tubes when fouling has become unacceptable. This is determined using

fouling curves developed from past operating data, and by comparing the heat

transfer characteristics to the temperature of the service water available. A

formal procedure is used for the tube cleaning, which includes replacing head

gaskets and retorquing bolts. At every refueling outage, a full eddy current

test of all tubes is performed to determine if any cracking or wall thinning is

present. Any tubes that are cracked or have their wall thickness reduced by

more than 60% are plugged. A summary of heat exchanger maintenance practices is

presented in Table 2.18.

2-16
Table 2.18 Plant A CCV heat exchanger preventive maintenance practices

PM Practice I Frequency i|

Clean tubes As Needed

Replace gaskets As Needed

Plug crack/thinned tubes As Needed

Retorque bolts As Needed

2.2.4 Plant A Corrective Maintenance Events

To understand the effectiveness of the IS&M and PM practices currently used

at Plant A, an analysis was made of the corrective maintenance (CM) events

needed for CCW system components. Plant records covering two years from 1988 to

1990 were obtained, and reviewed to identify any problem areas not addressed by

current practices. The data included 254 CM events from both units at the plant

site, each of which has its own CCW system.

The majority of CM events are related to valves (47%), followed closely by

instrumentation and controls (44%), as shown in Figure 2.3. Pumps (8%), and

heat exchangers (1%) account for a very small percentage of the CM events.

Since these results are not normalized to account for the numbers of components,

the relatively large percentage of CM events for valves and I&C can be

attributed to the large number of these components found in the plant. These

results are typical of those -found in the previous Phase- I study, and show where

the predominant CM effort is expended. As indicated in Figure 2.3, the majority

of the CM events are related to aging of the components.

A closer examination of the valve CM events, which totaled 119, shows that

by far the type of valve most commonly requiring CM is the manual valve (70%),

as shown in Figure 2.4. This is followed by the air operated'valve, the motor

operated valve, the relief valve, the check valve, 'and the solenoid operated

valve. Again,, these results are not normalized, therefore, population effects

contribute to the relative percentages. The fact that manual valves require the

most CM does not, by itself, mean that current, ISM and PM practices for this

component are inadequate.

Since manual valves account for most of the CM activities (83 events), the

data were examined to identify their failure modes. The predominant failure mode

was found to be packing leaks (30%), followed by binding of the valve (20%),

failure of the operating chain or reachrod (12%),- and broken or missing

handwheels (11%), as shown in Figure 2.5. The' packing leaks are typically

detected by visual inspection, however, there was one incident where the packing

blew out of the valve completely, resulting in a'relatively large leak. The

leak was detected by observing that the surge tank required an excessive amount

2-17
TOTAL CM EVENTS

50%

0% M30M7771

VALVES I&C PUMPS HX

COMPONENT

M TOTAL E AGING

Figure 2.3 Plant A corrective maintenance events

of makeup water. CM events attributed to binding had several causes, including

packing that was adjusted too tightly, gear box problems, and malfunction of the

operator.

The 27 CM events for air operated valves (AOVs) and motor operated valves

(MOVs) were also reviewed to identify failure modes (Figure 2.6). As for the

manual valves, the predominant failure mode was packing leaks (19%), along with

seat leakage (19%), excessive stroke time (19%), and failure to open or close

(19%). Again, the packing leaks are typically detected by visual observation

and usually require readjustment or replacement of the packing. The seat

leakage problems were typically associated with the AOVs, and were due to

incorrect stroking of the valve, which prevented it from fully closing. This

was usually corrected by readjusting the stroke settings.

From the analysis of the valve data, one area that might benefit from

increased attention is valve packing inspections. Consideration should be given

to replacing the packing, or, as a minimum, readjusting it regularly to mitigate

the number of leaks experienced. It should be noted that occasional CCW valve

packing leaks are a relatively minor problem, which can usually be dealt with

without shutting down the plant. However, if the root cause of the failure is

not corrected, the packing failures may become more frequent as the component

2-18
TOTAL VALVE CM EVENTS

70%

M0V=WTOR OPERATED VALVE

AOV=AIR OPERATED VALVE 60 ....... ............ I . . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . 60% SOVXS=SLENOOI OPERATED VALVE

503% .............................................................................

40X .......~.......................................................................

3C0 4 .............................................................. ................................. ...........

20% ...............................................................................

I KM _ ..... .|....... ........ .... =......... . . . .. . . . .. . . . .. . . .

MA2NUAL AOV b<OV RELIEF CHECK SXOV

VALVE TYPE

Figure 2.4 Plant A valve types requiring CME

ages. Therefore, in addition to checking the packing, the structural

subcomponents interacting with the packing should also be examined for signs of

long term aging. This includes the stuffing box, 'packing -gland, and valve stem.

Long term aging effects such as distortion, pitting, scoring, or cracking can

result in premature failure of the packing. This-'type of degradation may take

many years to manifest and become a serious problem; therefore, techniques to

detect it may not be included in the periodic inspections. Since it could cause

increasing failure rates,' it is important that it be considered.

The plant data were also analyzed to identify the types of I&C components

-receiving CM. As shown in.Figure 2.7, of the 111 CM events, indicators (73%)

were by far the predominant I&rC component receiving CM, while controllers (1696)

and transmitters (11%) contributed only a small part of the I&C CM activities.

The most common failure mode was incorrect reading (50%6), followed by broken

face glass (20%), bent or broken indicator (12%1), and leaky fittings (-5%), as

shown in Figure 2.8. Indicator failures giving an incorrect reading typically

involved the instrument reading no flow with flow in the line, or. reading a flow

with the system shutdown. Failures involving incorrect reading can be aging

related; however, failures involving breaking of the face Slats or bending of

the indicators are not.

2-19
FAILURE MODE

PACKING LEAK

81 ND I NG

CHAIN/REACH ROD FAIL

HANDWHEEL BROKEN

STEM BENT/BROKEN

OIL/GREASE SEAL FAIL

SEAT LEAKAGE

INDICATOR BROKEN

GEAR BOX CRACK

UNKNOWN

FLANGE LEAK

0% 5% 10% 15% 20% 25% 30%

TOTAL MANUAL VALVE FAILURES

Figure 2.5 Plant A manual valve failure modes

Relatively few pump C~s were found in the two years of data reviewed (20

events). However, the pumps are a very important component for CCW system

reliability (Figure 1.6), therefore, effective pump ISM and PM practices are

critical. The pump failure modes identified from the data showed that 45% of

the pump CMs were due to leakage of the water seals (Figure 2.9), followed by

leakage of the oil seals (35%), breakage or leakage from the constant level

oiler (15%), and loosening of the slinger ring (5%). The failures related to

leakage of the water and oil seals were all detected by visual observation. A

thorough inspection of the seals is made every time the pumps are overhauled,

during refueling outages when at least one pump is overhauled. Since not all

pumps are overhauled during refueling, some of the pump seals may not be given

a thorough inspection for several years. This contributes to the fact that seal

degradation is usually not detected until failure occurs.

With the redundancy built into the system design, occasional pump seal leaks

do not seriously impact CCW system availability or reliability. They are

typically handled without shutting down the plant, although a limiting condition

for operation (LCO) state may be entered. However, the cause of the seal

failures may be due to undetected aging degradation of structures internal to

2-20
FAILURE MODE

I

PACKING LEAK

SEAT LEAKAGE

LONG STROKE TIME

WILL NOT OPEN/CLOSE

_ I IME

DECLUTCH LEVER FAIL

MOTOR BURNING

AIR DIAPHRAM LEAK

STEM BENT/BROKEN

INDICATOR BROKEN

0% 5% 10% 15% 20%

TOTAL AOV/MOV FAILURES

Figure 2.6 Plant A AOV and NOV failure modes

the pump casing, such as support structutesor mounting surfaces. Over the

years, clearances can change or parts can( become distorted, resulting in

increased wear on the seals. If the frequency of seal failure increases, it may

decrease system availability and reliability. Therefore, it is important to

trend the nature and frequency of component failures with time. Although the

failed subcomponent has been replaced, the underlying cause of the failure may

not have been corrected.

The corrective maintenance data are also useful for evaluating the

effectiveness of preventive maintenance practices. One method of doing this is

to construct time-lines representing the PH/CM history of a particular

component. By comparing the relative frequency of PM events with the resulting

CH events, the strengths and weaknesses of the various PM activities can be

determined. This was done on a trial basis for two years (June -1988 to June,

1990) for three of the components from plant A; a manual valve, a motor operated

valve, and a pump.

The manual valve selected for the time-line analysis is a CCW isolation valve

from a non-regenerative heat exchanger. The data show that for the time period

examined, no preventive maintenance was performed on this valve (Figure 2.10).

2-21
TOTAL I&C FAILURES

80%

60% .... l . .

4 0% .. . . . . . . . . .. . . . . . . . . .. . . . . . . . . .

20 i'..- ........ ''....'..'.'.'''..'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.'.....'....'.'.'.'..'.'.'.'....

0%

INDICATORS CONTROLLERS TRANSMITTERS

I&C TYPE

Figure 2.7 Plant A I&C components requiring CH

This is in contrast to the plant's practice of inspecting and lubricating manual

valves every 6 months, as stated previously. It is possible that the PM actions

were performed but never recorded, however, the time span includes at least four

scheduled inspections, and none are Rhown in the data. The data for other

manual valves show that these inspections are typically recorded. It is also

possible that certain manual valves are not considered important enough to

warrant periodic maintenance, and this particular valve may be in that category,

or this valve may be in a high radiation area and ALARA concerns prevent regular

preventive maintenance.

There were three instances of packing leaks in this manual valve in 1989,

approximately 2 months apart (Figure 2.10). The first two instances were

detected visually, and the valve packing was adjusted. In the third instance,

the packing was blown out of the valve resulting in a relatively large leak.

This caused the surge tank level to drop and makeup water to be added to the

system. These two indicators were used to detect the third leak. After this

occurrence the valve was rebuilt.

Analysis of this valve history indicates that the valve packing problem

should have received more attention. It is possible that the packing was

2-22
FAILURE MODE

INCORRECT READING

BROKEN FACE GLASS

INDICATOR BENT/BROKE

FITTINGS LEAK

FLOAT BENT/BROKEN

SPURIOUS ALARM..

STUCK MAGNET

INCORRECT SIGNAL OUT

LOOSE HOUSING

FLOWRATOR BROKEN

SENSE LINE PLUGGED

0% 10% 20% 30% 40% 50%

TOTAL I&C FAILURES

Figure 2.8 Plant A I&C component failure modes

installed or adjusted improperly, or the wrong packing was used. It is also

possible that the packing had reached the end of its useful life. In cases such

as this, where repeated failures occur,' a root cause evaluation should be

performed. Although the failures of this valve did not have a major impact on

the system, a similar failure of a more critically located valve might adversely

affect'the system's availability.

A similar time-line history was generated for a motor operated valve (Figure

2.11). The valve is a CCW isolation valve at the outlet of an RHR heat

exchanger. There were three incidents of 'packing leaks for this valve; one

occurring two months after an EQ inspection of the 'valve-in 1988. Following

each repair, a post maintenance test was performed to check motor current and

verify proper operation. Since MOVsare a more complicated component than

manual valves, it is expected that they would fail more often. This was found

to be the case in the Phase I CCW studyg. The fact that this plant does not

have a higher failure rate for the MOVs suggests that their maintenance and

monitoring practices are effectively detecting and mitigating aging degradation

before it results in failure. Aside from the packing leaks, no serious

failures of the valve were experienced.

2-23
FAILURE MODE

I

WATER SEAL LEAK

OIL SEAL LEAK

OILER BROKENWLEAKS

SLINGER RING LOOSE

I

I

I

I I I

0% 10% 20% 30% 40% 50%

TOTAL PLUP FAILURES

Figure 2.9 Plant A pump failure modes

The last component analyzed using the time-line history method was one of the

CCW pumps (Figure 2.12). The pump history shows that quarterly inspections and

bearing oil changes were performed regularly. The only failures were a water

seal leak and a bearing oiler leak. The pump uses a gravity-fed, constant level

oiler to lubricate the bearings. From the previous discussion on plant ISM

practices, the quarterly pump inspection includes measurement of seal leakage;

however, the results are not trended (Table 2.14). The time-line history shows

that seal failure occurred approximately two months after the quarterly

inspection, suggesting that the inspection may not have effectively determined

the extent of seal degradation. One improvement might be to trend the results

of the leakage measurements. An increasing amount of leakage could indicate

increasing degradation. In addition, a more thorough inspection of the seal

subcomponents may be required. Since this may require some disassembly of the

pump,it should only be performed if some other indication of a seal problem is

apparent.

2-24
-- PM ACTIONS . - . CM ACTIONS

_/ 9

Ifes

4/89 PACK ING LEAK

A[DJUST PACKING

6/89 PACKI NG LEAK

ADJUST PACKING

8/89 PACKI NG LEAK

REBUILD VALVE

1/90

_/9 I

Figure 2.10 Plant A manual valve time-line history

2.2.5 Summary of Plant A Findings

Examination of the corrective maintenance data for plant A indicates that

their inspection, surveillance, monitoring, and maintenance practices are

effective-at detecting and mitigating gross forms of aging degradation. This

conclusion is based on-the fact that for the two years of data examined, the

only component failures occurring involved seal or packing leaks which did not

result in loss- of component function and were relatively easy to repair. There

were no serious failures involving complete loss of the component or loss of

system function. This analysis is limited, however, because only two years of

data were available for analysis. The effectiveness of current practices at

2-25
PM ACTIONS I- -CM ACTIONS

8/88 EO INSPECTION

10/88 VALVE STEM LEAK

1/_,

1/89. POST MAINTENANCE

MOTOR CURRENT TEST

10/89 POST MAINTENANCE 10/89 PACKING LEAK

MOTOR CURRENT TEST ADJUST PACK I NG

11/89 POST MAINTENANCE _ 11/89 PACKING LEAK

MOTOR CURRENT ANO REPLACE PACK ING

STROKE TIME TEST 1/90

6/90

Figure 2.11 Plant A NOV time-line history

managing aging mechanisms that require a longer time period to manifest can not

be evaluated. For example, corrosion or erosion of a pump casing may require

twenty years or more to result in a detectable failure. If techniques are not

in place to measure casing wall thickness periodically, no evidence will ever

exist that current practices are not effectively controlling this aging-related

failure mechanism until a failure occurs. Therefore, although current practices

appear to be managing the most common aging-related failure mechanisms,

attention needs to be given to detecting the less obvious mechanisms which

require a longer time period to result in failure.

2-26
PM ACTIONS CM ACTIONS

6/SB

7/98 LUBE OIL ANALYSIS

9/88 CHANGE BEARING OIL

V/9

2/89 WARTERLY PUM INSP.

6/89 OUARTERLY PUIP INSP.

10/99 OUARTERLY PtW INSP

10/B9 CHANGE BEARING OIL

12/89 OUTIr0o WATER

SEAL LEAK

1/90

V190 QUARTERLY PLW INSP.

1/90 CHANGE BEARING OIL

4/90 QUARTERLY PWP INSP.

4/90 CHAN BEARING OIL S 90 I OARD BEARING

6/90 OUARTERLY PUAP INSP. OILER LEI

6/90

Figure 2.12 Plant A CCV pump time-line history

2.3 Plant B Data Evaluation

The second plant visited to collect CCM information also is approximately 17

years old but has one reactor unit on site. As for plant A, information was

collected on CCW system ISM&M practices and a list of corrective maintenance

events was obtained for the past several years for plant B. This section will

discuss the analysis of that information.

2-27
2.3.1 Plant B CCW System Design

The plant B CCW system design includes three pumps, two heat exchangers, and

one surge tank (Figure 2.13). The pumps are of the horizontal, centrifugal type

with a capacity of 3600 gpm, an operating pressure of 150 psig, and a design

temperature of 2000F. The pumps are driven by 250 HP motors and are equipped

with mechanical seals. The heat exchangers are tube and shell type, and are

cooled by service water from a nearby river on the tube side.

RECIRCULATION LINE

Il SURGE

TANK

_CC PUMPS CCW HEAT

TO

LOADS

SE^RVIECE

FROM

LOADS

Figure 2.13 Plant B CC9 system design

During normal powered operation, two pumps and two heat exchangers are

required to be in service. The pumps discharge into a common 20 inch header.

From the header, the flow is directed to the shell side of the heat exchangers

through two separate 14 inch tributary headers. The heat exchanger outlets are

headered together in a 20 inch supply line which directs cooling flow to the

various plant loads.

The surge tank accommodates expansion, contraction, and in-leakage of water,

as well as providing a reserve supply of cooling water in the event of a system

leak. The surge tank is normally vented to the atmosphere. In the event of a

radiation leak into the CCW system, the vent valve closes automatically. The

working fluid in the CCW system is purified water treated with potassium

chromate as a corrosion inhibitor.

2.3.2 Plant B Inspection, Surveillance, and Monitoring Practices

The format of the ISM practices used at plant B is similar to that used at

plant A in that some practices are performed daily, while others are performed

quarterly or yearly. The daily activities include system walkdowns to check for

2-28
visual or audible abnormalities in operating equipment, and to monitor various

operating parameters. Formal procedures are not required and findings are

recorded on log sheets. The CCW operating parameters monitored daily are shown

in Table 2.19.

Table 2.19 CCW parameters monitored daily for plant B

Parameter .,Frequency

1. CCW flow to/from loads 4 hours

2. CCW temperature to loads 4 hours

3. CCW surge tank level 4 hours

4. CCW pump suction temperature 4 hours

5. CCW HX outlet flow 4 hours

6. Check for unusual noise 4 hours

7. Check for unusual leakage 4 hours

The ISM practices performed periodically are typically required to satisfy

plant technical specifications or code requirements. Formal procedures are

required to perform them. CCW pump practices include a quarterly-test which

measures pump head, vibration, and bearing temperature to satisfy ASME code

requirements. In addition, pump seal leakage is measured quarterly. The lube

oil level is checked daily during the system walkdown, and every 6 months a lube

oil analysis is performed. If there is evidence of deterioration or

contamination, the lube oil is changed. Every two years the pump is

disassembled and thoroughly inspected for internal corrosion and erosion. In

addition, the impeller, seals, and bearings are examined for signs of wear. The

casing and shaft are visually inspected for cracks. However, non-destructive

examination (NDE) techniques, such as dye-penetrant or eddy current testing, are

not used to detect hidden flaws. A dial indicator is used to measure shaft

warpage, and wear ring clearances are measured. Any parts showing unacceptable

degradation are replaced or refurbished. The pump ISM practices are summarized

in Table 2.20.

The ISM practices for CCW valves also are similar to those at plant A,

however, the frequencies are different. As at plant A, all valves are visually

inspected daily during system walkdowns to check for gross leakage. For the

MOVs, a stroke time test is performed every cold shutdown. Disassembly

inspections are not performed unless there is evidence of a problem with the

valve. MOVATS testing is being instituted, and will be performed every 5 years

or after an overhaul. The AOVs are stroke tested quarterly. As for the MOVs,

disassembly inspections are not made unless there is a problem with the valve.

For the manual valves, there are no scheduled actions. This is in contrast to

plant A, which strokes and lubricates the manual valves every 6 months. The CCW

relief valves are bench tested every 5 years. The ISM actions for CCW valves at

plant B are summarized in Table 2.21.

2-29
Table 2.20 Plant B CCW pump ISM practices

ISM Practice Frequency Trended

1. Check lube oil level Daily No

2. Measure vibration Quarterly Yes

3. Measure differential pressure Quarterly Yes

4. Measure bearing temperature Quarterly Yes

5. Measure seal leakage Quarterly No

6. Perform lube oil analysis 6 months No

7. Inspect for corrosion/erosion 2 years No

8. Inspect impeller/seals/internals for wear 2 years No

9. Check rotor torque 2 years No

10. Inspect for casing/shaft cracks 2 years No

11. Inspect for shaft warpage 2 years No

12. Inspect bearings/shaft sleeves for wear 2 years No

13. Measure wear ring clearance 2 years No

ISM practices for the CCW heat exchangers at plant B are limited to daily

observations of heat exchanger flow and temperature at the loads. These

parameters are used as indicators of heat exchanger performance. Plans are

being made to institute inspections for tube leakage and tube fouling. Table

2.22 lists the heat exchanger ISM practices for plant B.

2.3.3 Plant B Preventive Maintenance Practices

The preventive maintenance (PM) practices are performed using formal

procedures; however, many of the PM actions are only performed on an as-needed

basis. Therefore, for these components, certain PM actions are not performed

unless there is some indication that the component requires attention. For

example, seals are not replaced unless there is some indication that the

existing seal is degraded to an unacceptable level. This is similar to the

practice at plant A for some PM; however, plant A schedules more overhauls based

on operating time, without requiring a degraded condition as a prerequisite.

Pump PM practices include lube oil changes and lubrication of motor bearings

and pump couplings. The remaining pump PM actions are performed only if pump

performance degrades. In this case, the pump may be disassembled and inspected

to determine and correct the cause, or it may be overhauled completely. The pump

PM actions for plant B are summarized in Table 2.23.

2-30
Table 2.21 Plant B CCW valve ISH&M practice

valve npe ISM&M Practice Frequecy

ALL Visually inspect for gross leakage Daily

MOVS Stroke time test Cold.

