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208 LIBRARY

NUREG/CR-4597

Volume 2

ORNL-6282/V2

AUG 19 1988 (c<V

REPACToMt Si., c;( ane,

APPLIED PMASICS

Aging and Service Wear of Auxiliary

Feedwater Pumps for PWR

Nuclear Plants

Volume 2. Aging Assessments and

Monitoring Method Evaluations

D. M. Kitch

J. S. Schlonski

P. J. Sowatskey

W. V. Cesarski

I

I C- L"

QC LU -

U. :D

.' II . I

I I.. I

,I .I'. I.

Prepared for the U.S. Nuclear Regulatory Commission

Office of Nuclear Regulatory Research

Under Interagency Agreement DOE 0551-0551-Al

NRC FIN No. B0828

.2..-

(PERATED BY

MARTIN MARIETTA ENERGY SYSTEMS. INC.

FOR THE UNITEO STATES

DEPARTMENT OF ENERGY

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NUREG/CR-4597

Volume 2

ORNL-6282/V2

Dist. Category RV

AGING AND SERVICE WEAR OF AUXILIARY FEEDWATER PUMPS

FOR PWR NUCLEAR PLANTS

Volume 2. Aging Assessments and Monitoring

Method Evaluations

D. M. Kitch P. J. Sowatskey

J. S. Schlonski W. V. Cesarski

Manuscript Completed - May 31, 1988

Date Published - June 1988

Report Prepared by

Westinghouse Electric Corporation

Generation Technology Division

P.O. Box 355

Pittsburgh, Pennsylvania 15230

under

Purchase Order No. 41X-56549 V

for Oak Ridge National Laboratory

Work Performed for

U.S. Nuclear Regulatory Commission

under

DOE Interagency Agreement No. 0551-0551-Al

NRC FIN No. B0828

OAK RIDGE NATIONAL LABORATORY

Oak Ridge, Tennessee 37831

operated by

MARTIN MARIETTA ENERGY SYSTEMS, INC.

for the

U.S. DEPARTMENT OF ENERGY

under Contract No. DE-AC05-840R21400

-S
. iii

CONTENTS

Page

LIST OF FIGURES .................. vii

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

ACKNOWLEDGMENTS . ....... .......... xi

EXECUTIVE SUMMARY ................ . xiii

1.1 Background ...... ;2

1.2 Project Scope . ......................................... 2

2. FAILURE.CAUSES . ............................................... 4

2.1 Result from Postservice Examinations and In Situ

Assessments ................................... 4

2.2 Failure Causes ....... 4..................................

4

.2.2.1 Failure cause identification . .................... 4

2.2.2 Failure causes attributable to various

categories ....................................... 6

3. CANDIDATE ASCM METHODS ....................................... 31

3.1 Potentially Useful ISCM Methods ........ .................. 31

3.2 Potentially.Useful ISCH Methods and Their Relation

to Aging and Service Wear ............................... 31

3.2.1 Rotor binding inspection ........................ 31

3.2.2 Visual inspection ............................... 31

3.2.3 Motor current monitoring ........................ 34

3.2.4 Motor power'monitoring ...... .................... 34

3.2.5 Turbine power monitoring ..... ................... 34

3.2.6 Rotational speed monitoring . 34

3.2.7 Dimensional inspection ........................... 34

3.2.8 Pump pressure or developed head monitoring ...... 35

3.2.9 Pump-delivered flow monitoring .................. e 35

3.2.10 Rotor vibration monitoring ........ ...............* 35

3.2.11 Incipient failure detection monitoring ...... T.... 36

3.2.12 Liquid penetrant inspection ..................... 36

3.2.13 Balance return-line flow monitoring ............. 36

-3.2.14 -Audible noise inspection ..... ................... 36

3.2.15 Bearing temperature monitoring .................. 37

3.2.16 Stuffing box temperature monitoring .............. 37

3.2.17 Rotor axial position monitoring ..... ............ 37

3.2.18 Bolt torque inspection 37

3.2.19 Leakage rate inspection ............ ............. 37

3.2.20 -Lube oil analysis and quantity inspection ........ 38

3.2.21 Dynamic pressure monitoring ... ............. 0........ 38
iv

Page

3.3 Summary of Measurable Parameter vs Degradation

Correlations * ........................................... 38

4. EVALUATION OF ISCM METHODS ......................................... . 40

4.1 Recommended ISCM Methods ................................ 40

4.2 Further Discussion of Recommended ISCM Methods .......... 40

4.2.1 Rotor binding inspection ..... ................... 44

4.2.2 Visuai inspection ........ .. . . . .. . . . . . ........ ...... . 44

4.2.3 Motor-power monitoring ........................... 45

4.2.4 Rotational speed monitoring ..... ................ 45

4.2.5 Dimensional inspection ........ .................. 46

4.2.6 Pump pressure or developed head monitoring ...... 46

4.2.7 Pump-delivered flow monitoring ... ............... 46

4.2.8 Rotor vibration monitoring .. * .......... 47

4.2.9 IFD monitoring . ........ .. ...... .. *.. .. o ..... 58

4.2.10 Liquid penetrant inspection .... o ................ 60

4.2.11 Balance return-line flow monitoring ....... o..... 60

4.2.12 Audible noise inspection ..... ................... 60

4.2.13 Bearing temperature monitoring .................. 61

4.2.14 Rotor axial position monitoring ................. 61

4.2.15 Bolt torque inspection .......................... 62

4.2.16 Leakage rate inspection ....... 63

4.2.17 Lube oil analysis and quantity inspection ... o... 63

4.3 Parameter Monitoring to Establish Trends ................ 64

5. THE ROLE OF MAINTENANCE IN ALLEVIATING AGING AND

SERVICE WEAR ..... o ..................... o....... ............ 66

5.1 Types of Maintenance ..................... o.... ..... o... 66

5.1.1 Predictive maintenance ........................... 66

5.1.2 Preventive maintenance ..... ...................... 67

5.1.3 Corrective maintenance ........................... 67

5.2 Vendor Recommendations .... ........ . . . . . .................. e ......... . 68

5.3 Current Utility Practices ............................... 68

5.3.1 Regular maintenance ...... ................... ..... 69

5.3.2 Surveillance and condition monitoring ............ 69

5.4 Inspection, Surveillance, and Maintenance Practice

Recommendations ............ 0..... . ........................ 70

5.4.1 Regular nondisassembly inspection,

surveillance, and maintenance .......... ... o....... 70

5.4.2 Surveillance and condition monitoring ............ 70

5.4.3 Periodic inspection, surveillance, and

* maintenance .... .o. ... ...o o.o .. . .. . ......... ..... . 73

5.5 Maintenance Practice Evaluations .. o .............. oooo 74

6.- SUMMARY AND CONCLUSIONS .o ... o..oo.........o.. ............. ...... 77
v

Page

REFERENCES ............... ........................................ 80

BIBLIOGRAPHY **************...................*.................. . 81

APPENDIX A. DEFINITIONS ......... o.*..........***so........ 85

APPENDIX B. OPERATING EXPERIENCE DATA BASES AND REPORTS ......... 93

APPENDIX C. INSTALLATION LIST ..... o..oo.. ........................ 103

APPENDIX D. LOW-FLOW TESTING ...... o .... ...... ... oo............... 109

APPENDIX E. TYPICAL AUXILIARY FEEDWATER SYSTEM DESCRIPTION

FOR WESTINGHOUSE PWR PLANT .... o.... .................. 111

APPENDIX F. AUXFP MINIMUM-FLOW RATE CRITERIA .... ................ 117

APPENDIX G. TEST GUIDELINES FOR FULL-FLOW TESTING .... ........... 123

-J
vii

LIST OF FIGURES

Figure Page

2.1 Packed stuffing box ................................... .11

2.2 Condensate cooling system- 12

2.3 .................. Packing loading - 13

2.4 Live-loaded Live-loaded pump packing 13

2.5 Mechanical seal assembly 14

2.6 Wear ring ring and and impellWear impeller combination 17

2.7 Effect of wear on head capacity curve ... 17

2.8 O-ring under flinger 21

2.9 Bearing housing lip seal 22

2.10 Bearing housing shield 23

2.11 Raised vent and oil fill ..... 24

2.12 AUXFP bearing system 25

2.13 Tilt pad thrust bearing system 25

2.14 Disk spring design 26

4.1 Ideal 90° out-of-phase time histories and frequency

spectra for shaft proximity probes mounted 90°

apart on the circumference of an AUXFP shaft .o.o....o..o 49

4.2 Lissajous pattern, time histories, and frequency

spectra of pump data including misalignment,

bearing wear, or possible unbalance 50

4.3. Lissajous pattern, time histories, and frequency

spectra of pump data showing a combination of

misalignment or unbalance, rubbing, sliding,

and impacting 51

4.4 Lissajous figure, time histories, and frequency

spectra of pump data showing a combination of

possible vibration indications ........... 52

4.5 Spectrum overlay of ball bearing vibration

progressing to wear failure 57

4.6 Relative signal amplitude vs days to failure for

acoustic and conventional vibration monitoring

methods oo o o o o o o o o o o o oo o o o o ~ o o * o o o 59

5.1 Means to predictive maintenance o..oo..oooooo.oo..oooo 66

E.1 AFW system simplified schematic .............. oo...... 111

E.2 Flow diagram (typical) AFW system four-loop plant o...... 112
viii

Figure Page

F.1 Anticipated useful operating ranges for pumps

used in large nuclear and fossil power

generating units ... .00......... ..... *O.*................. 118

F.2 Minimum continuous stable flow, percentage of

BEP capacity at maximum diameter impeller 119

F.3 Minimum flow correction factor 120
ix

LIST OF TABLES

Table Page

2.1 Pump failure causes-related to aging and service wear .... 5

2.2 Pump failure causes attributed to aging and service .

wear-rankings according to overall terns of'importance,

-frequency of occurrence,.interaction consequences, and -

influence on operational readiness ........................ 7

2.3 Antifriction bearing degradation ......................... 9

2.4 Plain bearing (journal) degradation 10 10

2.5 Packing troubles, their cause and cure 15

2.6 The importance of maintenance in mitigating pump

failure causes attributed to aging and service wear ...... 28

3.1 Failure causes and measurable parameters to be

considered in an AUXFP ISCM Program ...................... 32

3.2 Measurable parameters and their relative ISCM methods .... 33

3.3 Parameter vs degradation correlation ..................... 39

4.1 ISCM evaluation summary ................................. . 41

4.2 Vibration causes and characteristics ..................... 54

5.1 Recommended inspection and surveillance practices

for AUXFPs' .... o......o..o...o...o.... ooooeo........... 71

5.2 Periodic inspection, surveillance, and maintenance

interval guidelines for AUXFPs ... ........................ 75

5.3 Maintenance practices evaluation .......................... 76

B.1 Summary of AUXFP-type failures reported in LERs

(1973--1983) o. . . .o o . 04 .0 0 .. . 6 0 * . . .of 94

B.2 Summary of AUXFP-type failures reported in LERs

(1985-1986) failures orted 95

B.3 AUXFP-type failures reported in NPRDS data base

(1974-1985) 96.. .................. o........ 97

B.4 Summary of AUXFP-type failures reported in NPRDS

data base ( 1986) o00000 000...0000...00 97

B.5 Summary of HHSIP failures reported in LERs

(1973-1986) ... o..... .. oo**oo.*.*o.. 98

B.6 Summary of HHSIP failures reported in NPRDS

(1974-1985) ...... ........ .. eo .. ****** 99

B.7 HHSIP failures reported in NPRDS data base for

<3600 rpm (1974-1985) 100

B.8 Ten major outage-producing failure causes for

feed pumps .. ~.066 ... O.000000 ... O*.101
I

x

Table Page

B.9 Typical failure causes reported for U.S. petrochemical

plants (centrifugal pumps) 101

B.10 Typical failure causes reported for several foreign

petrochemical plants (centrifugal puups) 102

C.1 Installation list, Ingersoll-Rand ..... .105

C.2 Installation list, Bingham .... 106

C.3 Installation list, Pacific Pumps .......... 106

C.4 Installation list, Byron-Jackson 107

o-f
xi

ACKNOWLEDGMENTS

* The authors wish to thank W. L. Greenstreet for his direction and

advice in compiling this report. We also wish to thank the following

equipment suppliers for their valuable discussions and input.

G.

D.

J.

L.

D.

W.

T. Morrissy

Bowman

McKenna

Boswell

Cummings

Lund

Pacific Pumps Division, Dresser

Pacific Pumps Division, Dresser

Ingersoll-Rand, Pump Division

Byron Jackson Pump, Borg-Warner

Bingham International

Crane Packing Company

Industries

Industries
xiii

EXECUTIVE-SUMMARY

This report addresses aging assessments and monitoring method evaluations for auxiliary feedwater pumps (AUXFPs). It is a continuation of

the findings reported in Vol. 1,- Operating Experience and Failure Identification. .

The report contains four major sections:

1. failure causes;

2. review of inspection, surveillance, and condition monitoring (ISCM)

methods;

3. evaluation of ISCM methods; and

4. role of maintenance in alleviating aging and service wear.

The identification of failure causes is based on the results from

Vol. 1 and Westinghouse postservice examinations and in situ assessments.

Failure causes are attributable to various categories, such as

1. aging and service wear;

2. design and installation;

3. testing;

4. maintenance; and

5. other.

Pump failures attributed to aging and service wear are ranked

according to frequency of occurrence, influence on operational readiness,

and interaction consequences. An overall ranking was developed that

allows the causes of failure to be listed in order of importance. Of the

20 failure causes listed in the report, the 15 most important are ranked.

Following are the five that rank highest in importance: (1) bearing

wear, corrosion, and breakage; (2) shaft seal deterioration and breakage;

(3) binding between rotor and stationary parts; (4) impeller wear and

breakage; and (5) thrust balancer wear, galling, and seizing.

Measurable parameters related to failure causes are identified.

These parameters include rotational torque, appearance, pump speed, wear

surface and critical fit clearance, pump head, delivered flow, vibration,

balance return-line flow, noise, temperature, rotor axial position, fastener torque, leakage, lube oil purity, motor power, and surface indications. The ISCM methods that correlate to these measurable parameters

are reviewed. Discussions of the relationships of identified ISCM

methods to the detection of aging and service wear and to the establishment of degradation trends are included.

ISCM method recommendations are given. These were developed through

evaluations based on Westinghouse experience and are intended to yield

required capabilities for establishing operational readiness and determining degradation trends. Recommended ISCM methods include rotor binding inspection, visual inspection, dimensional inspection, audible noise

inspection, bolt torque inspection, leakage rate inspection, lube oil

analysis inspection, liquid penetrant inspection, rotational speed moni-

*toring, developed head monitoring, delivered flow monitoring, vibration

monitoring, balance return-line flow monitoring, incipient failure
xiv

detection monitoring, bearing temperature monitoring, rotor axial position monitoring, and motor power monitoring. ISCM evaluations are summarized. They considered the effectiveness in determining aging and

service wear, importance in terms of safety, and implementation ease and

cost.

The role of maintenance in mitigating aging and service wear effects

is discussed. Current utility practices and procedures are reviewed, as

are vendor recommendations. Recommendations regarding inspection and

surveillance practices for guiding maintenance actions are provided, and

relationships between maintenance practices and ISCM methods are identified. Both regular maintenance and periodic inspection surveillance and

maintenance practices are discussed. Also considered are recommended

maintenance intervals. Predictive, preventive, and corrective maintenance practices are evaluated in terms of their effectiveness in addressing the identified failure causes.

Appendixes are included that contain definitions, failure data base

information, AUXFP installation lists, discussion of low-flow testing,

auxiliary feedwater (AFW) systema description, AUXFP minimum-flow-rate

criteria, and Westinghouse proposed guidelines for full-flow testing.
AGING AND SERVICE WEAR OF AUXILIARY FEEDWATER PUMPS

FOR PWR NUCLEAR PLANTS

D. M. Kitch P. J. Sowatskey

J. S. Schlonski W. V. Cesarski

ABSTRACT

This report was produced under the Detection of Defects

and Degradation'Monitoring Element-of the Nuclear Plant Aging

Research Program. It addresses aging assessments and monitoring method evaluations for'auxiliary feedw'ater.pumps (AUXFPs).

The report contains-four major'sections:

1. 'failure causes;

2. review of inspection,'surveillance, and'condition monitoring (ISCM) methods;

3. evaluation of ISCM methods; and

4. role of maintenance in alleviating aging and service wear.

Failure causes attributable to aging and service wear are

given and ranked in terms of importance. Cause identifications are made on the bases of experience, postservice examinations,.and in situ assessments.

Measurable parameters related to failure' causes are identified. ISCM methods are also identified, evaluations are

made based'on Westinghouse (W) experience, and recommendations

are given.' The methods are intended to yield'required capabilities for establishing'operational readiness, as well as

for detecting andtracking degradation.'

The role of maintenance'in mitigating aging and service

wear effects is discussed, and the relationship-of maintenance

to ISCM methods is-identified. Predictive, preventive, and

corrective maintenance practices are discussed and evaluated.

Appendixes have been included that contain failure data

base information, AUXFP installation lists; discussion-'of lowflow testing, auxiliary feedwater system description, AUXFP

minimum-flow-rate criteria,''and W proposed guidelines for

full-flow testing.
2

1. INTRODUCTION*

1.1 Background

This report is the second of three volumes on the study of aging and

service wear of auxiliary feedwater pumps (AUXFPs) in pressurized-water

reactor (PWR) nuclear power plants. This study program is sponsored by

the Office of Nuclear Regulatory Research (RES) of the U.S. Nuclear Regulatory Commission (NRC).

The first volume was entitled Operating Experience and Failure Identification and addressed the time-related degradation of AUXFPs. This

report builds on the results of the first by expanding on the identification, categorization, and ordering of aging and service wear related

failures; providing a review and evaluation of inspection, surveillance,

and condition monitoring (ISCM) methods; and discussing the role of maintenance in reducing or correcting aging and service wear effects. All

definitions are listed in Appendix A.

1.2 Project Scope

Following is a summary of the three volumes.

Volume 1 - Operating Experience and Failure Identification (Phase 1)

1. background information on AUXFPs - boundary of AUXFPs to be studied,

types, functional requirements, and materials of construction;

2. reviews of regulatory requirements, guides, and standards;

3. summary of operational and environmental stressors;

4. summary of operating experience;

5. manufacturers', input; and

6. state-of-the-art aging and service wear monitoring and assessment.

Volume 1 has been published and issued as NUREG/CR-4597, Vol. 1 (ORNL6282/V1) in July 1936.

Volume 2 - Aging Assessments and Evaluation of Monitoring Methods

(Phase 2)

1. detailed identification of failure causes based on results from postservice examinations and in situ assessments; also classification and

ordering of those causes;

2. review of currently used and developmental ISCM methods;

3. evaluation and recommendation of ISCM methods; and

4. examination of the role of maintenance in mitigating aging and ser- I'

vice wear effects and recommendations.

*Due to the nature of this subject matter and current practice in

this field, SI units will not be used.
3

Baseline information used in the preparation of Vol. 2 was derived from

Vol. 1 and other sources.

Volume 3 - Analysis and Recopmendations

1. application of ISCM practices;

2. operational readiness acceptance criteria; and

3. criteria for maintenance, repair, or replacement.

The identification and analysis of failure causes in Vol. 2 are

based on the premise that information in existing data bases regarding in

situ testing and postservice examinations and tests is sufficient and

that no additional examinations and tests supported by the Nuclear Plant

Aging Research (NPAR) Program are needed. The results of the studies

described in Vol. 2 attest to the validity of that premise.
4

2. FAILURE CAUSES

2.1 Results from Postservice Examinations

and In Situ Assessments

Various data sources were used to assemble the results of this

report. Westinghouse (W1) sources include pump vendors (many of whom are

involved in AUXFP manufacturing), architect engineers, nuclear and fossil

utility companies, Si site service representatives [located on many nuclear plant sites using W nuclear steam supply systems (NSSSs)], foreign

architect engineers and pump vendors, chemical and petrochemical plants,

and other NSSS suppliers. In particular, valuable information and discussions were provided through utility personnel and representatives from

Ingersoll-Rand; Byron-Jackson; Pacific Pump Division, Bingham-Willamette;

and the John Crane Packing Company. Also, W has performed (1) design

evaluations on numerous pumping systems, (2) failure studies, and

(3) analyses on numerous pump types used in the nuclear industry.

Other data sources retrieved through W facilities include reports

about the High Head Safety Injection Pump (HHSIP). The HHSIP, although

installed on the primary side of the nuclear plant, is functionally very

similar to the AUXFP because it is an intermittently operating safetyrelated pump. HHSIPs are typically multistage, split-case, electricmotor-driven pumps that operate at 3600 rpm. They are similar in construction to AUXFPs except that HHSIPs are constructed of stainless steel

and employ mechanical shaft seals instead of stuffing box packing. HHSIP

data (Appendix B) are provided as a comparison to the AUXFP data. Other

operating experience data base information is also provided in Appendix B.

Appendix C contains installation lists for AUXFPs and provides general

reference data.

2.2 Failure Causes

2.2.1 Failure cause identification

Failure cause nomenclature for this report was obtained from Vol. 1

to ensure that Vols. I and 2 are consistent. Specifically, only the

failure causes considered to be proximate causes are addressed.

Table 2.1 is a master list of failure causes compiled from the

studies and data base information of Vol. 1 and the postservice examinations and in situ assessments of Vol. 2. Also given in Table 2.1 are

correlations between failure causes and failure modes. The latter are

failure to operate, failure to operate as required, and external leakage.

(See Vol. 1 for explanations of failure modes.)

Failure causes not identified by postservice examination and in situ

assessments but identified in Vol. 1 include the following. -'
5

Table 2.1. Pump failure causes related

to aging and service wear

Failure

Pump segment Parts Failure cause modesa

1 2 3

Rotating Binding between rotor and sta- X

elements tionary parts

Shaft Shaft breakage X

Impeller Impeller wear, breakage X

Thrust runner Thrust runner wear, breakage X X

Fasteners Fastener loosening, breakage X X

Nonrotating Diffusers Structural damage to stationary X

internals or volutes vanes (diffuser or volute)

Wear surfaces Wear-surface wear, erosion, X X

corrosion, seizing

Fasteners Fastener loosening, breakage X

Pressure Casing Leak at casing split X

containment Leak at casing rupture disk X

casing Suction nozzle Suction nozzle leak, breakage X

Discharge nozzle Discharge nozzle leak, breakage X

Fasteners Fastener loosening, breakage X

Mechanical Bearings Bearing wear, corrosion, breakage X X

subsystems Shaft seals Shaft seal deterioration, breakage X X

Thrust balancer -Thrust balancer wear, galling, X X

seizing

Coupling Coupling wear, breakage X X

Fasteners Fastener loosening, breakage X

Support Base frame - Base frame breakage X

Fasteners Fastener loosening, breakage X

aFailure mode designation:

1 - Failure to operate

- 2 - Failure to operate as required -

3 - External leakage
6

Pump segment Failure cause

Nonrotating internals Structural damage to stationary vanes

(diffuser or volute)

Pressure containment Suction nozzle leak, breakage; discharge -

casing nozzle leak, breakage; fastener

loosening, breakage

Support Base frame breakage; fastener loosening,

breakage

A failure cause not identified in Vol. 1 but identified from the

postservice examination and in situ assessment data is casing rupture

disk leak.

2.2.2 Failure causes attributable to various categories

Although the aging and service wear category is the focus of this

report, other categories have also been reviewed:

1. aging and service wear,

2. design and installation,

3. testing,

4. maintenance, and

5. other.

Each of these is discussed in the subsections that follow.

2.2.2.1 Aging and service wear. Table 2.2 ranks pump failure

causes attributed to aging and service wear according to (1) overall

terms of importance, (2) frequency of occurrence, (3) interaction consequences, and (4) influence on operational readiness. The lowest number, unity, corresponds to the highest ranking. Rankings beyond 15 are

not given because there is no meaningful basis for the assignment of

larger numbers.

The ranking for overall terms of importance was obtained from a

weighted average of the ranked categories, frequency of occurrence,

interaction consequences, and influence on operational readiness. The

weighting criteria used to establish the ranking for overall terms of

importance was frequency of occurrence (low), interaction consequences

(medium), and influence on operational readiness (high).

For most rotating machinery (e.g., pumps, compressors, and turbines), regardless of application, the most predominant failure causes

appear to be (1) shaft seal deterioration and breakage and (2) bearing

wear, corrosion, and breakage. The single most frequently reported

failure cause attributed to normal wear was shaft seal (packing) leakage,

but bearing wear, corrosion, and breakage ranked first in terms of over- -

all importance. Each of the 15 causes ranked is described in more detail

in the following paragraphs.

Bearing wear, corrosion, and breakage. Bearing-related problems

rank first in overall terms of importance in the aging and service wear

category. Bearing failures are the second most frequently reported failure and also have a significant impact on operational readiness.
i

7 - I

Table 2.2. Pump failure causes attributed to aging and service wear

rankings according to overall terms of importance, frequency

of occurrence, interaction consequences and

influence on operational readinessd

Pump segment Parts Failure cause 0 FO IC OR

Rotating Binding between rotor 3 3 4 2

elements and stationary parts 6 9 3 3

Shaft Shaft breakage 4 4 5 7

Impeller Impeller wear, breakage

Thrust runner Thrust runner wear, 10 13 7 6

breakage

Fasteners Fastener loosening, 8 7 10 10

breakage

Nonrotating Diffusers or Structural damage to 14 >15 14 13

internals volutes stationary vanes

(diffuser or volute)

Wear surfaces Wear-surface wear, 7 6 8 9

erosion, corrosion,

seizing

Fasteners Fastener loosening, 12 10 12 12

breakage

Pressure Casing Leak at casing split 13 11 15 15

containment Leak at casing rupture >15 14 >15 >15

casing disk

Suction nozzle Suction nozzle leak, >15 >15 >15 >15

'breakage

Discharge nozzle Discharge nozzle leak, >15 >15 >15 >15

breakage

Fasteners .. Fastener loosening, >15 15 >15 >15

breakage

Mechanical Bearings Bearing wear, corrosion, 1 2 2 1

subsystems breakage

Shaft seals Shaft seal deterior- 2 1 1 4

Thru-tbalancer - ation, breakage

Thrust balancer .Thrust balancer wear, 5 5 6 5

galling, seizing . -

Coupling Coupling wear, 11 12 9 8

breakage

Fasteners Fastener loosening, 9 8 11 11

breakage

Support Base frame Base frame breakage >15 ->15. 13 14

Fasteners Fastener loosening, 15 >15 >15 ->15

breakage

aThese rankings are abbreviated as follows:

0.- Overall.terms of importance (weighted average of FO, IC, and OR)

FO - Frequency of occurrence -

IC - Interaction consequences-(one cause activating others)

OR - Influence on operational readiness
8

Even when properly applied and maintained, a rolling contact bearing

will be subjected to normal fatigue wear and ultimately fail. Fatigue

wear results from the cyclical shear stresses immediately below the bearing load carrying surfaces. However, premature bearing failure is normally associated with one or more of the following nonaging or service

wear related factors:

1. defective bearing seats on shafts and in housings,

2. misalignment,

3. faulty mounting,

4. incorrect shaft and housing fit,

5. inadequate lubrication,

6. ineffective sealing (dirt and moisture),

7. vibration while the bearing is not rotating, and

8. passage of electric current through the bearing.

When the amount of lubrication is inadequate, the bearing will overheat,

wear, and eventually fail. An excessive amount of lubricant can also

produce an excessive temperature rise because of churning. Overheating

creates a breakdown of viscosity in the lubricant, rendering it inadequate. Water has a similar degrading effect on oil viscosity. Also,

water will begin to corrode the rollers, balls, or races of the bearing

and ultimately lead to failure. This phenomena is characteristic of

AUXFPs that normally remain idle. Because these pumps can be driven by

steam turbines or are located near steam pipes, both of which produce

high-humidity environments, the probability of the condensate accumulation in the lubricant can be high. Also, leaking packing or mechanical

seals can result in lubricant water contamination.