Shutdown

Disassembly inspection and overhaul

- deanAnspect parts for wear/corrsion/erosion As needed

- lubricate moving parts

- replace degraded parts as needed - check electrical connections for tightness

- inspect, dean electrical contacts/controls

- inspection torquellimit switches for crackstbreaks

- inspect wiring for cracks/brittlenesslabrasions

- check lube oil for watertdirtlforeign material

* adjust torque/limit switch settings

- measure motor current

- measure stroke time

- verify position indicator functioning

- install new gaskets

MOVATS Testing 5 years

* measure stem thrust or after

- measure motor current overhau'

- check operator alignment

- perform signature analysis

- check stem play

AOVs Stroke Time Test Quarterly

Disassembly inspection and overhaul As needed

- deanAnspbct parts for wear/corrosion/erosion

- replace degraded parts as needed

- lubricate moving parts

- adjust limit switches

- dean air filter

- dean and calibrate pressure regulator

- adjust actuator spring tension

- bench test the actuator

Manual No planned actions -

Relief Bench Test 5 years

*Currently planned

2-31
Table 2.22 Plant B CCV heat exchanger ISM practices

ISM Practice Frequency

Visually inspect for gross leakage Daily

Monitor heat exchanger flow Daily

Inspect for tube leakage Planned

Monitor cooling water temp. at load Daily

Check for tube fouling Planned

The PM actions for the CCW valves are also limited to cases where there is

evidence of degraded performance. If a valve is operating properly, the only

attention it receives is the ISM actions discussed previously. When a valve

requires overhaul, it is common to replace the packing, gaskets, and seals, and

to lubricate all moving parts. On MOVs and AOVs, the torque or limit switches

may also be replaced, and the operator and valve are realigned. These PM

actions are shown in Table 2.24.

There are no scheduled PM activities for the CCW heat exchangers. When

performance degrades to an unacceptable level, as indicated by the outlet

cooling water temperature, the tubes are cleaned and checked for leaks. If the

heat exchangers are disassembled for inspection and cleaning, new gaskets are

typically installed and the head bolts are retorqued upon reassembly. The heat

exchanger PM activities for plant B are summarized in Table 2.25.

Table 2.23 Plant B CCW pump PH activities

PH Practice Frequency

Change lube oil 6 months

Lubricate motor bearings 6 months

Lubricate pump couplings 12 months

Replace gaskets As needed

Replace seals As needed

Replace bearings As needed

Rework impeller As needed

Replace wear rings As needed

Retorque bolts As needed

Replace shaft/shaft sleeves As needed

2-32
Table 2.24 Plant B CCV valve PH actions

PR Practice Frequency

Replace packing As needed

Replace Gaskets/Seals As needed

Replace torque/limit switches As needed

Realign operator As needed

Lubricate moving parts As needed

Retorque bolts As needed

Table 2.25 Plant B CCW heat exchanger PH activities

PH Practice Frequency

Clean tubes As needed

Replace gaskets As needed

Plug cracked/thinned tubes As needed

Retorque bolts As needed

2.3.4 Plant B Corrective Maintenance Activities

The corrective maintenance events for the CCW system of plant B were analyzed

to determine the effectiveness of the plant's monitoring and maintenance

programs. Plant records covering three years from July 1986 to June 1989 were

reviewed, and a total of 72 CM events were recorded. The results were sorted

and tabulated to identify problem areas.

The data analysis, identified the components most frequently requiring CM.

As shown in Figure 2.14, valves required the most CM. (58%), followed by

instrumentation and controls (24X). This is consistent with the findings from

plant A and, again, is attributable to population effects. Pumps (15%) also

contributed a significant number of CMs, while heat exchangers (1%) and piping

(1%) accounted for a very small portion.

Examination of the valve CMs (42 events) shows that manual valves account for

the majority reported (48%), followed by air-operated valves (33%) and motoroperated valves (12%), as shown in Figure 2.15. Check valves (5%) and solenoid

valves (1%) accounted for a very small portion of the valve CMs. These findings

are also consistent with those for plant A. Since the population of manual

valves in the CCW system is much higher than that of other valve types, these

findings are understandable. They do not, by themselves, indicate that manual

valve maintenance and monitoring practices are ineffective.

2-33
- -

TOTAL CM EVENTS = nae ouM

50x _ .l................................... .......................... ..................................

40% . ... ............................................................................

30%4 .. ...........................................................................

2c04 .l..... | ---.......... ................................

VALVES I&C PLUPS HX PIPE

COMPONENT

TOTAL m AG ING

Figure 2.14 Plant B corrective maintenance events

To better understand the reasons for the manual valve Cls (20 events), the

data were sorted to identify the failure modes. As shown in Figure 2.16, the

most common failure mode for the manual valves was a broken or missing handwheel

(35%). This type of failure is clearly not related to aging of the valve, and

is in contrast to the most common failure mode for plant A's manual valves,

which was packing leaks. The second most common failure mode was broken stems,

which also is not aging related. The most common aging related failure mode was

packing leaks, however, they accounted for only 15% of the manual valve CMs.

Therefore, plant B has fewer failures of manual valves caused by aging

degradation than plant A. This could be attributable to better maintenance and

monitoring, less severe operational environments, better materials of

construction, or a combination of these factors. It should be noted that the

low percentage of packing leaks in plant B could be due to unreported

adjustments of packing nuts. This could not be determined from the information

available.

The failure modes for MOVs and AOVs were also identified from the data (19

events), the most common being failure of the limit switches (37%), followed by

failure to open or close (16%), as shown in Figure 2.17. No failures due to

packing leaks were reported during the three-year period examined, which is in

2-34
TOTAL VALVE CM EVENTS

50%

40X _ ...............................................................................

10% 20% i.... .... ............................... . . . . . . . .

MANUAL AOV YOV CHECK SOV RELIEF

COMPONENT

Figure 2.15 Plant B valve types requiring CH

contrast to the failure modes for plant A, where packing leaks were the

predominant failure mode for MOVs and AOVs. This difference is not attributable

to any special ISM&M techniques for valve packing, since none is-used at plant

B.

The component category ranking second in CM frequency is instrumentation and

controls (17 events). In that category, temperature; and flow controllers

accounted for the predominant number of Cts (Figure 2.18), followed by

indicators (24%), and transmitters (18%). These results differ from those of

plant A where indicators accounted for 73% of the I&C CM events. For plant B,

the most common I&C failure mode is incorrecttreading (41%), followed by fitting

leaks (23%), as shown in Figure 2.19. Again, no special ISM&M techniques are

used at plant B which would account for this.

As for plant A, few pump failures were found for plant B (11 events).

However, since the CCW pumps are an important component for system availability,

the failure modes were identified. The most common pump failure modes were

leakage of the water and oil seals, and leakage of the gaskets (Figure 2.20).

These are typical pump failure modes and are consistent with the findings'from

plant A.

2-35
FAILURE MODE

HANDWHEEL BROKEN

STEM BENT/BROKEN

PACKING LEAK

BINDING

SEAT LEAKAGE

CLOGGED

FITTING LEAK

0% 5% 10% 15% 20% 25% 30% 35%

TOTAL MANUAL VALVE FAILURES

Figure 2.16 Plant B manual valve failure modes

2.3.5 Summary of Plant B Findings

The maintenance and monitoring practices at plants A and B are very similar,

with the exception of the performance frequencies. At plant B, many of the

maintenance actions are not scheduled periodically, but are performed only on an

as-needed basis. For example, the CCW pumps are overhauled only if their

performance degrades to an unacceptable level. At plant A, however, at least

one CCW pump is overhauled every refueling outage, whether its performance is

unacceptable or not.

As was found for plant A, the monitoring and maintenance practices for plant

B do not include practices to address long-term aging. For example, there is no

mechanism to measure and trend pipe wall thicknesses nor valve/pump casing

thicknesses. Over many years, corrosion and erosion could reduce wall

thicknesses in critical locations to unacceptable levels. Unless there are

specific techniques to monitor such long-term aging effects, they may never be

manifested until they result in a catastrophic component failure. This common

weakness in the maintenance and monitoring programs at both plants should be

addressed, particularly if extending the operating life of the plant is being

considered.

2-36
FAILURE MODE

LIMIT SWITCH FAILED

WILL NOT OPEN/CLOSE

SEAT LEAKAGE

AIR DIAPHRAM LEAK

INDICATOR BROKEN

GASKET LEAK

BINDING

0% 10% 20% 30%

TOTAL AOV/MOV FAILURES

40%

Figure 2.17 Plant B AOV and NOV failure modes

In discussing the data analysis for the survey, as well as for plants A and

B, recommendations have been made for increased maintenance in some areas. For

example, some of the data indicated that increased adjustment or replacement of

valve packing might be beneficial. In each case, it is assumed that the

maintenance would be performed correctly. However, it should be noted that

there is some probability that maintenance could be performed incorrectly and

lead to a failure that may not have occurred. This should be considered when

increasing maintenance frequencies.

2-37
TOTAL I&C FAILURES

45%

40%

35%

30%

25%

20%

15%

10%

5%

0%

_ ~~~.. ... ......... .. ... ... ... .... ............ .. .......... .... .. ..... .. .......................

CONTROLL ERS I ND ICATOR TANNhI TTERS RELAYS RADI ArION K3N I TOS

I &C TYPE

Figure 2.18 Plant B I&C components requiring CM

FAILURE MODE

Is

INCORRECT READING

FITTINGS LEAK

BROKEN FACE GLASS

SPURIOUS ALARM

I : * :I : :

i I i i ! i I . . . . . l.

0% 5% 10% 15% 20% 25% 30% 35% 40% 45%

TOTAL I&C FAILURES

Figure 2.19 Plant B I&C component failure modes

2-38
FAILURE MODE

WATER SEAL LEAK

OIL SEAL LEAK

GASKET LEAK

CASING CRACK

MOTOR BURN OUT

0% 5X 10% 15% 20%

TOTAL PUMP FAILURES

Figure 2.20 Plant B pump failure modes

I.

25% 30%

2-39
3. EVALUATION OF COMPONENT MATERIALS

The materials used to construct the various components in the CCW system

influence the type and degree of aging degradation. For example, some materials

may be less susceptible to corrosion in a particular environment; therefore,

their use could help mitigate failures due to corrosion. An understanding of

the various materials used can also help determine the extent and frequency of

inspections and maintenance actions required. Since material selection plays

such an important role in managing aging, this subject was reviewed for the

major components in the CCW system. Information was obtained from the data and

literature reported by utilities, as well as from various manufacturers and

vendors.

3.1 Heat Exchangers

Heat exchangers are one of the primary components in the CCW system, and

are prone to aging degradation. In this section, the materials used to

construct the heat exchangers for the CCW system are presented, and their

susceptibility to aging degradation is discussed.

3.1.1 Description

Most CCW heat exchangers in use are of the horizontal shell and tube type

with straight tubes (Figure 3.1). The major parts of the heat exchanger are the

shell, the channel/bonnet heads, the tube bundle, the tubesheet, and the

baffles. Although designs vary greatly among plants, the specifications for a

typical horizontal shell and tube CCW heat exchanger are as follows:11

Number of Tubes: 3,389 straight tubes

Shell Diameter: 68 in

Overall Length: 75 ft

Tube Diameter: 0.75 in

Tube Thickness: 18 BWG AVG

Tube Length: 64 ft

Tubeside Design Velocity: 3 ft/sec

CCW flow is typically on the shell side of the heat exchanger, while

service water flow is on the tube side. This arrangement facilitates cleaning

out any debris introduced by the service water, which is usually seawater,

brackish water, or fresh water from a river or lake. The material used for the

shell is usually carbon steel, while the tube material varies, depending on the

service conditions. Table 3.1 shows the typical shell and straight tube heat

exchanger design conditions for the three main PWR vendors.'2

3.1.2 Heat Exchanger Materials

Materials of construction are primarily chosen based on expected service

conditions, which include low susceptibility to corrosion and erosion, good

weldability, and high thermal conductivity. For tube bundles and tube sheets,

which are exposed to the harsh environment of service water, the most common

materials are the admiralty metals, brass, bronze, and copper-nickel (Figure

3.2). Each material is briefly discussed in the following paragraphs.

3-1
I

shell Inlet tube outlet

head tubesheet

tube bundle

shell

IV

A

4 .1

Zoe I I

ed

byl

baf'f Ies

lI

tube Inlet shell outlet

Figure 3.1

Copper-Nickel 31%

Typical shell and tube heat exchanger

Brass/ Bronze/

Admiralty Metals 33%

Copper 4%

Aluminum 6%

Stainless Steel 13%

Carbon Steel 13%

Figure 3.2 Heat exchanger tube and tubesheet materials (NPRDS 1974 to 1987)

3-2
Table 3.1 Typical CCW heat exchanger design conditions12

Tube Side Shell Side

Reactor

Vendor Press Temp No. Press Temp No.

l(psig) (Deg F) Passes (psig) (Deg F)_Passes

Babcock &

Wilcox 100 125 1 150 150 1

Combustion

Engineering 150 200 1 150 200 1

Westinghouse

150 200 1 150 200 1

Carbon steels:

Carbon steels are widely used for shells, heads, baffles, and tie-rods.

They also can be *used for tubesheets and tubes under mild operating

conditions. The main advantages of carbon steels are low cost and high

strength. However, their corrosion resistance is not high in seawater

nor in untreated water. If carbon steels are to be used in these

environments, protective measures are needed, such as 'cathodic protection

or coatings.

Copper alloys:

Copper alloys are widely used in heat exchangers because of their high

corrosion resistance, high thermal conductivity, and high resistance to

fouling. A number of alloys are available which combine copper with

zinc, aluminum, iron, 'nickel, and other elements in -varying -degrees.

Some of the more commonly used copper alloys are discussed below 13.

Admiralty metals:

Admiralty metals are composed primarily of copper (71%) and zinc (28%),

with small amounts'of tin (1%), and trace amounts (0.02 to 0.06%) of

arsenic, antimony, or phosphorus. They have good corrosion resistance in

fresh, salt or brackish water, and are used for heat exchanger tubes.

Admiralty metals were developed to improve dezincification resistance by

adding 1% tin to brass; the presence of arsenic, antimony, or phosphorus

increases dezincification resistance further. Dezincification is a form

of selective leaching of zinc from the alloy, which is a common

degradation mode for brass.

3-3
Aluminum brass:

Aluminum brass is composed of copper (77.5%), zinc (20.5%), aluminum (2%)

and arsenic (0.06%). This metal has good resistance to erosion from the

action of high velocity salt and brackish water. Tubes of this alloy are

frequently recommended for power stations where cooling water velocities

are high and where admiralty metal tubes have failed because of

impingement attack.

Aluminum bronze:

Aluminum bronze is composed of copper (91%) and aluminum (7%), with small

amounts of iron (2.5%) and tin (0.5%). Silicon can be substituted for

iron and tin. Aluminum bronzes are used for service in potable water,

brackish water, or in seawater. This alloy resists oxidation and

impingement corrosion because of the aluminum in the surface film. Tube

sheets made of this alloy have been specified for coastal power stations.

Copper-Nickel (10%):

Copper nickel 10% is composed of copper (88.7%), iron (1.3%), and nickel

(10%). This alloy has excellent resistance to corrosion and impingement

attack.

Copper-Nickel (30%):

This copper-nickel alloy is composed of copper (70%), iron (0.6%), and

nickel (30%). It also has excellent corrosion resistance, and the best

impingement attack resistance. The 30% nickel alloy is used by US Navy

for most shipboard condensers and heat exchangers.

Stainless steels:

Stainless steels have very good resistance to general corrosion and

erosion, however, they are susceptible to pitting in stagnant water and

stress-corrosion cracking in a chloride environment. The popular Type

304 stainless steel has a sensitization problem when welded without

special precautions. For heat exchangers, a large amount of welding is

required, therefore, Type 304 stainless steel is not a good choice.

Instead, Type 304L, Type 347, or Type 321 stainless steel, which are less

sensitive to welding, are used.

Titanium:

Titanium is probably the best material to construct heat exchangers from

the standpoint of its properties. However, its use has been limited by

high cost. Nevertheless, chemical plants are increasingly using this

metal in heat exchangers since the extra cost can be justified by the

increased life. The only disadvantage of titanium is its susceptiblilty

to crevice corrosion in a chloride solution at temperatures above 1750F.

3-4
However, this disadvantage can be mitigated by proper design and

precautions.

The susceptibility to various aging mechanisms for each of the materials

discussed above is summarized in Table 3.2, which shows the performance rating

of each alloy, on a scale of 1 to 10 (10 being excellent), based on its

resistance to the failure mechanism specified. The information in this table is

extracted from References 12 and 13, and is presented for comparison purposes

only.

Table 3.2 Performance Ratings of Heat Exchanger Materials

BesistAnce to Aging Hb4c.an.sm (1-oor _10-Ecellent)

Material1T I that r~~elemral -Strcss | rosion Pittin-| Pitting |Chl ride | -wa

Corrosion Corrosion (operatlon) s tag Attack Attack

Copper 5 N/A 3 NIA N/A N/A I/A

Admiralty : 3 5 8 5 7 5

Metals

Aluninui 7 3 6 8 5 8 5

Brass

Aluminunm SI/A 7 8 IN/A /A /IA

Bronze

Copper 8 10 e0 9 10 a

Nickel-202:

Copper 9 9 9 8 9 9

Nickel-302 _

Stainless 3 10 8 3 3 10

Steel _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

Titanium 10 10 10 10 10 10 10

* NIA Not Available

3.1.3 Heat Exchanger Aging Mechanisms

The heat exchanger subcomponents that are most prone to failures are the

tubes, tubesheets and channel/bonnet heads. Among these, tubes are reported to

fail most frequently. Tube failures can be categorized into two major modes;

blockage and leakage. Blockage of tubes can be caused by aging mechanisms, such

as fouling, or non-aging mechanisms, such as clams. Leakage is primarily due to

aging mechanisms, such as corrosion, erosion, and wear.

3-5
3.1.3.1 Fouling

Fouling can be categorized into two major types; macrofouling and

microfouling. Macrofouling is the accumulation of solid materials on the inside

surface of the tubes and on the tube sheets. It is caused by clams, seaweed,

mud, sand, silt, and other debris which are typically entrained in the service

water. 40 .41,4 Very often macrofouling causes blockage of the tubes, which

increases the pressure drop across the heat exchanger, and in addition, reduces

the available heat transfer surface area. It also induces crevice corrosion of

the tubes and tube sheets, which occurs under debris deposits. Usually, regular

maintenance to clean the tubes and the tubesheets is employed to minimize the

effects of macrofouling (see section 3.1.4.5 for detailed discussion of

cleaning).

Microfouling is the multiplication and accumulation of microorganisms on

the inside surfaces of heat exchangers that causes microbiologically induced

corrosion, MIC.43 Although some details are disputed, the mechanisms for MIC

are generally understood. Microbes do not attack metals directly, but microbial

activity induces corrosion in several ways. One way is by forming "living

crevices', which lead to crevice corrosion. In addition, microbial activity

produces corrosive agents, such as organic acids, mineral acids, ammonia, or

hydrogen sulfide. It also interferes with the cathodic half-cell reaction,

which increases corrosion rate, and promotes the oxidation of metal anions to

less soluble forms. Microbial activity also induces the destruction of

protective coatings.

Although copper alloys are very resistant to MIC, failures of such heat

exchanger tubes due to MIC still occur1 ' 5. Stainless steel is also susceptible

to MIC1O. One of the necessary conditions for MIC to manifest itself is a low

flow rate or stagnant condition. The periods when the CCW heat exchangers are

most susceptible to MIC are during preoperational testing and standby operation,

when the heat exchangers can experience stagnant conditions. Also, inadequate

lay-up and improper draining procedures can provide the necessary conditions for

MIC to occur. As an example, one utility reported retubing of the CCW heat

exchangers after preoperational testing was completed, but. a subsequent

inspection revealed pitting underneath light green tubercles"1. It is suspected

that the pitting was caused by MIC, even though the utility did not discuss MIC

as a root cause for the failures.

3.1.3.2 Corrosion, Erosion, and Wear

Aside from fouling, aging of a heat exchanger can also take the form of

general thinning and localized failures (such as pitting, crevice corrosion) of

its various subcomponents. General thinning of the tube sheets andtubes is

caused by corrosion from electrochemical reactions, wear from mechanical

rubbing, or erosion from high-velocity fluid and/or suspended particles in the

liquid stream. Corrosion due to electrochemical reactions, and erosion are the

main causes of thinning for channel/bonnet heads and tubesheets, which must

operate in service water. Since the CCW water is treated, corrosion of the

shell and baffles is of less concern, although they are not immune to corrosion

related failures.

3-6
Localized failures are typically caused by crevice corrosion or by other

localized corrosion, such as pitting, stress-corrosion cracking, and

intergranular corrosion. Most heat exchanger materials are susceptible to

crevice corrosion, which starts underneath deposits of foreign solid materials,

such as sand, mud, and silt.

3.1.4 Failure Prevention and Mitigation

It is very important from a safety standpoint to prevent unexpected

failures, and to assure continued operation of the CCW heat exchangers. The

first, and possibly most important stepsin preventing failure is to select the

proper construction materials, which must be well suited to the operating

conditions and environment in which they will operate. When the proper

materials are selected, there are several methods that can be employed to

increase the service life and prevent premature failures of the heat exchangers.

Most of these methods are applicable to new or operating heat exchanger systems.

3.1.4.1 Coolant Water Treatment

In most cases, chlorine is used to treat service water, since it is

typically supplied by a nearby river or ocean. The CCW water is usually treated

with chemical inhibitors to minimize corrosion on the shell side. Chemical

inhibitors may be classified into three types't; adsorption, scavengers, and

oxidizers. The adsorption inhibitors are generally organic compounds, which

adsorb onto the metal surfaces and suppress anodic and/or cathodic reactions.