Another factor that must be considered for idle equipment is false

brinelling, which is vibration-fed through the foundation or piping system. This problem is caused by the continuous single-point impact of the

rollers against the raceway. False brinelling can be mitigated by periodically rotating the shaft. Tables 2.3 and 2.4 show various failure

mechanisms for antifriction and sleeve bearings, respectively.

Shaft seal deterioration and breakage. Shaft seals have the highest

frequency of failure occurrence of any pump part. Their frequency of

failure is disproportionately large compared with most other failure

causes. Shaft seal failures rank highest in interaction consequences, in

particular, the relatively frequently reported occurrences of water contamination in the lubrication system caused by leaking shaft seals.

The shaft seals used in AUXFPs are typically made of packing that is

contained within a stuffing box located near each shaft end. Packing is

the material used in an AUXFP to throttle or restrict feedwater leakage

between the moving shaft or shaft sleeve and stationary part, normally

called the "packing gland." Packing wear is a function of various factors, such as temperature, pressure, chemical action, shaft runout, shaft

gyration, misalignment, pump vibration, and shaft surface condition.

Figure 2.1 shows the typical' cross section of a packed stuffing box. One

characteristic feature of a packed stuffing box is that the packing must

be permitted to leak to provide lubrication and cooling to prevent overheating and premature failure.
9

Table 2.3. Antifriction bearing degradation

Resulting degradation

Fracture/ Deformation wear Corrosion

separation I D iC

Failure mechanisms

bO

c

5.4a

-441

Sc

0.

gn

1.4

U

ba

to

S.

C

a

W

U

.I

to

IV.

0

v

So

a

C-,

0

n

-0.

r0.

4W

Co

C

r

4j

CC

a

Wa

WSn

a.

to

.0.

4-A

._C

*e

'C

44

Z

C

a

-C

._

0. at

DI a

.._

0.

0

C

C

40-

a.

0

C

a

v

In

_o1

1.4

a

a

-4

_a

a,

a

be

C

D

4

C

C

S.

0

.0

4

S. W

a,

%a

C

-4

C

v

W

oC

0

'v

0

L.4

SO144

0'

_,2

0

.44

0

U

.4

a.

toC

C

a,

a,

a

So

C.

-14

ba

to

vO

Assembly

Excessive, uneven heat _0

application _

Hammer blows - _ 0

Improper tooling _ 0 0 0

Loose/tight fits a I 0 0

Distorted bearing _0 _ a 

housing.

Rotor unbalance _ _ _

Misalignment _ _ _ 0 0

Operating conditions

Vibration Stationary - r T$ 1

Current-passage . . - 1 1 -I T

Life attainment/fatigue c . - I

Overload | *0 a 

Design error | 0 0

Seal

Contamination I 1 L | 0 

Moisture ingress | | 1 1 _ _ J j * 0 

Lubrication

Lack of lubricant T9 lb 0 S'|

Excess of lubricant |0| V 

Unsuitable lubricant -1 - | | -0 *1 .T 

Source: Reprinted with permission from H. P. Bloch and F. C. Gietner, PracticaZ Machinery

Management for Procese Plante, VoZ. 2, Machinery FaiZure AnaZyeis and TroubZeshooting7, Gulf

Publishing Company, 1983. - -
10

Table 2.4. Plain bearing (journal) degradation

-

Resulting degradation

Fracturei Deformation Wear Erosion _

8epr. ion I _

Failure mechanisms

0a

-4

'a

0.

0

U

Cba

0

N

Va

0c

0

Ua

0

a4

.0

a

a

a

'A

0

'a

0.

'0

0

C

0

V

4

'a

30

W

9U

'a

.a

.0

149

bO

a

5

0

L.

-4

t.0C:

U

a

W

a

IV

3

.0

.9

C

0

a2

0

0

la

U

0

0

I0

S..

0

U

Assembly and manufacture

Insufficient clearance _

Misaligned journal *

bearing

Rough surface finish * e

on journal

Pores and cavities in

bearing metal

Insufficient metal bond _ _ _ _ _ _ -

Operating conditions and design

General operating _*

conditions _ I 

Overload/fatigue _ 0 |

Overload/vibration _ _ 0 0 * |*

Current passage _ 0 

Unsuitable bearing 0 *

material _

Lubrication

Contamination of

lubricant

Insufficient or lack

of lubricant

Oil viscosity too

Oil viscosity too

Improper lubricant

selection

Lubricant deterioration

Source: Reprinted with permission from H. P. Bloch and F. C. Gietner,

Practicat Machinery Management for Process Ptants, Vol. 2, Machinery Faiture

Analysis and Troubleshooting, Gulf Publishing Company, 1983.
11

ORNL-DWG 88-4002 ETD

-- PACKING NECK BUSHING

Fig. 2.1. Packed stuffing box.

Many of the AUXFPs are shipped to the plant site from the manufacturer without the stuffing box packing. The compatible set of packing is

shipped with the pump in its shipping crate. The initial installation of

packing in the field is obviously a very important step in ensuring

proper packing life. One pump manufacturer's instruction or maintenance

manual emphasizes that the packing gland should not be excessively

tightened and should be kept as loose as possible to prevent excessive

sleeve and packing wear. Also important is that ,the packing should be

"broken in" after its installation.to induce proper leakage. This task

is accomplished by starting and quickly stopping-the pump a few times

until leakage is observed, If leakage fails to occur, the stuffing box

is packed too tightly and should be disassembled and repacked.

Although not specifically identified in any'of-the data as being a

failure cause, abrasives contained in the pumpage can also be a source of

rapid packing wear and deterioration. When abrasives are a problem, a

lantern gland must be installed into the stuffing box. Clean condensate
12

can be introduced through the lantern gland to prevent abrasives from

coning into contact with the packing or sleeves (Fig. 2.2). Flushing

liquid should be introduced at 5 to 10 psi greater pressure than operating pressure. -

The shaft sleeve surface finish and the packing gland internal surface finish have a direct relation to the packing life. One major packing supplier recommends that these finishes be between 16 and 20 pin.

Rougher finishes-will cause the packing to wear and polish these surfaces.

However, during this process, both the packing and moving parts will

deteriorate as well as "wear in.". Proper finishes reduce the "wearingin" time and increase the "wear-out" time. The packings must also seal

against the inside diameter of the packing box (or box-bore). Therefore,

it is important that the finish be held to within 50 to 75 pin. If the

shaft sleeve and packing gland surfaces are rough, they will not form a

proper seal of the packing with the gland bore; consequently, in attempting to compress the packing sufficiently so that it will seal on the

packing box bore, the packing will also be forced against the shaft and

may be sealed off and thus overheat. Although the bore may be properly

finished when the pump is new, corrosion often occurs at this location

because there is so little movement of the fluid.

For normal multiring-packing, the first few rings of packing absorb

the bulk of the gland loading. These first few rings are also the rings

that do the majority of the sealing. (This situation is analogous to a

bolt-nut fastener combination: the first few engaged threads absorb a

majority of the bolt load.) This loading condition is aggravated by

improper individual ring seating at the time of initial installation

and/or a rough surface in the bore of the stuffing box that restrains the

rings and prevents them from sliding forward under gland adjustment

(Fig. 2.3). The use of die-formed packing will help to alleviate this

unbalanced loading condition.

ORNL-DWG 88-4003 ETD

PRESSURE

5 ~~GAGE

MAIN

STRAINER COIL

RESERVOIR---

STUFFIX~ f PLASTIC BODY

BO _ ROTOMETEiR

BUCKET.. IZ_~~~ TRAP

GLAND -sT.

Fig. 2.2.- Condensate cooling system. Source: Adapted with permission from Engineered FZuid Sealing, Crane Packing Co., 1976.
13

ORNL-DWG 88-4004 ETD

. PACKING RINGS oe .- I....

PACKING

GLAND

SHAFT

.THESE RINGS NOT NEEDED

4 00 V MECHANICAL

PRESSURE (psi)

Fig. 2.3. Packing-loading.--.Source: Adapted

Engineered Fluid Sealing, Crane Packing Co., 1976.

with permission from

A-technique now-being used on valves-in-the nuclear industry is the

use of "live loading"-with springs. 'However, this technique-has not yet

been widely applied in the pump industry.- One form of spring-loaded,

packing is shown in Fig.-2.4. In this arrangement, the spring compensates for any slight wear or compression of the packing. -The gland-is

tightened to the face of the stuffing box, and no further-adjustment is

ORNL-DWG 88.4005 ETD

LUBRICATION

1/// ,,,^

)rMXgR90MN

D_\x .x\\s,

A_

r ' FLUID PRESSURE

FLUID PRESSURE

- 4

-T INNER

PACKING

HELICAL

SPRING

OUTER

PACKING

I 9 9 6

HIGHEST

PRESSUR

POINTS

- SPRING

f SPACF

INNER

PACKING

OUTEIPACKING r_ PRESSURE , I - -.................... _ A AT GLAND

LUBRICANTt

PRESSURE

'Fig. 2.4.- Live-loaded pump packing. Source: Adapted with permission from Engineered Fluid Sealing, Crane Packing Co., 1976. '
14

needed. (This arrangement is analogous to a cartridge mechanical seal:

the assembly is preset and requires no final adjustment).

High vibration caused by worn bearings, unbalance, misalignment, or

a bent shaft will also cause premature aging and wear of packing or

mechanical seals. Table 2.5 identifies the more common causes of packing

problems.

Mechanical seals are also installed on a small number of AUXFPs. A

few of the AUXFPs were manufactured with mechanical seals in the original

installation. Several utilities have chosen to replace the packing in

AUXFPs with mechanical seals. Figure 2.5 shows a typical mechanical seal

assembly. A mechanical seal is composed of a primary seal and secondary

seals. The primary seal consists of a primary ring that normally rotates

and floats against the face of a stationary seat. The primary ring is

often carbon, whereas the seat is tungsten carbide. Other combinations

include tungsten carbide against tungsten carbide and silicon carbide

against silicon carbide. The secondary seal consists of a bellows and

0-rings and is normally constructed of an elastomer material.

Mechanical seal age-related failures result from normal "nose" wearout of the primary ring, overheating of the seal faces (which could result from dirt or poor coolant flow), and high shaft vibration. Leakage

also results from aging, which causes a loss of elasticity and sealing

capability of the secondary elastomer seals. Set-screws are often used

to fasten parts to each other, such as the primary ring cartridge assembly to the shaft sleeve. Loose set-screws are a common problem with

mechanical seals and can result in misalignment of seal parts and, ultimately, seal-failure.

Binding between rotor and stationary parts. Rotating element binding or seizure often leads to total inoperability of the pump. Binding

ORNL-DWG 88-4006 ETD

SEAL FACE WASHER

INLETS

I J stSEAL HOUSING

OUTLETJtu\

INTEGRAL SHAFTl. 1

SLEEVE/PUMPING RING

,---\-SHAFT

SEAL FACE SEAT .

PRIMARY SEAL FACE

Fig. 2.5. Mechanical seal assembly. Source: Adapted with permission from David M. Kitch, "Pump Selection and Application in a Pressurized Water Reactor Electric Generating Plant," Proceedings of the

Second International Pump Symposiwn, Texas A&M University, April 1985.
15

Table 2.5. Packing troubles, their cause and cure

Trouble Cause Cure

No liquid

delivered

Lack of prime

Air leaking into

stuffing box

Not enough liquid

'delivered

Packing too loose or defective,

allowing air to leak into suction

Tighten or replace packing and

prime pump

Check for some leakage through

stuffing box while operating;

if no leakage after reasonable

gland adjustment, new packing

may be needed

or

Lantern ring may be clogged or

displaced and may need centering in line with sealing liquid

connection

or

'Sealing liquid line may be

clogged

or

' Shaft or-shaft sleeve below

-packing may be badly scored and

allowing air to be sucked into

pump

Replace packing and check

smoothness of shaft or shaft

sleeve

Defective packing

Not enough pressure

Pump works for a

while and quits

Defective packing ,Same as for preceding

Pump takes I

much power

too

Air leaks into 'Same as for preceding

stuffing box

Packing too tight Release gland pressure

Retighten'reasonably; keep leakage flowing'- if none, check

packing, sleeve, or shaft

Defective packing ,Replace worn packing; replace

- . packing damaged by lack of

lubrication

Pump leaks excessively at stuffing

Wrong type of

packing

Scored shaft or

shaft sleeves

- Replace-packing not properly

installed or run-in;-replace

improper packing with correct

grade for liquid being handled

Put in lathe and machine true

* and smooth-or replace -
16

Table 2.5 (continued)

Trouble Cause Cure

Stuffing box

overheating

Packing too tight Release gland pressure

Packing wears too

fast

Packing not

lubricated

Wrong grade of

packing

Insufficient

cooling water

to jackets

Stuffing box

improperly

packed

Shaft or shaft

sleeve worn or

scored

Insufficient or

no lubrication

Improperly packed

Wrong grade packing

Pulsating pressure on external

seal liquid line

Release gland pressure and

replace all packing if any

burnt or damaged

Check with pump or packing manufacturer for correct grade

Check if supply line valves

opened or line clogged

Repack

Remachine or replace

Repack and make sure packing

loose enough to allow some

leakage

Repack properly, making sure all

old packing removed and box

clean

Check with pump or packing manufacturer

Makes packing move and prevents

it from taking a "set"; remove

cause of pulsation

Source: Reprinted with permission

Engineered Fluid Sealing, 1976.

from John Crane Packing Co.,

can result from anything that causes the loss of clearance in (1) impeller to nonrotating internal wear surface clearance, (2) balance drum to

nonrotating bushing wear surface clearance, or (3) thrust runner to bearing surface clearance.. Factors that cause increased changes in these

internal clearances are (1) pump starts and stops, (2) overheating caused

by pump operation with a closed discharge and miniflow valve or a closed

suction valve, (3) worn bearings, (4) shaft misalignment, (5) dirt or

debris, or: (6) improper material hardness selection.

Impeller wear and breakage, wear-surface wear, erosion and corrosion

seizing. Centrifugal pump impellers have wear surfaces that are normally

V
17

located on both the front and rear hub. The impellers rotate within the

wear surfaces (or rings) of the nonrotating internals. These surfaces

form internal seals that restrict leakage from stage to stage. Figure

2.6 shows an impeller and wear-ring combination. As these internal wearring clearances increase,:the stage-to-stage internal leakage increases

and the pump efficiency decreases. Figure 2.7 shows the effect of this

ORNL-DWG 88-4007 ETD

Fig. 2.6. Wear ring and impeller combination.

ORNL-DWG 88-4008 ETli . .

INMFIL HO0 CURVE

PLACE

dL'

Fig. 2.7. Effect of wear on head capacity curve. Source: Adapted

with permission from Igor J. Karassick,' Centrifugal Pump Clinic, Marcel

Dekker, Inc., 1981.
18

internal leakage increase on the pump head-capacity curve. An increase in

pump power at a given flow rate may also result because the impeller is

pumping not only the normal through flow, but also the added internal

recirculation leakage. Another effect caused by internal clearance increases is vibration because these clearances also act as water bearings

to provide rotor stiffness, and increasing clearances result in reduced

rotor stiffness.

A further cause of worn or broken impellers is a loose impeller bore

to shaft fit, which can result in fretting wear of the impeller bore or

key, ultimately leading to slipping of the impeller on the shaft. Impeller failures can also be caused by hydraulically induced resonance, which

can lead to catastrophic impeller structural failure. Impeller or nonrotating internal wear-ring failures can result from fatigued or broken

welds or pins that affix the wear rings to their holders.

Low-flow testing can be a possible source of impeller cavitation

damage. The resulting hydraulic recirculation present inside the pump at

low flows can create cavitation damage. This problem is further discussed in Appendixes D and F.

Thrust balancer wear, galling, and seizing. As discussed in Vol. 1,

the thrust balancer is an axial balancing device used to balance thrust

generated by hydraulic pressure forces within the pump. The thrust balancer rotates inside a bushing-or against a nonrotating internal surface.

Small clearances and large pressure differentials exist between these

rotating and nonrotating internals. Their surfaces are thus subject to

wear and erosion. Other factors that have been found to cause thrust

balancer wear, galling, and seizing are identical to those discussed

earlier in this report under "Binding between rotor and stationary parts."

Shaft breakage. Shaft failures reported on AUXFPs appear to be more

a result of rotating element binding or seizure or other rotating element

part failures than inadequate shaft fatigue or torsional design. The

fact that AUXFPs do not operate long enough to accumulate significant

shaft fatigue cycles, at least now, probably explains this finding. In

any event, there were only a few reported shaft failure events. Obviously, shaft failure is a significant failure cause because it can render

the pump totally inoperable.

Fastener loosening and breakage (rotating elements, nonrotating

elements, mechanical subsystems, support, and pressure-containing

casing). Fasteners are used on AUXFPs to locate axially items such as

impellers, miscellaneous spacers, and sleeves on the shaft. Fasteners

are also used to secure the bearing assemblies to the shaft. Set-screws

are often used to lock these fastener nuts to the shaft and to affix

various parts of the shaft seal to the shaft sleeves.

Influencing factors, including vibration, thermal expansion and

contraction, and rotational torque often cause these fasteners to loosen

or break. Improper torquing is a major source of fastener failure, which

may occur during shop assembly or following field repair. Overtorquing

of fasteners can lead to excessive prestress, which can result in thread

stripping or, when combined with vibration, expansion, or contraction can

result in fastener failure. Undertorquing can result in fastener loosening, thread stripping, or shear failure from loosely loaded parts. Loose

foundation or support bolting can also lead to high pump vibration.
19

Coupling wear and breakage.. Gear couplings are most commonly used

on AUXFPs because they tend tolbe the least expensive type for this service. The most common failure cause experienced-with couplings is coupling gear tooth wear. This failure results from improper or inadequate

grease lubrication of the gear teeth and/or excessive misalignment of the

driver and pump shafts. Other problems include loose hubs resulting from

either improper shrink fit or fastener tightness. Catastrophic coupling

failures can result from torsional resonance that occurs when the pump

and driver rotor assembly torsional natural frequency is equal to the

rotational speed of'the pump.

Thrust runner wear and breakage.. This discussion refers to the

thrust runner as the rotating part, fastened-to the shaft and captured by

a double-acting oil-film thrust'bearing. The failure of this component

can lead to such problems aslrotor seizure and shaft breakage. Thrust

runner failures can result from inadequate thrust bearing lubrication,

oil contamination, or excessive thrust loads caused'by hydraulic unbalance or failure of the pump thrust balancer. However, most AUXFPs employ

a double-acting ball bearing'or antifriction bearing and do-not incorporate a thrust runner.

Leak at casing split. AUXFPs are typically-horizontal split-case

pumps. The pressure containment casing consists of an upper and a-lower

casing that are held together'by preloaded bolt fasteners. A gasket

provides a seal at the casing split line. Gasket aging and degradation

can cause leaks. Improper torquing or fastener failure can also result

in a leaklat the casing split. A small-leak, if left unrepaired, can

lead to much larger leaks because'of casing erosion that occurs along the

leak path.

Structural damage to stationary vanes (diffuser or volute). This

failure cause often results from hydraulic-pressure pulsations that

create fatigue loading on internal parts, which are'normally castings.

Defective castings (i.'e., cracked ,or porous castings) can accelerate

structural failure. Fatigue loading cycles can accumulate quickly if the

hydraulic pulsations occur at impeller vane-passing frequency. Hydraulic

pressure pulsations are of stronger magnitude as the flow increases or

decreases from pump best efficiency point (BEP) flow. Although not yet a

common failure cause for AUXFPs, this problem is common to high energy

per stage pumps, such as large boiler feed pumps.' (See Sect. 2.2.2.3.)

2.2.2.2 Design and installation.' PWR AUXFP designs evolved frou

small boiler feed pumps used in older low-pressure fossil electric generating stations. Presently, AUXFPs are classified as the American Nuclear

Society (ANS) Safety Class 3Yand built to the nuclear design rules of the

American Society of Mechanical Engineers (ASME) Sect. III, Subsect. ND

(Class 3) requirements. Although the ASME'Code was introduced to specifically address the pressure boundary design, its introduction led to

the improved quality of all aspects of'AUXFP design and manufacturing.

Most of the data obtained from operating nuclear plants and used in this

report were based on AUXFPs designed and manufactured in the late 1960s

to early 1970s.' During that time, there was only a small operating -

experience base to draw from,-and equipment suppliers were in strong

competition with each other. Consequently, equipment, including AUXFPs,

tended to be purchased on the basis of lowest price and not necessarily

on the basis of quality or reliability.
20

Since that time, several design change recommendations have been

made by AUXFP suppliers to improve the reliability of these pumps. In

the problem area of bearing- and lubrication-related failure causes-,,one

major factor appears to be water contamination of the oil, which ultimately results in bearing-fai-lure. -Because of the crios ximity-ofmthebe-i-ng-houstn-s-to-the-s-eal-or-p!Era-gilands, water either spraying or

leaking from the glands enters the bearing housing and contaminates the

oil, causing bearing failure. No deflector or seal was provided on these

designs to divert or prevent water from leaking into the housings. Figures 2.8-2.11 all show recommended modifications that will prevent water

from entering the bearing housings.

Many of the bearing-related problems have involved the thrust bearing. AUXFPs typically use a double-row rolling contact or antifriction

bearing. As shown in Fig. 2.12, these bearings are usually the preloaded

angular contact type that obtain their lubrication by immersion in surrounding reservoir oil. Conversely, double-acting tilt-pad thrust bearings (Kingsbury type) are used on many of the larger boiler feed pumps,

and even on the lower-horsepower-rated nuclear centrifugal charging and

HHSIPs used In PWR emergency core cooling systems (ECCSs). The tilt-pad

bearing shown in Fig. 2.13 is capable of higher thrust loads than the

comparably sized antifriction bearing. The tilt-pad bearing appears to

be working reliably on the other cited applications; therefore, consideration should be given to the tilt-pad thrust bearing as an upgrade for

AUXFPs or when new or replacement pumps are purchased.

Figure 2.14 illustrates another modification recommended by Z

Ingersoll-Rand to improve the reliability of their supplied AUXFPs. Because the shaft must move to permit the balance disc to properly balance

the hydraulic thrust, the addition of the spring reduces the thrust load

imposed on the rolling contact bearing and allows the shaft to move

axially to increase the thrust produced by the balance disk. A seemingly

simple design modification to reduce the problem of oil contamination by

particulates is to replace the existing standard oil drain plug with a

magnetic plug. The magnetic plug attracts the concentration of free

metallic particles floating in the lubrication oil.

One other important note of comparison is that the ECCS pumps (i.e.,

centrifugal charging and HHSI) use a forced-feed lubrication system for

both the thrust and radial bearings. This system consists of an oil

pump, reservoir, oil cooler, and filter. Unlike the ring oil feed radial

journal bearings now used on many AUXFPs, the pressurized system provides

a positive flow of oil to the bearings and filters dirt frost the oil.

Although this system has more auxiliaries, which are also subject to

failure, it may be more reliable than the typical AUXFP system, as suggested by the HHSIP failure data.

Shaft seals (i.e., packing and mechanical seals) are the most

troublesome pump parts and result In the largest number of recorded

problems on all pump applications in the nuclear industry. One issue is

the lack of any standard acceptable leakage criteria for seals or packing. It now appears that each utility establishes leakage criteria based

on its own experience. Most of the AUXFPs now In operation use packing

such as that shown in Fig. 2.1 or single-end-face mechanical seals such

as those shown in Fig. 2.5. It is important to recognize that packing

requires some finite leakage to ensure cooling and lubrication, whereas
IC.

'4 .1i '

ORNL-DWG 88-4009 ETD

I-

-ORING.

Fig. 2.8. O-ring under,,flinger. Adapted with permission from

F. J. Mollerus, R.-D. Allen, and J. D. Gilcrest, FaiZures Related to

SurveiZZance Testing of Standby Equipment, VoZ. 1: Emergency Pumps,

EPRI NP-4264, Vol. l, Electric Power Research Institute, October 1985.
I

22

ORNL-DWG 884010 ETD

V-RING

SEAL BEARING

HOUSING

SHAFT

Fig. 2.9. Bearing housing lip seal. Adapted with permission from

F. J. Mollerus, R. D. Allen, and J. D. Gilcrest, Failures Related to

Surveillance Testing of Standby Equipment, Vol. 1: Emergency Pumps,

EPRI NP-4264, Vol. 1, Electric Power Research Institute, October 1985.

that required by a comparable mechanical seal is much lower and normally

undetectable. Packing is typically a much less expensive sealing technique than the use of mechanical seals. None of the pumps installed on

the-primary side (e.g., centrifugal charging and residual heat remaoval)

is furnished with packing. Of course, unlike the AUXFPs, these primaryside pumps must seal against potentially higher temperature, pressure,

and radioactive environments.

Recently, significant design and application improvements have been

made to shaft seals. For example, new packing materials that contain

colloidal graphite are now extensively used in nuclear valve applications. They provide much longer life than traditional packing materials,

such as cottonite. Shaft sleeves used on packed pumps tend to exhibit

more wear than those used on mechanical seal applications. Thus, it is

important to select sleeves constructed of high-strength, corrosionresistant steel (e.g., SA 276 type 410 or another equivalent 400 series)

that has been properly heat treated to obtain adequate hardness.

Several utilities have chosen to replace the packing on AUXFPs with

mechanical seals. Mechanical seals, if properly selected, installed, and

maintained, will'provide better absolute sealing-than conventional packing. New improvements identified with mechanical seal configurations include better wearing mating materials and environmentally superior 0-rings

and bellows (secondary seals). Also, the implementation of a disaster or

throttle bushing located at the extreme outboard end of the seal provides

backup sealing in case of primary seal failure. This bushing is a

spring-loaded packing that rides near the shaft and forms a very tight

leakage clearance to seal against the catastrophic failure of the primary

seal or its subcomponents. Other problems encountered with mechanical

seals include the loosening of fasteners, such as the set-screws used to
i f - I. .V.,I ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ 

l * u

SHEET METAL SHIELD

ORNL-DWG 88-4011 ETD

EET METAL

IELD

- Jr' F Li

I

Fig. 2.10. Bearing housing shield. , Adapted with permission from

F. J. Mollerus, R. D. Allen, and J. D. Gilcrest, Failures Related to

Surveillance Testing of Standby Equipment, Vol. 1: Emergency Pumps, _

EPRI NP-4264, Vol. 1, Electric Power Research Institute, October 1985.
ORNL-DWG 88-4012 ETD

Fig. 2.11. Raised vent and oil fill. Adapted with permission fron

F. J. Mollerus, R. D. Allen, and J. D. Gilcrest, Failures Related to

Surveillance Testing of Standby Equipment, Vol. 1: Emergency Pumps,

EPRI NP-4264, Vol. 1, Electric Power Research Institute, October 1985.

II d
25

ORNL-DWG 88-4013 ETD

THRUST BEARING JOURNAL BEARING

HEAT EXCHANGER

Fig. 2.12. AUXFP bearing systerm. Adapted with permission from

M. L. Adams and E. Makay, Aging and Service Wear of Auxiliary Feedwater

Pumps for PWR Nuclear Power Plants, Volume 1, Operating Experience and

Failure Identification, NUREG/CR-4597, Volume 1 (ORNL-6282/V1), Oak

Ridge Natl. Lab., July 1986.

ORNL-DWG 88-4014 ETD

THRUST SHOES

THRUST RUNNER

Fig. 2.13. Tilt pad thrust bearing system.
0a

Fig. 2.14. Disk spring design. Adapted with permission frou

F. J. Mollerus, R. D. Allen, and J. D. Gilcrest, Failures Related to

Surveillance Testing of Standby Equipment, Vol. 1: Emergency Pumps,

EPRI NP-4264, Vol. 1, Electric Power Research Institute, October 1985.

it of ..o
27

secure the pumping ring to the shaft sleeve. One major nuclear pump supplier recognized these problems and has provided'a significant improvement

in seal assembly design. Figure 2.5 presents this modified design, which

shows a one-piece integral shaft sleeve and pumping ring assembly.