Scavengers inhibit corrosion by removing oxygen from the coolant; one example is

sodium sulfite (Na2SO3). Oxidizers are used for metals which show activepassive transitions, such as carbon steels and stainless steels. These inhibit

corrosion by raising the corrosion potential of the metal above the transition

potential, so that the metal surface stays in a passive state. The most popular

oxidizer, is chromate.

In most CCW systems, the coolant has been treated with potassium chromate

to protect the shell and baffles, which are made of carbon steel. However, due

to environmental concerns regarding chromates, many utilities are now searching

for alternative corrosion inhibitors. Some have already instituted

alternatives'8, such as sodium molybdate, sodium tolyltriazole, sodium nitrite,

sodium borate, and hydrazine. Estimates indicate that approximately half of the

operating PWRs use chromates, while the other half use chromate alternatives.

3.1.4.2 -Cathodic Protection

Metallic components can be protected from corrosion by making them

cathodes, which means that only cathodic reactions occur on the surfaces of

these components. Protection can be achieved either by passing a dc current

through the component, or by installing sacrificial anodes into the component.

Installing zinc sacrificial anodes is the more popular method for heat

exchangers. These are used to protect channel/bonnet heads and tubes made of

carbon steels, as well as tube sheets and tubes made of aluminum bronze,

aluminum brass, or admiralty metal.

3-7
A common problem with sacrificial anodes is that they separate from the

protected surfaces. Loose anodes may damage the tubes and other parts of the

heat exchanger as they are carried around by the flowing service water.

3.1.4.3 Coatings and Linings

The parts of the heat exchanger that are not critical to the heat

transfer process, such as channel/bonnet heads and tube sheets, may be coated

with a protective coating. The most common coating is an epoxy, although PVC

liners have also been used to protect channel/bonnet heads. The coatings and

linings are susceptible to erosion, and they should be regularly inspected.

These coatings must be properly applied, or they can fail and cause flow

blockages in the system.*2

3.1.4.4 MIC Prevention

The CCW heat exchangers are susceptible to MIC during construction,

preoperational testing, and lay-up periods. The following recommendations were

made by EPRI as ways to prevent MIC1 5:

1. Clean debris and dirt during and after construction or retubing.

2. Drain the system of all water and dry it during construction.

3. Hydrotest the system with clean water and use a biocide treatment.

It is also recommended that optimum rotation schedules be developed to

prevent prolonged standby periods during which MIC can occur. MIC of the

operating heat exchangers also may be prevented or minimized by conducting

proper preventive maintenance, as discussed in the next section.

3.1.4.5 Preventive Maintenance

Early detection and correction of problems can minimize the frequency of

failures and prolong the service life of components. This can be accomplished

through proper maintenance, which should include periodic cleaning of tubes, and

inspection of all seals.

The inside of the tubes may be cleaned mechanically and/or chemically.

Chemical methods use a solvent to dissolve deposits, usually followed by

flushing with water. Mechanical methods used to clean the inside of the tubes

include a high-velocity water flush (hydroblasting) using a 5,000 - 10,000 psi

water jet, cleaning with a long wire brush, and in extreme cases, using cutting

tools to remove hard deposits. Frequent cleaning of the tube insides will

minimize fouling problems and crevice corrosion, and enhance the efficiency of

a system. However, the wear on the tubes caused by cleaning should be

considered, and an optimum maintenance schedule should be developed based on

operation and performance data.

The prevention/mitigation methods for each aging mechanism are summarized

in Table 3.3.

3-8
Table 3.3 Prevention/mitigation measures for heat exchanger aging mechanisms

Aging Mechanism Prevention/Mitugatlom Advantages Disadvantages

l________ Measure

Macrofouling Regular cleaning Restores efficiency Tube wall thinning

Microfouling Regular cleaning Reduces MIC Tube wall thinning

Proper drain and layup Reduces MIC gone

after preoperational

tests

Corrosion Coolant water treatment Prevents corrosion on shell None

side

Cathodic protection Prevents corrosion of Not practical for tubes

tubesheet and channel head

Regular cleaning Reduces crevice corrosion Increased tube wear

Coatings and linings Prevents corrosion of Not practical for tubes

tubesheet and channel head

Erosion minimize flow rates Mitigates erosion Too-low a flow degrades

degradation eat transfer, and allows

tubericle growth and

__icrofouling

Wear Develop optimum cleaning Reduces wear from mechanical lone

schedule cleaning

3.1.5 Findings for Heat Exchangers

A variety of materials can be used to construct heat exchangers. Each material has a different resistance to the various aging mechanisms; therefore, the

material should be selected to match the conditions under which it will operate.

This will help to minimize failures and improve the system's performance.

The most common form of heat exchanger failure is leakage of the tubes, which

is caused by corrosion, erosion, and wear. In most cases, the corrective action

for these failures involves plugging the leaky tubes, which is a temporary

solution that reduces heat transfer capability. When an excessive number of

tubes are plugged, an entire retubing of the heat exchanger is required.

There are various methods to prolong the service life of a heat exchanger,

and prevent unexpected, premature failures. These methods include installing a

cathodic protection system, applying a protective coating or liner,, and

replacing the failure susceptible parts with those made of materials that

perform better in the particular operating environment.

3.27.- Valves

As reported in NUREG/CR-5052, valves are the most commonly failed components

in the CCW system. This can be partially attributed to their relatively large

population, as compared to other components in the system. However, they are

also susceptible to aging, 'which is a significant cause of most valve failures.

3-9
The most common failure mode is leakage, including internal leakage through the

valve seats, and external leakage through gaskets and packing seals. In this

section, the aging of valves is discussed, emphasizing the evaluation of

different materials used in valve construction and the effect of aging on them.

3.2.1 Description of Valves

There are several different types of valves used in the CCW system, including

gate valves, globe valves, butterfly valves, and swing check valves. These can

be further categorized into functional types, such as isolation valves, throttle

valves, check valves, or pressure-relief valves. The isolation valves and the

throttling valves can be controlled either by valve operators, which permit

remote operation of the valve, or by handwheels, which must be operated

manually.

Although the designs of the various valve types differ, there are certain

basic subcomponents that are common to all valves. As shown in Figure 3.3, the

common subcomponents include the body, the stem, the seat, the disk, the stem

packing, and various gaskets and seals. Special trim material is usually

attached to the valve seat to provide special flow or sealing capabilities.

Degradation of any one of these subcomponents can affect performance and lead to

failure of the valve.

Figure 3.3 Typical valve subcomponents

3.2.2 Valve Materials and Aging Susceptibility

The valve body is a pressure containment subcomponent. Therefore, the

material selected for it is dependent on operating pressure and temperature,

along with the corrosive and erosive properties of the fluid media. In the

NPRDS data reviewed, carbon steel (75%) and stainless steel (21%) accounted for

most valve body materials. Carbon steel is strong and economical, which makes

3-10
it a popular valve body material. The corrosive resistance of.carbon steel is

not as good as that of stainless steel and-other more expensive alloys; however,

in the chemically treated CCW water, this is not a major concern. Corrosion of

the body materials is more problematic for relief valves because the fluid

inside the valves is stagnant. Therefore, a more corrosion resistant material,

such as stainless steel, might be used.

Failures caused by corrosion-of the valve body were not reported in the data

reviewed for this analysis. However, this does not indicate that such failures

will not occur in the future. After many years of corrosion and wall thinning,

it is possible that a valve body may fail. This should be considered as part of

a plant life extension program, and valve body' wall thicknesses should be

monitored.

The valve trim parts are usually made -of more noble metals (e.g., stainless

steel), and-are protected from corrosion at the expense of the body due to the

galvanic coupling. However, corrosion of the valve body does affect the valve

trim. As the body corrodes, the corrosion products deposit on the surfaces of

trim, causing improper seating. This, in turn, leads to abnormal wear and

leakage through the valve seat. The corrosion products also cause other valve

problems, such as dirty internals and crevice corrosion. The selection of trim

materials depends on flow, characteristics 'and fluid conditions, such as

temperature, corrosiveness, and erosiveness. Some of the applications of common

trim materials are shown in Table 3.410.

Table 3.4 Valve trim materials19

Material Service Fluids Service Environment

Mild Service: Mild Service:

-Bronze - water - non-erosive

- air - non-corrosive

- gas - - low pressure drop

- -. -saturated steam

Stainless Steel General Service: General Service:

- Type 316 - steam - corrosive -

- water' - non-erosive

- oil - moderate pressure drop

Stainless Steel Severe Service: Severe Service:

- Type 410 - all fluids ' - corrosive

- 17-4 PH '' --erosive -

- high pressure drop

Stellite

Butterfly valves used for isolation are usually equipped with a liner on

their seat. The liner is typically made of an elastomer material, and provides

good sealing for the valve. The requirements for a good liner material are

temperature stability, abrasion resistance, swelling resistance, and tear

3-11
resistance. These liners are vulnerable to aging degradation, and any

deterioration could lead to leakage through the valve seat. Table 3.5 shows the

performance characteristics for some of the common elastomer seat materials20.

Table 3.5 Characteristics of elastomer liners20

1 emperature ______ _ _____Resist~ance to

mtebrial limt

(Degrees _)Abrasion Cali Licat Water Tearing

Bung 1 1 to to 180 Good Fair Excsllznt Excellent Fi

Nordel -30 to 250 Excellent Fair to Good Poor Very Good Good

VLton -10 to 400 Good Poor Very Good Very Good Fair

Neoprene 0 to 175 Zxcallent Good Good Fair to Good Fair to Good

* Indicates ability to withstand swelling

Many failures of butterfly valves are due to aging of the rubber seat

materials, which takes the form of tearing and hardening of the seat.

Hardening, in turn, causes increased friction, which further increases wear. In

one utility, actuator failures were reported due to increased frictional forces.

The problem was mitigated by resetting the opening torque switches to allow

maximum torque. This problem also raised concerns related to undersized

actuators, which prompted the NRC to issue information notices 88-94 and 90-21,

and generic letter 89-10 (see Section 5.3.3).

Packing leaks are a common problem with all types of valves. Valve packing

prevents the process fluid from leaking up through the area where the valve stem

passes through the valve bonnet. The packing is placed in a stuffing box, and

a packing follower and gland are inserted on top of it (Figure 3.3). By

tightening down on the packing gland, the packing material is squeezed up

against the valve stem and provides a seal. As the valve is operated, the

movement of the stem against the packing causes wear of the packing material,

which can eventually lead to deterioration and leakage. Therefore, the packing

gland must be adjusted periodically to maintain a good seal. When the packing

has worn to the point that gland adjustment can no longer provide a good seal,

the packing must be replaced.

In the past, asbestos was used as a packing material; it was relatively

inexpensive and provided good sealing properties. However, due to environmental

concerns, it is being replaced with new asbestos-free packings, such as PTFE

packings, Aramid/PTFE packings, and graphite packings. Among these, graphite is

the most popular and best performing packing material.

There are three different types of graphite packing rings that are

commercially available21; laminated graphite rings, graphite ribbon rings, and

braided graphite rings. Laminated graphite rings are made up of many thin,

washerlike sheets of laminated graphite. Rings made from graphite ribbon are

formed by winding the ribbon around a mandrel the same size as the valve stem,

until the ring is large enough to fit loosely inside the packing box. Pressure

3-12
VALVE STEM

4i PACK P ING GLAND

Figure 3.4 Typical valve packing arrangement

then is applied~to the two sides of the foil to compress it into an accordionlike strucVture. Braided graphite filament rings are graphite filaments braided

into a rope-;likestructure. The braid'is cut to the proper length to make one

turn around the valve stem. Pressure forces the-two ends together.

In addition to the material used, the method of installation can influence

the life, expecitancy of-valve packing. In a recent study91 it Was Shown that an

optimum arrangement of graphite packing rings can dramatically improve the

performance of the packing. When only graphite ribbon-wound rings are used as

valve' packing, tiransifer .of graphite particles occurs and causes leakage

(graphite particle transfer is a process which removes particles of graphite

from the packing ring and deposits them on the polished stem surface). The stem

surface becomes rough and causes wear of the packing rings, which results in

leakage.

Packing rings made of braided graphite filament do not show particle

transfer. Furthermore, they are an excellent clean-up material for the

particles transferred from the laminated or ribbon rings. By installing a

combination of the two types of packing rings-, a dramatic improvement in life

expectancy is achieved. testresults pThe on-the different combinations of

3-13
laminated, ribbon, and braided graphite rings are shown in Figure 3.521: the

improvement in life expectancy with leak-free performance is dramatic when the

optimum combination is used.

5

4

3

2

1

0

LEAK RATE (CC/HP)

LAMINATED GRAPHITE

< 800 CYCLES TO EXCEED 1 CC/HR

_.1 ,;t............................................. ........................................

RIBBON GRAPHITE

|| i800 CYCLES TO EXCEED i CC/HR

LAMINATED/BRAIDED GRAPHITE COMBINATION

50 000 CYCLES TO EXCEED I CC/HR

RIBBON/BRAIDED GRAPHITE COMBINATION

25,000 CYCLES TO EXCEED 1 CC/HR

I I . I I

0 5 10 15 20 25 30

CYCLES CThousands)

35 40. 45 50

Figure 3.5 Life expectancy of packing materials2 1

Other common aging mechanisms for valve packing are wear and deterioration.

Wear occurs as the valve stem moves relative to the packing, which causes

frictional forces to act on the packing material, leading to a removal of

material at the surface. In addition, the frictional forces produce heat, which

can cause hardening of the packing surface. Both processes reduce the packings

ability to provide a good seal. Further deterioration of the packing occurs if

it is exposed to extreme environments, such as high pressures and temperatures,

or caustic process fluids. Therefore, packing materials used in severe

environments should be inspected and adjusted more frequently. Severe

environments are typically not a concern in the CCW system.

3.2.3 Findings for Valves

The evaluation of valve construction materials produced the following

findings:

- The severity of valve aging mechanisms is strongly influenced by the

materials used. There are a variety of different materials available,

providing an assortment of properties. Selection of the best material

depends on many factors, including service conditions.

3-14
- Even though failures have not been reported, valve bodies are

susceptible to aging degradation which can lead to failure after long

periods of time. Therefore, valve bodies'should 'receive increased

attention in a plant'life extension programni

- In addition to selecting the best valve packing material for the service

environment, the method of installation can also be important.

Combinations of different packings can improve life expectancy.

3.3 Valve Operator

Another significant contributor to valve failures is the valve operator,

which consists of an actuator and various accessories. A valve operator is used

on any valve which must be operated from a remote location, such as the control

room. In this section, the materials used for constructing valve operators, and

their associated aging mechanisms will be reviewed.

3.3.1 Description of Valve Operators

The function of a valve operator is to remotely move a valve stem linearly

or rotationally. The energy source for the operator can be either stored energy

in fluid, such as compressed air, or electric energy. These define the two

basic types of valve operator commonly used in the CCW system; the pneumatically

operated diaphragm type, and the electrically operated motor type.

An air operated valve (AOV) uses a pneumatically operated diaphragm

actuator to remotely position the valve. The operator can be used on isolation

valves, where the valve is either completely open or completely closed, or it

can be used on control valves, where the valve may be positioned anywhere

between full open and full closed. The basic operation of the pneumatic

operator is such that a diaphragm is connected to the valve stem and enclosed in

an air tight housing. The injection of compressed air to one side of the

diaphragm creates a force on the valve stem, moving it in one direction. A

combination of return springs and the exhausting of the compressed air cause the

valve to move in the opposite direction. An air regulator and various solenoid

valves control the air flow into the actuator. The actuator also includes

various 0-rings, retainers, and gaskets to prevent air leakage from the system.

A-motor operated valve (MOV) uses an electrically operated valve -actuator.

The main components of-this type of actuator are a motor mounted on'top of'the

valve actuator, along with a gear train and screw assembly, which transmits the

motor's work to the valve stem. 'Kotorizedivalve operators can be used for

isolation'valves or control valves. The disadvantage to this type 'of actuator

is the long stroke time'typically required when used on large valves.

3.3.2 Valve Operator Materials

In pneumatic valve actuators, diaphragms and O-rings are most affected by

aging degradation. When these components deteriorate, the compressed air used

to operate the valve can leak out of the actuator, leading to valve failure.

The failure mode for' the valve would be' classified as a failure to operate,

while that for the valve operator would be leakage.

3-15
Elastomers are normally used to make diaphragms and O-rings. They include

natural rubber and synthetic rubbers. For diaphragms, ,the elastomers are

reinforced with fibers. Figure 3.6 shows some different types of elastomers,

along with their operating temperature range1 . The properties for the

ELASTOMER

Isoprene/Natural . .

Polyurethane .

Butyl/Butadlene

PolysulfIde/Hypalon -

EpichlorohydrIn

Low Temp Nitrite

Neoprene _

High Temp Nitrile _

Polyacrylate _

Ethylene propylene _

Fluorosillcone C

Fluorocarbon

Sililone

_ _ _ I - - - =_

C-

_ :_ _ :_ I

I = -__7=- 

I

=

-100 0 100 200 300 400 500

TEMPERATURE RANGE (DEG. F)

Figure 3.6 Temperature range of elastomer materIals19

elastomers most widely used for diaphragms and O-rings are described below 19 '

22:

Buna N (or Nitrile rubber): Buna N is a copolymer of butadiene and

acrylonitrile. The acrylonitrile content of commercial products varies from 18

to 48%. As the nitrile content increases, resistance to petroleum base oils and

hydrocarbon fuels increases, however, low-temperature flexibility decreases.

Nitrile compounds are superior to most elastomers with regard to compression set

or cold flow, tear, and abrasion resistance. However, they are not very

resistant to ozone and sunlight. Thus, these materials should not be stored

under direct sunlight or near electric motors or other equipment that might

generate ozone.

Neoprene Rubber: Neoprenes are homopolymers of chloroprene. Their broad

temperature range and modest cost make them popular for diaphragms, hose, seals,

gaskets, and automotive V-belts.

Ethylene Propylene Rubber: Ethylene propylene rubber is an elastomer prepared

from ethylene and propylene monomers. It has outstanding resistance to oxygen,

ozone, and heat. Two types of ethylene-propylene copolymers are commercially

3-16
available; ethylene-propylene copolymers (EPM) and ethylene-propylene-diene

terpolymers (EPDM). Ethylene-propylene rubbers are used for gaskets, seals, and

automobile radiator hoses.

Most valve operator manufacturers use neoprene diaphragms reinforced with

fiber glass, cotton, or nylon for normal ambient conditions. For example, one

company makes molded diaphragms of nylon-reinforced oil resistant elastomer.

This diaphragm is described as having a long life at air pressures up to 85 psi.

If the ambient conditions 'exceed 200 OF, higher temperature materials such as

silicones, Viton, or polyacrylics with Dacron or fiberglass fabric may be

used2 0 .

Table 3.6 shows the relative performance of the common elastomers including

those discussed above.23 -The resistance of each material to important aging

mechanisms, such as abrasion, compression set, oxidation, ozone damage, and

swelling by water is presented.

3.3.3 Valve Operator Aging Mechanisms

In many cases, failures- of pneumatic valve -operators are caused by

deterioration of diaphragms and 0-rings, due to: aging degradation of the

elast-omer--material. The degradation that occurs over time relates to the

nature of the rubber molecules, which are long, chainlike structures consisting

of many smaller molecules joined together. At least three principal types of

reaction are responsible for their aging 19'24. They usually occur concurrently,

but in varying degrees,

1. Scission: The molecular bonds are cut, dividing the chain into smaller

segments. Exposure to ozone, ultraviolet light,- and radiation causes

degradation of this type. Excessive scission will result in loss of

material strength and, in extreme cases,-will cause elastomers to become

mushy.

2. Cross-linking: An oxidation process occurs, whereby additional

intermolecular bonds are formed. Exposure to heat and oxygen are

principal causes of this type of degradation. Excessive cross-linking

will result in material hardening and loss of resilience, which leads to

cracking and brittleness.

3. Modification of side groups: A change in the complex, weaker fringe areas

of the molecular structure due to chemical reaction. Moisture is one

factor which can cause this type of degradation, which can result in

changes to the materials strength and durability.

The aging process of air diaphragms is more complex than the simple aging

of elastomers for two reasons; 1) diaphragms are made from composites of

elastomers and fibers, and 2) the diaphragms are exposed to mechanical cyclic

stresses, in addition to chemical degradation. The cyclic stresses cause

fatigue, which is also an aging mechanism.

3-17
Table 3.6 Relative performance of common elastomers2

Raesitanc- to Aging Hachanium

Ej.-t r om Abrasion ICaression Oxidation ozne Radiation Water Stem Gas

se ot - Parneabillty

Natural Excellent Good Good Poor Fair Excellent Poor Poor

Rubber

Styrene Excellent Good Good Fair Good Excellent Poor Fair

Butadiene

Neoprene Excellent Good Good Excellent Fair Good Fair Fair

Nitrile Good Good Fair Poor Fair Good Fair Fair

Hypalon Excellent Fair Excellent Excellent Good Good Good Good

Ethylene Good Fair Good Excellent Poor Good Good Fair

Propylene

Butyl Good Fair Excellent Excellent Poor Excellent Fair Good

Viton Good Good Excellent Excellent Good Good Good Good

Kalres Good Good Excellent Excellent Very Good Good Excel- Good

lent

Silicon* poor Excellent Excellent Excellent Excellent Good Good Good

Polyurethane Excellent Good Excellent Excellent Good Good Poor Good

In addition to the stresses experienced during operation, elastomers also

degrade while they are stored as spare parts. To minimize such degradation, the

following storage conditions are recommended' 0:

1.

2.

3.

4.

5.

6.

Ambient temperature not exceeding 120 OF

Exclusion of air (oxygen) -

Exclusion of contamination

Exclusion of light (particularly sunlight)

Exclusion of ozone-generating electrical devices

Exclusion of radiation

Table 3.7 lists the life expectancy during storage for different elastomers

exposed to ambient conditions'9. As shown, Buna N and natural rubber have a

relatively low resistance, with a storage life of 2 to 5 years. Neoprene and

EPDM have a better resistance, with a storage life of 5 to 10 years. These

rankings are also applicable for the in-use aging resistance, even though they

are strongly affected by the operational environment.

3-18
Table 3.7 Life expectancy during storage of various elastomerszi

Elastaner | - [ CMo or Trade Vm I Expected Lire

Fluorosilicone Silastic LS Up to 20 years

Polyacrylate - Acrylate Up to 20 years

PoLysulfide Thiokol Up to 20 years

Silicon. Silastic. Silicone Up to 20 years

Chlorosulfonated polyethylene Hypalon - - 5 to 10 years

EthyleneIpropylene/diene (EPDK) Ethylene propylene tersolymer 5 to 10 years

Fluorocarbon Fluorel, Viton ' S to 10 years

Isobutylene/isoprene _- utyl. Neoprene, Chloroprene 5 to 10 years

Polyvinyl Chloride - Vinyl Poly 5 to 10 years

Polyurethane Urethane - '5 to 10 years

Butadiene/acrylonitriie K Ritrile, Buna X 5 to 10 years

Butaditneistyrene '- 'una S - 2 to 5 years

Cis Polybutadiene Stereo Polybutadiene 2 to 5 years

Natural Rubber Pale crepe, smoked sheets - 2 to 5 years

3.3.4 Findings for Valve Operators

The review of-valve operators has generated the following findings:

- For pneumatic operators, an important cause of failure is degradation ofthe elastomer materials used to construct the diaphragms and O-rings.

Other failures-involve solenoid valves, positioners, and air regulators.

- Diaphragms 'and 0-rings should be inspected frequently.-and replaced

regularly, with the interval based on past operating data. -

- Storage conditions, as well as operating conditions, are important in

determining the life expectancy of elastomeric components. The storage of

elastomeric parts should follow-the recommendations discussed to providea 'longer life expectancy. -

3.4 PumRs

Pumps are the second most frequently failed component in the CCW system

(Figure 1.2). Since a high percentage of the pump failures are related to

aging, the various subcomponents in the pump are susceptible to aging

degradation. In this section, the materials used for pump construction are

examined and their associated aging processes discussed.

3-19
3.4.1 Description of Pumps

The pumps in CCW systems are motor-driven centrifugal pumps. The number

of pumps in each system ranges from two to eight; however, the most common

configuration uses three pumps. A typical pump has a flow range of 3000 gpm to

10,000 gpm, with a total developed head (TDH) of 150 ft to 225 ft. -The pumps

are driven by either 480 volt or 4160 volt ac electrical power, supplying 400 to

700 horsepower.

Centrifugal type pumps are supplied by several different manufacturers;

however, the design principles are the same. The main components of the pump

include the casing, impeller, shaft, shaft seals, wear rings, bearings, sleeves,

and assorted gaskets and seals. Other accessories are also needed to support

the pumps operation, including a bearing lubrication system. Figure 3.7 shows

a typical horizontal, single-stage, double-suction pump.

In a centrifugal pump, the process fluid is taken into the casing through

the suction or inlet piping. The fluid then enters the center of the rotating

impeller, where centrifugal force drives the fluid out radially from the eye of

the impeller to the volute of the pump at high velocity. Upon exiting the

impeller, the fluid is slowed and the velocity energy is converted into pressure

energy. The fluid then is discharged through the outlet piping to the system.

The pump shaft runs through the casing connecting the impeller with the

motor driving the pump. Typically, it is supported by two bearings. The

inboard bearing is located at the coupling end of the shaft, and provides radial

support for the impeller. The outboard bearing is typically a thrust bearing,

located on the opposite end of the shaft, which provides axial support for the

impeller. The bearings are lubricated by either grease or oil. One common

lubricating system uses a constant level oiler which maintains a constant oil

level in the bearing cavity by gravity.

Sleeves are used to protect the pump shaft from corrosion, erosion, and

wear. They are attached mechanically to the pump shaft, and are replaceable.

Elastomer 0-rings are used between the sleeve and the shaft to protect the shaft

from corrosion.

Wear rings are located between the impeller and casing to protect the

casing from wear due to the constant rotation of the impeller. They also

provide a seal between the high-pressure discharge side of the pump and the lowpressure suction side of the pump. Worn wear rings can be replaced with new

ones. They can be mounted either on the casing or on the impeller, or on both.

3-20
WEAR RINGS

SHAFT SLEEVE NUT

W

r.

PUMP SHAFT

BEARING HOUSING

9 WEAR RINGS 2-11111

PUMP CASING

PUMP CASING

This copyrighted Illustration Is reprinted with permission from the Ingersoll-Rand Company, Phillipsburg, N.J.

Figure 3.7 Typical horizontal single-stage double suction pump
As the pump operates, the shaft seals prevent the process fluid from

leaking around the shaft circumference and out through the pump casing.

Typically, there are two shaft seals; an inboard and an outboard seal on each

end of the pump shaft. In addition, there are oil seals to prevent leakage of

the bearing lubricating oil. These are located on each bearing.

Two types of shaft seals are commonly used on the pumps; mechanical seals

and packing gland seals. Of the two, mechanical seals are the most widely used

because they provide a tight seal while minimizing shaft (or sleeve) wear. As

shown in Figure 3.8, the main parts of the mechanical seal are a stationary

sealing ring, a secondary seal for the stationary ring, a rotating sealing ring,

a secondary seal for the rotating ring, and a spring or bellows to press the two

ring faces together23. The components most prone to failure are the sealing

rings; however, all of the components are susceptible to aging degradation. As

shown in this illustration, the leakage path for mechanical seals is between

surfaces that are perpendicular to the shaft axis. This is in contrast to

packing gland seals, in which the leakage path is parallel to the shaft surface.

ROTOR STATOR

Figure 3.8 Subcomponents of a mechanical seala

3.4.2 Pump Construction Materials

A variety of materials are used to construct the pump subcomponents. In

this section, these materials are discussed and their susceptibility to aging is

evaluated.

3-22
The materials used in constructing a pump must be based on the operating

conditions expected, as well as the properties of the fluid being pumped. Some

of the requirements typical for pump materials are:

1. Corrosion resistance

2. Abrasion/wear resistance

3. Cavitation/erosion resistance.

4. Favorable casting and machining properties

5. High Strength

6. Fatigue resistance

7. Low notch sensitivity

8. Favorable galling characteristics

To meet these requirements, several different combinations of materials may

be used for pump construction. Table 3.8 presents a sample listing of the

materials used26. -

Bronze is widely used for wear rings since it has good resistance to

galling where metal-to-metal contact occurs. Seal ring bodies, spring housings,

and springs are usually made of stainless steel, bronze, or other corrosionresistant materials (e.g., Hastelloy C, titanium)23.- The subcomponents most

susceptible to deterioration are the primary and secondary seals, which prevent

the process fluid from leaking through the seal. Table 3.9 shows some of the

combinations of the materials used for rotating sealing rings (RSR) and

stationary sealing rings (SSR) in a mechanical seal, along with their relative

resistance to wear in water23. Selection of the secondary seal materials is

based on the operating temperatures; Table 3.10 lists some materials used for

secondary seals, along with their temperature limits.

Over 40% of pump failures are due to seal problems (Figure 1.7). Table

3.11 shows the various aging mechanisms that are experienced with seals,- and

their corresponding cause23.- A good maintenance and monitoring program should

check for these aging mechanisms.

Packing is sometimes used on pump shafts in place of mechanical seals. As

for valve packing, asbestos yarns formerly were the standard packing material;

however, they are being replaced by new, non-asbestos materials. The aging

mechanisms for pump packing are similar to those discussed for valve packing

(section 3.2.2). - Some of the newer packing materials being used for pump seals

are the following23 :

PTFE Packing: PTFE packings-have low friction,--and are-chemically inert. The

disadvantages of this material are its low strength, low thermal conductivity,

and tendency to shrink with increasing temperature.

Aramid/PTFE Packing: This material consists of yarns or monofilaments of Kevlar

(aramid fiber from Du Pont) precoated with PTFE dispersant, which are braided

and impregnated with PTFE to make Aramid/PTFE packings. These packings offer

exceptionally long life, low friction, and chemical inertness.

3-23
A Graphite Packing: Graphite fiber packings can be used up to 750 IF, and have a

chemical resistance similar to PTFE. These packings offer low friction and high

thermal conductivity.

Two classes of bearings are used in pump construction; anti-friction

bearings, and sleeve bearings. Bearing construction falls into three main

categories; single metal, bimetal, and trimetal. Single metal bearings are made

of one material, commonly either a copper alloy or an aluminum alloy. Bimetal

and trimetal bearings have one or two surface layers, respectively. The backing

layers for bimetal bearings are made of steel, lead bronze, or aluminum alloy,

while those for trimetal bearings are usually made of steel. The selection of

bearing material is based on the expected operating conditions, and a great deal

of proprietary technology is used to formulate alloys to meet specific

conditions2 7. The materials typically used are leaded or unleaded tin bronze.

Bearing degradation is another major cause of pump problems, accounting for

more than 25% of pump failures (Figure 1.7). Table 3.12 shows the major aging

mechanisms for pump bearings and their associated causes.

Table 3.8 Typical pump construction materials 2

Haterials of Ccstructkm

part 1a Ort my | ~Calmbi ai1 | oatio 2 | mbin tion 3 | C na 4

Casing Cast Iron - Class 301 Carbon St3_lWCB

IrMyller Bronze Alloy 922 Cast Iron-Class 253 Stainless Steel-CFe Cast Iron-Class 25B

Impeller RizBs Sring BronzaStl-ASI 1020 Stainless Steel-CFS Stool-ArSI 1020

Casing Rings Cast Iron - Clas3 303 Stainless St*&l-CPS Cast Iron

Shaft Slew.. Bearing Bronze Steel-AISI CS2iStSS-hIS? 303 Steel-AISI C2215

Shaft Steel-AISI 1045

Seal cages Cast Iron- Class 30B Teflon N/A

Glands Cast Iron-Class 303

Gland Studs Stainless Stoel-AISI 303

Gland Nuts Stainless Steel-AISI 303

Packing Non-Asbestos

Stuffing Box Bushing Ste*L-AISI C1215

Shaft Sleeve Nuts Stainless Steel-AISI 416

Shaft Sleeve 0-Ring Buna-N

Bearing Bodies Cast Iron-Class 303

Dolts Carbon Steel-A307 Grade B

Gaskets NonAsbestos

3-24
Table 3.9 Materials used in mechanical primary seals23

Face MaterialsI

r Wear Resistance

Rotating Sealing Ring Stationary Sealing Ring -

Stainless Steel Carbon Low

Lead Bronze Carbon Low

Alumina Ceramic Carbon Medium

Tungsten Carbide Tungsten Carbide Medium

Stellite Carbon Medium

Chrome Oxide Carbon High

Tungsten Carbide Carbon High

Table 3.10 Materials Used-in Mechanical Secondary Seals 23

Temperature Limits (Degrees U)

Seal material I

High Nitrile Rubber -22 248

Ethylene Propylene Rubber -58 302

Viton Fluoroelastomer -40 482

Kalrex Perfluoroelastomer -58 590

PTFE -148 482

High Temperature Polymers -148 572

Compressed Asbestos Fibre -148 752

Pure Graphite Materials -328 5432

3-25
Table 3.11 Pump seal aging mechanisms and causes2

Seal Cepnent I Aging becshanlua Cause

Primary Seal Face Overall corrosion - Normal operating exposure

_- Harsh environment

Seal face distortion - Operation at high pressures

- Operation at high temperatures

- Excessive swell of secondary seal

- Contamination by foreign material

- Operation at high fluid pressure/velocity

values

- Operation outside design limits

- Loss of seal cooling

Fracture - Excessive thermal streas

- Excessive fluid pressure

- Excessive swell of secondary seal

- Excessive fluid pressure/velocity

values

Edge chipping - Excessive fluid pressure

- Excessive shaft run-out, deflection, or

whip

- Seal facts out of square

- Seal vibration

Severe, uniform - Excessive fluid pressure/velocity values

abrasive wear - Deposition of dissolved solids

- Contamination of cooling fluid

- Excessive shaft end play

- Loss of seal cooling

- Harsh operating environment

Heavy, non-uniform - Contamination of seal cooling fluid

wear, Salling, - Excessive fluid pressure/volocity values

and grooving

Erosion - Contamination of seal cooling fluid

Blistering of carbon

graphite faces

- Excessive or cyclic fluid

limits

- Inadequate seal cooling

pressure/velocity

Secondary Seal Extrusion - Excessive pressure

- Excessive temperature

_ - Excessive swell

Cracking - Excessive temperature

- Chemical attack

- Ozone attack

Cuts, tears, splits - Material operating outside design limits

Corrosion of interface - Crevice corrosion

- Fretting corrosion due to vibration

3-26
Bearings are another subcomponent which are subject to aging degradation

and can cause the pump to fail. Table 3.12 presents the major aging

mechanisms acting on bearings, and.their causes.

Pump-casing failures were not found in the data; however, there is a

potential for casing failures to occur during later years of operation.

Casings are commonly made of cast iron or carbon steel, which are

subject to corrosion and erosion. Over many years of operation, wall

thinning can occur, leading to weakening of the walls and possible

failure. This should be addressed in a life extension program.

K4

3-28
4. SAFETY SYSTEM FUNCTIONAL INSPECTIONS OF CCV

Since 1985 the U.S. Nuclear Regulatory Commission (NRC) has performed Safety

System Functional Inspections (SSFIs) at various nuclear power plants in the

United States. The purpose of these inspections is to evaluate the readiness of

safety systems to perform their design function when called upon. However,

SSFIs can also be useful for evaluating how effectively a plant is managing the

effects of aging. The inspections focus on systems which are critical to plant

safety during normal or emergency conditions. Since they began, the CCW system

has been included in five SSFIs.

As part of this phase II aging analysis, the CCW SSFI reports were examined

to determine if any information related to aging of CCW systems was identified.

The data were categorized to determine what types of problems are most commonly

identified. In addition, the SSFI methodology was evaluated to determine if it

is well suited to identifying aging-related problems. This section presents the

results of these analyses, along with recommendations for improvements in the

SSFI structure to make it more effective at addressing aging concerns.

4.1 SSFI Structure and Methodology

In principle, the SSFI should be well suited for identifying the effects of

aging degradation in systems and components since its goal is to verify that the

system will perform its function when called upon. To achieve this goal, the

SSFI begins by evaluating plant practices in two major areas; maintenance and

surveillance testing. Table 4.1 summarizes the SSFI activities which could

provide useful information for identifying aging problems. For example, during

the system walkdown the components are visually inspected to verify operability.

This inspection can also provide information on component degradation.

Indicators such as water or oil leaks, unusual noise or vibration, surface

corrosion on components, and excessive temperatures provide insight into the

condition of the components and the adequacy of the maintenance practices used.

The review of corrective and preventive maintenance actions also provides

useful information for identifying aging concerns. The corrective maintenance

performed shows what types of failures are most common for each particular component, and whether they recur. This information can be correlated with the

preventive maintenance practices to determine if any modifications are needed to

the program to better control component degradation. By trending the corrective

maintenance data, the failure frequency of the various components can be determined. An increasing failure frequency with age would then indicate that aging

degradation is not being properly controlled and further actions need to be

taken.

The examination of functional test procedures and results gives a good indication of how well a system performs. By comparing the results to a baseline

and trending them over time, the effects of aging degradation on system performance can be determined. Although the system may meet its performance requirements, a decreasing trend will suggest how long various components can remain in

service before they are replaced or overhauled.

4-1
Table 4. 1 SSFI inspection areas and subtasks related to aging

SSFI AREA SUBTASK

Maintenance 1. System Walkdown:

- provides gross determination of equipment

operating condition

2. Review of Corrective Maintenance History.

- identifies equipment with repetitive or frequent

failures

- determines if appropriate root causes were

identified

3. Review of Preventive Maintenance History:

- determines if PM activities are adequate

- determines if PM frequency is adequate

4. Review of Vendor Maintenance Recommendations:

- determines if recommendations have been

appropriately incorporated into plant

maintenance procedures

Surveillance L. Evaluation of Periodic Functional Tests:

Testing - determines if the tests adequately verify the

functional status of the system

2. Evaluation of Test Results:

- determines if the results indicate deterioration

of function

- determines if adequate programs are in place to

l________________ identify and correct such deterioration

The NRC inspection manual for SSFIs28 was reviewed to determine where explicit or implicit methodology for evaluation of system or component aging is described. Table 4.2 lists the sections in the manual and the evaluation methodology, and gives a short discussion of the relationship to detecting or mitigating the effects of aging.

The review of the structure and methodology of the SSFI shows that these

inspections can be useful for evaluating how effectively a plant is managing

aging. The SSFI can identify weaknesses in the plant's maintenance and monitoring techniques and provide insight into what improvements can be made. Therefore, it is recommended that the SSFI be used more extensively to perform evaluations. Some insights provided by past SSFIs are presented in the following

section.

4-2
Table 4.2 Sections of NRC SSFI manual related to aging

Manual Section Description | Relationship to Aging

Section 1__I

ILA Review the design basis requirements for the se- This step in the methodology establishes the

lected system and determine the operating con- baseline from which any aging analysis could

ditions under which each ative component will start.

function during accident or abnormal conditions.

U.B.2 Determine if system modifications implemented This step can identify any new aging stresses imsince initial licensing have introduced any unre- posed on the system due to design modifications.

viewed safety questions. For example, determine if

modified components have been evaluated for environmental equipment qualification considerations, such as temperature, radiation, or humidity.

ILC2 Review the maintenance and test records for the This step provides an evaluation of test and

selected system. Determine if the system compo- maintenance practices as to their effectiveness at

nents are being adequately maintained to ensure detecting and mitigating aging degradation.

their operability under all accident conditions.

I.C.3 Determine the adequacy of the licensee's preven- This step provides an evaluation of PM practices

tive maintenance program. for managing aging.

Hl.E4 Determine if surveillance test procedures compre- This step provides an evaluation of test practices

hensively address required system responses. for detecting aging effects.

II.F Review of operating experience for the selected This step provides a correlation of actual experisystem. ence with failures and component degradation.

II.F.1 Determine the historical reliability of the system This step evaluates the effects of aging on sysand its components based on the review and analy- tem and component reliability.

sis of the operation experience.

II.F.2 Determine if the licensee has aggressively pursued, This step determines if aging has been consididentified, and corrected rmot cause of failures. ered, or identified as a cause of system failures.

I.F.3 Determine the extent of the maintenance backlog This step verifies that procedures are in place to

and ascertain if the licensee has a program to iden- control aging in a timely manner.

tify, prioritize, and perform timely safety-related

maintenance.

4.2 CCW SSFI Findings Related to Aging

To date, five CCW SSFIs have been performed by the U.S. NRC, and 23 items

related to aging of systems and components were identified. This section gives

a brief discussion of some of the more significant findings related to inadequate control of the effects of aging. The results of an SSFI conducted by a

utility are also included to illustrate the types of observations made by a

self-assessment.

4-3
4.2.1 Increasing System Leakage Leads to Potential Inoperability

In one of the plants inspected, the CCW system was designed to be a "zero leakage" system. Because of this design, the makeup system to CCW was not classified as a safety system and was not designed to be seismically qualified. Therefore, in the event of an accident, the makeup system must be assumed to be unavailable. A Final Safety Analysis Report (FSAR), based on a leakage rate of 0.008 gpm for pump seals and valve seat/stem leakage, determined that the CCW system could operate for 122 days without makeup. During operation, problems were experienced with the CCW heat exchangers because marine debris and marine life on the salt-water cooling side of the CCW heat exchanger began to cause leakage and fouling of the heat exchanger tubes. The leakage was calculated to be 0.142 gpm; however, documentation in the plant files indicated that even higher leakage was occurring. With a leakage rate of 0.142 gpm, the CCW system could only operate for seven days before makeup would be required. Since this was unacceptable from a safety standpoint, a temporary makeup system was installed, using a fire truck and hoses, pending installation of a permanent, seismically qualified system.

not 

This incident shows how safety concerns can arise if aging degradation is taken into account in the original design. The original calculation for the leakage rate simply took vendor-listed values for pump seals, and valve stems and seats. The calculation did not take into account component degradation, such 

increased 

as erosion of the heat exchanger tubes, which eventually led to an leakage rate. Also, it did not account for increased pump seal leakoff, internal leakage of the valve due to seat or disk erosion, and increased valve stem leakage due to degradation of the packing. Each of these aging 

properly 

mechanisms is common and should have been anticipated. Therefore, to address aging, its effects must be understood and accounted for, not only in the operation and maintenance of a system, but also in its design.

4.2.2 Design Change Potentially Increases Component Aging Rate

In several plants, the CCW system provides cooling to the reactor coolant pump (RCP). A modification was made at one plant to the isolation valve to the RCP loop to allow jogging control of the actuator. This modification would allow CCW flow to be controlled, thus reducing the potential for thermal shock. In 

the 

the 

fully 

original design, a "seal-in" was provided that caused the valve to go to

operator 

open or fully closed position once activated. In the new design, the

modification 

could jog the valve to intermediate positions. However, the

designed 

did not consider whether the Limitorque valve operator had been

different 

or qualified for jogging service. The SSFI team was concerned that the thermal duty cycle that was imposed on the motor, and the mid-travel operation 

considered 

of any "hammer-blow" features provided with the actuator, were not when the change was made. During the inspection, information was received 

acceptable 

from the manufacturer verifying that the valve actuators were for jogging duty, provided that no more than 20 starts were made for the 15 minute duty rating of the motor.

the 

Although the component was eventually found to be capable of performing in new operating mode, this incident demonstrates how a design change can inadvertently impose new aging stresses on a component. If the valve actuator

4-4
was not capable of performing in jogging service, the design modification could

have led to an increased aging degradation rate and premature failure.