Failure causes associated with impellers, shafts, wear rings, couplings, fasteners, thrust runners, thrust balancers, and stationary vanes

(diffuser or volute) are not as common as failures associated with shaft

seals and bearings. Binding or'seizing between rotor and stationary

parts can be a result of improper wear-ring material selection or a bent

shaft caused by the shaft fabrication or .straightening technique (whereby

imposed residual stresses relieve themselves). Binding can also be

attributed to high internal vibration resulting from inadequately specified minimum flow. It is important'to review the wear-ring materials and

select compatible materials that-will not be susceptible to galling, yet

provide adequate wear resistance..-

Although binding-can result in reduced pump capacity, this reduction

can also result from wear that causes changes in internal clearances,

thus increasing internal recirculation leakage. This loss can be mitigated through the proper selection of or upgrade to more compatible wearring and balance drum or bushing materials.

There was only one reported instance of cavitation damage on AUXFPs.

This situation was discovered during a routine planned outage and repair

on an AUXFP. The discovered damage was minor and was not reported to be

a failure. The pump supplier thought that it might be caused by low-flow

testing, which will be discussed later in this report. As specified

earlier, AUXFPs have not accumulated many operating hours to date; consequently, unless there exists a significant or very poor hydraulic design

resulting in cavitation, cavitation damage may not be visible by inspection for some time. This report of cavitation damage suggests that periodic disassembly and inspection may be warranted to assess adequately

machine condition.

2.2.2.3 Testing. No identified failures can specifically be tied

to testing. A recent Electric Power Research Institute (EPRI) report

details the results of a two-fold evaluation: first, to identify significant failures or problems of standby emergency pumps, and second, to

determine whether those failures were by-products of surveillance testing

and, if so, to suggest ways to minimize them. AUXFP license event reports (LERs) from 1979 throu'gh late 1982 were reviewed to identify failure frequencies,'failure modes, causes, and potential remedial action.

Three'pump manufacturers; also supplemented these records with maintenance

records that they had accumulated. The EPRI report concluded that none

of the reviewed failures was directly caused by 'the surveillance testing

although most of those failures occurred during testing. However, because of the destructive nature of low-flow testing, degradation-associated with the practice of low-flow'testing is to-be expected.'

Appendix D provides a perspective of low-flow:(pump miniflow) testing of AUXFPs. Appendix G provides W proposed test guidelines' for AUXFPs

and discusses the potential for testing at higher flow rates.

' 2.2.2.4 Maintenance. Timely and correct maintenance'is probably

the single most important factor influencing premature AUXFP component

failure.-'Table 2.6 ranks the importance'and influence of maintenance
I

28

Table 2.6. The importance of maintenance in mitigating pump

failure causes attributed to aging and service wear

Pump segment Parts Failure cause Ranking

Rotating Binding between rotor and 1

elements stationary parts

Shaft Shaft breakage 7

Impeller Impeller wear, breakage 5

Thrust runner Thrust runner wear, breakage 12

Fasteners Fastener loosening, breakage 4

Nonrotating Diffusers Structural damage to stationary

internals or volutes vanes (diffuser or volute)

Wear surfaces Wear-surface wear, erosion, 8

corrosion, seizing

Fasteners Fastener loosening, breakage 9

Pressure Casing Leak at casing split 13

containment Leak at casing rupture disk

casing Suction nozzle Suction nozzle leak, breakage

Discharge nozzle Discharge nozzle leak, .breakage

Fasteners Fastener loosening, breakage 14

Mechanical Bearings Bearing wear, corrosion, breakage 2

subsystems Shaft seals Shaft seal deterioration, breakage 3

Thrust balancer Thrust balancer wear, galling, 10

seizing

Coupling Coupling wear, breakage 11

Fasteners Fastener loosening, breakage 6

Support Base frame Base frame breakage

Fasteners Fastener loosening, breakage 15

';

practices in mitigating the identified failure causes attributed to wear

and aging. Again, the lowest number corresponds to the highest ranking.

The components that formed a part of the rotating element or

mechanical subsystems were most influenced by maintenance. Failures

attributed to aging and service wear are often actually caused by poor

maintenance. Proper maintenance training cannot be overemphasized.

Maintenance and operations personnel must receive regular training in the

operation of the equipment, including its installation and repair. Technical bulletins, maintenance bulletins, vendor training programs, vendor

changes, and current drawings and parts lists should be included in the

overall training program. Components that are not properly repaired

cannot be expected to fulfill their expected service life. For example,

the consequences of excessive gland nut tightening cannot be overemphasized. The resulting inadequate leakage and lubrication not only burns

the packing-but damages the shaft sleeve and possibly the gland. Proper

packing installation is another very important point in obtaining controlled leakage with a set of packing..

Again, it is recommended that die-formed packings be purchased to

minimize the errors that may result during packing, cutting, forming, and
29

installation. If mechanical seals are used, the cartridge seal, although

more expensive, leads to fewer installation and maintenance problems.

Improper lube oil level was the single most important factor reported under-maintenance involving bearings. Other factors contributing

to bearing failures included water or dirt contamination of the oil,

blocked oil drain return, and several instances of a leaking oil pipe or

fitting. -

Rotating element and.mechanical subsystem problems included improper

balance drum to bushings clearance and improperly installed wear rings.

2.2.2.5 Other. This category includes all other causes not previously discussed that specifically affect the pump. Failure causes

attributed to the steam supply, turbine, or motor were excluded from this

report.

The most commonly reported problems in this category include instrumentation and control logic circuitry malfunction, deficient procedures

and documentation, and human performance errors. A recent Institute of

Nuclear Power Operations (INPO) report stated that two nuclear units contributed over 50% of the pressure switch and pressure transmitter failures, the primary cause being human error, such as incorrectly calculated

pressure switch set-points. Most actuation and control circuitry failures were also caused by human error, particularly the mispositioning of

manually operated switches and the use of deficient procedures to verify

operability following work on the circuitry. Other important human

performance errors included improper valve alignment that caused a loss

of water to the AUXFPs and actions that resulted in a loss of the automatic start-up signal to the pumps. Deficient procedures and documentation suggests that some of these events could be precluded by a systematic

review and improvement of procedures for technical content and format.

Several nuclear plants are equipped with low-pressure switches that

trip the AUXFPs on low water suction pressure. This instrumentation

caused inadvertent equipment shutdowns, especially during plant start-ups

when pressure surges caused temporary low pressure. A time delay was

added to this switch to alleviate this problem. Another problem that can

affect pump performance is steam binding caused by leakage from the main

feedwater system. This problem was documented in NRC IE Bulletin No.

85-01, "Steam Binding of Auxiliary Feedwater Pumps."

The pump, driver, and auxiliary systems assembly is typically

mounted on a common fabricated steel baseplate that is rigidly anchored

to the building floor, normally through foundation bolting. The base is

then filled with grout, which stiffens and strengthens the base installation. The suction nozzle is connected to a hydraulic circuit that originates at the condensate storage tank. The discharge nozzle connects to a

piping circuit that ties into the main feedwater header. Pump operational

problems can result from improper installation in the plant. Many such

problems have been found in nuclear and fossil-generating plant and

chemical plant applications. The structural baseplates must be properly

leveled prior to final grouting. Improper leveling could lead to pump

and driver vibration caused by the fact that pump and driver alignment

cannot be initially achieved or maintained. Poor grout or improperly

installed grout can also leave the base flexible, which could result in

structural vibration or even resonance, possibly affecting the pump or

driver. Excessive piping and end loads applied to the pump nozzles are
30

probably the most prevalent sources of plant installation problems with

pumps. If the piping is improperly aligned to the pump nozzles or the

piping has too few supports, excessive loads can result, which could

cause equipment misalignment and high stress at the pump supports and/or

the nozzles. This condition is aggravated in a high-temperature service,

such as boiler feed, in which piping thermal expansion adds additional

nozzle loads. Although AUXFPs may be subjected to initial piping misalignment, the thermal changes through the pump are essentially nil, thus

eliminating any local thermal effects.

-
31

3. CANDIDATE ISCM METHODS

3.1 Potentially Useful ISOI Methods

The information on pump failure causes and rankings in Table 2.2 was

used to identify causes to be considered in an AUXFP ISCM program; the

causes and associated measurable parameters to be considered are tabulated in Table 3.1. Table 3.2 summarizes the potentially useful ISCM

methods for obtaining each measurable parameter. Discussions of ISCM

methods and their relation to aging and service wear are contained in

Sect. 3.2. -A summary of correlations between measurable parameters and

degradation is given in Sect. 3.3.

.3.2 Potentially Useful ISCM Methods and Their Relation

to Aging and Service Wear

3.2.1 Rotor binding inspection

This inspection is to be performed before pump start-up. Power to

the pump driver should be disconnected to prevent injury caused by an

inadvertent pump start. A suitable "spanner wrench" or other tool should

be applied to the coupling and the pump rotor turned. The inspector

should feel resistance or listen for rubbing that may result from insufficient clearance between the rotating and stationary parts, bearing failure, or shaft seal failure.' If excessive rotating resistance results,

then the cause of the failure should be investigated and corrected.

3.2.2 Visual inspection

This inspection pertains to the appearance of the parts. This detection method is composed of two types: regular inspection, which is

the regular examination of the pump that can be performed-without disassembly, and periodic inspection, surveillance, and maintenance, which

requires disassembly of the pump.

Regular visual inspection should include observations for lube oil

system leaks, shaft seal or casing leakage rates, coupling lubrication

leaks, external fastener looseness, and lube oil level or quantity.

Periodic visual inspection requires some disassembly of the pump

segments. Inspections should include examination for such things as

binding, wear, mechanical looseness, erosion, corrosion, broken parts,

and overheating. For example, binding between rotating and stationary

parts will show galling indications and heat discoloration (depending on

the severity of rubbing) to the wearing surfaces.

Normal wear of parts will also show metal removal and may result in

mechanical looseness or-change in clearance. Impellers should be examined for signs of cavitation at both the leading and trailing vane edges.

Cavitation will result in erosion of the impeller surface. Impeller

bores and key fits to the shaft should be inspected for signs of looseness. Bearing fits -should be examined to ensure that the bearings are
32

Table 3.1. Failure causes and measurable parameters

to be considered in an AUXFP ISCM Program

Pump segment Parts Failure cause Measurable parameters

Rotating

elements

Binding between

rotor and

stationary parts

Shaft

Impeller

Thrust

runner

Shaft breakage

Impeller wear,

breakage

Thrust runner

wear, breakage

Rotational torque,

appearance, motor current,

motor power, turbine power,

speed, wear surface and

critical fit clearance

Rotational torque, appearance,

developed head, delivered

flow, motor current, motor

power, turbine power, speed,

vibration, surface indications, dynamic pressure

Rotational torque, appearance,

developed head, delivered flow,

motor current, motor power,

turbine power, speed,

vibration, balance return line

flow, noise, wear surface and

critical fit clearance,

surface indications, dynamic

pressure

Rotational torque, appearance,

motor current, motor power,

turbine power, speed,

vibration, temperature,

axial position, surface

indications, noise

Rotational torque, bolt torque,

motor current, motor power,

turbine power, vibration

speed, axial position, dynamic

pressure

Appearance, developed head,

delivered flow, vibration,

noise, dynamic pressure

Fasteners Fastener loosening,

breakage -

Nonrotating

internals

Diffusers or

volutes

Structural damage to

stationary vanes

(diffuser or

volute)

Wear Wear-surface wear,

surfaces erosion, corrosion

seizing

Fasteners Fastener loosening,

breakage

Pressure

containment

casing

Mechanical

subsystems

Casing

Bearings

Leak at casing

split

Bearing wear,

corrosion,

breakage

Rotational torque, appearance,

developed head, delivered flow,

vibration, axial position,

balance return line flow, wear

surface and critical fit

clearance, noise, dynamic

pressure, motor power, turbine

power

Bolt torque measurement

appearance, vibration, noise

Appearance, leakage rate

Rotational torque, appearance,

motor current, motor power,

turbine power, speed,

vibration, temperature, lube

oil purity, axial position,

wear surface and critical fit

clearance, noise, dynamic

pressure, oil quantity
33

Table 3.1 (continued)

Pump segment Parts Failure cause Measurable parameters

Mechanical Shaft Shaft seal Rotational torque, appearance,

subsystems seals deterioration, temperature, vibration, leakage

(continued) breakage rate, wear surface-and critical fit clearance, noise,

dynamic pressure

Thrust Thrust balancer Rotational torque, appearance,

balancer wear, galling, wear surface and critical fit'

seizing clearance, motor current,

motor power, turbine power,

developed head, delivered

flow, vibration, axial

position, balance return line

: - - flow, noise

Coupling Coupling wear, Rotational torque, appearance,

breakage motor-current, motor power,

turbine power, speed,

vibration, noise

Fasteners Fastener loosening, Bolt torque, appearance,

breakage vibration, noise

Support Fasteners Fastener loosening, Bolt torque, appearance,

breakage' vibration, noise

Base frame Base frame Appearance, vibration, noise

breakage

Table 3.2. Measurable parameters and their relative ISCM methods

Measurable parameters ISCM methodsa

Rotational torque : ,*Rotor binding inspection

Appearance . *Visual inspection

Motor current. Motor current monitoring

Motor power *Motor power monitoring

Turbine power Turbine power monitoring

Speed - - *Rotational speed monitoring

Wear surface and critical fit clearance *Dimensional inspection

Developed head *Pump pressure or developed head

monitoring

Delivered flow *Pump delivered flow monitoring

'Vibration *Rotor vibration monitoring

*Incipient failure detection monitoring

Surface indications *Liquid penetrant inspection

Balance return line flow *Balance return line flow monitoring

Noise *Audible noise inspection

Temperature *Bearing temperature monitoring

Stuffing box temperature monitoring

Axial position *Rotor axial position monitoring

Bolt torque *Bolt torque inspection

Leakage rate *Leakage rate inspection

Lube oil purity, quantity *Lube oil inspection

Dynamic pressure Discharge dynamic pressure monitoring

aItems with asterisks are discussed in detail in Chap. 4.
34

not excessively worn or broken. Journal bearing babbitt may show wear or

discoloration caused by dirty lube oil.

The shaft seals should be examined for wear or abnormal wear that

may result in indications of overheating of parts such as packing, shaft

sleeves, packing gland, stuffing box, mechanical seal washers, and seal

seats.

Highly stressed parts, such as the shaft, antifriction bearings, and

fasteners, should be examined for cracks or breaks.

3.2.3 Motor current monitoring

This measurement collects motor dynamic current signatures. By examining the electric current spectra analysis, one can determine whether

there are factors actively producing change in the current signature.

These include mechanical rubs within the pump, loose components, or worn

parts. Instruments used to collect this data consist of clamp-on current

probes that may be installed at the motor control center.

3.2.4 Motor power monitoring

This measurement indicates pump power and is applicable to motordriven pumps. Rotor binding will result in an increase in motor inrush

current to the point where complete pump rotor binding will result in the

motor current being equal to the "locked rotor" current value. Normally,

the motor circuit breaker will open shortly after this condition is

reached; otherwise, motor overheating and damage will result. In some

cases, an increase in pump internal clearances caused by aging can result

in increased pump power consumption.

3.2.5 Turbine power monitoring

This measurement also indicates pump power and is applicable to

turbine-driven pumps. Rotor binding will result in an increase in steam

flow because the turbine cannot accelerate and the flow control valve

will open to provide more steam. This situation is synonymous to motor

locked rotor. The steam flow, pressure drop, and turbine speed are

required to perform this measurement. In some cases, an increase in pump

internal clearances caused by aging can result in increased pump power

consumption.

3.2.6 Rotational speed monitoring

The speed measurement must also be used in verifying the cause of

reduced pump.delivered flow or developed head because these parameters

are proportional to pump speed. This measurement can also indicate a

problem with the power source.

3.2.7 Dimensional inspection

This inspection pertains to the measurement of critical pump part

fits and wearing surfaces. These measurements include those on the
35

impeller bore, shaft, bearings, impeller wearing rings, wear surfaces,

thrust runner, thrust balancer, and shaft seal wearing parts. This

Inspection should include a comparison of the new part's dimensional

requirements with the "as-inspected" part condition. The condition of

aging and wear can often be correlated to the resulting change in, for

example, fits and clearances. In all cases, these as-inspected dimensions should be compared with the pump vendor's specified dimensions, and

the parts should be replaced as required (e.g., a rule of thumb stated by

several pump vendors is to replace wear rings when clearances have

doubled). Section 2.2.2.1 further' discusses the effect on performance of

changes in some of these critical dimensions and their relation to aging

and service wear.

3.2.8 Pump pressure or developed head monitoring

The purpose of pump operation is to develop pressure or head and to

deliver flow. As the pump ages, the ability to do both diminishes. This

condition is caused primarily by the loss of critical wear clearances on

the impeller, wear surfaces, and thrust balancer. The resulting increase

in clearances reduces the pump's hydraulic efficiency because of the increased internal recirculation flow through these "opened" clearances.

Section 2.2.2.1 and Fig. 2.7-more thoroughly address the resulting effect

on hydraulic performance caused by these "opened" clearances.

3.2.9 Pump-delivered flow monitoring

As explained in Sect. 3.2.8, as a pump ages, its ability to deliver

flow also diminishes because of the loss in hydraulic efficiency caused

by the increased internal recirculation losses.

3.2.10 Rotor vibration monitoring

Rotor vibration monitoring is one of the most extensively practiced

methods for detecting machinery condition. Excessive or increasing rotor

vibration can be an indication of rotor component wear, unbalance, wearsurface wear, impeller wear, loose fasteners or fits, bearing deterioration, coupling wear, driver misalignaent,-and almost anything associated

with the pump's rotating parts. .:The consequences of excessive vibration

are an increased potential for fatigue failures for both rotating and

stationary parts, reduced bearing life, accelerated shaft seal aging,

shaft failure, rubbing at close clearance fits, and, ultimately, the loss

of those close clearances, with a respective deterioration in hydraulic

efficiency... Probably the sinfgle most important mechanism for wear and

aging in a pump is excessiv6e rotor vibration because this vibration can

affect all of the pump parts.

Rotor vibration can be trended and the various harmonics examined.

A gradual change in vibration' indicates component wearing 'or 'aging, such

as an increase in bearing or wearing ring clearances, rotor unbalance,

parts looseness, and coupling misalignment. A sudden change in vibration

can indicate catastrophic failure, such as a broken shaft, bearing or

shaft seal failure, and coupling failure.
36

An examination and trend of the various multiples of the running

speed component (e.g.,-lX, 2X, 3X . . . blade passing frequency) can be

used to predict the failure mechanisms progressing inside the pump.

3.2.11 Incipient failure detection monitoring

This monitoring method is especially useful in obtaining highfrequency noise or vibration measurements. (It is also referred to as

acoustic, high-frequency, or stress-wave emission measurement.) Incipient failure detection (IFD) instrumentation is often used on rolling

contact (antifriction) bearings. This bearing type is commonly used for

both the radial and thrust bearings on AUXFPs. IFD is a relatively new

monitoring method that can be successfully applied to measure and predict

rolling contact bearing, coupling, gear wear, shaft seal deterioration,

rotor rubbing, and other problems.

3.2.12 Liquid penetrant inspection

This inspection involves the application of a penetrant dye to part

surfaces to determine the presence of surface indications (or cracks).

It is to be used only on metal parts. The part is first carefully

cleaned, and then the dye is applied. Once the dye dries, a developer is

sprayed over the dye. The developer causes the dye to "bleed" from the

locations that contain cracks. This bleeding is often visibly obvious;

however, as with all nondestructive examination methods, the user must be

experienced in the application of the method and reasonably experienced

in the interpretation of results.

3.2.13 Balance return-line flow monitoring

This measurement pertains to the pump designs that include a thrust

balance flow return line. This line connects the downstream chamber of

the balance drum or disk to the pump suction chamber. Flow through the

balance drum or disk clearances is returned to the pump suction. An increase in the flow rate signifies an increase in thrust balancing device

clearance between the rotating device and its mating wearing surface.

Increased thrust balancing device clearances are often indicative of

similar wear at the impeller and wear surfaces.

3.2.14 Audible noise inspection

This inspection requires the pump to be operating. A properly running pump will produce a distinct audible noise signature, whereas an

abnormally running machine will result in a change to the audible sound.

Problems or failure causes associated with cavitation, rubbing, high

shaft vibration, bearing wear, coupling wear, and so forth, can often be

diagnosed through this method.
37

3.2.15 Bearing temperature 'monitoring -

This method is primarily applicable to sleeve bearings, such as

radial journal or tilting pad thrust bearings, although it has also been

used to indicate the condition of rolling element (antifriction) bearings. An increase in bearing temperature normally indicates bearing wear

or eventual failure. Increased bearing temperature can also be-caused by

inadequate lube oil flow or level, impure oil, general bearing deterioration, or. overloading, possibly caused by the deterioration of other parts

of the pump (e.g. the thrust balancer).

3.2.16 Stuffing box temperature monitoring

This method is used to detect shaft' seal packing deterioration

caused by'packing wear, shaft sleeve wear, inadequate packing clearance,

excessive packing gland tightness, or inadequate mechanical seal cooling. Shaft seal deterioration and leakage often result from worn packing

and mating parts.

As these parts wear, rotating friction increases, and stuffing box

temperature increases. Inadequate packing leakage causes inadequate

packing cooling and lubrication, which in turn can cause severe wearing

of the packing, shaft sleeve, and even stuffing -box inside diameter. All

of these conditions cause stuffing box temperatures to increase.

3.2.17 Rotor axial position monitoring

This measurement indicates rotor axial position relative to the stationary parts of the pump.- Thrust'balancer (drum and disk), thrust runner, 'or bearing wear will cause-a change in the normal axial pump rotor

position.

3.2.18 Bolt torque inspection

This inspection consists of measuring the critical fastener torque.

A suitable calibration torque measuring device, such as a torque wrench,

should be used to check bolt torque against recommended vendor values.

Fastener wear or clamped part wear often causes a-relaxation to specified

torque values. Undertorquing can lead'to fastener wear and ultimate

fatigue failure, whereas overtorquing can lead to excessive preload to

the fastener and clamped part, causing overload'failures.

3.2.19 Leakage rate inspection

This measurement consists of a visual inspection of shaft seal

leakage and casing split line leakage. Shaft seal packing must allow a

finite leakage to ensure proper cooling and lubrication of the rotating

sleeve and mating stationary packing. As the packing wears, it will

normally exhibit increased leakage. Mechanical shaft seals should not

allow noticeable leakage. However, as the seal wears, noticeable leakage

can also be expected.
38

No leakage at the casing split line should be observed. Leakage

there may result from inadequate pressure boundary casing fastener

torque, a deteriorated casing split line gasket, or erosion of the pulap

casing split line surface.

3.2.20 Lube oil analysis and quantity inspection

This inspection consists of periodic sample analyses of the lube oil _

to inspect for contamination caused by dirt, wear, or abnormal bearing

and babbitt filings. An increase in the concentration of metallic contaminants indicates an increase in bearing wear. The presence of free

water in the lube oil can cause roller bearing corrosion and ultimately

failure. Improper oil viscosity can also cause bearing wear and failure

because the viscosity index directly affects lubrication capability.

Lube oil quantity is another important variable that must be checked.

3.2.21 Dynamic pressure monitoring

A measurement of the pump discharge pressure using a dynamic pressure transducer may show hydraulic instabilities occurring within the

pump caused by various problems, such as low-flow internal recirculation,

cavitation, and impeller stall.- This measurement is commonly used in

shop or laboratory tests of high energy per stage pumps, such as large

boiler feed pumps, steam generator feedwater pumps, and condenser circulating water pumps to determine the point of low-flow instability. A

centrifugal pump should produce a smooth, pulsation-free flow signature.

Flow-induced instabilities will cause a change in the flow signature,

generally manifested as low frequency pulsations (<10 Hz).

Cavitation or impeller stall often causes a strong vibration that

occurs at a frequency equal to blade passing frequency (i.e., rotating

speed multiplied by number of impeller vanes). Not only can this

frequency be detected with a pressure transducer, but it can also be

detected with vibration monitoring equipment, such as a vibration transducer mounted to monitor shaft vibration.

3.3 Summary of Measurable Parameter vs

Degradation Correlations

This summary, which is based on the previous discussions, is given

in Table 3.3. The parameters are to be used for both detecting and

tracking degradation caused by aging and service wear.
39

Table 3.3. Parameter vs degradation correlation

Parameter Degradation

Rotational torque Rotor-stationary part binding

Motor current Rotor rubbing or.binding and loss of

Motor power -efficiency due to wear

Turbine power

Rotational speed Overallamachine-healtha -'

Wear surface and critical Rotating and stationary part wear and

fit clearance gallingPressure or developed head Overall machine'health

Delivered flow. Overall machine health.

Vibration Wear of wear surfaces, impeller, bearings, gears, and-coupling; loose

fasteners; shaft seal deterioration; and

rotor-rubbing'

Surface indications- Cracks,-surface irregularities, etc.,.

-related to-structural integrity and

machine operation.

Balance return line flow' Internal clearance-increase

Audible noise - Rotor-stationary. part-rubbing or binding

and rotating part wear

Temperature Bearing wear -

Stuffing box packing deterioration

Rotor axial position -Thrust balancer, thrust runner, or bearing

wear

Bolt torque Fastener'loosening

Leakage rate, Shaft seal and casing split seal

-deterioration -

Lube oil purity ' -'Bearing wear -

Discharge-dynamic pressure Passage clearance changes due to wear

aRequired for reference in determining pump head and flow. '
40

4. EVALUATION OF ISCM METHODS

4.1 Recommended ISCM Methods

-7

This section identifies recommended ISCM methods selected from those

discussed in Chap. 3 and discusses the recommended methods. Major factors

influencing the selections were based on their ability to (1) establish

operational readiness, (2) detect aging and service wear degradation, and

(3) determine aging and service wear degradation trends. The selections

were also guided by W field experience with pumps similar to AUXFPs,

reactor coolant pumps, heat exchangers, steam turbines, steam generators,

reactor internals, and piping systems, as well as laboratory tests performed on pumps. An evaluation of the selected ISCM methods is summarized in Table 4.1.

The ISCM methods selected are labeled with an asterisk in Table 3.2.

The ISCtM methods not selected are motor current, turbine power, stuffing

box temperature, and dynamic pressure monitoring. The reasons are as

follows.

Motor current monitoring. Work has been done on the signature

analysis of motors in valve operator and other applications, and the results show broad potential for diagnostic use. However, experience with

signature analysis of this type is limited, and the data base required is

not available for near-term use.

Turbine power monitoring. Turbine power monitoring requires simultaneous knowledge of steam flow, steam pressure drop, and turbine speed.

It is unlikely that the accuracy and repeatability of these parameters,

when taken together, would provide a reasonable indication. Considering

the expense of such measurements and the lack of confidence in the results, turbine power monitoring based on the three variables mentioned

was not selected. However, other means for determining turbine power

should be investigated because this is an important parameter to correlate with pump flow and head.

Stuffing box temperature monitoring. An experience base for using

this method has not been identified. Consequently, there is not enough

information to select this as a viable method at this time.

Dynamic pressure monitoring. Pump hydraulic passage clearance

changes resulting from aging and service wear will often produce changes

in discharge pressure signatures. But it is unlikely that AUXFPs will

produce sufficient change in this signature to warrant monitoring of this

parameter because of their low to moderate energy per stage.

4.2 Further Discussion of Recommended ISCM Methods

In the following subsections, additional elaboration on the use and

capabilities of the selected methods is given to provide added insight

into details of their application and usage and the results to be

obtained.
I "r ,

I Table 4.1. ISCM evaluation summary

Effectiveness Importance a

MethodauedL os f ~ ,Method parameter (in determining in terms Cos t ion Remarks

aging and wear) of safety

Rotor binding Rotational Determines pump High Low Break-away torque measurement

inspection

Visual

inspection

Motor power

monitoring

torque rotating element's

ability to function;

Indicates operational

readiness

should be recorded/trended

and compared to baseline value

Appearance Very elementary but

highly effective means

to determine pump

operational readiness

Power

I;

Rotational Pump spo

speed

Dimensional Wear sui

inspection and cr1

fit cel

Indicates hydraulic

and mechanical

degradation

!ed Necessary to correlate

delivered flow and head

-face Indicates mechanical

Ltical wear

!arance

High

Medium

I

Low

M4edium to

high

Low

Implementation

cost - low;,

'instrumentation

cost - low

Implementation

cost - medium;

instrumentation

cost - low

Low to medium

Most elementary form of

inspection that can be

'performed; should be performed

during regular (routine)

maintenance and periodic

inspection, surveillance, and

maintenance

Should be trended

Instruments

Watt transducer:

Accuracy - medium,

Repeatability - high

Should 'be trended

Instruments

Proximity probe

Infrared stroboscope

Accuracy - medium

Repeatability - high

Should be performed during

regular '(routine) maintenance

and periodic inspection,

surveillance, and maintenance;

should be trended

ASME XI test acceptance

standard; tech. spec. standard;

should be trended

Instruments

Gages

Transducers

Transmitters

Accuracy - Medium

Repeatability -'high

Developed

head

monitoring

Pump head Indicates hydraulic'

(pressure) degradation; low 'flow -

may 'indicate only gross

degradation due to curve

"flatness"; wear and

aging indication improves

with increasing flow;

indicates operational

readiness

High Impilementstion

cost - high (if

instrumentation is

installed in

pressure boundary);

instrumentation

cost - low.
Table 4.1 (continued)

Measured Effectiveness Importance Costa of bc

Method parametr a(in determining in terms implementation Remarks Method parameter aging and wear) of safety

Delivered

flow

monitoring

Delivered

flow

Vibration Vibration

monitoring (displacement,

velocity,

acceleration)

Balance

return-line

monitoring

Audible

noise

inspection

Balance

return-line

flow

Noise

Indicates hydraulic

degradation;

low flow -'poor accuracy

and repeatability;

indicates operational

readiness

Indicates mechanical

degradation and

mechanical operational

readiness

Indicates hydraulic

degradation by virtue

of increased internal

leakage measurement

Change in audible

level may indicate

impending pump problem;

requires experienced

individual to perform

the assessment

Indicates mechanical

degradation;

especially effective

in determining impending

antifriction bearing

and shaft seal problems;

indicates operational

readiness

High

High

Low

Medium to

high

Implementation

cost - high

(if installed in

pressure boundary);

instrumentation

cost - high

Implementation

cost - medium to

high; instrumentation cost - medium

Implementation

cost - high (if

installed in

pressure boundary);

instrumentation

cost - high

Low

ASME XI test acceptance standard;

should be trended

Instruments

Orifice or Venturi:

Accuracy - medium

Repeatability - medium

Externally mounted instruments

(e.g., ultrasonic meter):

Accuracy - medium

Repeatability - low

ASME XI test acceptance standard;

should be trended

Instruments

Proximity probes:

Accuracy - medium

Repeatability - high

Velocity or accelerometers:

Accuracy - low

Repeatability - medium

Should be trended

Instruments

Orifice or Venturi:

Accuracy - medium

Repeatability - medium

Externally mounted instruments

(e.g., ultrasonic meter):

Accuracy - medium

Repeatability - low

Should be performed during

periodic surveillance testing

Incipient

failure

detection

(IFD)

Highfrequency

vibration

Medium to

high

Implementation

cost - medium;

instrumentation

cost - medium

Should be trended;

relatively new technique

Instruments

Piezoelectric sensor:

Accuracy - low

Repeatability - low

A'.1 4 I~~~~~~~ 44t '0 I ,, 41,
Ifs

Table 4.1 (continued)

Measured Effectiveness Importance Costa of

Method paret (in determining in terms Costion Remarksai

aging and wear) of safety

Bearing Teoperature Indicates bearing High Implementation ASME XI test acceptance standard;

temperature condition; can also cost - high, if should be trended

monitoring provide an indication installed in or Instruments

of lube oil purity and in proximity Thermocouples or resistance

quantity; indicates to bearing; thermal detectors (RTD):

operational readiness instrumentation Accuracy - high

cost - low Repeatability - high

Rotor axial Rotor axial Indicates mechanical Medium to Implementation Should be trended

position position degradation of the high cost - medium to Instruments

monitoring thrust bearing, balance high; instrumenta- Proximitor:

drum, or balance disk; tion cost - medium Accuracy - medium

indicates operational Repeatability - high

readiness

Bolt torque Torque Indicates fastener tight- Medium to Low Should be trended;

inspection ness, worn condition high should be performed during

of fastener or assembled , routine inspection (where

parts practical) and during periodic

inspection, surveillance, and

maintenance:-

Leakage rate Leakage rate Most practical indica- Medium to Low Should be trended;

inspection (shaft seal, tion of shaft seal high should be performed during

case, nozzles) condition routine inspection

Lube oil Lube oil Indicates condition of High Low - if performed Should be trended

analysis purity., lube oil; can prevent "in-house"

inspection impending bearing wear,

corrosion, or seizure

Liquid Surface Indicates cracking High Low Should be performed during

penetrant indications caused by overstress, periodic inspection, surveillance,

inspection corrosion, erosion and maintenance

aCost criteria:

High $10-$S50K

Medium $5-$IOK

Low e $0-$5K

bAccuracy criteria:

High 0.5-1%

Medium 1-10%

Low >10%

"Repeatability criteria:

High 1-5%

Medium 5-10%

Low >10%
I

44

4.2.1 Rotor binding inspection

This inspection is recommended as an important prerequisite to each

controlled pump start. The power to the pump driver should be disconnected to prevent inadvertent start-up during this inspection. A suitable

spanner wrench or other tool should be applied to the coupling and the

pump rotor turned. The inspector should determine whether any resistance

to rotation is excessive and should listen for rubbing noise that may

result from insufficient clearance between rotating and stationary parts,

bearing failure, or shaft seal failure. For consistent inspection

results, it is recommended that the torque required to maintain rotation

(free rotation torque) be measured and compared with the manufacturer's

specifications or a previous baseline measurement. Acceptance criteria

should be made available to determine whether the free rotation torque is

excessive. If excessive rotating resistance exists, the cause should be

investigated and corrected to avoid the possibility of catastrophic failure during startup or operation. A stethoscope or similar device can be

used to determine whether the rubbing is within the pump or driver. The

following inspection steps are suggested to minimize the investigation

effort:

1. determine whether binding is in the pump or driver;

2. check for proper lubrication;

3. determine whether binding is caused by misalignment of the pump and

driver; and

4. upon determining that the pump is at fault, disassemble and inspect

the pump in steps according to the manufacturer's procedure or other

approved procedure to determine the following:

- quality of lubricant;

- seal condition;

- bearing condition, including thrust bearing;

- corrosion, scoring, pitting, and overheating effects on rotor and

stationary surfaces; and

- dimensional changes of critical pump parts and wear surfaces.

4.2.2 Visual inspection

Regular inspections are those that are normally performed on a

routine basis and do not require disassembly of the pump. Regular visual

inspections should check the following:

1. lube oil level or quantity,

2. shaft seal leakage rate,

3. casing split leakage rate,

4. lube oil system leaks,

5. coupling lubrication leaks, and

6. external component or fastener looseness.

Periodic inspection, surveillance, and maintenance that should be perforned at certain intervals as described in Chap. 5 require disassembly

of the various pump parts. This inspection should include a visual
45

inspection and be combined with a dimensional inspection to include at

least the following:

1. radial bearings (journal or antifriction);-

2. thrust bearings (tilting pad or antifriction);

3. shaft seals, packing, packing gland, stuffing box, and shaft

sleeves;

4. coupling;

5. fasteners;

6. wear-ring surfaces and clearances;

7. thrust balancing device (drum or disk);

8. impellers;'

9. diffusers and return channels; '

1O.' shaft; and

11. 'casing split-surfaces. ' -

Chapter 5'discusses periodic inspection, surveillance, 'and maintenance in

more detail.

4.2.3 Motor power monitoring -- - -

Motor power monitoring can correlate the changes in developed head

and delivered flow. Comparing the changes in measured head and flow with

a resulting change in power will add confidence'to the head'-and flow -

measurements. The power measurement would be most useful in the part of

the pump performance region that shows a rising brake horsepower curve as

a function of-flow'rate'. *At high-flow rates'-the power curve' often "flattens," thus making it' difficult 'to measure-power changes'unless the pump

efficiency' were to change significantly. ' -

Increases 'in internal clearances caused by wear, and aging can result

in an increase-in power at a given flow-rate because'the impellers are

pumping both'the delivered flow 'and the "internal recirculation flow.

4.2.4 Rotational speed monitoring -- --

The ability of a centrifugal pump to produce both developed head and

delivered flow for a given impeller diameter is a function of pump rotational speed. ASME Sect. XI IWP requires that pump speed be measured on

pumps powered by variable speed drivers, such as steam turbines or diesel

engines.

Speed measurement is required so that-the proper-head 'and flow.

correlations can be established to compare pump hydraulic performance

against the 'base 'parameters. A baseline speed must be chosen and the

pump' developed head,'flow,'and'horsepower corrected to this base'c6ndition. To properly judge whether'the pump head and flow are degrading

because of aging and 'service wear, the actual speed should be measured

and'the performance corrected through the "affinity laws" to baseline

speed 'conditions. It is-also iip-ortant to measure the speed of motordriven 'pumps because voltage 'and-frequency variations to' these drivers

will affect the motor speed. The speed 'measurement" may also be used to'

confirig a problem with the 'driver power source.
46

A permanently installed speed measuring instrument, such as an eddy

current proximity probe, should be installed on the pump to read a signal

from the pump shaft. Such an instrument will provide repeatable measurements and minimize errors obtained with a portable device, such as a

stroboscope or tachometer. The proximity probe can also double as a key

phasor indicator for the rotor vibration measurement to facilitate rotor

vibration phase angle measurements.

4.2.5 Dimensional inspection

This inspection should be performed concurrently with the periodic

inspection, surveillance, and maintenance visual inspection. As

explained in Sect. 3.2, these measurements should include the impeller,

wear rings, shaft, bearing journals, keyways, thrust runner, thrust

balancer, shaft seal wearing parts, and coupling.

Pump vendors normally will not provide detailed part drawings to a

customer; however, they will provide the nominal new part dimensions and

tolerances as well as recommended dimensions to be used as guidance for

part replacement. These dimensions should be recorded and compared with

the new part dimensions. Proper records should be kept of all dimensions

to establish a history of part wear.

4.2.6 Pump pressure or developed head monitoring

As a pump ages and wears, its ability to produce delivered flow and

developed head reduces because of the reduction in hydraulic efficiency

caused by worn hydraulic parts. The effect of wearing parts on developed

head is described in the following subsection on delivered flow. It is

necessary to measure both the pump developed head and delivered flow to

determine specifically how the characteristic curve is degrading.

Existing plant instrumentation used to measure developed head normally consists of local suction and discharge pressure gages. Often, the

main control board contains a discharge pressure indicator. The existing

pressure measuring instrumentation may not be sufficiently accurate to

measure small changes in developed head. Therefore, it is recommended

that accurate pressure gages, or preferably a differential pressure

transducer connected to a digital readout, be used to measure and trend

small changes in developed head.

4.2.7 Pump-delivered flow monitoring

The primary purpose of an AUXFP is to deliver flow to the feedwater

system to provide secondary system emergency heat removal. Therefore, it

is important to accurately measure pump delivered flow.

As aipump ages and wears its hydraulic efficiency is reduced, and

for a given system resistance and pump speed, the pump-delivered flow

will be reduced. The reduction in efficiency results from the change in

wear-ring clearances between the impeller and stationary wear surfaces

and between the hydraulic balancing device (drum or disk).and its mating

wear surface. When these clearances are excessively opened, the hydraulic performance of the pump suffers because of the increased internal
47

stage-to-stage and balance return-line leakage. A centrifugal pump is

"1volume sensitive," meaning that it will develop head as a function of

flow. When the increased stage-to-stage recirculation flow is added to

the normal'through flow, the flow through the impeller is increased, and

because of the rising head characteristic, the pump impeller provides

less head. Each pump impeller is actually pumping the delivered flow and

the recirculation flow so that-the net effect is to develop less head

than that developed with only the delivered flow. Figure 2.7 shows the

effect of this recirculation flow on the pump head capacity curve. A

secondary effect of this recirculation leakage is the disruption in the

main flow component as it approaches the impeller eye. In Vol. 1, Fig.

D.3 demonstrates the secondary flow effects caused by-the recirculation

leakage at the impeller eye. Although this figure is designed to show

the effect on inlet flow'at off-design conditions, it also demonstrates.a

similar'condition resulting from the recirculation leakage.

Presently, testing on AUXFPs is performed at the pump minimum-flow

rate. As explained in Appendix'D,'Low-Flow Testing, the effect:of aging

and service wear'is'more difficult to detect in the low-flow region.

Technically, the change in delivered flow caused by wear and aging is

greater in the low-flow region than in-the high-flow region because at

lower discharge flow rates, the internal recirculation loss will increase

with the increased head'by the square 'root of the head difference. The

greatest flow loss effects will result when testing at low-flow, highhead conditions, whereas the'head-degradation will be more pronounced at

high-flow, low-head conditions.

Although testing at miniflow may confirm pump mechanical operational

readiness, -it may not demonstrate the'hydraulic operational readiness of

the pump, which is expected't6 deliver flow in an emergency at conditions

closer to the pump BEP.

Most AFW systems now contain 'a flow-measuring meter in the system

header. This meter may be an orifice or-venturi. A delivered flow readout'is also-contained on the plant main control board. -However,-because

we are often looking for small changes (<5% flow), it-is unlikely that

this readout is sufficiently accurate to predict-small changes in pump

performance.' If the existing flowmeter-system is judged not to be

sufficiently accurate to measure small changes, the meter upstream and

downstream taps should be connected to a differential pressure transmitter and-ultimately to a digital readout so that accurate and repeatable flow readings can be monitored,'trended, and evaluated. A dualrange instrument system should'also be considered. One instrument'would

be selected to measure low'flows accurately, while the second instrument

would measure'-in'the high'flows. This system is probably the best to

maximize accuracy and repeatability at-all flow conditions.

4.2.8 Rotor vibration monitoring

Comparison studies have shown the value of a vibration surveillance

program in reducing both pump failures and maintenance costs.-' This -

demonstrated value has resulted in the alteration of vibration monitoring

policies. Whereas previous practice used intermittent or as-needed

vibration monitoring as a diagnostic, troubleshooting tool, plants are

increasingly using-vibration monitoring in combination with other proven

.
I I

48

methods to implement predictive or preventative maintenance programs.

With AUXFPs, operational readiness is critical to plant systems' functionability and safety; therefore, the value of vibration monitoring

increases. Periodic vibration monitoring of AUXFPs is recommended to

enhance and complement existing operational readiness testing. Vibration

monitoring during operational readiness testing can provide additional

means for the early detection of abnormal vibration caused by bearing

wear, shaft seal deterioration, impeller and wear-surface wear, rotor

unbalance, driver misalignment, and shaft failure.

As discussed in Chap. 2, as a pump wears, the close running internal

clearances and the bearing clearances increase and change the rotor

dynamics. As wear progresses, the rotor vibration amplitude normally increases and vibration responses caused by multiples of the rotation speed

may change. By monitoring and trending the change in vibration amplitude

and frequency, it becomes possible to predict the extent of wear and

aging of the machine.

Recommended sensors include permanently installed noncontacting

rotor shaft proximity probes to measure shaft displacement. The proximity probes should be mounted 90° apart on the circumference of the

bearing housing. Bearing housing vibration should also be measured in

the same directions as the probes to determine shaft absolute vibration

amplitude. Bearing housing vibration can be measured using either the

dual-probe concept or bearing housing accelerometers. The dual-probe

concept uses a velocity transducer to measure housing vibration in

addition to shaft vibration. After integrating velocity signals, displacement signals from a proximity probe and velocity transducer are

summed to provide-shaft absolute motion. Data forms, such as Lissajous

(orbital) patterns, frequency vs amplitude plots, and time vs amplitude

plots can be generated from proximity probe data.

Lissajous (orbital) patterns are produced by inputting the proximity

probe signals to the X and Y axes of an oscilloscope or signal analyzer

and observing or recording the pattern produced by amplitude changes in

the two signals with respect to time. The Lissajous pattern describes

the motion of the rotor shaft relative to the bearing housing. Figures

4.1-4.4 show Lissajous patterns along with corresponding time histories

and frequency spectra for increasingly complex data signals. Time

histories and frequency spectra are included to illustrate the need for

evaluating multiple data forms because the Lissajous pattern can be

complex and inconclusive, depending on signal content and data signal

filtering. Figure 4.1 shows an ideal Lissajous pattern, corresponding

time histories, and frequency spectra. The data shown in Fig. 4.1 would

result from a single frequency response, such as rotation speed. In

actual data, other frequency responses, such as machine rocking, shaft

modes, and piping vibration modes may affect the Lissajous pattern.

These responses should be identified to recognize and trend only the

responses that are significant to pump degradation. Figure 4.2 shows a

typical Lissajous pattern resulting from misalignment, bearing wear, or

possible unbalance. The X-amplitude is significantly larger than the

Y-amplitude.'- The data in Figs. 4.1 and 4.2 may result from band-pass

filtering of the IX-rpm rotation speed, which' would exclude lower and

higher frequency responses, leaving only the rotation speed component.

Figure 4.3. 'shows patterns that could result from a combination of vibration indications, including misalignment, unbalance, rubbing, sliding,
49

Y

ORNL-DWG 88-4016 ETD

x

i(s)

(s)

w

0~

wU0

a-

_ 11111I 1-1

- | | ,I xrpm | | | I

_~~~ _I

_ 11 I I I I 1

I I

_ _ L _ _ _ _~~ I

0 10 20 30

FREQUENCY (Hz)

40 50- 0 10 20 30 40 . 50

FREQUENCY (Hz)

Fig.-4.1. Ideal 90°.out-of-phase time histories and frequency

spectra for shaft proximity probes mounted 90° apart on the-circumference of an AUXFP shaft.
I

50

ORNL-DWG 88-4017 ETD

Y

x

K - 0.05 S

-J

0~

wR

0j

a.

/ \ K'K I, k

71'1KMIiXLZH2iK7

1- L 1 - -- E-

(s)

t fcl 1 . %-,

I

1 Xrpm

W0 _l-- I TIl TI I I 1

0.

ig

wM0

-j

a.

I

_ __ __[_ I1 I I a . . . , . . . . . _

0 10 20 30 40 50

FREQUENCY (Hz)

0 10 20 30

FREQUENCY (Hz)

40 50

Fig. 4.2. Lissajous pattern, time histories, and frequency spectra

of pump data including misalignment, bearing wear, or possible unbalance. J.
51

ORNL-DWG 88-4018 ETD

Y

IMPACTING

x

-RUBBING OR SLIDING

(s)

t (s)

i

w

0Q

111W-'-_ 1 Xrpm __ - _ _

K-~~T1

:IMPACTING

i I~rpr Xp_

a-

-

0 40 80 120 160 200

FREQUENCY (Hz)

0 40 80 120

FREQUENCY (Hz)

160 200

Fig. 4.3. Lissajous pattern; time histories, and frequency spectra

of pump data showing a combination of misalignment or unbalance, rubbing,

sliding, and impacting.
I I

52

ORNL-DWG 88-4019 ETD

Y

.1

-X

t (s)

(s)

0 40 80 120 160 200 0 40 80 120 160 200

FREQUENCY (Hz) FREQUENCY (Hz)

Fig. 4.4. Lissajous figure, time histories, and frequency spectra

of pump data showing a combination of possible vibration indications.

-I
53

and impacting from bearing wear. Figure 4.3 Lissajous pattern shows the

double loop expected from the 2X-rpm frequency component along with the

1X-rpm frequency component and higher frequency random vibration caused

by impacting. Although Fig. 4.3 shows random vibration caused by impact-

'ing occurring at <200 Hz, impacting indications may occur at much higher

frequencies. Impact frequencies may be >20 kHz, but an upper frequency

of 5 or 10 kHz is generally adequate for impact investigations. Further,

the spectrum may show some broadening of the 1X rpm resulting from speed

changes caused by rubbing and sliding. Figure 4.4 shows a typical

Lissajous figure, time histories, and frequency spectra resulting from

severe rubbing, sliding, and impacting. Although difficult to observe,

this type of Lissajous pattern may contain harmonics of the rotational

speed and random vibration along with rubbing, sliding, and impacting

indications. The result may appear as random shaft motion but, most

importantly, shows relatively large amplitudes. Figure 4.4 also shows

other possible vibration responses that may be observed in the frequency

spectra, thus illustrating the need to understand the vibration signature

of the pump or other equipment and to determine which responses are useful for diagnostic and trending purposes.

The ASME Boiter and Pressure Vessel Code, Sect. XI, Subsect. IWP,

states the rules and requirements for the in-service testing of Class 1,

2, and 3 centrifugal- and displacement-type pumps-installed in lightwater-cooled nuclear power plants. However, Article IWP-2000 states,

"These tests are not designed to establish complete pump performance.'1

The in-service test requires the measurement of rotor displacement in the

frequency range of one-half minimum speed to at least maximum pump shaft

rotational speed along with other parameters. This discussion of the

ASME Code'requirements is included here to illustrate that the' recommendations of this section are a logical extension of current in-service

testing practice.

During'in-service testing, it is recommended that rotor shaft vibration data and other data be recorded on a Frequency Modulated-(FM) tape

recorder with an expanded vibration frequency range limited only'by

proximity probe maximum response. With the' availability of multichannel

tape-recorded data, it becomes possible to study and'trend many additional pump-vibration characteristics in addition to meeting in-service

testing.requirements. These recommendations are not intended to imply

that the use of hand-held vibration equipment should be discontinued.

Although hand-held equipment is valuable for many applications, the data

collection and analysis capabilities of hand-held equipment are limited

in comparison to the wide range of available data collection and analysis

hardware and software. - -

Table 4.2 contains a list of vibration causes and characteristics

that are useful in relating vibration to failure data. Figure 4.5

illustrates possible trending of frequency spectra and shows the progression of bearing vibration to near failure.- Other pump operating

problems, such as cavitation and flow turbulence, may result in bearing

vibration spectra similar to those shown in Fig. 4.5. However, assuming

the transducer is installed near the bearing and data from other machine

locations show no changes, then the cause of the change in vibration

signature at this bearing location should be investigated, particularly

if the rotor vibration amplitude is approaching maximum in-service test
54

Table 4.2. Vibration causes and characteristics

Frequency relative

Cause to pump speeda Amplitude Remarks

7

Unbalance

Bent shaft

lx Radial, steady

1X, often 2X,

sometimes 3X or 4X

1X

Axial - high

Sleeve bearings Primarily

radial

Roller bearings Radial - low

Journal bearings

loose in

housing

Mechanical

looseness

10-I OOX

Subharmonics of

shaft speed;

1/2 or 1/3X

O.1X-1X, could also

be 2X, 3X, or 4X

Primarily

radial

Most common cause of

vibration

Axial vibration up

to 2 times radial

Shaft and bearing

amplitude same

Frequency depends upon

type of bearing; use

acceleration mode;

consider cepstrum

analyses

Looseness may develop

only at operating

speed and temperature

Note subharmonics of

loose journal bearings

above; includes

foundations

Axial amplitude 0.7 or

higher of vertical or

horizontal

Oil whip excites

balance resonance

Misalignment

Parallel

Angular

Oil whirl or

whip in journal

bearings

Blade/vane pass

Cavitation

Gears

1X, 2X, 3X

1X, 2X, 3X

0.4-0.49X

Radial

Axial - high

Radial,

uxis teady

Number of blades/

vanes times X;

also harmonics

Random

High, related to

other meshing

frequencies (X

times number of

teeth) and harmonics

1X or sub 1X

High, can be

multiples of IX-lOX

Radial

Fluctuating

Radial - low

Also look for radial

vibration in direction

of discharge piping

Can be up to 2 kHz

Cepstrum analysis can

be valuable technique

Fluidic forces

Common rubs

* ax is machine speed in revolutions per minute. 5-

I
55

Notes to Table 4.2

Unbalance - Unbalance is the most common cause of vibration. It occurs when the

center of mass of an object is not also'its center of rotation. The apparent

presence of a "heavy spot" causes forces to be applied that result in vibration.

Unbalance produces a vibration reading whose amplitude is directly proportional

to the amount of unbalance and whose frequency is the same as the running-speed

of the machine being measured.

For example, an 1800-rpm motor that is-unbalanced will have vibrations at 1800

cpm (30 cycles per second), and the amount of vibration will be proportional to

the amount of unbalance.

Bent shaft - In case of a bent shaft- a high axial -vibration-level at a frequency of single and sometimes double the'shaft revolutions per minute will be-noted.

By observing the axial vibration at bearing A and bearing B, with-the pickup held

in the same direction on both bearings, the phase indication will be that of a

static pair condition (reference mark at the same position for both bearings).

Note that for every rotation'of the-shaft a vertical impulse on the'out-board and

inboard end of each bearing will occur. This results in two impulses of vibration

for each rotation of the shaft. If the bent shaft condition occurs as deflection,

or deformation, at operating'speeds, it can-in many cases be corrected by-adding balance weights at the center of the-shaft.' This will tend to straighten the

shaft, and the masi centerline will'then coincide with-the rotation centerline.

Normal'two-plane balancing-should'be followed. - ' -

Misalignment - Misalignment of couplings and bearings results in a high axial

vibration reading. This may'be-as much as 1.5 times the vertical'or horizontal

readings. This condition generally occurs at two times'the running speed of the

machine, although it may also occur at one (or even three) times the running or

primary frequency. ' '

Oil whip - A condition known as "oi whip" may occur in lightly loaded sleeve

bearings."This instability is reflected by vibration frequency-near, but always lower than one-half, the actual'shaft speed. Correction of "oil whip" can be'

made by changing the bearing clearances or bearing design, changing the positions of the'oil groove; increasing the'shaft loading, or changing the oil characteristics, such as viscosity. -

Cavitation -Cavitation is a-somewhat common-problem with centrifugal pumps and normally results whenever the pump is-operated above its -designed capacity or

with inadequate suction pressure. 'Since the pump is "starved," -the fluid'coming into the pump will-literally be pulled apart in an'attempt to-fill the void that

exists., This creates pockets, or cavities, of nearly perfect vacuum which are

highly unstable and which collapse or implode very quickly.- Because of their

impactive nature, these implosions excite the local' natural frequencies of the

pump housing, impellers, and other related pump parts; and,'since these implosions

may occur at random intervals at various-locations within the pump or piping, the resulting vibration will be random in amplitude and frequency. Thus,'a vibration

caused by cavitation in a pump may cover a broad frequency range,'where individual

amplitudes and frequencies are constantly changing.

A distinctive noise often accompanies Cavitation. Mild cavitation may have the

sound of sand being pumped, whereas a more severe caVitation may sound as though gravel was being passed through the pump. In cases of extremely severe cavitation, it may sound as though rocks-are being passed throug'hthe pump.
I I

56

Notes to Table-4.2 (continued)

Common rubs - Rubs are typical phenomena to which a machine has no corrective

response. In most cases a machine experiencing a full rub condition will

progress to an immediate and catastrophic destruction of the machine. Rubs are

typically introduced in machines by introducing contact between the rotor and a

stationary element (labyrinth seals, diaphragms, etc.). Contact may be initiated

by increased mass unbalance, thermal bow, or other mechanism causing the shaft to

deflect or bend beyond the available clearances or by misalignment of the stationary elements.

In most cases, a full rub is preceded by a partial rub. Since the rotating

system has no self-correcting capability, the rub must be defined and eliminated.

Dismantling of the unit and examination usually are required to determine the

extent of damage.