Therefore, design modifications must address the effects of aging.

4.2.3 Potential for Stress Corrosion Cracking Identified

When improved analytical methods were instituted, one utility found that the

chloride content of its CCW water (1.0-1.5 ppm) was much higher than originally

measured by the old method (0.15 ppm). The old method had been used for the

past 11 years of operation under the mistaken belief that the readings were

accurate. The chlorides appeared to originate from the original corrosion

inhibitor used in the system. High chloride levels pose a serious threat of

stress corrosion cracking to stainless steel components. The utility has not

been able to assess the potential stress corrosion damage to the stainless steel

safety-related portions of the CCW system (e.g., RHR heat exchangers, letdown

heat exchangers, and reactor coolant pump thermal barriers).

In this instance, the SSFI uncovered an aging stressor that the plant

operators were unaware of. The many years of operation with this aging

mechanism uncontrolled may have shortened the life of some of the components.

However, now that it has been identified, the problem can be monitored and

controlled to mitigate any future problems.

4.2.4 Undetermined Causes for Calibration Discrepancies

A review of the preventive maintenance calibration records in one plant

revealed that, despite obtaining as-found calibration readings that were beyond

the instruments' acceptability criteria, several safety-related instruments were

calibrated and returned to service without correction. No root-cause analyses

were performed. The history of various out-of-calibration instruments revealed

that deviations had occurred several times before, and some instruments were in

service even after the calibration had exceeded the acceptability criteria.

This is an instance where aging degradation was not detected and controlled

due to inadequate trending and analysis of calibration discrepancies. Ideally,

the root cause of the calibration drift should have been determined and

corrected before the instruments were recalibrated and returned to service.

4.2.5 Untested Check Valves Added to Design

There are numerous check valves in the typical CCW system. During normal

operation, most of these valves are required to perform their two basic

functions, which are to stop flow in one direction while allowing flow in the

opposite direction. For these valves, aging degradation resulting in a failure

to perform either of these functions could be detected any time the system is

operating. However, some check valves in the system only perform one of their

functions during normal operation; the other function may not be required unless

there is an accident. Aging degradation in these valves would be difficult to

detect unless special tests are performed specifically for that purpose.

Consequently, their availability to function is not known and an undetected

failure may exist. One such existing failure, together with a single failure in

a redundant train, could render the CCW system inoperable.

4-5
One SSFI determined that six check valves had been added to the CCW system.

However, they were not added to the surveillance test program. The check valves

were, therefore, vulnerable to aging degradation, which may never have been

detected until an accident condition arose.

4.2.6 Incomplete Procedure for Motor Operation

As part of the SSFI at one plant, the operating procedure for one of the CCW

pump motors was examined. It was found that the procedure did not include the

manufacturer's recommendations for the maximum number of consecutive motor

starts allowed and the required interval between starts. Without this

information, the potential for overheating the motor insulation exists.

Overheating is an aging mechanism that can rapidly reduce the life of the

motor's insulation and lead to premature failure. This incident demonstrates

how the SSFI can help to mitigate aging stresses.

4.2.7 Throttling of Valves Causes Accelerated Aging of Seats

The CCW system design at one plant uses butterfly valves as inlet and outlet

isolation valves on various heat exchangers in the system. During an SSFI on

this CCW system, it was determined that the butterfly valves were being used to

throttle flow to the heat exchangers, which is not what they were designed for.

Discussions between the utility and the valve manufacturer indicated that when

the valve is less than 20 degrees open, the water velocities may increase

substantially and result in cavitation at the valve seat, which would reduce the

expected life of the valve. The manufacturer recommended a formal analysis be

performed to determine if the specific application would cause unacceptable seat

damage.

This is a case where operation of a component outside its design

specification could lead to accelerated aging and premature failure. The SSFI

identified this problem so that the condition could be analyzed and any

potential aging degradation mitigated.

4.2.8 Insights from a Utility Self-Assessment SSFI

In a CCW system SSFI conducted by a utility for self-assessment, several

important observations were made. These observations demonstrate the usefulness

of this type of inspection, as well as the potential areas of vulnerability of

CCW systems in older plants.

One observation was that the CCW system was capable of performing its safety

functions during normal operating conditions. However, from a mechanical design

perspective, it had not been demonstrated that the CCW system could adequately

perform its safety function during postulated emergency conditions. There were

two reasons for this.

The first issue was related to the CCW flow rates to the shutdown cooling

heat exchangers and the containment coolers. The flow rates from the flow

balance test were approximately 25% less than the values assumed in the

containment response analysis for a loss of coolant accident (LOCA). These

flows are critical since CCW is the only means of post accident heat removal

4-6
from the containment. The team pointed out that "...inadequate heat removal

could potentially result in exceeding containment structural design parameters

and/or result in a more severe environment (e.g., temperature, pressure) than

what safety related equipment is qualified for..." This finding raises two

issues appropriate for the aging study:

1. Flow measurements to safety-related components should be periodically

verified, and,

2. The acceptance criteria for system flow capacity tests should be based

on postulated accident conditions, if they are greater than normal

operating values.

The second issue of significance to aging from the self-assessment SSFI

concerns the environmental qualification of the CCW pump motors. The room where

the pump motors were located was determined to be a mild environment, based on

the lack of high energy lines in the immediate vicinity. A maximum temperature

of 110OF was assumed. However, the team found that the room's ambient

temperature could reach 150OF following a loss of the non-safety-related

ventilation. This ventilation system would not be operable during a design

basis LOCA, because it is not automatically loaded onto the emergency bus. The

long-term performance of the CCW pump motors, which remove decay heat, could not

be assured.

There was another observation from the utility SSFI related to aging, but of

lesser significance. The inspection team observed that one of the more

frequently maintained components of the system was the CCW heat exchangers.

Fouling of the tube side from marine growth resulted in the need for periodic

cleaning of the head and hydrolasing of the tubes. Leaking tubes accounted for

more than 10% tube plugging on one of the heat exchangers. Analysis at this

plant indicates that up to 15% plugging can occur before the heat removal

capability is jeopardized. Non-destructive examination (NDE) had noted a marked

increase in degradation of tube wall thickness in the last several years. One

heat exchanger required a re-tubing after 13 years of operation because the 15%

plugging criteria was exceeded.

4.2.9 Summary of SSFI Findings

NRC SSFI reports have been useful in identifying problems in the design,

operation, and maintenance of the CCW system that are related to aging. Some

examples include the following:

- An inadequate makeup supply to the CCW system existed due to a design

assumption of a "zero leakage" system. This failed to address the effects

of aging on pump seals and valve packings.

- The modification of the control logic of an MOV from a seal-in to a jogging

circuit did not consider the additional stresses imposed on the motor.

- Numerous cases of out-of-calibration instrumentation were not analyzed to

determine the root cause. Aging effects, such as calibration drift, were

not detected nor managed satisfactorily.

4-7
Butterfly valves in the CCW system at one plant were being used to throttle

flow, an operation for which they were not designed. Increased wear on the

seats of these isolation valves resulted.

The design

temperature

ventilation

performance

operating temperature for the CCW motors was lower that the

expected during an accident when the non-safety related

system would not be in service. Therefore, the long-term

of the system could not be assured.

The findings indicate that the SSFIs can be a useful tool for determining

how effectively the effects of aging have been addressed. Table 4.3 summarizes

the areas where SSFIs can be useful for identifying aging problems, and presents

the lessons learned from the SSFI reviews discussed.

Table 4.3 Areas where SSFIs provide useful aging information

Area Affected SSFI Lesson Learned From Previous SSFI

By Aging Useful? |

Original Design Yes Aging degradation can be a factor in determining the original system

design. Aging effects must, therefore, be understood and accounted for in

design calculations.

Design Yes When design modifications are made, new aging stresses may inadvertently

Modifications be introduced into the system. These new stresses must be mitigated by

modifying existing ISM&M practices or adding new ones.

Corrective Yes When corrective maintenance is performed, the root cause of failure

Maintenance should be determined whenever possible. If it isn't, aging degradation can

go undetected and the failures can reoccur.

Preventive Yes Preventive maintenance procedures should include manufacturer's

Maintenance recommendations to avoid imposing unnecessary aging stresses on components.

Monitoring Yes Monitoring methods are not always comprehensive enough to detect aging

Methods degradation in an incipient stage before it results in degraded

performance.

4.3 Recommended Additions to the SSFI Methodolo"y

The SSFI was not intended to identify aging problems in nuclear plants.

However, a significant number of age-related conditions were found in previous

inspections, even without an aging focus. It is not clear whether the

conditions identified represent all of the aging problems or just a small

portion. However, it is clear that the SSFI can be a useful tool for helping to

uncover age-related problems in CCW, and probably in other safety systems. To

focus the inspections on aging concerns more directly, a list of recommended

additional information to obtain during the SSFI has been prepared (Table 4.4);

their inclusion in future SSFIs could more clearly determine if there are

additional aging phenomena beyond the types that are currently identified. It

should be noted that the information requested is not intended to indicate that

there are regulatory requirements related to control and identification of aging

4-8
degradation; the additions are recommended only as a means of determining the

extent to which aging of systems and components is addressed at a particular

plant.

The review of CCW SSFIs did not identify common aging phenomena from plant

to plant, however, it did identify potential aging related problems that could

occur at more than one plant. While all of these conditions would not be

expected to affect any one CCW system, individual conditions would be expected

to affect a number of plants and could reduce the reliability of the CCW system

if left unchecked.

4-9
Table 4.4 Recommended additions to SSFIs

[ SSFI Area Additional Information to Obtain

System Walkdown Determine the following:

- do systems and components appear to be well maintained and functioning properly (e.g., are

there any visible signs of unchecked aging degradation)

- is aging related degradation a possible cause of any malfunctions observed

Preventive Determine the following:

Maintenance

- are components properly maintained such that compensations are made for expected wear and

tear

- are frequencies adequate to mitigate aging degradation leading to failures

Corrective Determine the following:

Maintenance

- are failure rates being calculated and trended

- are failure rates higher than expected

- are modifications or compensating measures being pursued to deter increasing failure rates

- are root cause analyses being conducted

Design Determine the following:

Modifications

- have unforeseen aging stresses been added to the system that could lead to accelerated aging

of systems and components (e.g., hot spots, more frequent or longer durations of operation,

higher radiation dose rates)

- have compensating measures been added to address any new stresses

- have analyses been performed to determine the effect on the aging and operation of associated

systems and components (e.g., addition of fire barriers can effect the environment of surrounding components)

Operation Determine the following:

- are systems or components operated beyond design limitations such that stresses are in excess

of those expected and premature aging is possible

- are system and component parameters being properly monitored for signs of deterioration, and

are data being appropriately evaluated

- have acceptance criteria been developed for the monitored parameters

- have appropriate actions been taken in response to identified trends indicating deterioration of

performance

- when aging degradation is detected during an inspection, how serious is degradation with

respect to acceptable performance, and will operability be affected

4-10
5. ASSESSMENT OF REGULATORY AND INDUSTRY REQUIREMENTS

The component cooling water (CCW) system is classified as one of the reactor

auxiliary systems required for safe shutdown during normal or accident

conditions. The design, operation, testing, and maintenance of this system are,

therefore, governed by regulations and industry standards, such as the General

Design Criteria in the Code of Federal Regulations (IOCFR Part 50), NRC

regulatory guides, the NRC Standard Review Plan, and various codes, standards,

and guides published by the professional societies. In addition, for certain

types of components, manufacturer's recommendations and guidelines are

considered for proper operation and maintenance of the equipment. Past

operating experience has identified problems requiring modifications to the

design, operation, and maintenance of the system. This section discusses these

requirements and assesses their adequacy for assuring continued reliable

functioning of the CCW system as the plant ages. Table 5.1 summarizes the

documents reviewed in this section.

5.1 CCW System Design Requirements

After the Three Mile Island (TMI) accident in 1979, the importance of the

CCW system to remain functional in supplying cooling water to the Reactor

Coolant Pump or Recirculation Pump seals was recognized. It became evident that

there were various concerns about the designs, as Generic Issues 23, 65, and

130, and Unresolved Safety Issue A-44 were issued during the last decade. In

addition, other design deficiencies, such as over-pressurization of the CCW

system and inadequate cooling to the RHR pump seals in certain configurations

were noted, and disseminated to individual licensees via NRC Information

Notices. Therefore, the design requirements of the CCW system are critical and

must continue to be reviewed and improved.

The design of the CCW system is governed by various design criteria,

included in the Code of Federal Regulations, whose purpose is to ensure reliable

system performance during normal or accident conditions. It is important that

these design criteria be followed for safety systems because of the adverse

impact that a failure in one of these systems could have on plant safety. The

design requirements for the CCW system are examined in this section, along with

some of the potential safety concerns related to a failure of the system. These

safety concerns are identified in various NRC generic letters and information

notices.

5.1.1 General Design Criteria

Although the basic design requirements of the CCW system follow the lOCFR

Part 50 General Design Criteria (GDC) and the NRC Standard Review Plan (SRP),

its configuration and the loads to which it provides cooling water vary widely

from plant to plant. ANSI/ANS-59.1-1986 29 provides requirements in the areas of

design, materials, fabrication, placement and testing of the CCW system. This

standard also identifies other relevant industry standards that govern the

design requirements for the system. However, none of these documents include

any specific requirements for addressing aging. The only requirement for aging

management is that equipment used in the system must remain operational

throughout the life of the plant.

5-1
Table 5.1 Regulatory and industry documents related to the CCW system

CCW St I Stdud/Cui" I SubjedtAddressd g

_ t____ _ INoesI Topics

Design General Design Criteria 2 Seismic requirements None

General Design Criteria 4 Missiles, pipe whip, pipe break, flow None

instabilities

General Design Criteria 5 Interficing systems and components None

Generl Design Criteria 44 System redundancy Non.

Generic [msue 23 RCP sel failure due to insufficient cooling N/A

Generic Issue 65 Probability of core meh due to CCW failure N/A

Generic Issue 130 Essential service water pump failure causing N/A

CCW beat exchanger failure

NRC Standard Review Plan Review of system design None

Unresolved Safety Issue A-44 Station blackout N/A

Information Notice 89-54 Over pressurization of CCW system NtA

Information Notice 89-71 Inadequate cooling of RHR pump seals N/A

Operationt General Design Cdteria 45 In-service inspection None

Testing

General Design Criteria 46 In-service teat None

ASME OM Standards Operation and maintenance Yes

ANSllANS-59.1-1986 - general discussion of

aging effects on

pumps, HXs, and piping

NRC Regulatory Guides 1.26 and 1.29 Classification of system None

components

Technical Specifications General system operating limits and test None

requirements

Generic Letter 89-10 Testing requirements for motor-operated None

valves

Generic Letter 89-13 System performance testing requirements None

Maintenance INPO Good Maintenance Practices Maintenance None

N/A Not Applicable

5-2
Specific sections of the General Design Criteria (GDC) to which the CCW

system must conform are 2, 4, 5, and 44 of Appendix A to 10 CFR Part 50. Based

on these criteria, the CCW system must be designed to accommodate the following:

GDC 2: The structures housing the system and the system itself must be

capable of withstanding earthquakes. NRC Regulatory Guide 1.29

defines the safety-related and nonsafety-related portions of the

system.

GDC 4: The system must be capable of withstanding the effects of

missiles from inside and outside the containment, pipe whip, pipe

breaks, and flow instabilities during normal plant operation, as

well as during upset or accident conditions.

GDC 5: The shared systems and components must be capable of performing

their required functions without impairing the ability of the CCW

system to perform its safety functions.

GDC 44: Suitable redundancy in components and features, and suitable

interconnections, leak detection, and isolation capabilities are

required to assure that, for on site and off site electrical

power system operation, the system safety function is

accomplished, assuming a single failure.

After the TMI accident, a requirement was added to GDC 44 that the design of

the CCW system must withstand a loss of power without damage to RCP seals. This

is in accordance with the TMI action plans II.K.2.16 of NUREG-0718, and

II.K.3.25 of NUREG-0737.

5.1.2 Generic and Unresolved Safety Issues on RCP Seal Cooling

Several potential safety concerns related to failure of the CCW system have

been identified from a review of the system designs. These concerns have been

addressed in various NRC letters, bulletins, and notices. They indicate the

importance of the CCW system to plant safety and identify weaknesses in the

system designs. These issues were reviewed and the results are discussed in the

following paragraphs.

Increasing attention has recently been focussed on the integrity of reactor

coolant pump (RCP) seals in the event that cooling flow to the seals is lost.

In Westinghouse and B&W plants, primary seal cooling is provided by an injection

flow directly into the seal assembly. As a secondary means of seal cooling, a

thermal barrier heat exchanger is included inside the pump housing that is

cooled by the CCW system. If the seal injection flow is lost, hot reactor

coolant would be cooled by the thermal barrier heat exchanger before flowing

through the pump seals. Although designed to provide redundant methods of seal

cooling, loss of either the seal injection system or the thermal barrier cooling

system would necessitate stopping the reactor coolant pumps within a limited

time to prevent pump damage.

Generic Issue 23, "Reactor Coolant Pump Seal Failures' discusses the

potential safety consequences of a failure in PWR primary coolant pump seals and

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BWR recirculating pump seals. It was found that seal degradation resulting in

mechanical failure of the seal can result from a loss of cooling to the seal,

that in turn could lead to leakage. Although seal failures have not resulted in

a direct threat to public health and safety, there is the potential for a seal

failure to cause leakage of primary coolant to containment; this has been

classified as a small LOCA.

Failure of the CCW system, in conjunction with a loss of seal injection,

will result in immediate exposure of the seals to hot reactor coolant. If the

seals fail after prolonged exposure to reactor coolant, and if the pumps used

for seal injection are also cooled by the CCW system, a LOCA without makeup

capability could result. In addition, if containment fan coolers are cooled by

CCW, containment integrity could be jeopardized. From this sequence of events,

Generic Issue 65, "Probability of Core Melt Due to Component Cooling Water

System Failures", has emerged and is expected to be resolved as part of Generic

Issue 23. As concluded in NUREG-0933, based on the PRAs associated with the

Zion, Indian Point, and Sizewell plants, even the lower bounds of the parameters

are in the medium priority category, and the "best" estimates are well into the

high priority. Therefore, maintaining the CCW system in operation is classified

as HIGH priority.

In another scenario, complete loss of the CCW system, seal injection system

and reactor makeup systems could result from loss of all AC power to the plant.

This condition is being evaluated as part of USI A-44, "Station Blackout", and

further investigated as part of Generic Issue 23.

Generic Issue 23 is in the process of being resolved, and a Generic Letter

is likely to be issued addressing the following proposals:

- to treat the RCP seal assembly as a safety-related component, similar to

other reactor coolant pressure boundaries, applying QA requirements

consistent with Appendix B of lOCFR Part 50.

- to provide procedures for normal and off-normal conditions, and the

instrumentation needed to implement these procedures.

- to provide RCP seal cooling during off-normal plant conditions involving

loss of all seal cooling, such as stated in station blackout.

5.1.3 IN 89-54: Potential Over Pressurization of CCW System

Information Notice 89-54 was issued to all operating reactor licensees on a

design deficiency in the CCW system at the Surry Power Station. The deficiency

results from under-design of the relief capacity for the CCW lines connected to

the thermal barrier heat exchangers on the reactor coolant pumps. The CCW

piping adjacent to the reactor coolant pumps at Surry is of schedule 160 carbon

steel and is designed to withstand full reactor system pressure. The lowpressure sections of the CCW system within containment and within the auxiliary

building are designed for 150 psig.

In the event of reactor coolant system inleakage (design basis of

approximately 275 gpm), the low-pressure sections of CCW piping are protected

5-4
from over-pressure by a check valve on the upstream side of the RCP thermal

barrier, and by a fast-closing AOV on the downstream side. The isolation valve

is designed to close on a high CCW flow signal, while a relief valve located on

the upstream side of the thermal barrier is designed to open at 150 psig. The

air-operated isolation valve is not safety-related, and the relief valve is

designed to pass 167 gpm. Failure to isolate the leak inside containment or to

provide adequate relieving capacity could lead to a reactor coolant leak outside

the containment building that cannot be isolated.

5.2 System Inservice Inspection and Testing Requirements

The ASME Section XI inservice inspection and testing requirements for the

CCW pressure retaining components and their supports are included in the plant

technical specifications to assure the operability of the system. In addition,

General Design Criteria 45 and 46 of Appendix A to lOCFR Part 50 require the

following:

GDC 45: The system must permit periodic inspection of important

components, such as heat exchangers and piping, to assure the

integrity and capability of the system.

GDC 46: The system must be designed to permit appropriate periodic

pressure and functional testing to assure (1) the structural and

leaktight integrity of its components, (2) the operability and

the performance of the active components of the system, and (3)

the operability of the system as a whole under all design basis

conditions.

In addition, the test control criteria of Section XI in Appendix B to 10 CFR

Part 50 require that a test program be established to assure that all testing

required to demonstrate that structures, systems, and components will perform

satisfactorily in service is identified and performed in accordance with written

test procedures, which incorporate the requirements and acceptance limits

contained in applicable design documents.