Looseness - Mechanical looseness, coupled with misalignment of couplings or bearings, generally occurs at a frequency of 0 to 1X the machine speed (rpm). The

amplitude of the machine is normally dependent on the amount of looseness and the

design of the machine.

Unbalanced rotational forces (no system is imperfect balance) and changing.

torque loads result in impacting of the base twice for each revolution. Excessive bearing clearance will produce the same results. Essentially, looseness

allows more vibration to occur than what would otherwise be expected. This is

particularly true in antifriction bearings, where small amounts of unbalance

result in large vibrations at the first and second harmonics of the shaft speed.

In most situations, this vibration will significantly decrease when the unbalanced force or misalignment is corrected.

Bearings - Excessive clearance in sleeve bearings can normally be determined by

comparing the vibration level reading on the bearing housing using an accelerometer or velocity pickup, as close to the bearing as possible, and the vibration

level of the shaft itself using a noncontact probe. Note that the pickups must

be in the same plane and direction when taking both readings.

In many cases, manufacturers balance an antifriction bearing part by rotating it

on the shaft, rather than in the bearing on which it will be finally assembled.

If the rotational center of the antifriction bearings in a race is not coincident

with the physical center of the outer races, a difference in the mass center and

rotational center of the shaft will occur. This obliterates any prior balance

performed. If bearing replacement, after original machinery installation, does

not take this factor into consideration, an unbalanced condition may occur.

In the case of antifriction bearings, the scoring or brinelling of the balls or

rolls will produce a high-frequency, low-amplitude vibration. It is best to use

acceleration or velocity readings to detect faulty antifriction bearings. (A

high-frequency but low-displacement signal has a high velocity, being a product

of frequency and displacement, and higher acceleration, being a product of the

displacement times the frequency signal squared.)

Verification of poor bearing performance is made by shutting off the machine and

observing that the high bearing frequency remains as a unit coasts down in

speed. This high-frequency signal will normally be retained until the machine

comes to rest. The frequency indication is usually from 5 to 20 times the

primary frequency of the part contained by the bearings.
57

ORNL-DWG 88-4020 ETD

0 100 -200 300- 400 500 -

FREOUENCY (Hz)

Fig.,4.5. Spectrum overlay of ball.bearing vibration progressing

to wear failure.
58

criteria. Using techniques similar to these, failure criteria can be

generated, and pump conditions leading to failure can be identified and

corrected.

Failure criteria in addition to in-service test criteria can be

generated and refined based on experience and current studies. One such

study is discussed in Vol. 1 of this report. Figures D.6-D.8 of Vol. 1

show some of the results of these studies. Particularly useful are data

such as those reported in Fig. D.8, which provides allowable rotor vibration levels measured relative to the bearing cap.

In summary, the recommendations for pump vibration include permanent

installation of shaft proximity probes and velocity or acceleration

transducers that are capable of measuring pump casing vibration and recording data with a broad frequency response for investigating and trending multiple vibration characteristics.

4.2.9 IFD monitoring

IFD monitoring, sometimes called acoustic high-frequency or stresswave emission monitoring, can be successfully applied to detect and predict rolling contact bearing, coupling, gear wear, or shaft seal deterioration. Acoustic frequencies are ones that are above the audible range

or from 2U to -300.kHz. In general, for AUXFPs, a piezoelectric sensor

with a resonance near 100 kHz will.provide the most useful data. Acoustic frequency responses are caused by rolling or sliding friction and

metal deformation when metal components, such as ball bearings and gears

are severely stressed. Severe stressing of components does not exist

during normal machine operation; therefore, changes in acoustic responses

are indicative of abnormal operation and potential failure. In the case

of shaft seal failure, leakage between seal faces may produce highfrequency broadband random responses. These responses have been detected

with IFD sensors and can be used to identify particular shaft seal failures. The attractiveness of IFD monitoring with respect to aging and

service wear and failure detection is that responses show changes that

precede low-frequency response changes. In general,-IFD response changes

may indicate a condition leading to a defect, and low-frequency response

changes indicate the progression of an existing defect. Depending on

bearing or gear design and application, changes in IFD responses may

precede lower frequency vibration changes by days or weeks. Figure 4.6

illustrates the time relationship between conventional vibration monitoring signal-amplitude and IFD emission signal amplitude. The root mean

square (rms) value of the high-frequency signal shows an increasing

amplitude before the low-frequency signal amplitude changes. Just prior

to failure, IFD may show a decrease while low-frequency vibration increases. This finding is believed to be caused by the reduction in metal

deformation at the onset of metal failure and mechanical defects.

Using signals from both low- and high-frequency sensors, the progression can be trended to provide the early detection of potential failure. For some actual bearing conditions, the sensitivity of IFD has been

demonstrated. Changes in IFD emissions were identified well in advance

of the detection of active defects. This sensitivity points out the need

to identify for particular machines a level of IFD activity that is

critical to avoid unnecessary early repairs. For example, referring to
59

ORNL-DWG 88-4026 ETD

wU

0

0L

0

C,)

w

cI I I -- 1

5 6, 7 8 9 10

DAYS TO FAILURE

Fig. 4.6. Relative signal -amplitude vs days to failure for

acoustic and conventional vibration monitoring methods.

Fig. 4.6, the level of activity critical to operation-may be specified

initially as a factor of 4 increase'in-high-frequency signal level along

with observable changes in low-frequency vibration responses. It is '

believed that critical emission signal levels can be identified by correlating and comparing data from shaft proximity probes, case accelerometers, and IFD sensors. Accelerometers are available with frequency responses up to 54 kHz, making possible some overlap of accelerometer and

IFO data for both correlations and comparisons.

Because of the value of detecting machine abnormalities early, a

piezoelectric sensor should be mounted as near as practical to each

bearing, and these data, along with other data, should'be used in studies

to determine IFD emission activity relative to more conventional vibration monitoring. A realistic determination of signal emissions with

respect. to failure causes could lead to eliminating some of the conventional vibration monitoring eqiuipment,,thus reducing both-monitoring and

maintenance costs.
60

4.2.10 Liquid penetrant inspection

This inspection is intended to be performed during periodic inspection, surveillance, and maintenance. Highly stressed areas, such as

fillets, grooves, keyways, and impeller bores should be inspected for

such problems as cracks and surface indications. Liquid penetrant inspection is a well-proven and commonly used form of nondestructive testing. However, like all forms of nondestructive testing, the user must be

experienced in the application of the method and in the interpretation of

results.

4.2.11 Balance return-line flow monitoring

As described in Chap. 2, when the close running clearances of a pump

wear, the internal leakage between stages increases and the pump's efficiency decreases. Since these wear-ring clearances also function as

bearings, the shaft vibration increases as these clearances increase.

A measuring technique that has been used on boiler feed pumps to

measure the change in clearance is to measure the increase -of balance

drum (or disk) return flow. The inner surface of a balance drum is exposed to high pressure (either full discharge pressure or an intermediate

pressure), whereas the outer surface is at suction pressure. Consequently, a controlled leakage occurs through the close rotating clearances of the balance drum and its mating bushing. As with the interstage

wear rings, leakage across the drum increases as the clearance increases.

This leakage is termed "return flow" because it is returned to the pump

suction. Although this technique only measures the flow through the

balance drum clearances and not that through the interstage wear rings,

it is generally accepted that an increase in balance drum clearance also

reflects a similar change in the interstage clearances.

One method to measure the return flow uses an orifice installed

between two flanges midway in the balance return line. Clamp-on ultrasonic flowmeters have also been installed on these lines. These meters

are not as accurate as an orifice or venturi meter, but they do not

require cutting into the line, nor do they produce a restriction and

resulting pressure drop.

The flow through an annular clearance, such as a wear ring, is proportional to the clearance; therefore, the increase in flow is basically

proportional to the clearance change. By first obtaining a baseline

measurement of flow and then monitoring and trending the change, one can

estimate the change in wear-ring clearance.

4.2.12 Audible noise inspection

This inspection, which requires the pump to be operating, can be

combined with-the regular visual inspection. It will require someone

with experience in pump or machinery noise who is familiar with the pump

and its operational history. A normally operating pump will produce a

distinct audible noise signature, whereas an abnormally running pump that

has developed a problem will often produce a change in audible noise.
61

Problems or failure causes associated with cavitation, rubbing, high

shaft vibration, bearing wear, coupling wear, and so forth,-can often be

diagnosed by this method.

4.2.13 Bearing temperature monitoring

Bearings should be instrumented with thermocouples or resistance

temperature detectors (RTDs) to measure bearing temperature. On AUXFPs

equipped'with-antifriction bearings,-the' bearing housing must be drilled

to accommodate a spring-loaded thermocouple. The thermocouple tip must

rest tightly against the bearing outer race to enable fast response to

any changes in bearing condition. For journal bearings, thermocouples

should be permanently embedded in the bearing liner metal near the -

babbitt to backing interface. Embedment will require drilling through

the bearing housing.

AUXFPs furnished with journal bearings have lubrication systems that

include an oil reservoir, a shaft-driven oil pump, an auxiliary motordriven oil pump, an oil cooler (oil-to-water heat exchanger),-and interconnecting piping. Depending on-the design of the lubrication system,

additional temperature measuring equipment may-be necessary to determine

overall bearing performance with time. To determine or infer the heat

generation in a bearing,--the temperaturevchange-of-the incoming and outgoing bearing-oil should be -determined. :Therefore, it is recommendedthat the-oil temperature leaving the bearings and the-oil cooler beinstrumented. - - -

As a rolling-element bearing wears, its temperature will-increase

because of-the additional frictional heat generated. Bearing'wear will

also result in increased shaft vibration.

- Bearing temperature and bearing oil- temperature should not exceed

values established by the pump vendors and the- oil supplier. Temperature

data gathered and. recorded during-an in-service test can be easily compared with baseline'test data to'determine-whether a change in bearing

performance has occurred. This-data can be used to prompt additional

data evaluation to pinpoint the cause of the change in bearing performance (e.g., bearing:wear, shaft and bearing misalignment'as a result of

wear-ring wear, pump element flow instabilities, and-unbalance). These

changes are most apparent during start-up when the machine is heating

from ambient conditions to normal operating conditions. Data m'anipulation is required to make comparisons because of changes -in ambient

temperatures-and cooling water temperature. This task is easily accom-

-plished using numerical techniques or-graphical techniques. Changes in

the slope, shape, or magnitude of a plot of temperature as a function of

time will reveal a-need for further investigation.

4.2.14 Rotor axial positi-6n monitoring'

This measurement indicates the axial position of the rotor relative

to the stationary pump parts. -It can provide a-wear indication of _the

thrust balancing device because a change in the clearance between the

rotating balancing device and the-stationary face or bushing-can disrupt

the hydraulic balancing capability of the balancing device. A change in
62

axial position can also indicate the wearing of a thrust bearing, and in

many instances, cavitation in the impellers can also disrupt the hydraulic balancing system of the pump. Both of these conditions can cause

axial shuttling of the rotor. This measurement is often used on large

fossil or process plant boiler feed pumps.

Most often, a proximity probe is installed to measure the rotor

axial movement. The probe is installed on the outboard or thrust end of

the pump against a relatively flat surface. The readout can be an analog

or digital meter that may contain a relay to trip an alarm. The pump

vendor should be consulted relative to the expected and maximum allowable

rotor end float so that this condition can be properly monitored.

4.2.15 Bolt torque inspection

Many different fasteners are used in pumps to secure the various

parts. Large fasteners secure the pump case to the support. Large

fasteners are also used to clamp together the two halves of the pressure

containment case. Smaller fasteners secure the shaft seal parts together.

Besides the different fastener sizes, various materials are involved, all

having different material and mechanical properties, such as corrosion

resistance and yield strength.

Fastener wear or clamped-part wear often results from shaft vibration, thermal relaxation, improper clamped-part fits, or improper

torquing during assembly. Undertorquing can lead to fastener wear and

ultimate fatigue failure caused by the clamped parts rubbing or fretting

against the fastener. Overtorquing can also lead to fastener failure

caused by excessive preload to the fastener and clamped part, causing

overload failures.

Fastener loosening or breakage has led to catastrophic failure of

shaft seals, bearings, and even rotating assemblies. Improper torquing

at gasketed surfaces, such as the pressure containment casing, suction or

discharge flanges, stuffing box to casing joint, and bearing housing

split lines, can lead to leaks caused by insufficient gasket seating

load.

High shaft vibration is the single most common source of fastener

loosening or breakage. Then again, casing or bearing housing vibration

can be caused by loose support or housing fasteners. Component movement

inside the pump caused by loose fasteners can often be diagnosed by

monitoring rotor shaft vibration frequency spectrum plots. Loose parts

will normally cause a one time or lesser multiple of running speed.

During the periodic inspection or whenever the pump is disassembled,

bolt torques should be checked at disassembly and, of course, during

reassembly. Many of the later pump manuals contain detailed torquing

criteria for all fasteners. If the manuals are unavailable, this information should be obtained from the pump supplier. A suitable calibrated

torque measuring device, such as a torque wrench, should be used to

torque the fasteners to recommended pump vendor values.

Note that bolt torque values are a function of preload, bolt size,

and material. If a thread lubricant is used, then the torque value must

be adjusted to avoid overtorquing because the fastener will more easily

tighten with the presence of a lubricant. In areas of high vibration,
63

or when fastener loosening has been a problem, the use of a locking

mechanism, such as a tab washer, lock washer, or double screw,-may be

warranted.

4.2.16 Leakage rate inspection

As noted in Sect. 3.2.19, leakage rate inspection consists of a

visual approximation of the leakage rate. At installation, or during

normal acceptable pump operation, the shaft packing should permit sufficient leakage to allow appropriate lubrication of the packing to keep the

packing running cool. Leakage during this normal -condition should be

visually noted and used as a baseline parameter for reference later. Increases in the visually observed packing leakage rate should be carefully

monitored and-trended. Simple tightening-of the gland nut ma'y'adjust

leakage to acceptable levels, but care must-be taken in order not to cut

off leakage entirely with resultant overheating and damage to the packing

and other stuffing box components. All packing adjustments should be

recorded and trended along with the leakage data discussed previously. -

Based on this trending, aging'and service wear degradation can be monitored and packing replacement indicated before overall pump failure

occurs.

4.2.17 Lube oil analysis and quantity linspection

Many of the bearing problems reported involved oil contamination

either by water or dirt., Research efforts begun years ago by the utilities industry have resulted in optimized lube oil analysis methods for

light lubricating oils. Numerous laboratories located throughout the

nation will perform analysis of-lube oil. A thorough lube oil analysis.

program checks for appearance, water, flash point, viscosity, total acid

number, and additive content.

- The appearance test is purely visual. If free water is noted during

the test, further testing is not warranted. Free water is highly undesirable in-rotating equipment reservoirs because it can accelerate the

formation of sludge and seriously lower the effective viscosity. -On many

occasions, ,the catastrophic failure of bearings has been attributed to

free water in the oil.- Flash point testing is performed whenever it is

believed that-light hydrocarbons-may be present in the oil. If the oilis contaminated, the flash point-of the oil is lowered. Viscosity is

lowered by light hydrocarbon contamination.

The oil viscosity test is among the most important tests.- Excessively low viscosity reduces oil film strength and deters the ability to

prevent metal-to-metal contact. Low viscosity also hinders the ability

of the oil to resist contamination and reduces its-ability to seal.

Excessively high viscosity impedes effective lubrication. Contaminants

that thicken the oil may cause accelerated wear or corrosion of lubricated surfaces and may leave harmful deposits.

Acid formation can result from high temperature or overused and

worn-out oil. Acidity can be considered a serviceability indicator that

increases with progressive oxidation but can also be influenced by atmospheric contaminants.
I I

64

Premium or good quality lubricating oils contain a phenolic oxidation inhibitor that breaks down after long-term operation of the oil

after contamination by water or exposure to high operating temperatures.

Oxidation inhibitors minimize the formation of sludge, resins, varnish,

acids, and polymers.

Other tests, such as wear-particle analysis, can provide valuable

information on component wear and incipient corrosion.

Lube oil quantity inspection must be an integral part of routine

inspection and maintenance.

4.3 Parameter Monitoring to Establish Trends

The parameter monitoring methods recommended in the previous section

should be implemented to determine operational readiness, to detect aging

and service wear degradation, and to track this degradation. Existing

instrumentation should be evaluated to determine whether this instrumentation will provide sufficiently accurate and repeatable data so that

relatively small changes in performance can be measured to establish data

trends.

We do not necessarily advocate the installation of "hard wired"

instruments that directly wire the transducers to permanently installed

back-mounted readout meters. However, we do recommend that pressure,

temperature, and vibration measuring transducers be permanently installed

on the pump (or piping systems) to minimize measuring errors. Data can

then be collected using either existing readout meters (if they are sufficiently accurate) or collected with a hand-held portable and programmable electronic data recorder (a device that is becoming increasingly

popular) to measure rotating equipment performance. These data can then

be fed into a personal computer and analyzed. Numerous vendors design

and produce software that can plot, analyze, and trend data. Software is

available that can print caution or alarm conditions and mathematically

extrapolate the data to predict the failure condition from the preestablished and program-entered alarm conditions. Software is also available

that will perform vibration analyses, such as fast fourier transformation

(FFT) analysis (otherwise known as spectrum analysis), which can be used

to display vibration amplitudes vs frequency components. This technique

is extremely valuable in diagnosing machinery problems and, when trended,

in analyzing changes in the machine caused by aging and wear mechanisms.

Monitored parameters that should be trended include

1. rotational speed,

2. vibration,

3. balance return-line flow,

4. developed head and delivered flow,

5. rotor axial position,

6. audible noise,

7. IFD response,

8. bearing temperature, and

9. motor power. 1'
65

These trends should be analyzed and compared with acceptable established

values, such as those provided by ASME XI (IWP), the American Hydraulic

Institute, or the pump supplier, to predict the condition of operational

readiness and the necessity to perforia corrective maintenance on the

diagnosed pump segment or part.

Data should be collected during each surveillance test and during

plant start-ups or shutdowns whenever the AUXFPs are operated. No

special testing outside of these requirements should be performed other

than to diagnose special problems.
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66

5. THE ROLE OF MAINTENANCE IN ALLEVIATING

AGING AND SERVICE WEAR

5.1 Types of Maintenance

Three aspects of maintenance - predictive, preventive, and cocrective are applicable to nuclear power plant safety systems. Figure 5.1

graphically displays the three modes of maintenance that have evolved

with time. Now most nuclear utilities are primarily in transition

between corrective and preventive maintenance.

ORNL-DWG 88-4021 ETD

ADVANCED PREDICTIVE

cn

w

E

E PREDICTIVE

ANALYSIS PREVENTIVE MAINTENANCE

BASIC CORRECTIVE MAINTENANCE

PRESENT - TIME - FUTURE

Fig. 5.1. Means to predictive maintenance.

5.1.1 Predictive maintenance

Predictive maintenance results frota the combination of preventive

maintenance and predictive analysis. Predictive analysis is the routine

monitoring, trending, and analyzing of operating data for components and

systems important to power plant productivity. By providing a key to

planning a program of preventive maintenance through the baseline evaluation of equipment, predictive analysis ensures a streamlined, highly

refined approach targeted to the operating trends and potential programs

of the specific component. Combining the preventive maintenance approach

with the unit-specific findings of predictive maintenance should result in

1. reduced component downtime;

2. forestalled maintenance outages;

3. forced outage avoidance;

4. optimized plans for upgrade, modernization, or plant life extension;

5. improved plant efficiency; and

6. reduced maintenance expenditures.

Once the utility adopts the predictive maintenance mode, it can adjust

the scope and schedule of equipment inspection, repair, and/or replacement and thus achieve its maintenance goal by

1. focusing expenditures on activities with the highest probable impact

on reliability,

2. eliminating unnecessary maintenance,
67

3. reducing actual maintenance costs through efficiency-improvements,

4. reducing the cost of lost production, and

5. reducing insurance premiums resulting from fewer equipment failures.

If followed, recommendations provided in the NRC NPAR Program concerning

inspection, surveillance, and monitoring will form good bases for the implementation of predictive maintenance practices in nuclear power plants.

5.1.2 Preventive maintenance

Plant maintenance is evolving from a corrective approach to a preventive one. Preventive maintenance involves routine service, inspection, and repair (or replacement) of equipment based on such factors as

time, experience, vendor recommendations, codes, standards, and regulatory

requirements. Utility'initiatives in preventive maintenance have been

valuable in both increasing plant efficiency and reducing forced outages.

However, preventive maintenance can also lead to component problems, such

as nonessential work. Without effective planning, management, and monitoring, the preventive approach can lead-to higher than necessary-maintenance costs. The critical goal now is to balance-the progressive -trend

toward preventative maintenance with the potential cost of lost production. Without this balance, the utility may risk over or under investing

in preventive maintenance with only marginal improvements in net power

plant productivity. Achieving this balance or maintenance goal offers

the minimum combined cost of production while maintaining component reliability. To assure long-term efficiencies in a preventive maintenance

program, it is recommended that component-specific maintenance activities

be developed by

1. applying engineering judgment and utility/station maintenance philosophy, by selecting, grouping, and evaluating known requirements'to

establish the most effective set of'-activities for the'equipment; and

2. establishing baseline signature analysis of the equipment, monitoring

the effectiveness of maintenance by periodic tracking of changes to

the baseline condition, and taking appropriate action when significant changes occur. - -

5.1.3 Corrective maintenance

Corrective maintenance involves the actual repair of a disabled

machine. -It considers the corrective measures necessary to return a

machine that is broken to safe and proper operation. Proper corrective

maintenance relies upon all areas of maintenance, such as

1. review of condition monitoring results,

2. component preventive maintenance,- --

3. planned, streamlined procedures to minimize oversights or errors in

assembly, - - -

4. specialized tools,

5. adequate spare part inventories,
68

6. proper updating of equipment manuals, and

7. regular training of maintenance personnel.

If the nuclear plant is at power, corrective maintenance on AUXFPs or

other safety components often requires working under a time limitation

specified by the technical specifications. Typically, 72 h is allotted

to complete the repair and return the component to service. Therefore,

it is even more imperative that correct, updated, and efficient records,

procedures, and spare parts be available to complete the repair to minimize component downtime and reduce the risk of plant forced outages.

5.2 Vendor Recommendations

As discussed in Vol. 1, vendor maintenance recommendations for

AUXFPs are not very extensive. For example, one AUXFP vendor technical

manual only includes the following regular maintenance information:

1. a general discussion of shaft seal stuffing box packing, including

packing gland tightness adjustment instructions;

2. bearing lube oil change interval; and

3. bearing lube oil level setting.

Other instructions pertaining to cleaning, pump-to-driver alignment,

bearing and coupling lubrication, bearing maximum temperature limits, and

shaft vibration limits are provided under the sections entitled "Installation" and "Operation." However, the only information provided under the

section specifically entitled "Maintenance" pertains to complete pump

disassembly and overhaul. Inspection information includes

1. shaft runout tolerances,

2. bearing visual inspection guidelines, and

3. running clearance dimensions of rotating internal and stationary wear

surfaces.

The information provided in the cited manual is typical of that provided

in most AUXFP manuals. The lack of detailed regular or periodic maintenance instructions is not the fault of the vendor alone. Equipment specifications seldom indicate operating times or modes, and consequently, the

vendor has no way of knowing the extent of regular maintenance to recommend. In retrospect, users often complain or ignore maintenance requirements that they believe are too stringent, frequent, or inconvenient to

apply.

5.3 Current Utility Practices

The following describes typical maintenance now being performed on

AUXFPs in nuclear power plants.
69

5.3.1 Regular maintenance

Utilities establish maintenance requirements for their equipment

based on the pump vendor's technical manual, vendor technical bulletins,

NRC inspection and enforcement bulletins, circulars,'-notices, INPO recoumendations, and other information provided by industry.

A review of several utilities' maintenance'activities has revealed

that operations personnel regularly - '-

1. inspect shaft seal leakage and adjust the gland as required,

2. inspect bearing oil level and adjust as required, '

3. inspect for water leaks at the casing split,,-and

4. inspect for oil leaks in the lubrication system.

Furthermore, periodic mainteenance 'includes changing the bearing lube oil

or performing a lube oil analys'is'every 6 months. No complete disassembly, inspection, or maintenance is normally performed unless the pump

develops a problem requiring this action.

5.3.2 Surveillance and condition monitoring

The plant technical specifications (part of the plant operating license), require that the AUXFPs, like'all safety-related pumps, be tested

normally each month to verify operational readiness. ASME Sect. XI Subsect. IWP (Refer to Vol. 1, Appendix A) provides a listing'of the parameters required to be measured. The general thrust of this test is directed

toward a verification of the pump operational readiness.

The test is performed while the pump operates at miniflow and requires measurement of pump developed-head, shaft-vibration, speed, and

bearing temperatures. Permanently installed instruments typically consist of (1) suction:and discharge pressure gages,-(2) motor current meter

or turbine steam flow element'(to measure pump power), and (3) a pumpdelivered flow element. All other instrumentation is typically the portable type (e.g., vibration meters and an optical pyrometer).

Acceptance criteria for pump head:is usually-.given-in the plant

technical specifications and ASME Sect.'XI. Vibration limits are based

on trending or change:from a baseline,.which is-defined in ASME Section

XI. Typically, the monthly test values are compared against acceptance

criteria. 'The'pumpleither passes the test unconditionally,.rates an,

alert condition, or rates an alarm condition that results in a limited

condition of operation (LCO). -The utility will normally not perform

diagnostic analysis-unless an alert or alarm condition exists. Also, the

test data are seldom used to establish a performance pattern or trend.

The pump is:tested only because regulations require it. If pump testing

shows the pump to be in an alert range because of high shaft vibration,-

then-utilities will, obtain additional data, such as rotor vibration

frequency spectrum plots, to diagnose the source of the problem. If the

hydraulic performance is unacceptable, the pump will either be repaired

or a safety analysis will -be completed to justify the operation of the

plant in its' present condition.

o
I I

70

5.4 Inspection, Surveillance, and Maintenance

Practice Recommendations

Table 5.1 provides-a detailed identification of recommended inspection and surveillance practices to identify and monitor potential failure

causes. Note that thistable lists categories of inspection and surveillance: nondisassembly, condition monitoring, and disassembly. The first

category consists of routine actions to be carried out on a regular

basis; the second follows from the recommendations given in Chap. 4; and

the third involves disassembly and detailed examination as a part of

periodic inspection, surveillance, and maintenance.

Maintenance actions, in summary, involve routine lubricating oil

changes and additions, lubrication, shaft seal gland adjustments, and

packing replacement.- Other actions include cleaning, repairing, refurbishing, and replacing parts and components.

5.4.1 Regular nondisassembly inspection,

surveillance, and maintenance

Regular inspection, surveillance, and maintenance involves the dayto-day preventive and corrective maintenance activities required to

ensure machinery operational readiness. These activities include the

ones that do not require pump disassembly. Many of these activities may

be considered commonsense practice.

5.4.2 Surveillance and condition monitoring

Chapter 4 details the recommended monitoring methods to establish

AUXFP operational readiness and to identify the condition of aging and

service wear. These methods include vibration; balance return-line flow;

rotational speed; delivered flow; developed head and rotor axial position; bearing temperature (sleeve, journal, and tilt pad thrust); and

motor power monitoring and IFD (rolling element bearings).

We recommend the permanent installation of transducers into the

various pump parts, such as proximity probes for vibration, speed, and

rotor axial position; balance return-line flowmeter; bearing thermocouples; and pressure measuring transducers (pressure and flow differential pressure). Permanently mounted transducers will provide for more

accurate and repeatable measurements. Transducer mounts for IFD measurements should be permanently installed on each bearing housing. These

mounts normally consist of threaded studs that can be installed either by

drilling and threading a short depth into the bearing housing or by

cementing the mount to the housing with a strong adhesive especially made

for transducer mounting.

Unless desired by the utility, hardwiring all of these transducers

to a permanent readout metering system is not necessary. It is recognized that some of this instrumentation may exist in hardwired form and

is already adequate for the duty. Portable instrumentation, such as

hand-held "data loggers," is available and can be temporarily connected

to the various permanently mounted transducers; then dynamic or static
I, I &

Table 5.1. Recommended inspection and surveillance practices for AUXFPs

Segment I Part Nondisassembly Condition monitoring I I, Disassembly

Rotating

elements

Shaft Rotor' binding

inspection

Rotor binding

inspection, audible

noise inspection

Impeller

Speed, rotor vibration,

developed head,

delivered flow

Speed, rotor vibration,

developed head, delivered

flow, balance return line

flow, acoustic emission

Speed,' rotor vibration,

temperature, rotor axial

position, acoustic emission

Speed, rotor vibration,.

rotor axial position,

acoustic emission

Thrust runner

Fasteners

Nonrotating

internals

Diffusers

or

volutes

Rotor binding

inspection, audible

noise inspection'

Rotor binding

inspection, audible

noise inspection,

visual inspection,

bolt torque measure-

-ment

Audible noise

inspection

Rotor binding

inspection, audible

noise inspection

*Rotor binding

inspection, audible

noise inspection,

visual inspection,

bolt torque measurement

Visual inspection,

runout inspection,

penetrant test for

surface indications

Visual inspection,

bore measurement, wearsurface clearance measurement, penetrant test for

surface indications

Visual inspection,

penetrant test for

surface indications

Visual' inspection,

bolt torque measurement,

Visual inspection,

penetrant test for

surface indications.

Visual inspection,'

wear-surface clearance

measurement

Visual inspection,

b-olt'torqu'e measurement'

Wear surfaces

Fasteners .

Developed head,

delivered flow, rotor

vibration, acoustic

emission'

Developed head, delivered

flow, rotor vibration,

rotor axial position,

balance return line flow

Rotor vibration
. Table 5.1 (continued)

Segment Part Nondisasseubly Condition monitoring Disassembly

Pressure

containment

casing

Mechanical

subsystems

Casing Visual inspection,

leakage inspection

Visual inspection

Bearings

Shaft seals

Thrust

balancer

Coupling

Fasteners

Rotor binding

inspection, audible

noise inspection,

oil level inspection,

oil leak inspection,

oil purity

Visual inspection,

leakage inspection,

audible noise

inspection

Rotor binding

inspection, audible

noise inspection

Rotor binding

inspection, audible

noise inspection,

lubrication, leak

inspection

Rotor binding

inspection, audible

noise inspection, bolt

torque measurement

Visual inspection,

rotor binding

inspection, audible

noise inspection,

bolt torque measurement

Speed, rotor vibration,

temperature, rotor axial

position, acoustic

emission

Rotor vibration,

temperature, acoustic

emission

Visual inspection,

wear-surface clearance

measurement, rotor axial

position measurement

Visual inspection

Rotor vibration, developed

head, delivered flow, rotor

axial position, balance

return line flow, acoustic

emission

Speed, rotor vibration,

acoustic emission

Rotor vibration

Rotor vibration

Visual inspection,

wear-surface clearance

measurement

Visual inspection

Visual inspection,

bolt torque measurement

Visual inspection,

bolt torque measurement

Support Fasteners

I. .! I. ..11
-73

data can be recorded. These data then can:beimanually analyzed or used

to develop trends or, more productively,--entered into-a personal computer

and analyzed,- with trends established through'-the use'of'pre-programmed

software. Numerous programs and software are available and can-perform

frequency spectrum analysis, develop data trends,-and perform alarm point

extrapolation.' .This logging technique -provides-an automated permanent

record of data and simplifies the'trending and evaluation process. Also,

it is much less expensive than the hardwiring method. This technique has

been used extensively in the chemical and-petrochemical industry for

years and is now finding its way into-the-utility industry.- '

Data should be obtained during~''each-required regulatory surveillance

test. We do not advocate starting and operating an AUXFP for:the sole

purpose of obtaiining'these data-unless'additional diagnostic data are

required for troubleshooting a pump problem.' -

It must be recognized that the implementation of such a formal pro-

:gram will require pump disassembly for the following purposes: transducer installation; possible purchase-and'maintenance of additional

instrumentation; and personnel training in the installation, use', and

evaluation of such hardware-and the resulting test information. A successful program requires proper planning and thorough review bef6re'it is

implemented. - - - - - - - -

- Once'the'surveillance and condition monitoring-program-is implemented, the first'step is to obtain a-baseline evaluation of the-equipment (for example, vibration, bearing 'temperatureand power) by'using

the monitoring methods recommended. Continued-monitoring-during the

surveillance tests should measure the effectiveness of the-entire maintenance program (i.e., predictive, preventive,-and corrective) by tracking

any changes -to the baseline condition and taking appropriate-action when

significant changes occur.

5.4.3 Periodicinspection,surveillance, . and maintenance. 

Periodic inspection, surveillance, and maintenance involves the disassembly., inspection, repair, and cleaning of an assembly after a-designated operational time. AUXFPs are :usually ina-standby mode and consequently do not accumulate operating hours very quickly. -.Unlike highspeed boiler feed or chemical process pumps, most-AUXFPs operate at <4500

rpm and therefore do not rapidly accumulate operational fatigue cycles.

Periodic inspection, surveillance, and maintenance intervals are

usually established by the equipment-supplier on the basis of experimental and development tests or by-well-documented operating experience.

Considering that AUXFPs do not accumulate many operating hours between

refueling outages, we do not'believe that-complete disassembly and

inspection after each refueling is warranted. Periodic'inspection intervals, such as those associated'with the aircr'aft industry, are based on

specific component destructive'testing. 'No comprehensive data base-of

this nature'exists for AUXFPs. Consequently,-it is difficult and unjustified to specify a distinct periodic inspection interval that must be

practiced by each plant.

Each AUXFP design may warrant a different inspection interval that

should be based on such criteria as mean time between failure evaluations. This inspection interval will therefore vary between plants.
74

The average operating time for an AUXFP, which also functions as a

low-power feedwater pump, is estimated to be 500 to 750 h, for one

refueling cycle (considered here to be 18 months). A periodic inspection, surveillance, and maintenance interval of 4 1/2 to 5 years or three _

refueling cycles would amount to 1500 to 2250 operating hours on a pump

used for low-power feedwater operation (but substantially less for those

not used for this service) and about 5 years of chronological time. The

three-cycle refueling outage interval was selected as an engineering

estimate for making the recommendations given here. It is not based on

other evaluations, such as mean time between failure.

Although periodic inspection, surveillance, and maintenance has

advantages, it also has many drawbacks. Needless disassembly of vital

parts is a major disadvantage. Problems often arise when good parts are

removed or replaced, no matter how much care is exercised. These problems may be a result of simply altering the normal fit. A prime example

of a high probability of errors being made during the assembly-disassembly

process is during bearing service. For example, fasteners can be overtightened or undertightened, and both nicks and burrs can result on critical surfaces. Dirt can also be introduced into the pump during these

disassemblies and inspections, and care must be appropriately exercised.

Experience has shown that frequent disassembly of an AUXFP will wear out

the part and pump at a much higher rate than would be normally expected

from the wear and aging process. Reference 2 discusses in greater detail

the advantages and disadvantages of the periodic inspection, surveillance,

and maintenance of machinery.

Table 5.2 provides inspection interval guidelines using 4 1/2 to 5

years as an inspection interval. We support complete periodic, inspection, and surveillance maintenance only for the purpose of developing a

maintenance database. The advantages of a regular periodic inspection

maintenance program are outweighed by the problems one can experience

during disassembly and reassembly. We recommend that after a data base

is established, only the periodic inspection of the pump bearings, shaft

seals, and bearing lube oil analysis be made. Bearing lube oil analysis

is specified every 6 months. We believe that it is very important and

will yield such data as bearing condition, moisture from packing leakage,

and lubrication oil viscosity and cleanliness. Once a utility establishes a regular inspection and monitoring program, the optimum intervals

for scheduled periodic inspection can be determined.

5.5 Maintenance Practice Evaluations

Table 5.3 lists maintenance practice evaluations for each failure

cause identified in Chap. 2. The maintenance activities are those categorized as predictive, preventive, and corrective. Each maintenance

practice is rated (high, medium, or low) with respect to effectiveness in

preventing or correcting failures related to aging and service wear.
75

Table 5.2. Periodic inspection, surveillance, and

maintenance interval guidelines for AUXFPs

Pump segment Parts Interval

(refueling outages)

Rotating elements Shaft 3

Impellers - 3

Thrust runner 3 ..

Fasteners 3

Nonrotating -Diffusers or volutes 3

internals Wear surfaces . 3

Fasteners 3

Pressure Casing 3

containment Suction nozzle

casing Discharge nozzle

Fasteners 3

Mechanical Bearings 1/3a, 3

subsystems Shaft seals 3 -

Thrust balancer 3

Coupling 3

Fasteners 3

Support Fasteners 1-2

aOil analysis.-
I I -I

76

Table 5.3. Maintenance practices evaluation

Failure Maintenance practice effectiveness

cause Predictive Preventive Corrective

Bearing wear, High High High

corrosion,

breakage

Shaft seal Medium High High

deterioration,

breakage

Binding between Low High High

rotor and

stationary parts

Impeller wear, High Low Low

breakage

Thrust balancer High Low Medium

wear, galling,

seizing

Shaft breakage High High High

Wear-surface High Medium Medium

wear, erosion,

corrosion, seizing

Rotating element Medium High High

fastener loosening,

breakage

Mechanical subsystem Low High High

fastener loosening,

breakage

Thrust runner High Medium High

wear, breakage

Coupling wear, High High Medium

breakage

Nonrotating Low High High

internals fastener

loosening

Leak at casing split Low High High

Structural damage Medium High Low T

to stationary

vanes (diffuser or

volute)

Support fastener High High High

loosening, breakage
77

6.. SUMMARY AND CONCLUSIONS -

AUXFP failure causes ranked in overall terms of importance were

determined to be

1. bearing wear, corrosion,.and breakage;

2. shaft seal-deterioration and breakage;

3. binding between rotor and stationary parts;

4. impeller wear and breakage;

5. thrust balancer wear, galling, and seizing;

6. shaft breakage; . -

7. wear-surface wear, erosion, corrosion, and seizing;..

8. rotating element'fasteners loosening and breakage;

9. mechanical subsystem fasteners loosening and breakage; .

10. thrust runner wear and breakage;

11. coupling wear and breakage;

\12. nonrotating internals fasteners loosening and breakage;

3. leak at casing split;.,

1X. structural damage to stationary vanes (diffuser or volu ; and

15\ support Las er-loosening-and-br-eakage. -

Measurable parameters that could be used 'to detector monitor these

failure causes include.vibration, temperature, rotational.torque, noise,

appearance, bolt torque, leakage rate, speed, wear surface and-critical

fit clearance, motor-power, lube oil purity, developed head, and delivered flow. ..-

1SCM methods that were recommended to be most beneficial in assessing aging and service-wear-related failures.include -

1. rotor.binding inspection,

2. visual-inrspection, .. . .

3. motor.power monitoring,.;.

4. rotational. speed monitoring,

5. dimensional inspection,

6. pump pressure or.developed head monitoring,

7. pump-delivered flow monitoring,

8. rotor vibration-monitoring,

9. IFD monitoring,

10. liquid penetrant inspection,

11. balance return-line flow monitoring,

12. -audible noise inspection,

13. -bearing temperature monitoring, - .

.14. rotor.axial position monitoring, -

15. bolt torque inspection,

16. leakage rate inspection,.and -

.17. lube oil analysis inspection. ..

ISCM method evaluations were summarized in Chap. 4. -Evaluation criteria included effectiveness, importance.in terms of safety, and ease and

cost of implementation. All ISCM methods were considered to have equally

high effectiveness, with the exception of rotational speed monitoring,
78

balance return-line flow monitoring, audible noise inspection, and bearing temperature and motor power monitoring, which were rated somewhat

lower. Implementation cost for the predictive monitoring techniques is

estimated to be high ($10 to $50K) if the pump must be disassembled or if _

the pump or system pressure boundary is affected by the instrumentation

installation. Instrumentation hardware costs are considered to be low to

medium ($5 to $10K) for all the instrumentation with the exception of that

for delivered flow monitoring and balance return-line flow monitoring.

Permanent installation of instrumentation transducers into the

respective pump parts is recommended to provide for accurate and repeatable measurements. Various recording and analysis hardware and software

exist to obtain, process, analyze, and trend data. It is emphasized that

a successful monitoring program requires proper planning and thorough

review before it is implemented.

Many different parameters were identified for use in detecting and

predicting various aspects of AUXFP aging and service wear. All of these

parameters should be evaluated collectively to predict pump condition;

that is, no single parameter should be used to track or trend pump aging

and wear. The entire collection of parameters should be compared against

each other to permit supportive correlations as to the accuracy of the

results. (For example, one might use vibration monitoring, IFD monitoring, audible noise inspection, etc., to predict a bearing failure.)

Interpretation'of the parameter measurements can be simplified by using a

"SMART" monitor, which is a computer-based system that can accurately and

repeatably interpret the data obtained.

It should not be construed from this report that utilities are not

following good inspection, surveillance, and maintenance practices. As

stated in Chap. 4, ASME Sect. XI requires that utilities perform monitor- i

ing. In addition, utilities use, to some extent, many of the inspection

and monitoring methods specified in this report. Some utilities are well

on the way to developing good predictive maintenance programs.

Experience obtained during the past decade in pump technology has

shown that hydraulic instabilities and unbalances can occur in pumps when

operating at low flows. Operating pumps at higher flows (e.g., >25% BEP

flow) is recommended to reduce the effect of hydraulic instability on

performance. This also makes the test data more meaningful since, in

reality, the pumps are not intended to operate at such low flows as miniflow (5-15% BEP flow) to perform their normal-plant design functions.

Increasing the flow rate should reduce vibration levels and consequently

reduce longer-term wear and aging effects on pump parts such as bearings,

seals, wear rings, etc. Obtaining test data at higher flows (i.e., >25%

BEP flow) should also provide more accurate and repeatable measurements

for the purpose of trending aging and service wear. Therefore, such

things as the W-developed AUXFP test guidelines (App. G) should be evaluated or other alternatives for increasing flow rates should be considered

to accommodate acceptably higher flow rate testing. I

Three types of maintenance - predictive, preventive, and corrective -

were reviewed in this report. Predictive maintenance results from the

combination'of preventive maintenance and predictive analysis. Predictive

analysis involves-monitoring, trending, and analyzing operating data;

while preventive maintenance involves service, inspection, and repair (or

replacement) of equipment, based on such factors as time, experience,
79

vendor recommendations, codes and- standards, and regulatory requirements.

Vendor's typical AUXFP technical manuals for pump maintenance normally

lack sufficiently detailed regular or periodic maintenance instructions.

Utility regular maintenance essentially'consists of external-visual

inspections, while periodic maintenance-usually results only in changing

bearing lube oil. No complete disassembly, inspection, or maintenance is

performed unless the pump develops a problem requiring this action. Surveillance-and condition monitoring is performed in accordance with the

plant technical specifications following the guidelines specified by ASME

Sect. Xl and NRC Standard Review Plan (SRP) 3.9.6.

Regular inspection, surveillance, and maintenance activities embrace

routine preventive and corrective maintenance actions; the inspections

include rotor binding, audible noise, oil level, oil leak, coupling

grease leak, and water leakage rate inspection. Periodic inspection, surveillance, and maintenance involve the disassembly, inspection, repair,

and cleaning of an assembly after a designated operational time; intervals

for performance are usually established by the equipment supplier on the

basis of experimental and developmental tests or by well-documented operating experience. However, no comprehensive data base exists for AUXFPs

to justify a specific time interval.

Interim schedules for periodic inspection, surveillance, and maintenance based on 4 1/2- to 5-year intervals are given in this report for

items other than pump bearing and shaft seal inspections and lube oil

analyses. The intervals stipulated for the latter are recommendations.

Once a utility establishes an inspection, surveillance, and maintenance

program, optimum intervals can be determined.

Good maintenance practices, besides utilizing inspection, surveillance, and monitoring techniques, rely on well-planned and streamlined

procedures to minimize errors during the maintenance process, an adequate

spare parts inventory, regular training of maintenance personnel, and

continuous updating of equipment technical manuals.

Maintenance practice evaluations were summarized in Chap. 5. These

evaluations considered the effectiveness of predictive, preventive, and

corrective maintenance practices in preventing or correcting aging and

service-wear-related failures.

The recommendations in this report should be transmitted to current

code and standard development groups, such as the ASME Operation and

Maintenance Committee, Working Group on Pumps and Valves, for possible

future incorporation into codes and standards.

Further studies should consider the development of methods to monitor and trend shaft seal leakage, motor current, and turbine power.

These parameters can potentially provide additional useful information

concerning AUXFP aging and service wear. Studies should also consider

developing "SMART" systems for monitoring and interpretation.

Finally, Vols. 1 and 2 of this report considered the pump only.

Many of the problems reported for the AFW system involve the steam turbine drivers for pumps and control systems. Therefore, consideration

should be given to evaluating problems encountered in these areas to

enhance the overall reliability of AUXFPs and systems.
I I

80

REFERENCES

1. ASME Boiler and Pressure VesseZ Code. An American National Standard, Sect. XI, Subsect. IWP, Article IWP-2000.

2. H. P.. Bloch, Practical Machinery Management for Process Plants,

Vol. 1, Machinery Reliability, Gulf Publishing Company, 1982.

';
81

BIBLIOGRAPHY

1.' F. W. Kirk and N. R. Rimboi, Instrumentation, 3rd ed., American

Technical Society, 1975. - -

2. Omega Engineering Inc., Omega Instrumentation and Control Handbook,

3rd ed., McGraw.

3. D. M. Considine, Process Instrumentation and Control Handbook, 3rd

ed., McGraw. '

4. Vitek, Vibration Primer, 3rd ed., 1985. -

5. Utility Machinery Vibration Monitoring Guide,'-EPRI NP-4346, -Electric

Power Research Institute, December 1985.

6. Bruel and Kjaer, Machine Health Monitoring, December 1985.'

7. Bruel and Kjaer, Catalog - 1983.

8. G. P. Erickson and J. C. Graber, Jr., Ultrasonic Flowmeters,

Westinghouse Electric Corporation. -

9. Polysonics, Practical Doppler Application Technique, Applications

Engineering Department.

10. Controlotron, Clamp-On, Transient-Time Ultrasonic Ftowmeter, Model

960P.

11. LEFM Executive Summary, Strap-On Flow Measurement, Westinghouse

Electric Corporation.

12. Bruel and Kjaer, Improved Maintenance Using Simple Vibration Measurement, P-100, May 1986.

13. Bently Nevada Corporation, Rotating Machinery Rubs, Application Note

101, 1982.

14. Bently Nevada Corporation, Machinery Protection and Diagnostics

Topics, Application Note 003, Februaary 1977.

15. D. E. Bently, S. Zimmer, G. E. Palmatier, and A. Muszynski, InterpretingVibration Information from Rotating Machinery, Bently :Nevada

Corporation,-February 1986.'

16. Bently Nevada Corporations Proximity Probes and Related Accessories,

Application Note 502, December 1978.

17. "Motor Current Signature Analysis Process," Bulletin Number 608,

Technology Applications Bulletins, Office of Technology Applications, Martin Marietta Energy Systems, Inc., Winter 1988.
I

82

18. Bently Nevada Corporation, The Keyphasor,* A Necessity for Machinery

Diagnostics, Application Note BNCO05, 1979.

19. R. F. Bosmans, Detection and Early Diagnosis of Potential Failures

of Rotating Machinery, Bently Nevada Corporation, L041-00, February

1982.

20. Bently Nevada Corporation, Oil Whirl and Oil whip, Application Note

BNC102, December 1977.

21. H. P. Bloch and F. C. Gietner, Practical Machinery Management for

Process Plants, Vol. 2, Machinery Failure Analysis and Troubleshooting, Gulf Publishing Company, 1983.

22. H. P. Bloch, Practical Machinery Management for Process Plants,

Vol. 1, Machinery Reliability, Gulf Publishing Company, 1982.

23. Igor J. Karassick, Centrifugal Pump Clinic, Marcel Dekker, Inc.,

1981.

24. Engineered Fluid Sealing, Crane Packing Co., 1976.

25. F. J. Mollerus, R. D. Allen, and J. D. Gilcrest, Failures Related to

Surveillance Testing of Standby Equipment, Vol. 1: Emergency Pumps,

EPRI NP-4264, Vol. 1, Electric Power Research Institute, October

1985.

26. E. Makay and 0. Szamody, Recommended Design Guidelines for Feedwater

Pumps in Large Power Generating Units, EPRI CS-1512, Electric Power

Research Institute, September 1980.

27. E. Makay and 0. Szamody, Survey of Feed Pump Outages, EPRI FP-754,

Electric Power Research Institute, April 1978.

28. B. Schmidt, Evaluation of Basic Causes of Repetitive Failures of

Nuclear and Fossil Feedwater Pumps, EPRI NP-1571, Electric Power

Research Institute, October 1980.

29. M. L. Adams and E. Makay, Aging and Service Wear of Auxiliary Feedwater Pumps for PWR Nuclear Power Plants, Vol. 1, Operating Experience and Failure Identifications, NUREG/CR-4597, Vol. 1 (ORNL6282/V1), Oak Ridge Natl. Lab., July 1986.

30. David M. Kitch, "Pump Selection and Application in a Pressurized

Water Reactor Electric Generating Plant," Proceedings of the Second

International Pump Symposium, Texas A&M University, April 1985.

*Keyphasor is a Bently Nevada trademark.
83

31. W. L. Greenstreet, G. A. Murphy, and D. M. Eissenberg, Aging and

Service Wear of Electric Motor-Operated Valves Used in Engineered

Safety Feature Systems of Nuclear Power Plants, NUREG/CR-4234,

Vol. 1 (ORNL-6170/V1), Oak Ridge Natl. Lab., June 1985.

32. P. D. Ritland and P. J. Craig, "Predictive Analysis: Toward Optimized Plant Maintenance," presented at Electric Utility Engineering

Conference, May 1985.

33. The Operational Performance of Auxiliary Feedwater Systems in U.S.

PWR's, 1980-84, INPO 85-036, Institute of Nuclear Power Operations,

September 1985.

34. Qualification of Active Mechanical Equipment for Nuclear Power

Plants, EPRI NP-3877, Electric Power Research Institute, March 1985.

35. Utility Machinery Vibration Monitoring Guide, EPRI NP-4346, Electric

Power Research Institute, December 1985.
85

Appendix A

DEFINITIONS

Absolute motion - Vibration measured with respect to an inertial

(fixed) reference frame,-which is often loosely referred to as "free

space." Seismic transducers measure machine casing or structural absolute motion.

Acceleration - The time rate of change of velocity, which is often

expressed as G. A, K, or d2x/dt2. Acceleration leads velocity by 90° in

time and leads displacement by 1800 in time'. Typical units for acceleration are feet per second per second (ft/s2), meters per second per second

(m/s2 ), or more commonly G's, zero-to-peak (where G = acceleration of

gravity = 32.17 ft/s2 ='9.81 m/s2). Acceleration measurements are generally made with piezoelectric accelerometers and are typically used to

evaluate high-frequency machine casing or bearing housing response characteristics.

Active 'pmp - A pump that must perform a mechanical motion during

the course of accomplishing a system safety function.

Aging - The combined'cumulative effects, over time, of internal and

external stressors acting-on a component, leading to degradation of the

component, which increases with time. Aging degradation may involve

changes in-'chemical, physical,'electrical, or metallurgical properties,

dimensions, and/or relative positions of individual-,parts.

Alignment - A condition whereby the axes of machine components are

positioned according to design requirements. A measurement of the relative position of a machine component with respect to another. Relative

alignment measurements can be made from bearing to bearing, rotor to

rotor, rotor to'bearing, bearing to casing, casing to foundation, casing

to piping, etc. Various alignment requirements utilize different techniques of cold and hot machine measurement, including optical, mechanical

(dial indicators), and electronic (proximity probes).

Ambient temperature - The average or mean temperature of the surrounding 'air that comes in contact with'the equipment and instruments

being tested.

Anmmeter- An instrument used to 'measure current.

Amplitude - The magnitude of dynamic motion or vibration. Amplitude

must be specified in terms of peak-to-peak, zero-to-peak, root mean'

square (rms), or average. - Peak-to-peak equals the maximum excursion from

the extreme positive peak to the extreme negative peak, and zero-to-peak

equals one-half of peak-to-peak. For pure sine waves only, rms equals

0.707 of zero-to-peak, and average equals 0.637 of zero-to-peak. Root

mean-square is'also-called effective amplitude and is useful for acoustical studies. For vibration measurements, amplitude' is usually expressed

in terms of displacement, velocity, or acceleration.

Asynchronous - Vibration frequency components that are not related

to shaft rotative frequency. 'Also referred to as nonsynchronous or'nonintegral motion. See Synchronous.'

Attenuation - The reduction in amplitude of a given signal without

changing the characteristic waveform.
86

Axial position - The average position, or change in position, of a

rotor in the axial direction with respect to some fixed reference.

Ideally, the reference is a known position within the thrust bearing

axial clearance or float zone, and the measurement is made with a proximity probe observing the thrust collar. However, the measurement can be

made effectively by a probe observing some other integral axial shaft

surface, if such surface is close to the thrust bearing. Also, the measurement of this position or change in position. Also called thrust

position.

Blade passing frequency - A potential vibration frequency on any

bladed machine (turbine, axial compressor, fan, propeller, etc.). It is

represented by the number of blades (on a disk or stage) times the shaft

rotative frequency.

Bow - A shaft condition such that the geometric shaft centerline is

not straight. Usually, the centerline is bent in a single direction

because of gravity sag, thermal warpage, etc; however, the bow may be

three-dimensional (corkscrew).

Calibration - The process of adjusting an instrument or compiling a

deviation chart so that the instruments reading can be correlated with

the actual value being measured.

Cavitation - The formation of vapor bubbles in any flow that is subjected to an ambient pressure equal to or less than the vapor pressure of

the liquid being pumped.

Compensated connector - A connector made of thermocouple alloys used

to connect thermocouple probes and wires.

Corrective maintenance - Those maintenance activities involving the

actual repair of a machine or component after failure is incurred.

Current - The rate of flow of electricity. The unit is the ampere

(A), defined as 1 ampere = 1 coulomb per second.

Data acquisition system - The system consisting of analog multiplexers, sample-holds, analog-to-digital converters, and other circuits that

process one or more analog signals and convert them into digital form for

use by a computer.

Displacement - The change in distance or position of an object. Displacement is typically a peak-to-peak measurement of the observed motion

and is usually measured in mils or micrometers. Eddy-current proximity

probes measure displacement directly. Because integration of a velocity

signal is necessary to obtain displacement, an acceleration signal requires double integration to yield a displacement measurement.

DuaZ-element sensor - A sensor assembly with two independent sensing

elements.

Dual probe - A transducer set consisting of a proximity probe and

velocity transducer installed radially at the same point (usually in a

common housing) on the machine casing. Four separate measurements are

provided by this transducer system. The proximity probe measures

(1) shaft radial position within the bearing clearance and (2) shaft

dynamic motion relative to the bearing. The velocity transducer measures

(3) machine casing absolute motion. When the velocity signal is integrated to displacement and vectorially added to the shaft relative displacement, the summation represents (4) shaft absolute motion.

Eddy current - Electrical current that is generated (and dissipated)

in a conductive material when such material intercepts the electromagnetic field of a proximity probe.
87

Failure mode - The manner in which a component does not perform a

function for which it was designed (e.g., fails 'to'actuate or leaks to

outside).

Failure cause - Degradation that results in the presence of a defect

in a component that is the proximate cause of its failure (e.g.-, bent

shaft, loss of lubricant, or loosening of a bolt).

Failure mechanisms - The phenomena that are responsible for the

degradation present in a given component at a given time.' Frequently,

several failure mechanisms are collectively responsible for degradation

(synergistic influences). One major failure mechanism, where identified,

has been called the "root cause."- Generic- examples of failure mechanisms

(and of root causes) include aging, human error, or'seismic events.