These test and inspection requirements are very general and can be applied

to three specific areas; preoperational testing, inservice inspections, and

inservice testing. Each area will be discussed separately.

5.2.1 Preoperational Test Requirements

The ability of the system to perform all of its design functions is tested

prior to starting normal plant operation. The preoperational requirements cover

prerequisite tests, station configuration, integrated system functional test,

and post-testing conditions. The requirements ensure that each component or

group of components has been tested in all specified combinations, either in the

system test or as a prerequisite.

ASME/ANSI OM-S/G-1990,3 0 Part 2 and ANSI/ANS-59.1-19862 9 standards delineate

system tests for both the cold and hot conditions which should be performed on

CCW components as preoperational test requirements. These standards also

include system-level tests, such as heat balances and flow adjustments. If the

5-5
actual heat loads are not available at the time of testing, then estimated

values are used and later verified as the heat loads are made available. These

activities are commensurate with the requirements given in the General Design

Criteria listed above.

The ASME standard lists pump flow, system flow, heat exchanger performance,

heat capacity, automatic control functions and their calibrations, and emergency

power operation tests for load shedding and sequential loading tests. Minor

deviations are corrected either by determining equivalent test methods and

retesting, or by making system adjustments and retesting. On the other hand,

major deviations are corrected by performing engineering evaluation to change

acceptance criteria, or by changing the system design and retesting in the new

conditions.

5.2.2 Inservice Inspection Requirements

According to Regulatory Guide 1.26, the components in the CCW systems are

classified as Quality Group C; the corresponding ASME Code Class is 3. However,

some portions of the system that penetrate containment are classified as class

2. As required by GDC 45 and 46, and 10 CFR 50.55(a), an inservice inspection

(ISI) program for the CCW system is provided in accordance with Section XI of

the ASME Boiler and Pressure Vessel Code.

To assure the structural and leaktight integrity and capability of the

system, pressure retaining components are visually inspected during hydrostatic

and leakage tests. Hydrostatic tests are performed at a pressure above normal

system operating pressure, and are required every 10 years. System leakage

tests are performed at normal system operating pressure, and are required every

three to four years. Additionally, the system supports and their integral

attachments are visually examined as part of the in- service inspection

requirements.

5.2.3 Inservice Testing Requirements

The inservice testing (IST) program for the CCW system requires periodic

functional testing to assure the operability and performance of the active

components of the system, in accordance with GDC 46. Pumps and valves are

tested in accordance with ASME Boiler and Pressure Vessel Code Section XI,

Division 1. Reference values are established when the pump or valve is known to

be operating correctly. Test values are compared to the reference values to

determine component operability.

Snubbers are functionally tested in accordance with Section XI and the

technical specifications. A representative sample from various locations in the

plant is tested. Service and environment are considered in selecting the

sample. Aging of snubbers is specifically addressed as part of the snubber

service life

monitoring program, as required by the technical specifications.

There are other factors which are part of an effective surveillance program.

Normal periodic data logging should be included so that the data on heat

exchanger fouling, or branch flow changes can be trended. Components not in

5-6
operation, such as standby heat exchangers, should be scheduled for periodic

operation to ensure operability.

It should be noted that the ASME Section XI inservice test requirements will

be replaced by the ASME Operation and Maintenance (O & M) Code. In particular,

pumps will be tested in accordance with ASME OM Code, Subsection ISTB, which

replaces Section XI, Subsection IWP. Valves will be tested in accordance with

ASME OM Code, Subsection ISTC, which replaces Section XI, Subsection IWV.

Snubbers will be tested in accordance with ASME OM Code, Subsection ISTD. As

plants update their inservice test programs, the OM Code requirements will be

incorporated.

Performance test guidance for the CCW system is included in part 2 of the

ASME/ANSI-OM-S/G-1990 standard. This standard provides guidance on what tests

should be performed and what data should be recorded; samples of data recording

sheets are also included. Evaluation of the test results and acceptance

criteria are also discussed. In Appendix D of this standard, there is guidance

for analyzing system degradation with a discussion of pipe friction increases

due to degradation, heat exchanger fouling, and pump head and capacity

degradation with time. Measurements to be made and calculations that can be

performed are also presented. Every five years, tests should be performed to

evaluate the heat removal capability of the system and degradation of system

components. This is included in the ASME OM standard which relates to aging of

the system, and is consistent with the requirements of Generic Letter 89-13.

The particular type and frequency of tests are selected based on the aging

characteristics established for the particular application of the equipment

within the CCW system.

Instrumentation and controls should be calibrated periodically to ensure

proper indications. Nominal tests are performed at a minimum of once every 18

months to demonstrate system operability, in accordance with technical

specifications. These tests include:

- Auto pickup of standby pump or heat exchanger, or both

- High and Low flow alarms

- Surge tank auto level controls and alarms

- Process radiation or monitoring alarm interlock, or both

- Local or remote controls, or both

- Low suction pressure (NPSH) alarm

5.2.4 Generic Letter 89-13 on Service Water System Problems

As an example of a safety issue related to testing, Generic Letter 89-13,

"Service Water System Problems Affecting Safety-Related Equipment" discusses

testing, maintenance, design, and human factor issues related to the CCW system,

and the lack of compliance with GDC 44, 45, and 46. The recommended action

items in the generic letter address the age-related problems associated with CCW

heat exchangers. These action items require 1) a test program be conducted to

periodically verify heat exchanger heat transfer capability, 2) verification

that the system will perform its intended function, and 3) verification that

maintenance practices, procedures, and training are adequate. Utilities are

required to implement the recommended actions, or submit alternatives. Operating

5-7
experience and studies indicate that CCW systems may experience significant

fouling from aging-related in-leakage of service water, along with erosion or

corrosion. The requirement for periodic testing of the heat transfer capacity

of heat exchangers serviced by the CCW system has not been considered necessary

because of the assumed high quality of chemistry control programs for the CCW

water. However, if the adequacy of these chemistry control programs cannot be

confirmed over the total operating history of the plant, or if any unexplained

downward trend in the heat exchanger performance is identified that cannot be

remedied by maintenance of the SW system, it may be necessary to selectively

extend the test program and the routine inspection and maintenance program

outlined in the ASME OM standard.

5.3 System Maintenance Requirements

As indicated in GDC 44, GDC 45 and GDC 46, the design integrity and

operational capabilities of the CCW system should be maintained throughout the

life of the plant to ensure the successful performance of its safety functions.

The periodic ISI and IST programs discussed above are the tools for determining

if these goals are being met. However, a well balanced maintenance program is

necessary to mitigate problems caused by degradation, such as aging, human

errors, or natural catastrophes. This section reviews the industry standards

and operating experience relating to maintenance of the CCW system.

5.3.1 Industry Maintenance Standards

Various industry standards were reviewed to determine if any direction is

provided for performing preventive and corrective maintenance on the CCW system.

Although there are various standards for preventive maintenance of certain

components, such as the Institute of Nuclear Power Operations (INPO) good

maintenance practices, there is no standard which specifically establishes

requirements for preventive maintenance. Preventive maintenance practices are

typically based on past operating experience and component manufacturer's

recommendations.

Corrective maintenance is performed when a failure occurs.' Typically,

either the component is repaired or refurbished, based on the assessment of its

condition at the time of failure, or the component is replaced at a fixed

interval, which is established by the requirements of the equipment

qualification program.

5.3.2 IN 90-21: Potential Aging Failure of Motor-Operated Butterfly Valve

An example of a safety issue involving testing and maintenance is discussed

in Information Notice 90-21, which was issued to all licensees to alert them to

a potential increase in friction forces on valve seats. This could result from

maximum seat hardening that exceeds the amount assumed when selecting the motor

actuators and setting the torque switches. The systems in which these valves

are located include the CCW system, SW system, and various ventilation systems

of Catawba Units 1 and 2. Failure of these MOVs could cause a loss of cooling

water to the RHR system heat exchangers. This underestimation of the friction

forces could lead to the common cause failure of a large number of motoroperated butterfly valves to open on an electrical signal.

5-8
As a result of this concern, Generic Letter 89-10, "Safety-Related MotorOperated Valve Testing and Surveillance," requested that the utilities

establish a program for testing, inspection, and maintenance of motor-operated

valves in safety systems. One factor contributing to the need was the

uncertainty in the analytical estimations used to select the motor actuators for

valves and setting their torque switches.

5.4 Summary of Findings

Regulatory documents and industry standards address the design and

operational requirements for the CCW system. The utilities are continuing to

modify the design and the operating procedures for the system as they find

deficiencies either from NRC notices and bulletins, or from their own

experience. An area which is not adequately addressed is aging degradation of

the system.

The aging of components, systems, and structures in nuclear power plants has

been receiving more attention as they approach the end of their licensing

period. However, most documents guiding the design, operation, testing, and

maintenance of such facilities do not explicitly address aging considerations.

The revised SRP for plant license renewal (SRP-PLEX), the technical

specification for snubbers, and the ASME ON standard are the only documents

which contain some guidance for managing aging.

The ISM&K requirements currently contained in the various industry codes and

plant technical specifications are able to detect degradation from many of the

aging mechanisms that commonly lead to failures. However, the results of the

phase 1 CCW system study show that, even with current requirements for

inspections and tests in place, a large fraction of failures are related to

aging. Therefore, current requirements are not comprehensive enough to

completely control all aging mechanisms. Methods of more effectively managing

aging are discussed in Section 7.

5-9
6. ADVANCED ISH&M PRACTICES

In addition to the routine practices which are performed at all plants,

there are other ISM&M practices which may detect and mitigate aging degradation.

Many are already used by most utilities, although not routinely. Other

practices are still under development and have not yet been applied. In this

section, a brief discussion of these advanced practices will be presented along

with their applicability to the CCW system.

For the CCW system, several ISM&M techniques which can indicate equipment

or system degradation were evaluated. These include techniques which have

application to heat exchangers, pumps, valves, and piping. While the emphasis

is on pumps, valves, and heat exchangers, the long term degradation of tanks and

piping should also be considered when planning a supplemental maintenance

program.

6.1 Ultrasonic Testing

Airborne ultrasonics is an effective test for locating and diagnosing

mechanical problems. It has been proven to be a very versatile test and

accurately spots potential bearing failures, as well as locates all types of

pressure and vacuum leaks. It is also effective in detecting internal leakage

in valves31.

Ultrasonic leak detection is based on the principle that forcing a fluid

through a small opening creates turbulence on the downstream side. This

turbulence generates a "white noise" that has strong ultrasonic components.

Most of the audible sounds of a leak might be masked; however, the ultrasonic

signals will be readily detectable, even when loud ambient noise is present.

Sounds above 20 Khz are the most crucial in detecting wear or leakage in

machinery, while humans can only hear sounds in the 20 to 20,000 Hz range.

Another advantage of ultrasonic detection is that audible sound waves are

long, therefore, they can penetrate walls and machine parts, and are reflected

off other surfaces. These attributes make it difficult to trace them to their

sources. However, ultrasonic sound waves are extremely short and travel in

straight lines. They cannot penetrate solids, although they do filter through

the tiniest of openings. These properties of ultrasonic sound waves enable

ultrasonic detectors to be largely unaffected by even the loudest machinery.

They are practical to use in plants where noise can be extreme32.

Since the ultrasonic detector is sensitive only to ultrasound, it is able

to pinpoint the sources of high frequency emissions. This is important since

wearing parts produce ultrasound long before they produce audible sounds.

Therefore, machine wear can be detected at a very early stage before much damage

is done. In using the detector, an operator listens for ultrasound through

earphones and gauges its intensity by the deflection of an analog meter.

6-1
6.1.1 Detecting Heat Exchanger Tube Leaks

Ultrasonic testing can be used to detect heat exchanger tube leaks in

three different ways33:

1. On-Line: By touching the instrument to the outer shell, the heat

exchanger can be monitored for a normal turbulent flow. When a leak

occurs in the tubes, the change in turbulence generally produces

popping sounds that facilitate the detection of the onset of

leakage. Smaller leaks in the peripheral tubes are more readily

detectable than are leaks in the central tubes, where mostly gross

leaks are detected.

2. Off-Line, Tone Generation: While the heat exchanger is off-line,

ultrasonic transmitters are placed in the inlet and outlet ports to

flood the internal shell around the tube bundle. Should a tube

leak, the sound will penetrate the leak hole and carry through the

length of the tube. Tube-to-tube sheet integrity may also be tested

in this manner.

3. Off-Line, Pressure Test: In this off-line test, the heat exchanger

is pressurized with air, and standard leak detection methods are

incorporated. A scan of the tube sheet for the telltale rushing

sound will indicate leakage.

6.1.2 Detecting Valve Internal Leaks

A poorly seated valve can be detected through the ultrasound created by

the fluid flowing through the seat. If the valve is correctly seated, no flow

will occur and no ultrasound will be detected. When the ultrasound detector

probe is touched to the body of a leaking valve, the recognizable sound of

liquid flowing through an opening will be heard. The noise of a leaky valve is

more evident on the downstream side of the leak because of the turbulence

created when the liquid flows from the high pressure side, through the leak, to

the low pressure side. The same technique can be used for relief valves.

6.1.3 Detecting Bearing Degradation

Ultrasonic inspection and monitoring of bearings is one of the most

reliable methods for detecting incipient bearing failure. Experiments performed

by NASA revealed that changes in frequency from 24 kHz through 50 kHz in a

bearing provided a warning long before other indicators, such as increases in

temperature or vibration.

The structural resonances of one faulty component, such as the repetitive

impact of a ball passing over the pit of a fault in the race, produces similar

increases in amplitude as balls get out of round. The repetitive ringing of the

flat spots is also detected as an increase in amplitude of the monitored

frequencies. Generally, a good bearing makes a rushing or hissing sound. Loud

rushing sounds similar to those of good bearings, only slightly rougher,

indicate lack of lubrication. Cracking or rough sounds mean that the bearing is

on the verge of failure.

6-2
There are two basic procedures for testing bearings: comparative and

historical. The first involves testing two similar bearings and comparing the

differences. Historical testing involves monitoring a given bearing over a

period of time to establish its history. Patterns of wear at particular

frequencies become obvious and allow for the early detection and repair of

problems. Sensitivity levels and meter readings, as well as frequency settings

are recorded on a chart for reference. Decibel levels can be determined from

one reading to the next. NASA has determined that a bearing has entered the

failure mode when the ultrasound level increases 10 decibels or more over the

initial base line reading.

6.1.4 Detecting Pump Degradation

Ultrasonic testing also detects pump degradation. For example, a chemical

plant reported that before it started using ultrasonic testing it had to wait

until the pump's efficiency decreased by at least 5% before degradation could be

detected. Now with the ultrasonic detector, degradation can be detected before

the pump loses more than 2% of its efficiency. Although routine vibration

surveys on all pumps are taken every six months, the ultrasonic tests detect

signs of degradation before it is picked up on the vibration surveys. When wear

between an impeller ring and its companion case ring occurs, the pump gives out

a high pitched sound caused by the water sliding under the ring and having its

pressure reduced. In this case, a whir or unusual noise will be detected.

Every pump has its own record; the velocity and level of any ultrasonic signals

detected during inspections is recorded and kept on file.

6.2 Eddy Current Testing

When an electromagnetic field is placed around a surface, any interaction

of a high frequency surface wave with a defect in the surface will cause a

perturbation in the electromagnetic field. This perturbation can be detected by

a receiving coil and used to produce an indication on a meter. This principle

is the basis for eddy current testing, which is used to detect surface and near

surface flaws in materials. The process requires information on the

characteristics of electromagnetic signals possible in the material34.

One use of eddy current testing is to check heat exchanger tubes for

cracks or defects. This is accomplished using a probe that is inserted into the

heat exchanger tubes and pulled or pushed through the tubes. The tubes usually

are cleaned before testing to remove scale or debris build-up that can affect

the results or block the probe. The eddy current's magnetic field cuts through

the coils in the probe and induces an electrical current through them. This

current is returned to the eddy current instrument, which amplifies it,

electrically processes it, then displays the signal on a CRT. As the signals

appear, the technician analyzes the amplitude, phase angle, and shape to

identify the specific defect. Each defect, such as pitting, wall thinning,

support damage, and cracks generates its own signal.

It is important to note that eddy current testing is normally conducted

only on non-magnetic tubing, which is the most common type for CCW heat

exchangers. However, if the tubes are made of ferrous (magnetic) material, a

6-3
similar approach to eddy current testing may be used. This is the remote field

technique, which is discussed in the next section.

6.3 Remote Field Technique

The Pennsylvania Electric Company, with the support of EPRI, evaluated the

techniques available for detecting, characterizing, and quantifying defects

associated with known failure mechanisms in heat exchangers constructed of

carbon steel tubes35. The basic process which was found to be most successful

is the remote field technique (RFT). It was demonstrated that the method could

identify the following degradation modes in a heat exchanger:

- gradual outside diameter (OD) wall loss (usually associated with

corrosion)

- one-sided OD wall loss (normally caused by debris damage within the

heater)

- OD circumferential defects (typically found at baffle locations as

a result of tube vibration)

- small volume circumferential grooves (typical of fatigue cracking

between support baffles)

- large volume OD pitting

The RFT inspection technology uses permanent, high-energy magnets

contained in the probe to magnetize a segment of tube. Both internal and

external defects produce a localized perturbation of the magnetic field in the

tube. These perturbations induce a signal in the probe's sensor coils that is

amplified and displayed on a CRT or strip chart recorder. An additional sensor

measures total magnetic flux in the tube wall to detect gradual wall thinning

due to wear or erosion. The RFT system is illustrated in Figure 6.1.

Demonstration of this test over six years revealed several limitations.

A calibration standard, which accurately represents the anticipated defect is

essential for evaluating the readouts. As illustrated in Figure 6.2, a

significant error can result due to the calibration standard that is used. For

example, a predicted wall loss of 15% could translate into an actual loss of 70%

by using a standard featuring a gradual wall loss to evaluate one-sided tube

defects. Even with the standards, some loss of sensitivity was found to occur

at baffle locations, and erroneous readings were sometimes obtained due to

magnetite buildup on the tubes. Therefore, a prerequisite was established that

tube cleaning be conducted before RFT testing. High pressure cleaning

techniques such as a 4000 psig water jet proved to be effective, removing

internal magnetite deposits without damaging the tube inside diameter.

While the RFT technique has some limitations, experience shows that when

it indicates that a tube is acceptable (no indication of defects exceeding 10%

wall thickness), the tube is fit for service. However, defects exceeding 10% of

wall thickness may or may not represent a risk, depending on the nature of the

defect. In these cases, the utility is advised to use a more sophisticated type

of RFT, an Internal Rotary Inspection System (IRIS). The IRIS technique uses a

rotating probe and an ultrasonic beam for inspection from the tube inside

diameter. Testing showed that the method can readily characterize the shape of

the defects, which can be used to improve the interpretation of the RFT results.

6-4
L Coil separation: I

I- ~3X lube diam I

Magneic circuit Seftsots Tute

Figure 6.1 Remote field technique concept"

This copyrighted illustration is reprinted with permission

from the Pennsylvania Electric Co., Johnstown, PA.

However, this process was found to be very slow and is recommended for use only

as confirmation of questionable RFT findings.

6.4 Vibration Monitoring

Most plants use vibration monitoring instrumentation to monitor the

condition of rotating equipment, such as pumps and motors. Each time a rolling

element passes over a defect, an impulse of vibration is generated. All of the

vibration monitoring techniques are fundamentally based on the recording and

quantification of these vibration impulses. This technology continues to be

improved in its sensitivity and diagnostic capability. One of these refinements

6-5
INDICATED WALL LOSS (%)

70 ,

60~~~~~~~~~~~~~~,

50

40

30

20

or* ,ided calciration

0

0 10 20 30 40 50 60 70

ACTUAL WALL LOSS C%)

Figure 6.2 Sample calibration standard used for RFT35

is the method used for processing the signal.

The vibration impulses generated by a defect create a higher frequency

signal than vibration caused by other parts of the driver36. As a result, since

the vibration energy produced by the impulses is concentrated intp a relatively

narrow band, it is more readily detected than the energy distributed over the

entire frequency range. The high frequency signal is processed to determine the

recurrence rate of these impulses. As illustrated in Figure 6.3, a seemingly

random vibration pattern can reveal a specific pulse amplitude and frequency.

This pattern can be used to more accurately trend the data and determine the

root cause of the problem.

The advanced vibration technology owes its high degree of sensitivity to

a mechanically tuned transducer that senses ultrasonic pulses. The pulses of a

typical bearing can be as much as 1000 times higher when failure is imminent, as

compared to when a bearing is new. The principle of operation of the transducer

is similar to an accelerometer except that a single frequency is selected where

the resulting signal is strongest. Therefore, it is possible to filter out all

other vibration frequencies which may be caused by background conditions and

which could otherwise mask the degradation in the bearing.

6-6
tviroceaod Vibration Signal

Frequency (Hz)

ilteod, Rectlfi'd Vlbratlon Signal

Spectrum (Envelope Spectrum)

Mi lI tude (G M5)

P DWect

Frequency (Hz)

Figure 6.3 Sample vibration patterns

This method has also proved useful in determining the condition of the

lubricating oil. In the loaded part of a bearing, the contact areas of raceways

and rolling elements are under high pressure. The behavior of the lubricant

film in the contact area is described by the theories of elastichydrodynamic

lubrication. This means that the pressure distribution in the contact area does

not follow a smooth curve. Therefore, pressure waves are generated in every

rotating bearing, even when test measurements show that there is no metallic

contact between rolling element and raceway. The amplitude of the signal

6-7
produced by the pressure wave increases as the oil film between the two surfaces

decreases. This change can be detected by the transducer.

6.5 Tracer Technology

The Tracer Technology Center at Brookhaven National Laboratory has

developed a perfluorocarbon tracer (PFT) technology over a 15-year period, which

has been applied in various atmospheric, hydrological, and subsurface

applications. PFTs are detectable at extremely low levels and have been used

extensively as tracers of gas and liquid flow.

A review of the operating experience shows that chemical analysis is

commonly used by utilities to detect leakage in heat exchangers. An extension

of this philosophy is the PFT technology in which a tracer is inserted into a

process fluid to provide leak detection information. In particular, this

technology has been successfully used to detect leakage in high voltage cables,

which are filled with a dielectric fluid medium to cool and insulate them. This

is done by tagging the dielectric fluid with a small amount of the PFT tracer,

a carbon compound saturated with fluorine. When a leak occurs, the harmless PFT

vapor rises to the street surface, acting as an invisible chemical flag. PFTs

can be detected in minute quantities by analyzers also developed at BNL37.

PFTs are non-toxic and inert, and are over four orders of magnitude more

sensitive than fluorescent dyes. In the CCW application, the tracer could be

added to the closed loop part of the system while monitoring the open loop

service water system. Any leakage from the CCW system would be detected through

routine sampling. This type of application is being explored on an experimental

basis at a fossil power plant's steam condensing system. In this case, a tracer

added to the service water system is detected in the condensate system if a

minute tube leak exists in the condenser. This method is much more sensitive

than standard chloride leak detection instrumentation. In a study performed in

cooperation with EPRI37, the results demonstrated the practicality and

sensitivity of this method.

6-8
7. UTILIZATION OF RESEARCH RESULTS

This study has provided insight into the measures available for the

detection and mitigation of aging degradation in CCW systems. This section

discusses how the results of this research can be used to 1) evaluate the

effectiveness of existing plant programs for managing aging, and 2) provide a

means of strengthening any weaknesses identified.

7.1 CCW System Performance Assessment

An important step in evaluating a plant's aging management is to assess the

performance of the system under study. This assessment can be done by reviewing

maintenance records and failure data to identify aging mechanisms that are not

being properly controlled. One method is to use the 'time-line" type of

analysis, as demonstrated in Section 2.2.4 (Figures 2.10 to 2.12). The

comparison of corrective and preventive maintenance events made in this method

identifies weaknesses in the plant's maintenance and monitoring programs. Once

these weaknesses have been identified, improvements can be made to the ISK&M

programs to correct them.

In addition to the review of maintenance data, a review of the materials

used for construction of the various system components helps identify aging

mechanisms which the components may be susceptible to. The materials research

presented in this report identified several aging mechanisms. Once the

characteristics of the materials are known, the maintenance and monitoring

programs can be tailored to control aging. Table 7.1 summarizes the information

available in this report related to CCW component materials and their

susceptibility to aging. The subcomponents most susceptible to aging

degradation within each of the major components are identified.

Table 7.1 Reference of component material information

Component Subcomponent Material lonrationO

Heat Exchanger Tube Bundle Section 3.1.2

Tubesheet Table 3.2

Shell

Valve Body/Bonnet Section 3.2.2

Trim Table 3.4

LUners Table 3.5

Valve Operator Diaphragm Figure 3.6

O-Ring Table 3.6

Table 3.7

Pumps Primary Seals Table 3.9

Secondary Seals Table 3.10

Table 3.11

l ______________________________ Bearing Table 3.12

These tables and figures are in Section 3.

7-1
One additional area which should be addressed in an ISM&M program is the

identification of important components. In reviewing the various CCW system

designs for this aging analysis, some components were found to be more important

than others in terms of system reliability. For example, some components in the

system have a double or triple redundancy included in the design. Therefore,

failure of these components would not immediately result in the system being

unavailable. However, failure of some components in critical locations could

result in system failure, and they should receive additional monitoring and

maintenance. For this reason, each CCW system design should be reviewed on a

case-by-case basis to identify important components, and this information should

be factored into the ISM&M program.

7.2 Evaluation of ISM&M Practices

The survey of PWRs performed for this study provided an excellent overview

of the ISM&M practices currently being used in nuclear plants. This information

can be used as part of a review of current plant programs to determine what, if

any, practices could be added to make the programs more effective at managing

aging. By comparing one plant's practices with others, potential deficiencies

and subsequent improvements can be identified. Table 7.2 summarizes the

information available on ISM&M practices in other plants.

Table 7.2 Reference of ISM&M information

Component Tests Maintenance/ Monitorins|

Operation Inspection |

Pump Table 2.1 Table 2.8 Table 2.4

Table 2.17 Table 2.14

Table 2.23 Table 2.20

Section 5.3 Figure 2.1

Section 5.2

Valve Table 2.2 Table 2.9 Table 2.5

Table 2.15 Table 2.15 Table 2.15

Table 2.24 Table 2.21

Section 5.3 Figure 2.1

Section 5.2

hleat Exchanger Section 2.2.2 Table 2.18 Table 2.6

Section 2.3.2 Table 2.25 Table 2.16

Table 33 Figure 2.1

Section 5.3 Section 5.2

Instrumentation/ Table 2.10 Table 2.10 Table 2.7

Controls Table 2.11 Table 2.11

System Table 2.3 Table 2.12 Table 2.13

Section 5.3 Table 2.19

Figure 2.1

Section 5.2

7-2
This study showed that two levels of activities exist within the plants:

1) basic activities, which are performed in most plants, and 2) supplemental

activities, which vary based on many factors related to the plant. The basic

activities provide a general indication of component health, and are typically

required by technical specifications or engineering codes. These activities are

useful for providing information on aging degradation, although that is not

their primary purpose. Trending the results of these basic activities can

indicate if aging degradation is increasing and when it may reach an

unacceptable level.

One area that is not covered in the basic activities is long-term

monitoring of passive subcomponents, such as pipe walls, pump casings, and valve

bodies. Since these subcomponents are vulnerable to wear, erosion, and

corrosion, wall thinning may occur after many years of service. If the problem

is severe enough and goes undetected, wall thinning could lead to failure,

therefore, long-term monitoring for wall thinning should be included in the

basic ISM&M activities every five to ten years. A list of the recommended basic

practices is presented in Table 7.3. This list is based on practices currently

used at plants, along with additional practices recommended from this study.

The frequencies are based on information obtained from plants that are currently

performing these practices, as well as the requirements specified in the various

codes and standards.

In addition to the basic practices, there are a variety of supplemental

activities. These vary among plants, and are usually selected based on

manufacturers' recommendations or plant experience. The supplemental activities

were reviewed to determine if they could be used to help ih the detection or

mitigation of aging degradation. They were then correlated with the aging

mechanisms they detect or mitigate, and generic listings were generated. This

was done for each of the major CCW components and the results are presented in

Tables 7.4, 7.5, and 7.6 for pumps, valves, and heat exchangers, respectively.

In evaluating a plant's maintenance and monitoring program, the equipment

history and corrective maintenance actions performed- should be examined, as

discussed in section 7.1. From this, any aging mechanisms that are not being

properly managed can be identified. In addition, all the aging mechanisms

common to the CCW system components should be identified by reviewing this

study, the phase I study, and experiences of other utilities. Once the aging

mechanisms are known, the information in Tables 7.4, 7.5, and 7.6 can be used to

Determine if the proper ISM&M techniques are in place. If not, they can be

added to the plant's current practices. If they are already in place, their

frequency can be adjusted or redundant practices can be included. The

equipment's performance should then be trended to ensure that failures are being

controlled. To have an effective ISM&H program, at least one technique should

be included to detect and mitigate each of the aging mechanisms the system is

susceptible to.

7-3
Table 7.3 Recommended basic ISM&M practices for the CCW system

Component ISM&M Practice Frquency Aging Mechanism

Pumps Monitor Vibration 1 to 3 Months - Wear/degradation of bearings

Measure Developed Head 1 to 3 Months - Wear of impeller, wear rings

Check Lube Oil Level Daily to Weekly - Deterioration of oil seals

Check for Unusual Noise Daily to Weekly - Distortion of internals

Check for Excessive Leakage Daily to Weekly - Degradation of shaft seals

- Deterioration of gaskets

Grease Bearings/Couplings 6 to 18 Months - Wear of bearings/couplings

Perform Lube Oil Analysis 6 to 18 Months - Wear of bearings

- Deterioration of oil seals

Inspect CasingfShaftAnternals for 12 to 60 Months - Corrosion/erosion of parts

Cracks, Warping. Corrosion, Erosion - Distortion of internals

Check for Casing Wall Thinning S to 10 Years - Wear of casing material

Valves Valve Stroking 3 to 18 Months - Corrosion of internals

- Distortion of components

Check for excessive leakage, Daily to Weekly - Deterioration of gaskets

corrosion - Wear of packing

Adjust Torque/Limit Switches 12 to 24 Months - Calibration Drift

Lubricate Moving Parts 6 to 18 Months - Wear of components

Check Body Wall Thinning 5 to 10 Years - Wear of wall material

Heat Monitor Flow Daily to Weekly - Corrosion/fouling of

Exchangers internals

Monitor Outlet Temperature Daily to Weekly - Fouling of Tubes

Check for Excessive Leakage, Daily to Weekly - Deterioration of gaskets

Corrosion - Cracking/corrosion of shell

Clean Tubes As Needed - Fouling of Tubes

Check for Shell/Tube Thinning S to 10 Years - Wear of shelltube material

System Monitor Surge Tank Level/Makeup 4 to 24 Hours - Corrosion/cracking of welds,

walls, pressure boundaries

- Deterioration of seals,

gaskets

Monitor Temperature at Loads 4 to 24 Hours - Fouling of Heat Exchangers

Monitor Fklw to Loads 4 to 24 Hours - Degradation of pump

performance

Check for Pipe Wall Tlinning 5 to 10 Years - Wear of pipe wall material

Hydrostatic Test S to 10 Years - Corrosion/cracking of welds,

walls, pressure boundaries

7-4
Table 7.4 Pump ISM&M practices versus aging mechanisms

. ....... .... I G 

1. WFAR OF BEARINGS/BUSHINGS 8. BINDING OF IMPELLER/SHAFT

2. WEAR OF INTERNAL CONTACT SURFACES 9. CAVITATION DAMAGE TO IMPELLER/CASING

3. EROSIONICORROSION OF INTERNALS

4. VIBRATION INDUCED LOOSENING/MOVEMENT

5. DISTORTION OF INTERNALS

6. DETERIORATION OF PACKING/SEALS/GASKETS

7. FATIGUE/THINNING OF CASING

.... .... t t 1- - -

BEARING TEMPERATURE MEASUREMENT X X

FLOW RATE MEASUREMENT X X X X

MOTOR AMP/WINDING TEMP CHECK X X X X

TRACK TIME AT MINIMUM FLOW X X

PACKING/SEAL LEAKAGE MEASUREMENT X

NDE FOR CASING SHAFT CRACKS/FLAWS X

DISASSEMBLY INSPECTION/OVERHAUL X X X X X X X

BOLT TORQUE MEASUREMENT X

ROTOR TORQUE MEASUREMENT X X

THERMOGRAPHY EXAMINATION X X X

CHANGE LUBE OIL X

REALIGN PUMP/DRIVER X X

REPLACE BEARINGS X

RETORQUE BOLTS X

REWORK IMPELLER X X

REPLACE GASKETS/SEALS X 7

REPLACE WEAR RINGS X

REPLACE SHAFT SLEAVES X

LUBRICATION SYSTEM PM X

7-5
Table 7.5 Valve ISM&M practices versus aging mechanisms

VALVXE MIN MSMANISM

1. WEAR OF BEARINGS/BUSHINGS 8. DETERIORATION OF MOTOR WINDINGS (MOV)

2. WEAR OF STEM CONTACT SURFACES 9. FATIGUE/THINNING OF CASING

3. EROSION/CORROSION OF SEAT/DISK/INTERNALS 10. BINDING OF STEM/DISK

4. VIBRATION INDUCED LOOSENING/MOVEMENT 11. SETPOINT DRIFT

5. DISTORTION OF INTERNALS 12. DETERIORATION OF AIR DIAPHRAGM (AOV)

6. DETERIORATION OF PACKING/SEALSJGASKETS 13. DEGRADATION OF ELECTRICAL CONTACTS/WIFES

7. CALIBRATION DRIFT OF TORQUE/LIMIT SWITCHES

.II7:;:-- 0 zcaAGING FE.TANISM DZinTE= MTzGAM

;. .ISHS _____________I~l~izhj2A±L.1-~-i-4 PRACTICE, y - - 3 7_--- ___ .|. i 0 Inlul13 ..

INSPECT/CLEAN CONTACTS/WIRES x

SEAT LEAKAGE TEST X X

PRESSURE DIFFERENTIAL TEST X X

STEM TORQUE MEASUREMENT X X

BOLT TORQUE MEASUREMENT X

PACKING/SEAL LEAKAGE MEASUREMENT X

NDE FOR CASING CRACKS/FLAWS X

STEM PLAY MEASUREMENT X

VALVE OPERATOR ALIGNMENT CHECK X X

MOTOR SIGNATURE ANALYSIS (N)Va) X X X X

MOTOR AMP/VOLTAGE MEASUREMENT X _ X X

MOTOR MEGER/SURGE/CAPACITANCE X

DISSASSEMBLY INSPECTION X X X X X X X X X X

BENCH TEST (RELIEF) X

REPLACE PACKING X

REALIGN OPERATOR X

COMPLETE OVERHAUL X X X X X K X X X X

REPLACE/REWORK SEATS X

REPLACE SEALS/GASKETS/PACKING X

RETORQUE BOLTS X

REPLACE DISK X

REPLACE TORQUE/LIMIT SWITCHES X

REPLACE MOTOR X X

REPLACE AIR DIAPHRAGM X

7-6
Table 7.6 Heat Exchanger ISM&M practices versus aging mechanisms

I HEA~~~~~BT MCR~ANRMhIG~AW

j1. EROSIONICORROSION OF TUBES 8. FOULING OF TUBES

2. DETERIORATION OF GASKETS

3. PLUGGING OF TJBES

4. CRACKING OF TUBES

5. CRACKING/THINNING OF SHELL

6. LOOSENING OF BOLTS OR INTERNALS

7. EROSION/CORROSION OF INTERNALS

I(~~**~IBGHZ MIED TE TEAcIIG& E

; fu-- . .T -a-f t-.E~d i- --;-t-i-;.. . .... t

DISSASSEMBLY INSPECTION/OVERHAUL X X X X X X X X

EDDY CURRENT TEST X X

ULTRASONIC TEST X X

ACOUSTIC MEASUREMENT X

DYE PENETRANT TEST X X

MONITOR FOR CCW CHEMICALS IN SW X X

PRESSURE DROP MEASUREMENT X X

BEAT BALANCE X X X

APPLY PROTECTIVE COATINGS X

REPLACE GASKETS/SEALS X

REPLACE/MONITOR SACRIFICAL ANODES X X

RETORQUE BOLTS X

7-7
In addition to the practices discussed above, there are several advanced

monitoring practices which may be used to manage aging. These practices typically require special equipment, and can be time consuming to perform. They

should be selected for inclusion in an ISM&M program using the same procedure

described for the supplemental practices. Table 7.7 summarizes the practices

examined in this study.

Table 7.7 Advanced monitoring practices

Technique [ Use Comments

Ultrasonics - Detects internal valve leakage -Can be used in areas with high

- Detects heat exchanger tube leaks background noise

- Detects bearing degradation -Can locate sources of high

- Detects pump degradation frequency emissions typical of

wearing parts

Eddy Current Testing - Detects material flaws (e.g., - Only applicable for non-magnetic

pitting, cracks, fractures) materials

- Used for heat exchanger monitoring - Heat exchanger tubes can be

inspected by inserting probe

down tube

Remote Field Technique - Detects wall loss, material - Can be used on magnetic materials

(RFI) defects, circumferential grooves, - Requires accurate calibration

cracks standard

- Used for heat exchanger monitoring l

Internal Rotary - Used for heat exchanger monitoring - Helps interpret questionable

Inspection System - Detects material defects results from RFT

(IRIS) - Process is very time intensive

Vibration Monitoring - Used to monitor rotating equipment - Sensitivity can be improved using

(e.g., pumps, motors) new methods of processing signals

- Detects bearing, support

degradation

Tracer Technology - Can be used to detect leaks in - New technique still under

heat exchangers and piping development

- Uses injection and detection of

perfluorocarbons

It should be noted that the list of practices presented in this report are

not intended to represent all possible practices available to the industry. The

practices discussed herein are the most commonly known and used. In evaluating

a plant's ISM&M programs, other sources of information should also be consulted,

such as manufacturer's literature and other research studies.

7-8
8. CONCLUSIONS AND RECOMMENDATIONS

The Phase I analysis of Component Cooling Water systems characterized the

effects of aging on the performance and reliability of the system. In this

Phase II analysis, the question of how to detect and mitigate aging degradation

was addressed. The techniques currently being used, along with new techniques

available were investigated in relation to their ability to manage the effects

of aging. The conclusions and recommendations from this analysis are discussed

in the following paragraphs.

8.1 Conclusions from the Review of ISM&M Practices

The review of inspection, surveillance, monitoring, and maintenance

practices has provided an overview of what is currently being done in plants to

maintain reliable performance of the CCW system. Many of these practices are

useful for detecting and/or mitigating aging degradation. The following

conclusions were made as a result of this review:

- Maintenance and monitoring programs typically include basic

practices which are common to all plants. These basic practices are

usually required by technical specifications or codes.

- In addition to the basic practices, each plant has several

supplemental activities that are performed as part of their

maintenance or monitoring program. These supplemental activities

may be included because of plant experience, or manufacturer's

recommendation.

- -In general, no specific actions are' in place to address long-term

aging of the CCW components. The failure data do not indicate any

failures of heat exchanger shells, pump casings, or valve bodies.

However, this is a potential concern for extended life operation.

Over many years of operation, wall thinning occurs which could

weaken these components. Consideration should be given to including

monitoring techniques that would address such concerns as pipe wall

thinning, and valve and pump case thinning.

- A standardized maintenance or monitoring program which requires all

plants to perform the same actions would not be practical due to

differences in plant designs, operating conditions, and environment.

An optimum program should include the basic practices, along with

supplemental and advanced practices specifically chosen to address

particular problems or weaknesses at the plant.

8.2 Conclusions From the Review of Component Materials

There are many different materials used in the construction of CCW

components. The review of these materials shows that the susceptibility of the

system to aging degradation is directly related to the materials selected.

While some materials may provide excellent resistance to the aging mechanisms

present in the CCW system, others may not. By knowing the characteristics of

the materials used, and their susceptibility to aging degradation, maintenance

8-1
and monitoring programs can be tailored to most effectively control the effects

of aging. Conclusions made during the review of component materials include the

following:

- The majority of heat exchanger failures are due to corrosion and

wear of the tubes, which are directly related to the materials

selected and the operating environment. Since all tubes in the tube

bundle are typically made of the same material, and are exposed to

the same environment, once tube failure begins, the number of

failures can increase dramatically in a short time.

- Several methods of extending the life of heat exchangers are

available, including cathodic protection and protective coatings or

liners. If the material selected for construction is incompatible

with the operating conditions or environment, aging degradation will

proceed rapidly. In these cases, the material should be replaced

with one more suitable for the service conditions.

- A valve subcomponent that is extremely susceptible to aging is the

packing. Several different materials are available for packing;

however, installation can also be important. Using combinations of

different materials can increase the life expectancy of the packing.

- Two valve operator components that are susceptible to aging are the

diaphragm and O-rings used in pneumatic operators. The materials

most commonly used are neoprene and buna-N. These components should

be inspected regularly and replaced periodically to prevent failures

while in service. These materials degrade even while in storage,

therefore, proper storage conditions should be maintained.

8.3 Conclusions From the Review of Codes and Standards

The various codes and standards that govern the design, operation,

testing, and maintenance of the CCW system also contribute to the proper

management of aging. A review of these items resulted in the following

findings:

- The design of the CCW system is governed by the General Design

Criteria in the Code of Federal Regulations. Although the criteria

address items related to safety, there are no specific requirements

addressing the issue of aging.

- Inservice Inspection requirements for the CCW system are governed by

ASME Section XI, and are included as part of the plant's technical

specifications. All the major pressure retaining components in the

system, and their supports must be inspected. However, the required

inspections are limited and include only visual inspections for

leakage while the system is pressurized.

- Inservice testing of the CCW system is governed by ASME Section XI

and is part of the plant's technical specifications. Periodic

8-2
testing of pumps, valves, and snubbers is required to verify that

the system can perform its design function if called upon.

Guidance on the performance testing of the CCW system is provided by

ASME-OM-S/G-1990, Part 2, however, this standard is not a

requirement. The guidance provided includes the evaluation of aging

degradation. This information is useful for evaluating the longterm effects of aging, and it is recommended that this information

be trended and used as an aging indicator.

The General Design Criteria require that the CCW system be

maintained throughout the life of the plant; however, no specific

guidance on how to accomplish this is given. No codes or -tandards

on system maintenance exist, although standards on good maintenance

practices for various components are available.

8.4 Conclusions From the Review of SSFIs

From the review of the NRC Safety System Functional Inspections, the

following conclusions were made:

Insights on the subject of aging in the CCW system have been gained

through the review of SSFI reports. Maintenance and surveillance

testing were the two inspection areas which provided the most useful

information for identifying aging problems.

The SSFI process is well suited for identifying the effects of aging

on the performance of a system. It can be effective in determining

how licensees manage aging with the inclusion of the recommendations

presented in Table 4.4.