- Frequency - The repetition rate'of a periodic wave within a unit

time. This is normally expressed in units of revolutions per minute

'(rpm), cycles per minute (cpm), events per minute (epm), or cycles per

second (cps or Hz). With respect to rotating machinery vibrations, two

types of frequencies are of interest: (1) the shaft rotational frequency

and (2) the various vibration frequencies (as measured by vibration

transducers). Rotational frequencies are commonly expressed in terms of

cpm, cps, or Hz or in terms of the shaft' rotational frequency: 1X means

one times rotational frequency, 2X means two times, 1/2X means one-half

times, etc. Vibration frequency can also be expressed as a percentage of

rotational frequency.'

Frequency response - The amplitude and phase characteristics of a

mechanical or electronic system with respect- to frequency.

Harmonic - Sinusoidal quantity at a frequency that is an integer

multiple of the fundamental frequency.

Hertz (Hz) - Unit of frequency measurement represented by cycles per

second.

Inspection, surveillance, and condition monitoring (ISCM) - The

spectrum of methods and'hardware for obtaining qualitative or quantitative values of a measurable parameter of a component. The methods may be

periodic or continuous, may be'in situ, or may require removal and installation-in a t.est stand or disassembly and may involve dynamic or static

measurements.

Imbalance (unbalance) - Unequal radial weight distribution on a

rotor system, a shaft condition such that the mass centerline (principal

inertial axis) does not coincide with the geometric centerline. Also,

the effective mass causing the rotor to be out of balance.

Measurable parameters - Physical or chemical characteristics of a

component that can be' described or measured directly or indirectly and

that can be correlated with aging. Useful measurable parameters are

those that (1) 'can be used to establish trends of the magnitude of aging

associated'with each failure cause,-(2) have well-defined criteria for

quantifying the approach to failure, and (3) are able to' discriminate

between the degradation that leads to failure and other'observed changes.

Mechanical' ruwout - A source of error on the output 'signal of'a

proximity probe transducer system;- 'a probe gap change that 'doe's not

result from either a shaft centerline position change or shaft dynamic

motion. Common sources include out-of-round shafts, scratches, chain

marks, dents, rust or other conductive buildup on the shaft, stencil

marks, flat spots, and engravings.
88

Naturat frequency - The frequency of free vibration of a system.

The frequency at which an undamped system with a single degree of freedom

will oscillate upon momentary displacement from its rest position by a

transient force. The natural frequencies of multiple degree of freedom

systems are the frequencies of the normal modes of vibration. _

Noise - Any component of a transducer output signal that does not

represent the variable intended to be measured.

Normat aging - Aging of a component that has been designed, fabricated, installed, operated, and maintained in accordance with specifications, instructions, and good practice and that results from exposure to

normal stressors for the specific application. Normal aging should be

taken into account in component design and specification.

Oil whirl/whip - An unstable vibration of the free vibration category whereby the bearing has insufficient unit loading. This can occur

because of various mechanisms, including excessive radial bearing clearance and a steady-state preload acting in the opposite direction to the

bearing load. Under this malfunction condition, the shaft centerline

dynamic motion is usually circular and forward (in the same direction as

shaft rotation). Oil whirl vibration occurs at a frequency equal to

average oil flow velocity within the bearing (i.e., 40 to 49% of shaft

rotative speed). Oil whip occurs when the oil whirl frequency coincides

with (and becomes locked to) a system natural resonance, often a rotor

balance resonance. Note that the whirl/whip mechanism is not restricted

to oil-lubricated bearings but can occur in any case where a fluid is

between two cylindrical surfaces, for example, system whirl or whip in a

steam seal.

Operational readiness - The capability of a pump to fulfill its

function.

Orbit - The path of the shaft centerline motion during rotation.

The orbit is observed with an oscilloscope connected to XY proximity

probes. An orbit is sometimes referred to as a Lissajous pattern.

Peak-to-peak value - The difference between positive and negative

extreme values of a signal or dynamic motion.

Power intensity - A relative measure of a pump's brake horsepower

per stage. Mathematically, the power intensity factor is defined as

FPI = B-?

D3

where BHP is the power (BHP) per stage and D is the impeller diameter

(in.).

Predictive maintenance - Those maintenance activities involving the

measure of parameters that indicate the performance or condition of a

machine or component. Parameter changes from the norm can be used to

predict and prevent failure.

Preventive maintenance - Those maintenance activities (e.g., schedules, lubrication, visual inspection, etc.) that involve preventive measures for the purpose of limiting facility outages.

. Probe - A generic term that is used to describe many types of

sensors.

Proximity probe - A noncontacting device that measures the displacement motion or position of an observed surface relative to its mounting
89

location. Typically, proximity probes used for rotating machinery measurements operate on the eddy current principle and measure shaft displacement motion and position relative to the machine bearing(s) or

casing.

Proximate cause - Final cause contributing to failure.

Radial - A direction on a machine that is perpendicular to the shaft

centerline.

Radial position- The average location, relative to the RADIAL bearing centerline, of the shaft dynamic motion. This can be determined by

evaluating the dc output signals of XY relative proximity probes.

'Radial vibration - Shaft dynamic motion or casing vibration that is

in a direction perpendicular to the shaft centerline.

Real time analyzer - A term used to describe an instrument that displays a vibration frequency spectrum. See Spectrum Display Unit. -

Repeatability - The ability of a transducer or readout instrument to

reproduce output readings when the same value is applied to it repeatedly,

under the same conditions, and in the same direction. Also, the maximum

deviation from the mean of corresponding data points taken from repeated

tests under identical conditions. The word accuracy is often used incorrectly as a synonym for repeatability.

Resolution - The smallest change in applied stimulus that will-produce a detectable change in the instrument output. Resolution differs

from precision because it is a psychophysical term referring to the

smallest increment of humanly perceptible output (rated in terms of the

corresponding increment of input).

Resonance - The condition of vibration amplitude and phase change

response caused by a corresponding system sensitivity to a particular

forcing frequency. A resonance is typically identified by a substantial

amplitude increase and related phase shift.

Seismic transducer - A transducer that is mounted on the case or

housing of a machine and measures casing vibration relative to free

space. An accelerometer is a seismic transducer that converts acceleration motion and/or gravitational forces capable of imparting acceleration

into a proportional electrical signal. A velocity transducer is a seismic transducer that converts velocity motion into a proportional electrical signal.-A

Signal - An electrical transmittance (either input or output) that

conveys information.

Sensitivity - The magnitude of the change in an output signal to a

known change in the value of the measured variable. Also called scale

factor.

Signature - The term usually .applied to the vibration frequency

spectrum that is distinctive and special to a particular machine or component, system, or subsystem at a specific point in time, under specific

machine operating-conditions, etc. .Used for historical comparison of

mechanical condition over the operating life of the machine.

;Span - The difference between the upper and lower limits of a range

expressed in the same units as the-range.

Specific speed - The speed at which an impeller, geometrically, similar to the one under consideration, would run if it were reduced in size

to deliver 1 gal/min at 1-ft head. Mathematically, it is expressed as
90

S H3/4 '

where N is the pump speed (rpm), Q is the design capacity (gal/min) at

the BEP, and H is the total head (ft) per stage at the BEP.

Spectrum - Presentation of the amplitude of a signal as a function

of frequency.

Spectrum display unit - An instrument that displays an XY presentation of vibration frequency (X) vs vibration amplitude (Y). This presentation is called a vibration frequency spectrum and is usually presented

on a CRT, with hard-copy capability, plotter outputs, and/or computer

interface connections.

Spectrum plot - An XY plot where the X axis represents vibration

frequency and the Y axis represents vibration amplitude.

Stiffness - The springlike ability of mechanical and hydraulic elements to elastically deform under load (resistance to deformation). This

concept is applicable to shafts, bearings, cases, and support structures.

The units normally used are pounds per inch or newtons per meter.

Subharmonic - Sinusoidal quantity of a frequency that is an integral

submultiple of a fundamental frequency.

Subsynchronous - Component(s) of a vibration signal that has a frequency less than the shaft rotative frequency.

Suction specific speed - Analogous to specific speed except that

here it is essentially an index descriptive of the suction capabilities

and characteristics of a given first-stage impeller. Mathematically, it

is expressed as

S =- N / _2

(NPSHR)34'

where

N = pump speed (rpm)

Q = design capacity (gal/min) at BEP for single-suction

first-stage impellers or one-half the design capacity for

double-suction first-stage impellers (at maximum

diameter),

NPSIR - net positive suction head required (ft) (at BEP).

Supersynchronous - Component(s) of a vibration signal that has a

frequency greater than the shaft rotative frequency.

Synchronous - Vibration frequency components that vary in direct

proportion to changes in rotative frequency. Typically, but not always,

synchronous components are whole-multiples, or integer fractions of rotative speed, and maintain that relationship regardless of speed (e.g., 1X,

2X, 3X, 1/2X, etc.).

Thermocouple - A temperature-sensing device comprised of two dissimilar metal wires that when thermally affected (heated or cooled),

produce a proportional change in electrical potential at the point where

they join.
91

Thermocouple type

(ANSI symbol) Material

J Iron/Constantan

K Chromel/Alumel

T Copper/Constantan

E Chromel/Constantan

R Platinum/platinum 13% rhodium

S Platinum/platinum 10% rhodium

B Platinum 6% rhodium/platinura 30% rhodium

G* Tungsten/tungsten 26% rhenium

C* Tungsten 5% rhenium/tungsten 26% rhenium

D* Tungsten 3% rhenium/tungsten 25% rhenium

*Not ANSI symbols.

ThermowelZ - A closed-end tube designed to protect temperature

sensors from harsh environments, high pressure, and flows. They can be

installed into a system by pipe thread or welded flange and are usually

made of corrosion-resistant metal or ceramic material, depending upon the

application.

Transmitter (two-wire) - A device that is used to transmit data via

a two-wire current loop. The loop has an external power supply, and the

transmitter acts as a variable resistor with respect to its input signal.

Ungrounded junction - A form of construction of a thermocouple probe

where the hot or measuring junction is fully enclosed by and insulated

from the sheath material.

Vane passing frequencies - A potential vibration frequency on vaned

impeller compressors and other machines with vaned rotating elements. It

is represented by the number of vanes (on an impeller or stage) times the

shaft rotative frequency.

Velocity - The time rate of change of displacement. This is often

expressed as V, A, or dx/dt; velocity leads displacement by 90° in time.

Typical units for velocity are inches per second or millimeters per

second, zero-to-peak. Velocity measurements are usually obtained with a

mechanically activated velocity transducer and are used to evaluate casing response characteristics. Electronic integration of an acceleration

signal will provide a velocity signal.

iX - Notation for the signal component in a complex vibration signal

that occurs at the rotational speed frequency. Also called synchronous.

2X, 3X, etc. - Notation for the component(s) in a complex vibration

signal having a frequency equal to an exact multiple of the rotative

speed. Also called harmonic, superharmonic, and supersynchronous.

XY - Perpendicular axes in a Cartesian coordinate system. Usually

used as a reference for orthogonal (mutually perpendicular) radial vibration transducers.
93

Appendix B -

OPERATING EXPERIENCE DATA BASES AND REPORTS

Failure data from LER, NPRDS, and various other data bases are summarized below. Data sources on AUXFP failures formed the basis of this

report. Other data were provided as a supplement. Only data pertaining

specifically to the pump are cited (i.e., drivers, etc., excluded).

Table B.1, AUXFP LER data (1973-83), is a reprint from Vol. 1 of

this report. Refer to Vol. 1 for details.

Table B.2, AUXFP LER data (1984-86), is a supplement to Table B.1

and provides data from 1984-86. There were four additional events

recorded in 1984-86.

Table B.3, AUXFP NPRDS data (1974-85), is a reprint from Vol. 1 of

this report. Refer to Vol. 1 for details.

Table B.4, AUXFP NPRDS data (1986), is a supplement to Table B.3 and

provides data from 1986. Only seven additional events were recorded in

1986.

Table B.5, HHSIP LER data (1973-86), contains supplementary data for

the HHSIPs. These data represent HHSIPs (also called charging pumps in

some plants) in addition to normal HHSIPs. Both puup types are similar

in design to the AUXFP. Functionally, the charging pumps can be considered as continuously operating, while the HHSIPs are intermittent-duty

pumps. There were 68 total events reported.

Table B.6, HHSIP NPRDS data (1974-85), contains supplementary data

for the HHSIPs. There were 53 total events reported.

Table B.7, HHSIP NPRDS data (1974-85), (N ( 3600 rpm), contains data

that are derived from the same data source as that reported in Table B.6.

The pumps that operate at (3600 rpm are considered the intermittent-duty

puMps, which are functionally similar-to the AUXFP. There were 27 total

events reported.

Table B.8, Major outage producing failure causes for feed pumps,

contains data that were derived from EPRI Report FP-754, entitled Survey

of Feed Pump Outages,1 and represents fossil boiler feed pumps, booster

pumps, nuclear steam generator feed pumps, and booster pumps.

Table B.9, Typical failure causes, centrifugal pumps (domestic

plants), contains data that represent petrochemical plant pump failure

data and includes single-stage, multistage, vertical, and horizontal

pumps.

Table B.10, Typical failure causes, centrifugal pumps (foreign

plants), contains data that represent failure causes for four foreign

petrochemical plants and would also. include single-stage, multistage,

vertical, and horizontal pumps. -

-- Reference

1. E. Makay and 0. Szamody, Survey of Feed Pump Outages, EPRI FP-754,

Electric Power Research Institute, April 1978.
94

Table B.1. Summary of AUXFP-type failures

reported in LERs

(1973-1983)

Ratea

ItemM

Failed component

Bearings 48

Packing and seals 30

Casing 4

Internal components 4

Impeller 2

Capacity 2

Shaft 2

Other 8

Methods of detection

Testing 42

Operation 29

Maintenance 6

Not stated 23

Maintenance action

Replacement 67

Repair 25

Modification 6

No repair required 2

Identified cause

Lack of lubrication or cooling 23

Maintenance error 17

Wear/end of life 15

Design error 6

Crud 4

Operator error 2

Other 4

Not stated 19

Unknown 10

aTotal of 53 events.

Source: M. L. Adams and E. Makay,

Aging and Service Wear of Auxiliary Feedwater Pumps for PWR Nuclear Power Plants,

Volume 1, Operating Experience and Failure

Identification, NUREG/CR-4597, Volume 1

(ORNL-6282/Vl), Oak Ridge Natl. Lab., July

1986.
95

Table B.2. Summary of AUXFP-type

failures reported in LERs

(1984-1986)

Item Occurrences Rate

_ _ _

Failed component

Bearings .1 25

Packing and seals 0 0

Casing 1 25

Internal components 1 25

Impeller 0 0

Capacity 0 0

Shaft 0 0

Other 1 25

Total 4 100

Methods of detection

Testing 2 50

Operation 2 50

Maintenance 0 0

Not stated 0 0

Total 4 100

Maintenance action

Replacement 2 50

Repair 1 25

Modification 0 0

No repair required 1 25

Total - 4 100

Identified cause

Lack of lubrication or cooling 1 25

Maintenance error- 0 0

Wear/end of life 0 0

Design error 1 25

Crud 0 0

Operator error - 0 0

Other 2 50

Not stated 0 0

Unknown 0 0

Total 4 100
96

Table B.3. AUXFP-type failures

reported in NPRDS data base

(1974-1985)

Ratea

Item (x

Failed component

Packing/gasket 50

Bearings 38

Internal components 6

Shaft 6

Methods of detection

Incidental observation 33

Surveillance testing 25

Routine observation 12

Audiovisual alarm 12

Operational abnormality 12

Special inspection 6

Maintenance action

Repair/replace 94

Modify 6

Failure cause

Wear 58

Lubrication 12

Binding 12

Aging 12

Abnormal stress 6

aTotal of 14 failure reports.

Source: M. L. Adams and E. Makay,

Aging and Service Wear of Auxiliary

Feedwater Pumps for PWR Nuclear Power

Plants, Volume 1, Operating Experience

and Failure Identification, NUREG/CR4597, Volume 1 (ORNL-6282/V1), Oak

Ridge Natl. Lab., July 1986.

Tt
97

Table B.4. Summary of AUXFP-type failures

reported in NPRDS data base

(1986)

Rate

Item Occurrences

Failed component

Packing/gasket

Bearings

Internal components

Shaft

Total

Methods of detection

Incidental observation

Surveillance testing

Routine observation

Audiovisual alarm

Operational abnormality

Special inspection

Total

Maintenance action

Repair/replace

Modify

Total

4

3

0

0

7

58

42

0

100

0

1

4

1

0

1

7

0

14

58

14

0

14

' 100

7

0

7

100

0,

100 '

Failure cause

Wear

Lubrication

Binding

Aging

Abnormal stress

Total

6

1

0

0

0

7

86

14

0

0

0

100
98

Table B.5. Summary of HHSIP failures

reported in LERs

(1973-1986)

Item Occurrences Rate

)

Failed component

Bearings

Packing and seal

Casing

Internal components

Impeller

Capacity

Shaft

Other

Total

Methods of detection

Testing

Operation

Maintenance

Not stated

Total

.Maintenance action

Replacement

Repair

Modification

No repair required

No data available

Total

5

8

2

22

6

7

7

11

68

30

22

6

10

68

8

12

3

32

9

10

10

16

100

44

32

9

15

100

34

19

3

15

29

100

23

13

2

10

20

68

Identified cause

Lack of lubrication

Maintenance error

Wear/end of life

Design error

Crud

Operator error

Other

Not stated

Unknown

Total

or cooling 5

3

22

14

1

7

9

3

4

68

8

4

32

21

2

10

13

4

6

100

1'*
99

Table B.6. Summary of HHSIP failures

reported in NPRDS

(1974-1985)

Item Occurrences Rate

Failed component

Packing/gasket 25 47

Bearings 10 19

Internal components 16 30

Shaft 2 4

Total 53 100

Methods of detection

Incidental observation 1 2

Surveillance testing 11 21

Routine observation 36 68

Audiovisual alarm 0 0

Operational abnormality 3 5

Special inspection 2 4

Total 53 100

Maintenance action

Repair/replace 51 96

Modify 2 4

Total 53 100

Failure cause

Wear 33 63

Lubrication 3 5

Binding 4 8

Aging 3 5

Abnormal stress 10 19

Total 53 100
100

Table B.7. HHSIP failures reported

in NPRDS data base for <3600 rpm

(1974-1985)

Item Occurrences Rate

)

Failed component

Packing/gasket 12 44

Bearings 5 19

Internal components 10 37

Shaft 0 0

Total 27 100

Methods of detection

Incidental observation 0 0

Surveillance testing 7 26

Routine observation 14 52

Audiovisual alarm 1 4

Operational abnormality 3 11

Special inspection 2 7

Total 27 100

Maintenance action

Repair/replace 26 96

Modify 1 4

Total 27 100

Failure cause

Wear 17 63

Lubrication 4 15

Binding 2 7

Aging 0 0

Abnormal stress 4 15

Total 27 100
101

Table B.8. Ten major outage-producing

failure causes for feed pumps

No. Pump failures: component,

symptom, or technology

1 Seals

2 Vibration: pump, piping, foundation

3 Axial balancing device

4 Journal bearing

5 Cavitation''

6 Impeller breakage

7 Wear-ring: rapid wear

8 Unstable head curve

9 Shaft broken/damaged

10 Thrust bearing

Source: Reprinted with permission from

E. MIakay and O.'Szamody, Survey of Feed Pump

Outages, EPRI FP-754, Electric Power Research

Institute, April 1978.

Table B.9. Typical failure causes reported

for U.S. petrochemical plants

(Centrifugal pumps)

Failure cause

Ranked by

frequency

of

occurrence

Shaft seal deterioration, breakage 1

Bearing wear, corrosion, breakage 2

Shaft failures 3

Binding between rotor and stationary parts 4

Coupling wear, breakage 5

Impeller wear, breakage 6

Wear surface wear, erosion, corrosion, seizing 7

Casing leakage 8

Source: Reprinted with permission from H. P. Bloch,

Practical Machinery Management for Process Plants, Vol. 1,

Machinery Reliability, Gulf Publishing Company, 1982.
102

Table B.10. Typical failure causes reported

for several foreign petrochemical plants

(Centrifugal pumps)

:1

Ranked by

Failure cause frequency

of

occurrence

Shaft seal deterioration, breakage 1

Bearing wear, corrosion, breakage 2

Impeller wear, breakage 3

Shaft failures 4

Casing and internal structural damage 5

Couplings 6

Source: Reprinted with permission from H. P.

Bloch, Practical Machinery Management for Process

Plants, VoZ. 1, Machinery Retiability, Gulf Publishing

Company, 1982.
103

Appendix C

INSTALLATION LIST
105

Table C.1. Installation list, Ingersoll-Rand

Pump Capacity Head Speed Temp.

size t (gal/min) (ft) (rpm) (°F)

Indian Point

Surry

Surry

Surry

Surry

Indian Point

Beaver Valley

Main Yankee

Donald C. Cook

Donald C. Cook

Beaver Valley

Main Yankee

Arkansas Nucl. One

Arkansas Nucl. One

Three Mile Island

Three Mile Island

Sequoyah

Sequoyah

Millstone

Millstone

North Anna

North Anna

Farley

Farley

Watts Bar

Watts Bar

Shearon Harris

Shearon Harris

Ginna

Commanche Peak

Commanche Peak

ASCO (Spain)

ASCO (Spain)

Callaway

Wolf Creek

WNP

WNP

KRSKO (Yugoslavia)

KRSKO (Yugoslavia)

St. Lucie

St. Lucie

Georgia Power

Georgia Power

3HMTA-9

4HMTA-6 -

3HMTA-8

4HMTA-6

3HMTA-9

3HMTA-9

4HMTA-6

3HMTA-5

4HMTA-6

3HMTA-8

3HMTA-8

3HMTA-8

4HMTA-9

5HMTA-4

3HMTA-8'

4HMTA-6

5HMTA-5

3HMTA-9

4HMTA-5

2HMTA-8

4HMTA-6

3HMTA-8

4HMTA-7

2HMTA-10

5HMTA-6

3HMTA-9

4X9N-7,

3HMTA-9

2HMTA-10

5HMTA-6

4HMTA-9

4X9NH-9

2HMTA-10

6HMTA-6

4HMTA-9

6HMTA-6

4X9NH-10

4X9N-9

2HMTAM-10

4HMTA-7

2HMTA-10

6HMTA-5

4HMTA-9

' -2

1

2

i.. .

1 . "

:.1:

2

2 ' '

1 . .

.1

4 -.

2

4

2

4

4

8

2

2,

4,

2

4,

5

,10.

-2

1

2

2

4

400

735

370

.735

370

400

:730

530

900

450

370

' 500

780

'1150

470

940

-920

440

600

300

735

370

700

350

1000

500

. 850

425

200

.1140.

.570

840

240

1060

535

.1400

600

810

370

540

300

1155

510

3118 3570

2726 - 4200

2726 ,3560

1716. 4200

2726 ''3560

-3118' 3570

2691 4200

2529' '4400

1137, ,4350

1137 3560

2691 3560

2529 3575

2569 3560

2340'' 3560

2553 3560

2553 4250

2529 3950

2834 -3570

3656 4200

2962 '3560

2815 4200

2815 3560

3641 3960

3641 3560

2927 3850

2927 3577

2934.. 4000

2934 3500

3354 -3560

3158 4050.

3158 *3560

3338 4000

3488 4000

3405 3800

3405 3560

3128 3850

3197 3850.

3398 3900

3354 4000

N/A 3725

N/A 3590

3169 3950

3169 3960

120

120

120

120

120

120

120

120

100

100

120

120

120

120

100

100

120

120

100

100

100

100

95

95

120

120

125

125

120

110

110

125

125

95

95

90

90

100

100

120

120

150

150
106

Table C.2. Installation list, Bingham

Installation Pump size Quantity

McGuire 3X4X9E MSD 4

McGuire 4X6X1OB MSD 2

North Anna 3X6X9C MSD I

North Anna 3X6X9C USD 2

North Anna 3X6X9C MSD 1

North Anna 3X6X9C MSD 2

Beaver Valley 3X6X9C MSV 2

Beaver Valley 3X6X9C MSD 1

Millstone 3X6X9C MSD 2

Millstone 4X6X10 MSD-D 1

Catawba 3X6X9E MSD 4

Catawba 4X8X10-1/2B MSD-D 2

Midland 4X8X10-1/2B MSD-D 2

Midland 4X8X10-1/2B MSD-D 2

Bellefonte 4X8X1OB MSD 2

Bellefonte 3X6X9C MSD 4

South Texas 4X6X9C MSD 8

Table C.3. Installation list, Pacific Pumps

Capacity Head Installation Pump size (gal/min) (ft)

Keewaunee 1 1/2-in. UNI 240 2850

Prairie Island 1 1/2-in. UNI 220 2920

Zion 3-in. JTC 495 3099

Zion 4-in. JTCX 990 3099

Braidwood 4-in. SRBFIDS 990 3350

Byron 4-in. SRBFIDS 990 3350
107

Table C.4. Installation list, Byron-Jackson

Capacity Head Speed Temp. Installation Pump size Qty- (gal/min) (ft) hp (rpm) (0 F)

Diablo Canyon 3X6X9E DVMX 2 490 3000 50U 3510 100

Diablo Canyon 4X6X9D DVMX 1 930 3000 900 4000 100

Diablo Canyon 3X6X9D DVMX 2 490 3000 500 3570 100

Diablo Canyon 4X6X9D DVMX 1 930 3000 900 4000 100

Calvert Cliffs 3X6C9E DVMX 2 700 2490 600 3990 100

Hutchison 3X6X9B DVMX 2 325 2660 350 3570 120

Island

Hutchison 3X6X9B DVMX 1 325 2660 350 3570 120

Island

Arkansas 3X6X9B DVMX 2 575 2800 600 3575 100

Davis-Besse 4X6X9D DVMX 2 1050 2500 800 3600 100

Almaraz 4X6X9D DVMX 4 450 3200 1000 2960 100

Almaraz 4X6X9D DVMX 2 900 3200 650 3900 100

San Onofre 4X6X9D DVMX 1 860 2842 800 3570 100

San Onofre 4X6X9D DVMX 1 860 2842 800 3570 100

San Onofre 4X6X9D DVMX 1 860 2842 800 3570 100

San Onofre 4X6X9D DVMX 1 860 2842 800 3570 100
109

Appendix D

LOW-FLOW TESTING

AUXFPs are considered "active" safety-related-emergency pumps. The

plant technical specification stipulates that these pumps must-be tested

monthly :to meet hydfaulic-and mechanical acceptance criteria. AUXFPs

typically have a design-developed-head equal to steam-generator safety

valve set pressure plus system line losses. Surveillance testing or any

operation of these pumps while the plant is at power requires special

precautions to protect against interference with normal operation.

Periodic surveillance testing is now performed on the pump while

pumping from the condensate storage tank through the miniflow bypass line

(which normally contains a miniflow orifice and isolation valves) and

returning to the condensate storage tank. Appendix E,-Fig. E.2 shows a

typical AFW flow diagram for a W PWR plant. The minimum flow for these

pumps was typically established only to prevent pump overheating and thus

is normally 10 to 15% of BEP flow. (For purposes of-this discussion,

"low flow" is defined as those flows equal to -10-15%'-of pump BEP flow.)

The pump miniflow circuit provides a convenient flow path through -

which the pump can be loaded and testing can be accomplished.- Currently,

ASME Sect. XI, Subsect. IWP, requires that the pump performance baseline

parameters be established first. The baseline measurements are very

critical because pump acceptance-criteria depend on performance changes

from the baseline, although the minimum acceptable developed head must

always be greater than an absolute minimum established curve, which is

normally included in the plant technical specifications Testing frequency is now once per month. Table-IWP-3100-2, Subsect. IWP, provides

parameter ranges that must be maintained to satisfy pump operational

readiness. Should the pump performance fall within the "alert range,"

per Table IWP-3100-2, normal test frequency is doubled. If deviations

fall within the "required action range" of Table IWP-3100-2, the pump

shall be declared inoperative and not returned to service until the cause

of the deviation has been determined and the condition corrected. Correction shall be either replacement or repair or shall be an analysis to

demonstrate that the condition does not impair pump operability and that

the pump will still fulfill its function. A new set of reference values

shall be established after such analysis. IWP-3111 discusses reference

value determinations following replacement or repair actions.