One SSFI determined that CCW system design leakage may be

underestimated in several plant designs. For instance, one plant

did not design the makeup portion of the system as safety-related

because zero leakage was expected. However, experience has shown

that as valves, pumps, and heat exchangers age, leakage increases.

This aging process should have been considered in the system design.

One SSFI determined that the expected ambient temperature in the CCW

pump areas during an accident were not accurately represented at one

plant. A review indicated that the ventilation system would not be

operable in a postulated event, which would expose the CCW pump

motors to higher temperatures than they had been designed and tested

for. The long-term performance of CCW at this plant was essential

for decay heat removal. The SSFI report indicated that the stresses

which could affect operation of CCW had not been addressed

completely. The high temperature could impose aging mechanisms on

the equipment resulting in premature wear and failure. The

equipment should have been designed and tested to operate under

these conditions.

8-3
8.5 Recommendations

The results of the Phase I and Phase II aging studies show that the

Component Cooling Water system is susceptible to aging degradation. As the

system ages the likelihood of failures increases, which can adversely affect the

reliability of the system. However, there are measures that can be taken to

monitor and mitigate the effects of aging degradation. The following

recommendations will help ensure that plants have the most effective maintenance

and monitoring programs in place to manage aging.

- Personnel cognizant of the CCW system performance should understand

the characteristics of aging degradation presented in the phase I

study. This understanding will give them insight into what should

be monitored and what indicators should be expected for their

particular system.

- Cognizant utility personnel should review past operating and failure

data to determine if any aging trends are evident, such as

increasing failure rates. This review will help to identify the

extent and magnitude of aging mechanisms present, along with any

weaknesses in the current maintenance program.

- Current maintenance and monitoring programs should be reviewed in

relation to the aging mechanisms identified for a particular CCW

system. The review should ensure that effective techniques are in

place to detect and/or correct any aging conditions. The ISM&M

information presented in this phase II study can be used for this

purpose.

- Consideration should be given to incorporating techniques to detect

and monitor the effects of long-term aging, such as pipe wall

thinning and pump or valve body degradation. This type of aging

degradation takes many years to manifest itself, and is a potential

concern for extended life operation.

8-4
9. REFERENCES

1. Lofaro, R.J., et. al., "Aging Study of Boiling Water Reactor Residual Heat

Removal System," NUREG/CR-5268, June 1989.

2. Gunther, W.E., et. al., "Operating Experience and Aging-Seismic Assessment

of Battery Chargers and Inverters," NUREG/CR-4564, June 1986.

3. Subudhi, M., et. al., "Improving Motor Reliability in Nuclear Power

Plants," NUREG/CR-4939, June 1987.

4. Villaran, M., et. al., "Aging Assessment of Instrument Air Systems in

Nuclear Power Plants," NUREG/CR-5419, January 1990.

5. Subudhi, M., et. al., "Age-Related Degradation of Westinghouse 480-Volt

Circuit Breakers," NUREG/CR-5280, July 1990.

6. Greenstreet, W.L., et. al., "Aging and Service Wear of Motor Operated

Valves Used in Engineered Safety Feature SysLems of Nuclear Power Plants,"

NUREG/CR-4234, June 1985.

7. Meyer, L.C., "Nuclear Plant Aging Research on High Pressure Injection

Systems," NUREG/CR-4967, August 1989.

8. Bacanskas, V.P., "Aging and Service Wear of Solenoid Operated Valves Used

in Safety Systems at Nuclear Power Plants," NUREG/CR-4819, March 1987.

9. Higgins, J., et. al., "Operating Experience and Aging Assessment of

Component Cooling Water Systems in Pressurized Water Reactors," NUREG/CR5052, July 1988.

10. Morris, B.M. and Vora, J.P., "Nuclear Plant Aging Research (NPAR) Program

Plan," NUREG-1144, Rev. 1, September 1987.

11. Stellern, J. and Warren, J., "The Retubing of Large Shell and Tube Heat

Exchangers," Proceedings of the Joint ASME/IEEE Power Generation

Conference, Milwaukee, Wis., October 1985.

12. Gupta, J.P., Fundamentals of Heat Exchanger and Pressure Vessel

Technology, p. 280, Hemisphere Publishing Corp., 1986.

13. American Society for Metals, Metals Handbook, Volume 2, p.466 , 1979.

14. Kobrin, G., "Corrosion in Microbiological Organisms in Natural Waters,"

Material Performance, July 1978.

15. EPRI Report, "Effects of Sulfides, Sand, Temperature and Cathodic

Protection on Corrosion of Condensers," EPRI Report No. CS-4562, 1986.

9-1
16. Licina, G.J. , Sourcebook for Microbiologically Influenced Corrosion in

Nuclear Power Plants, EPRI Report No. NP-5580, p.5-3, 1988.

17. Fontana, M. and Green, N., Corrosion Engineering, p.198, McGraw-Hill,

1978.

18. Brobst, G.E., "Chromate Substitutes for Corrosion Inhibitors in Cooling

Systems," EPRI Report No. NP-5569, 1987.

19. Lyons, J.L., Lyons' Valve Designer's Handbook, p.71, Van Nostrand Reinhold

Co., New York, 1982.

20. Hutchison, J.W., ISA Handbook of Control Valves, p.122, 2nd edition,

Instrument Society of America, 1976.

21. Wilson, R.T.,"Graphite Packing Technique," Chapter 54 in Reference 19.

22. Ulich, H., Introduction to Industrial Polymers, Hanser Publishing Co.,

1982.

23. The Trade and Technical Press Ltd., Seals and Sealing Handbook, 2nd

edition, p.51, The Trade and Technical Press Ltd., England, 1986.

24. Lee, B.S., et. al., "Studies on Electrical Cable Insulation for Nuclear

Applications," Report No. BNL-43813, December 1989.

25. Karassik, I. et. al., Pump Handbook, McGraw-Hill, 1976.

26. Ingersol-Rand, Tyve S Horizontal Split Case Pump, Form 70510-I, IngersolRand Co., 1990.

27. American Society for Metals, Metals Handbook, Volume 3, p.802, American

Society for Metals, 1980.

28. U.S. NRC Inspection and Enforcement Manual, Chapter 2595., Appendix D,

"Safety System Functional Inspection," August 30, 1988.

29. American National Standard, "Nuclear Safety Related Cooling Water Systems

for Light Water Reactors," ANSI/ANS-59.1-1986.

30. American Society of Mechanical Engineers, "Standards and Guides for

Operation and Maintenance of Nuclear Power Plants," ASME/ANSI OM-S/G-1990.

31. Fousek, T. , "How Ultrasonic Instruments Aid Maintenance," Hydrocarbon

Processing, January 1988.

32. Vendor Catalog, "Using Ultrasonics", Maintenance Technology, August 1988,

Maintenance Log.

33. Bandes, Alan S., "Leak Detection Through Airborne Ultrasound," SENSORS,

November, 1987.

9-2
34. Foley, T., et. al., "Eddy Current Testing Detects Defective Tubes," Plant

Service, October 1989.

35. Ratjer, L.C., "NDE Helps Anticipate Heat Exchanger Problems," Power,

September 1990.

36. Vendor Catalog, "Shock Pulse Method for Bearing Analysis," Maintenance

Technology, Maintenance Log, February 1990.

37. Senum, G.I., et. al., "Adaption of the Perfluorocarbon Tracer Technology

for Aqueous-Phase Studies in Subsurface Applications," Brookhaven National

Laboratory Report No. BNL-43812, January 1990.

38. Greenstreet, W. L., et. al., "Aging and Service Wear of Check Valves Used

in Engineered Safety Feature Systems of Nuclear Power Plants," NUREG/CR4302, December 1985.

39. Murphy, G.A., and Cletcher, J.W., "Operating Experience Review of Failures

of Power Operated Relief Valves and Block Valves in Nuclear Power Plants,"

NUREG/CR-4692, October 1987.

40. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Notice 86-

96, "Heat Exchanger Fouling Can Cause Inadequate Operability of Service

Water Systems," November 20, 1986.

41. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Bulletin

81-03, "Flow Blockage of Cooling Water to Safety System Components by

Corbicula Sp. (Asiatic Clams) and Mytilus Sp. (Mussels)," April 10, 1981.

42. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Notice 85-

24, "Failures of Protective Coatings in Pipes and Heat Exchangers," March

26, 1985.

43. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Notice 85-

30, "Microbiologically Induced Corrosion of Containment Service Water

System," April 19, 1985.

44. U.S. Nuclear Regulatory Commission, Inspection and Enforcement Notice 81-

21, "Potential Loss of Direct Access to Ultimate Heat Sink," July 21,

1981.

9-3
APPENDIX A

Survey of PWRs
Enclosure I

CCW QUESTIONNAIRE RESPONSE BY PWR PLANTS

(Unless otherwise noted, numbers in parentheses are the number of units

responding. The number of units responding to a particular parameter,

activity, etc. may not add up to the number of units responding to a

questionnaire issue because not all respondents addressed the same

parameters, activities, etc.)

1. CCW Periodic Testing and Frequency

a. Pump Testing* Yes (12) No (0)

Parameter:

- Pump dP

- Suction P - Flow rate

- Vibration amplitude - Lubricant level

- Lubricant temp. - Vibration acceleration - Motor driver bearing temp.

- Pump performance test

- Motor current, voltage

Frequency in Months (# of units):

1(3),3(10)

1(3) 3(8)

1(2),3(4)

1(1),3(10),12(3)

3(4)

3(2),12(2)

18(2)

3(5)

3(1),12(1)

1(1), 3(1)

b. Valve Testing* Yes (12) No (0)

Parameter:

- MOV stroke time - Check valve leak - Check valve flow - Verification of remote

position indicator - Seat leakage (Type C.LLRT) - Relief valve setpoint verification - MOV signature analysis

Comments: One utility is planning to implement

analysis program.

3(10)

3(5), 18(4)

3(5)

18(1),24(2),36(1)

3(1)

60(3)

18(1)

an MOV signature

c. Hydrostatic Tests Yes (9)

120(7)

No (2)

d. System Logic Response Tests Yes (8), No (2)

Test:

- Slave relay tests

- Automatic actuation of components

e. Others:

- System leakage check

1(2) 3(3)

12(1),18(7)

- 3(1), 40(1)

*Pump and valve testing is performed per 10CFR50.55a(g) for ASIIE Code

components.

A-1
2. Preventive Maintenance Practices

a. Pump Inspection Yes (10) No (2)

Activities:

- Check lube oil level and temp. - Lube oil system preventive

maintenance - Radial bearing oil change - Thrust bearing oil change

- Coupling lubrication - Disassembly inspection - Coupling alignment - Gasket replacement (EQ) - Mechanical seal leak inspection

1*(1), 3(1)

6(2),12(2),18(2)

6(1),12(1)

6(1),12(1)

12(1),60(1)

48(1),60(1),90(1)

36(1)

84(1)

12(2)

b. Heat Exchangers Yes (5) No (7)

Activities:

- External visual inspection - Performance test

- Open/inspect

- Flow balance

- Eddy current tubes

c. Electrical Components

Not Specified (1)

18(1)

12(1)

18(2)

18(1)

Yes (12) No (0)

Activities:

Check lube level and clean air filters

Motor IR

Bearing lubrication

Switchgear circuit breaker maintenance

Pump circuit breaker maintenance

Motor inspection

Panel meter calibrate

Motor space heater check

Protective relay functional tests

Measure stator current

Thermoscan

Motor disassembly/inspection

Motor vibration measurement

EQ Inspections

Motor winding phase/polarization index

6(1)

12(3),18(2)

6(1),12(1),18(4)

12(2),18(2)

12(1),24(1)

48(1),60(2)

36(2)

12(1),18(2)

18f3f,24(1)

12(1)

60(1)

120(1)

3(2)

40(2)

18(2)

A-2
d. Instrumentation & Control Yes (10) No (0)

Activities:

- Calibration (CAL) surge tank

level/alarms loop. - CAL flow indicators - CAL heat exchangers flow loops - CAL header pressure switch - CAL react. cool. pump (RCP) ret.

flow indicators - CAL RCP thermal barrier temp. loop - CAL temperature indicating/alarm units - CAL contain. spray pump- seal- flow control - CAL pump suction pressure loop - CAL pump discharge press. transmitter - CAL heat exchanger outlet temp. loop - CAL RCP oil cooler return flow indicators - CAL motor stator temp. loops - CAL motor bearing temp. loops - CAL pump bearing temp. loops - CAL RHR heat exchanger flow alarms - Limit switch clean contacts - CAL RTD probe

12.(1),18(6),24(1),48(2)

12(1),18(6),24(1),48(2)

12(1),24(1),36(2)

12(1),36(2),48(2),96(1)

12(1,

12(1

12(1

12(1,

24(1:

12(1:

12(1;

36(2;

120(2j

120(2:

120(2,

36(2;

60(1:

48(1'

,24(1),36(2)

),24(1),36(2)

),24(1),36(2),48(2)

,36(2)

,18(6),96(1)

1.24(1)

e. Valves Manual (MAN)

Air-operated (AOV)

Motor-Operated (MOY)

Check (CHV)

Yes (5)

Yes (7)

Yes (8)

Yes (3)

No

No

No

No

(6)

(3)

(7)

(7)

Activities:

MAN

MOV

MOV

MOT

MOV

AOV

MOV

AOV

CHV

MOV

AOV

NOV

AOV

AOV

MOV

MOV

clean, lube stem

circuit breakers maintenance

IR test

operator maintenance

current, timing check

lubrication

operator EQ maintenance

packing replacement

inservice testing

packing replacement

diaphragm replacement

motor replacement (EQ)

disassembly, inspection

parts replacement (EQ)

disassembly, inspection

parts replacement

3(1'

12(1;

-12(1,

12(2;

12(1;

12(1;

18(2;

48 11

3(4,

36(1,

60(1

60(1

18(1

43(3

120(1

43(1

),12(2)

,18(1),36(2)

,18(2)

1,40(2)

1,18(2),48(1)

),120(1)

f. Others:

- Relief valve setpoint verification

- Vacuum breaker stroke

54(2), 120(1)

3(1)

A-3
3. Operational Activities

a. Equipment Rotation

Pumps

- Weekly (4) A - 2-3 wks. (1) - As required to equalize time (2) - Monthly (3) - Quarterly (2)

Heat Exchangers

- Rotate with pump weekly (1) - As required to equalize time (2) - Monthly (2)

b. Routine Readings Taken

Pump discharge pressure

Pump flow

- hourly by computer (1) - once per shift (1)

Motor amps

Motor winding temp.

Heat exchanger dP

Yes (12) No (0)

Yes (5) No (7)

Yes (5)

Yes (2)

Yes (5)

-Yes (1)

Yes (0)

No

No

No

No

No

(7)

(10)

(7)

(11)

(12)

- monitored when fouling expected (2)

Critical component flows

- CCW heat exchanger flow once per shift (1)

Yes (5) No (7)

Others:

- CCW surge tank level once per shift (3) - CCW heat exchanger outlet temp. every 4 hrs. (1) - CCW heat exchanger dT 1 hr by computer (l), once per shift (3) - Valve lineup verification monthly (1)

c. Is Chemical Treatment Performed

- Chromate (7)

- Hydrazine (1) - Nitrite borate (3)

Yes (13) No (0)

A-4
4. Reliability or Trend Analysis Program Yes (10) No (2)

- No program, but NPRDS, ISI/IST, PM data evaluated (4)

- Valve stroke times; pump dP, vibration, and bearing temp. (2)

- Pump flowrate dP and vibration, motor IR (1) - ISI/IST data (3)

- Pump vibration (2)

5. Procedure Copies

See Attachment 1 for procedure highlights. Copies of procedures from

volunteer plants are also attached.

6. Corrective Maintenance Summary Responding units (7)

( ) indicates number of occurrences reported

a. Pumps

- Rebuilt shaft and impeller (2)

- Realigned to eliminate excessive vibration (2)

- Repair leaking seals (10)

- Repair oil leak (8) - Repair water leak L.O. cooler (3)

- Repair oil flow indicator (1)

- Realigned bearing (2)

b. Valves

- Repaired seat leak (31) - Replaced or lubricate stem bushing (4)

- Repaired/replaced packing (15) - Repaired body-bonnet leak (3)

- Adjusted limit switch (19)

- Adjusted torque switch (8)

- Actuator repair EQ (5) - MOV repair mechanical (8)

- AOV repair mechanical (6) - Actuator repair electrical (8)

- Adjust relief valve setpoint (3)

- Replaced HAN valve (1)

Comment: Almost all MOV torque or limit switch adjustments that

affect valve closure require a seat leak test.

c. Instrumentation and Control

- Replaced failed level transmitter (1)

- Adjusted controller response band for temp. control valve (1)

- Reset temperature switch for solenoid valve (1) - Repaired loose solenoid causing improper valve operation (1)

- Reset air flow to isolation valve controller (1) - Vented total flow transmitter and recalibrated (1)

- Recalibrated numerous instruments due to drift

- Recalibrate pressure switch (4)

- Repair fluid leak at transmitter (4)

A-5
d. Electrical

- Replaced relay (4) - Replaced motor on MOV (1)

- Repair breaker (11) - Replace breaker (6) - Replace ammeter (2) - Repair motor cooler water leaks (not specified) - Replace pump motor bearings (2)

e. Heat Exchangers:

- Performed eddy current exam, plugged tubes (13) - Replaced anodes on service water side (4) - Inspected/cleaned tubes/tube sheet (20) - Sand blast, recoat water box (6) - Repair flange leak (6) - Replaced nozzles (1) - Weld repair end bell (3)

f. Other:

- Replaced rad. monitor power supply (1) - Replace snubber (7) - Repair snubber (5)

7. Effect of System Degradation on Tech. Specs

72 hour LCO for one of two trains out of service (4)

24 hour LCO for one of three trains out of service (2)

8. Three Parameters Assuring Operational Readiness

a. Pumps/Motors

- Inlet pressure (1) - Differential pressure (3) - Flow rate (3)

- Vibration amplitude (1) - Lubrication (1) - CCW pump testing (7)

b. Valves

- Surveillance (IST) procedures (8) - Valve lineup (1)

c. Instruments

- testing, calibration, PMs (3)

d. Heat Exchangers

- dP check (2)

e. Operator/Supervisor plant tours (1)

A-6
NRC FORm 335 UiS.NUCLEARREGULATORCOMMISSION 1. REPORT NUMBER

NRM1 1029 (AsIgnwd by NRC. Add Vo._ Supi.. Rev.. NRC201102. BIBLIOGRAPHIC DATA SHEET Sad Addenduffl NUmbers. if gnV. v

See insrtruction on the ,etersej NUREG/CR-5693

2. TITLE AND SUBTITLE BNL-NUREG-52283

Aging Assessment of Component Cooling Water Systems in

Pressurized Water Reactors 3. DATE REPORT PUBLISHED

MONTH j YEAR

June 1992

4. FIN OR GRANT NUMBER

A3270

5. AUTHOR IS) 6. TYPE OF REPORT

R. Lofaro, W. Gunther, M. Subudhi, B. Lee

7. PERIOD COVERED Urncdusi, Dmro.

W PPARflARlId. AfAt7ATI1A*V - dAEC AMIlN AflhaEte an Kot" I. . p .. v .tl.

,lame end mailing eddes ,.)

Brookhaven National Laboratory

Upton, NY 11973

9. SPONSORING ORGANIZATION -NAME AND ADDRESS IW NRC. ue -Vwm A sbowe- icencm pmvid#NRC Divion. Ofi k o Reoia. U.S Nude.rReglatory Comamshon,

.nd m~ailin addftvuj

Division of Engineering

Office of Nuclear Regulatory Research

U.S.. Nuclear Regulatory Commission

Washington, DC 20555

10. SUPPLEMENTARY NOTES

11. ABSTRACT 1200 owramtJ

A two-phase aging analysis of component cooling water (CCW) systems in pressurized water reactors

(PWRs) was performed. In phase 1, which was published separately as NUREG/CR-5052, the effects of aging

on the CCW system were characterized, and the predominant failure modes, aging mechanisms, and

components susceptible to aging degradation were identified. Failure rate trends were examined, and their

effect on time-dependent system unavailability was investigated.

In phase II, which is the subject of this report, the methods used to manage aging degradation in the

CCW system were studied. Information was collected and analyzed on inspection, surveillance, monitoring,

and maintenance techniques from a survey of operating PWRs. The results are presented herein. Advanced

techniques that may help detect and mitigate aging degradation also are included. A detailed examination

of the materials of construction and their relationship to various aging mechanisms is discussed.

In addition, the various standards, codes, and regulatory requirements that govern the design,

construction, and operation of the CCW system were investigated. Recommendations to better manage aging

degradation in component cooling water system are discussed.

12. KEY WORDS/OESCRIPTORS tust wohc hrphaws that wiibittArtahaorni mecaing the 3o0nt.) 13. AVAILABILITY STATEMENT

unlimited

Aging; Light Water Reactors; Component Cooling; Failure Rates; 14. SECURITY CLASSIFICATION

Failure Modes; Aging Mechanisms; Inspection Practices IThis Pe

unclassified

.rha Revorrt

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC FORM 335 (2891
THIS DOCUMENT WAS PRINTED USING RECYCLED PAPER
UNITED STATES

NUCLEAR REGULATORY COMMIJSSION

WASHINGTON, D.C. 20555-0001

FIRST CLASS MAIL

POSTAGE AND FEES PAID.

USNRC I

PERMJTNO. G-67

BUSINESS

IVATE USE, $300

n '

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REPORT. SECTION 9700 S CASS AVE - .

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ARGONNE 

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