Experience gained in both the laboratory and the field during the

past decade has shown that instabilities and unbalances can occur in

pumps at low flows. There are reported cases of pump vibration and

unusual flow pulsation frequencies and amplitudes occurring during lowflow testing. Vibration-induced damage to pumps and valves has been

known to occur during extensive operation of pumps at low flow.

Pump vibration is typically highest when the pump is operated at low

flow, as in the case of surveillance testing. On a new or refurbished

machine, that is, a pump with tight wear-ring clearances, new bearings,

etc., the effects on vibration caused by the hydraulic instabilities

would be lower than for worn pumps. However, as the pump ages and the

critical clearances increase, the damping effect of these clearances is
110

reduced, and the effect on vibration caused by these instabilities becomes more pronounced and measurable. This could result in prematurely

declaring the pump to be in the alert or required action range. Operating the pump at higher flows (e.g., >25% BEP flow) would reduce the

effect of hydraulic instability on pump performance, thus making the test

data more meaningful because, in reality, the pump is not intended to

operate at such low flows to perform its normal plant design function.

Reducing the vibration levels by operating at higher flows will also

reduce the longer-term aging and wear effects on such parts as wear

rings, bearings, seals, etc.

The increase in internal clearances, such as wear-ring and balance

drum clearances that occur through pump aging, results in increased

stage-to-stage leakage, which reduces pump hydraulic efficiency. Figure

2.7 shows the effect of wear on the head-capacity curve of a centrifugal

pump. At any given head, the net capacity is reduced by the increase in

leakage. The leakage is proportional to the square root of the stage-tostage pressure differential. Note that in the low-flow portion of the

curve the change in head, after wear has taken place, is small compared

with the larger change taking place near expected BEP or runout flow.

Because, in reality, these pumps are to perform their function at the

higher flows, the measurement of head change at low flow will not provide

an accurate indication of the actual influence of wear and degradation.

Periodic testing at low flows is now conducted to detect gross pump

degradation such as that caused by impeller structural damage-or other

hydraulic component failure. Low-flow testing will not provide a good

indication of gradual pump performance deterioration that can be expected

to result from the normal wear and aging process. Full-flow testing will

more accurately detect these gradual changes.

In summary, obtaining test data at higher flows results in more consistent and dependable data for determining and trending pump wear. In

addition, aging and service wear rates should be reduced.
ill

Appendix E

TYPICAL AUXILIARY FEEDWATER SYSTEM DESCRIPTION

FOR WESTINGHOUSE PWR PLANT

Function

The AFW system serves as a backup system to supply feedwater to the

secondary side of the steam generators whenever the noruial main feedwater

system is not available in order to maintain the steam generator as the

principal reactor shutdown heat sink. This system also functions as an

alternate to the main feedwater system during start-up, hot standby, and

cooldown. As an engineered safeguards system, the AFW system is directly

relied upon to provide core cooling during off-normal or emergency transients such as loss of normal feedwater or secondary system piping failure. Thus, feedwater is continuously supplied to the steam generators

following main feedwater isolation or main feedwater pump turbine trip.

Figure E.1 is a simple schematic of the system, while Fig. E.2 is a more

detailed schematic.h

ORNL-DWG 88-4022 ETD

- Fig. E. 1. AFW system simplified schematic.
ORNL-DWG 884023 ETD

Fig. E.2. Flow diagram (typical) AFW system four-loop plant.

AE~ ( 4 I}
113

Design Basis

The AFW system is designed to meet the cooling requirements for the

following emergency conditions:

1. loss of main feedwater system,

2. loss of site electric power,

3. steamline rupture, ;

4. feedline rupture, -

5. control rooma evacuation, and

6. loss of coolant accident.

To meet these requirements, the systems are to incorporate the following recommended features:

1. Two sources of cooling water.

2. Two 100% capacity trains of electric-motor-driven pumps, etc.

3. A third 200% capacity-turbine-driven pump.

4. Only two of the four steam generators are needed for a safe cooldown.

5. Alternate and redundant power supplies, control systems, and instrumentation and piping systems are provided 'to meet the design requirements for engineered safety features. -

6. The system must perform adequately with'a single active or passive

failure.

Minimum flow requirements for safe shutdown require at least one

motor-operated AUXFP to establish hot shutdown following any accident or

transient'condition. The AFW system'then provides adequate coolingcapacity to cool the plant from hot standby to a reactor coolant hot leg

temperature of 350'F. This temperature will permit extended cooling

using the residual heat removal system. A cooldown from hot standby to

350'F can be achieved in -5 h.

Automatic start-up of the system following initiation of the auxiliary feedwater actuation signal will deliver water to the steam generator

within 1 min.'

System Description

General description (Fig. E.1) ^-

The AFW system consists of two motor-driven pumps, one steam-turbinedriven pump, :and associated piping, valves, instruments,-and'controls.

Each pump can deliver water to all four steam generators. Normal flow is

from the condensate storage tank containing feedwater.quality water,

through the motor-operated isolation valves, to the AUXFPs. -Backupsources typically include the safety class essential service water (ESW)

system. Flow rate to the steam'generators-is'controlled by pneumatic

diaphragm or motor-operated flow control-valves downstream of pump d4is-.

charges. Pumps start automatically on sensed loss of heat sink events.
114

The system is located within the auxiliary building, with adequate

missile barrier protection provided.

Motor-driven pumps

The two motor-driven AUXFPs are multistage horizontal centrifugal

pumps. They are powered by two separate 3600-rpm, 60-Hz motors that draw

power from different busses. Emergency power is from physically separate

emergency diesel generator busses. Maximum pump capacity, not including

recirculation flow, is typically about 500 gal/min, at a maximum developed head of 3200 ft.

Turbine-driven pump

The one steam-driven AUXFP is also a multistage horizontal centrifugal pump. Maximum pump capacity, not including recirculation flow, is

typically about 1000 gal/min at a maximum developed head of 3450 ft. The

steam is supplied from main steam loops B and C upstream of the main

steam isolation valves. The steam supply lines contain isolation valves

and bypass valves. The turbine is designed to operate over a wide range

of steam pressures, -100 to -1200 psig at a maximum steam temperature of

580'F. The turbine is controlled by two independent, redundant

electrical-hydraulic governors, either of which may control the turbine.

An emergency overspeed governor shuts off the main steam supply by closing the trip/throttle valve at 110% rated speed. The turbine lube oil

system is cooled by auxiliary feedwater from the first stage of the pump.

The turbine exhausts to the atmosphere. Auxiliary steam can be lined up

to the turbine but is used only for testing.

Auxiliary feedwater supply

Normal supply. Normal supply is from a 450,000-gal stainless steel

condensate storage tank containing feedwater-grade makeup water. Water

temperature is maintained at least 50'F by steam heating coils. Minimum

required volume is 200,000 gal. The flow by gravity from the tank

through a common supply header divides into a separate supply line to

each AUXFP. Flow is controlled through motor-operated isolation valves.

Emergency supply. Emergency supply is from two ESW system headers.

The first ESW header divides into a separate supply line to Motor Pump A

and to the turbine pump through two motor-operated isolation valves. The

second ESW header divides into a separate supply line to Motor Pump B and

to the turbine pump through two motor-operated isolation valves.

Auxiliary feedwater pump discharges

The turbine.pump discharge divides into two headers. Each header

further branches into two feed lines, one going to each steam generator.

Flow is controlled through pneumatic diaphragm valves. Downstream of the

flow control valves, each line joins with a feed line from the associated
115

motor-driven pump into a single auxiliary feed header, which connects

into each main feed line just'upstream of-containment penetration.

Motor Pump A discharge divides into two lines that supply the common

auxiliary feed header to steam generators B and C through motor-operated

flow control valves. Motor Pump B similarly supplies steam generators A

and D through motor-operated valve flow control valves, respectively.

The motor-driven pump discharges may be cross-connected through a

line normally shut by locked-shut isolation valves..

Continuous recirculation from each AUXFP'to the condensate storage

tank is maintained for pump protection. -The separate recirculation lines

combine into a'single return. Manual isolation valves in each individual

recirculation line are normally open.

Downstream of each supply source, pump, and flow control valve are

nonreturn valves and manual isolation valves that prevent backflow and

allow for system isolation. -Each pump and motor-operated/pneumatic -

isolation or-control valve may be operated manually at a-local station.

Instrumentation and control . . .

Instrumentation is provided that informs the operator in the control room of the state of the system. Instrumentation is also'provided

locally, which enables operation of the system in the event of evacuation

of the control room.

Alarms are also provided in the control 'rooia for minimum level in

the condensate tank, low suction pressure in both condensate and alternate suction lines, low turbine stop'valve steam pressure, and an alarm

annunciator that indicates when the remote control is overridden by local

control.

In addition tothe manual actuation of the AUXFPs, the following

signals provide for automatic actuation:

1. Motor-driven AUXFP automatic actuation signals::

A. 2/4 low-low level in any one steam generator,

B. trip of all main feedwater pumps,- ;;

- C. blackout sequence, and.

D. safeguards sequence (initiated by safety injection signal).

2. Turbine-driven AUXFP automatic actuation signals: -

- A. 2/4 low-low level in any twozsteam generators, and -

B. 2/4 undervoltage reactor coolant pump busses (loss of off-site

power).

Whenever any AUXFP starts, the steam generator blowdown and sampling

systems are automatically isolated.

The minimum number of pumps must be supplied with power and the

required flow to the steam generators must be established automatically

under a loss of station power or a loss of normal feed system.
I

116

System Operation

Normal conditions

-Plant startup. During a normal startup, the AFW system can-be used

in manual-control to maintain steam generator water level;until sufficient steam is generated to allow startup of the steam-driven main feed

pumps. Suction is from the condensate storage tank.

Power operation.: The system is-not used in normal operation. The

AUXFPs may be tested by pumping into main feed. lines while at power.

Plant cooldown. During normal plant cooldown, the system is used, to

supply feedwater to the steam generators for decay heat removal and reactor coolant systeia cooldown. The rate of auxiliary feedwater flow is

regulated from the main control room to maintainsteam generator level.

After the- primary coolant temperature reaches%'350'F, the residual heat

removal system is placed in operation, and the AFW system is no longer

required. Suction is taken from the condensate storage tank.

Abnormal conditions. The system is normally'lined-up for operation

with the exception of AUXFPs. Upon emergency start of the AUXFPs, feedwater from the condensate storage tank will be automatically pumped into

steam generators. Whenever the auxiliary feedwater actuation signal

(AFAS) is' initiated, the steam generator blowdown and sample lines are

automatically isolated. These blowdown and sample isolation valves may

not be opened until the AFAS reset pushbutton' is reset. If loss of normal vital power supply' has also occurred, the motor-driven' AUXFPs will be

powered by separate emergency diesel generators and will be started in

accordance with the engineered safety feature safeguards timing sequence

to prevent overloading the emergency diesels. In case of failure or loss

of condensate 'storage-tank water supply, the'normally closed ESW supply

isolation valves will automatically open.

In the event of a main feed line break, flow restrictors in the

AUXFP discharge lines will sufficiently limit flow to the break so that

cooldown flow is maintained to other steam generators for removal of

reactor decay heat.- In'the event of a main steam line break inside

containment, the flow restrictors will'sufficiently limit flow to the

faulted steam generator to keep containment pressure below the design

limit. - ' ''' -

Adequate control functions and indications are available at the

auxiliary shutdown panel and the local component control stations to

operate the AFW system upon loss of the main control room. An undesirable valve position or'pump status selected on the' main control panels

may be overridden by local/remote control switching and duplicate

selector switches on the auxiliary shutdown panel.
117

Appendix F

AUXFP MINIKUM-FLOW RATE CRITERIA

Many technical articles, textbook discussions, and research studies

have been completed in an attempt to understand and develop specification

criteria for minimum pump flow. Traditionally, minifaum flow was established on the basis of pumped fluid temperature rise. Pumped fluid temperature rise is a result of the hydraulic inefficiency of the pump that

occurs when-shaft power-is--converted-to-water power. -The temperature

rise in a pump with water flowing through it is

H(; - .; AT = (778r

where AT is the temperature rise (0F/min), n is the pump hydraulic efficiency, and H is the pump head (ft).

Near the shutoff point, the efficiency of a centrifugal pump is -

almost zero, and most of the energy will go into heating the liquid in

the pump. Unless a minimum flow passes through the pump to carry away

the heat, overheating will cause liquids with low vapor pressure to boil

in the low-pressure regions of the pump and will cause the pump rotating

element to seize. A general rule!of thumb to establish .minimum continuous flow, based on AT, is to limit temperature rise to 150F/min.

However, currently it is generally understood by pumap manufacturers

and users that temperature rise is only one concern. Centrifugal'pumps

will demonstrate a condition of inlet-flow breakdown at some point'on

their characteristic curve. This-breakdown point results in a mixed flow

condition at the impeller eye, with flow simultaneously moving in 'and out

of the inlet. This condition has been described in a variety of ways

such as backflow, stall, and inlet recirculation. Volume 1, Appendix D,

of this report provides a detailed description (with illustrations) of

this phenomenon. -

Vane separation and recirculation can be-expected to occur at the

impeller exit and inlet when a pump is operating at flow rates considerably below the BEP. The percentage of- design-point flow rate at which

recirculation will commence is dependent on many factors, including the

following:

1. impeller t6'volute or diffuser match,

2. inlet vane angles and position of the leading edge,

3. impeller radius ratio,

4. shaft diameter ratio,

5. power intensity,

6. specific speed,

7.--suction specific--speed; and -

8. net positive suction head (NPSH).available margin.

Simplifying-matters, it is widely believed that the most significant

factors affecting AUXFPs are-power-intensity and-suction specific speed.
118

Most of the guidelines that have been published stipulating recommended

minimum flow for pumps present minimum flow rates (or percentage of BEP

flow rate) as a function of specific speed. Guidelines from references

are included [Figs. F.1 (Ref. 1), F.2 (Ref. 2), and F.3 (Ref. 2)1. Figures F.1 and F.2 present minimum flow as a function of specific speed and

suction specific speed, respectively. Figure F.1 reflects the impact of

ORNL-DWG 88-4024 ETD

10

z

IL

0

0

0

w

0.

a.

C.)

50

PUMP FLOW (% OF RATED)

100

Fig. F.1. Anticipated useful operating ranges for pumps used in

large nuclear and fossil power generating units.
119

if 16 - 6-in. DISCHARGE AND LARGER (1800 rpm AND LOWER) I

SINGLE-STAGE. DOUBLE-SUCTION. 4-in. DISCHARGE AND SMAULER- _ .

X 15_ MULTISTAGE, 3-In. DISCHARGE AND LARGER I

ui .-- C -SINGLE-STAGE. OVERHUNG, 6-in. DISCHARGE AND- . 14 LARGER (3600 rpm) 1 K _ co 14- SINGLE-STAGE, DOUBLE-SUCTION, 6-in. 1 S r o DISCHARGE AND LARGER- - -

a9' - 1 1 - _ -| - 17 - = = ==

8 COTZ A --0-0= = a13

o 10 20 30 40 50 60 70 80

BEST EFFICIENCY POINT CAPACITY (MW)

AT MAXIMUM DIAMEITER IMPELLER (%)

Fig. F.2. Minimum continuous stable flow; percentage of BEPcapacity at maximum diameter impeller. Adapted with permission from

C. C. Heald and R. Paigrave, "Backf low Control lmproves:Pump Performance," Oil Gas J. (Feb. 25, 1985). - '-' -

power intensity onl minimum flow. These criteria result in-a rminimuw

continuous flow rate of >25% of BEP. Similar comments ~can .be found ini

Refs. 3 to 6 in addition to Refs. 1 and 2, already noted. '''''; '

However, the final selected minimum flow value should''be mutually

agreeable to both the user and manufacturer and should reflect* the'ex-.

perience gained for the specific pump configuration. It will be important to monitor dicag pesre pulsations and shaft vibration when

operating at these low flows. Note''that specification API 610 defines''

minimum continuous flow as "ithe lowest flow at which the pump can operate

without exceeding the noise and vibration limits 'imposed by this specification."

One point to keep in mind is that the AUXFPs operate on minif low

intermittently and not continuously. -The-overheating effect of excessive

temperature could be considered a short-term problem, while the effects

of hydraulic internal recirculation will result in a longer-term aging

-and wear issue. The question of what is adequate flow for continuous vs

intermittent operation is-now constantly asked, with special emphasis on

intermittent operation. 'The ability for a pump to operate at low flow

rates for various periods of time depends on many different factors, some
120

ORNL-DWG 88.4027 ETD

-3.5

-J 4--

-~~~ a. 2.0

1.0

0.6 0.7 .0.8 0.9. 1.0

MINIMUM FLOW CORRECTION FACTOR (Km)

Fig. F.3. Minimum flow correction factor.-

of which are listed below:

1. suction specific speed,

2. specific speed,

3. percentage of BEP flow,

4. power intensity (specific speed),

5. available NPSH margin,

6. rotor design,

7. bearing design,

8. shaft design,

9. casing and support design, and

10. seal design.

No-proven formulas are available to determine how long a specific pump

design can operate at given flow rates. Only through further testing and

accumulation of data can this determination be made.

References

1. M. L. Adams and E. Makay, Aging and Service Wear of Auxiliary

Feedwater Pumps for PWR Nuclear Power Plants, Volume 1, Operating

Experience and Failure Identification, NUREG/CR-4597, Vol. 1

(ORNL-6282/Vl), Oak Ridge Natl. Lab., July 1986.
121

2. C. C. Heald and R. Palgrave, "Backflow Control Improves Pump

Performance," Oil Gas J. (Feb. 25, 1985).

3. Igor J. Karassick, Centrifugal Pump Clinic, Marcel Dekker, Inc.,

1981.

4. F. J. Mollerus, R. D. Allen, and J. D. Gilcrest, Failures Related to

SurveilZance Testing of Standby Equipment, Vol. 1: Emergency Pumps,

EPRI NP-4264, Vol. 1, Electric Power Research Institute, October

1985.

5. E. Makay and 0. Szamody, Recommended Design Guidelines for Feedwater

Pumps in Large Power Generating Units, EPRI CS-1512, Electric Power

Research Institute, September 1980.

6. Westinghouse Electric Corp., Nuclear Training Services, PWR Information Manual, Vol. 1.
123

Appendix G .

TEST GUIDELINES FOR FULL-FLOW TESTING.

At present, periodic testing at power is performed at relatively,

"low flows" by utilizing the'pump miniflow path. Increasing the flow

through the pump miniflow path would most-likely, require-considerable

hardware changes and'may decrease the reliability.of the system to.

perform its'intended functions.

An alternative "full-flow" periodic testjthat~requires no hardware

changes was-proposed by W a number of years ago. IThe W-proposed test,

which is summarized below, would allow the.pumps.to-deliver..flow.-into the

steam generators during power operation.' This type of periodic test imposes additional temperature transients on the steam generators and has a

small transient impact on the steam generator level control system.- However, these additional temperature transients and level transients appear

to be well within the design specifications :for the.W steam generator and

steam generator level control systems, respectively. Also, this type of

test would require that the-source of-auxiliary feedwater (typically, the

condensate storage tank) during 'testing be condensate.quality and that

all noncondensate'quality sources'of feedwater be securely isolated during-testing to protect'the long-term structural;integrity-of the steam

generator.

In conclusion, the W-proposed "full-flow" test procedure appears to

be a viable alternative to low-flow miniflow testing and can.be implemented at minimal cost because'it'requires no system or hardware design

changes.

These guidelines address W-des-igned'plants.' No attempt has been

made to determine their applicability'to other plant designs.

The'test guidelines, included in the following 'pages, are proposed

by W as an alternative for upgrading'periodic AUXFP testing and to,

address the latest industry concerns. However, it must be recognized

that this procedure should be evaluated by all utilities on an individual

plant basis before implementation.

Westinghouse-Proposed AUXFP Test Guidelines

1.0 Each AUXFP should be demonstrated operable at least once--every-quarter.by verifying at least:.one point on the characteristic'(headflcw) curve of the pump. The portion-of the-head-flow curve-that is

verified should ensure that the pump can deliver its design flow.

The AUXFPs should be tested individually one at a time.

1.1 If it should be necessary to isolate an AUXFP by closing pump discharge valves to test the pump or some other portion of the system,

only one AUXFP should be so isolated or tested at any given time.

During this period of isolation, the other AUXFPs should remain

operable, and the system alignment should be such that an automatic

start signal will actuate the remaining pump(s), allowing them to

deliver flow into the steam generators.
124

1.2 The operability of an AUXFP should be demonstrated by manually

starting the pump and allowing the pump to deliver flow into the

steam generator feedwater lines, provided that the precautions and

limitations discussed in item 1.3 below are observed. Such a test

actually demonstrates the capability of the system to deliver flow

into the steam'generators-and should be performed quarterly.

1.3 To demonstrate the ability of-the AUXFPs to deliver into the steam

generators;'each pump should be tested individually. Each pump

should be permitted to deliver flow into all steam generators to

which it is normally aligned. For regular quarterly testing purposes, the flow rate delivered into any one steam generator should...

- not exceed 500 gal/min. Only condensate quality water may be

injected into'the steam generators.

The remote manual flow control valve(s) in the branch discharge

line(s) leading from'the pump to-the steam gernerator(s) may be

closed'immediately preceding the test and thereafter slowly opened

progressively during the' test until: the flow rate to any steam

generator reaches the 500-gal/min limitation. This procedure should

provide that the aforementioned flow limit is observed and should

minimize the transients experienced by the steam generator and the

flow and level control systems.

With the pump running, the'operators should observe or record pump

discharge pressure, pump suction pressure, discharge flow, re-

'circulation flow, flow to each steam generator, turbine inlet pressure, and pump speed (turbine pumps), in addition to other pertinent

test data, and should verify that these performance indicators conform to expectations. After stopping the pump, the remote manual

control valves in the branch discharge lines should be returned to

the full-open position.*

1.4 Following quarterly pump testing, the operator should verify that.

each valve (whether it be manual, power-operated, or automatic) in

the auxiliary feedwater flowpaths is in its correct position.*

*Standard technical specifications (STS) require this check only for

valves not locked, sealed, or secured in position.
125

'NUREG/CR-4597 ., Volume 2

ORNL 6282/V2

Dist. Category RV

~; - -'Internal Distribution

1. D. A. Casada- - 20. G. -A.' Murphy

2-7. D. M. Eissenberg 21. H. E. Trammell

8. E. C. Fox 22. ORNL Patent Section

9. J. A. Getsi 23. Central Research Library

10-16. W. L. Greenstreet 24. Document Reference Section

17. H. D. Haynes 25-26. Laboratory Records Department

18. D. E. Hendrix 27. Laboratory Records (RC)

19. R. C. Kryter

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Pittsburgh, PA 15230

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75 Parkway, Suite 1500, Atlanta, GA 30339

35. W. V. Cesarski, Westinghouse Electric Corporation, P.O. Box 2728,

Pittsburgh, PA 15230

36. W. S. Farmer, Division of Engineering Technology, Office of

Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission,

5650 Nicholson Lane, Rockville, MD 20852

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Richland, WA 99352

38. L. B. Marsh, Office of Nuclear Reactor Regulation, U.S. Nuclear

Regulatory Commission, Washington, D.C. 20555

39. P. McDonald, EG&G Idaho, Inc., P.O. Box 1625, WCB-3, Idaho Falls,

ID 83415

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37830

41. J. E. Rhoads, Washington Public Power System, 3000 George

Washington Way, P.O. Box 968, Richland, WA 99352

42. J. S. Schlonski, Westinghouse Electric Corporation, P.O. Box

2728, Pittsburgh, PA 15230

43. G. Sliter, Electric Power Research Institute, 3412 Hill View

Ave., P.O. Box 10412, Palo Alto, CA 94303

44. P. J. Sowatskey, Westinghouse Electric Corporation, P.O. Box

2728, Pittsburgh, PA 15230

45. J. H. Taylor, Engineering and Risk Assessment Division, Department of Nuclear Energy, Brookhaven National Laboratory, Upton, NY

11973

46. M. Vagins, Division of Engineering Technology, Office of Nuclear

Regulatory Research, U.S. Nuclear Regulatory Commission, 5650

Nicholson Lane, Rockville, MD 20852
126

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Nuclear Regulatory Research, U.S. Nuclear Regulatory Commission,

5650 Nicholson Lane, Rockville, MD 20852

48. Office of Assistant Manager for Energy Research and Development,

Department of Energy, Oak Ridge Operations Office, Oak Ridge,-TN

37831

49-50. Office of Scientific and Technical Information, P.O. Box 62, Oak

Ridge, TN 37831

51-380. Given distribution as shown in NRC category RV (10-NTIS)
IIRCFORMZSI U t NUCLEARREGULATORYCOMISSION I REPOR T NUMBERIA,#..* a, oO.dbvof NOo, av.

12141

,N1.R,'02. BIBLIOGRAPHIC DATA SHEET NUREG/CR-4597

Vol. 2, ORNL-6282/V2 SEE INEFAUCTINS5 Off THEt REVERSE

2 TITLE AND SUBTITLE 3 LEAVE BLANK

Aging and Service Wear of Auxiliary Feedwater Pumps for

PWR Nuclear Plants. Volume 2. Aging Assessments and

Monitoring Method Evaluations 4DATEREPORTCOPLETED

S AUTHORISI

D. M. Kitch, J. S. Schlonski, P. J. Sowatskey, _ _ArEREPORTISSUED

W. V. Cesarski MONTH YEAR

7 PFRORMING ORAGANIZATIO4 NAME AND MAILING ADORESS tI..a..Z. Cool a PROJECTIIASAtWORK UNIT N4UMBER

Oak Ridge National Laboratory

P.O. Box 2009 9 PIN OH GRANT NUMBER

Oak Ridge, Tennessee 37831-8063 B0828

10. SPONSORING ORGANIZATION NAME AND MAILING ADDRESS IM EZ. CofI II. TYPE Of REPORT

Division of Engineering Technology Topical

Office of Nuclear Regulatory Research

U.S. Nuclear Regulatory Commission s ERIODCOVERED

Washington, DC 20555

12 SUPPLEMENTARY NOTES

.. ^.T , .. A.. - ,

Failure causes attributable to aging and service wear of auxiliary feedwater pumps

(AUXFPs) are given and ranked in terms of importance. Cause identifications are

made on the bases of experience, post service examinations, and in situ assessments.

Measurable parameters related to failure causes are identified. ISCM methods are

also identified, evaluations are made based on Westinghouse experience, 'and

recommendations are given. The methods are intended to yield required capabilities

for establishing operational readiness, as well as for detecting and tracking

degradation.

The role of maintenance in mitigating aging and service wear effects is discussed,

and the relationship of maintenance to ISCM methods is identified. Predictive,

preventive, and corrective maintenance practices are discussed and evaluated.

Appendixes are included that contain failure data base Information, AUXFP

installation lists, discussion of low-flow testing, auxiliary feedwater system

description, AUXFP minimum-flow-rate criteria, and proposed guidelines for full-flow

testing.

This report was produced under the U.S. Nuclear Regulatory Commission's Nuclear

Plant Aging Research Program.

b4 DOCUMEhr A'.ALISS -A KEYWORDS OESCR.PTORS AVAI.ABILITI

STATEIVENIT

Pumps, centrifugal pumps, auxiliary feedwater pumps, aging, service wear, Unlimited

maintenance, degradation, hydraulic instability, trend, failure mode,

failure cause, measurable parameter, incipient failure, inspection, I

surveillance, monitoring, functional indicators, operating experience IT...

o ENTIooRs COPEN 1EDfD TERMS Unclassified

Unclassified

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