IEEE-242-BUFF-Recommended-practice-for-protection-and-coord-2.pdf

Approved as an American National Standard (ANSI) IEEE Std 242-2001
(Revision of
IEEE Std 242-1986)
IEEE Recommended Practice for
Protection and Coordination of
Industrial and Commercial
Power Systems
Sponsor
Industrial and Commercial Power Systems Department
of the
IEEE Industry Applications Society
Approved 14 June 2001
IEEE-SA Standards Board
Abstract: The principles of system protection and the proper selection, application, and
coordination of components that may be required to protect industrial and commercial power
systems against abnormalities that could reasonably be expected to occur in the course of
system operation are presented in a in a simple, yet comprehensive, format. The principles
presented apply to both new electrical system design and to the changing, upgrading, or
expansion of an existing electrical distribution system.
Keywords: bus protection, cable protection, calibration, conductor protection, coordinating
time intervals, current transformers, current-limiting fuses, fuse coordination, fuse selectivity,
generator grounding, generator protection, high-voltage fuses, liquid preservation systems,
low-voltage motor protection, medium-voltage motor protection, motor protection, overcurrent
protection, potential transformers, power fuses, protective relays, relay application principles,
relay operating principles, service protection, short-circuit protection, switchgear protection,
system design, system protection, transformer protection, voltage transformers

Grateful acknowledgment is made to the following organizations for having granted permission to
reprint material in this document as listed below:
Table 10-1 from National Electrical Manufacturers Assocation.
Reprinted from NEMA MG10-1994 by permission of the National Manufacturers Assocation. © Copy-
right 1997 by the National Electrical Manufacturers Assocation. All rights, including translation into
other languages, reserved under the Universal Copyright Convention, the Berne Convention for the Pro-
tection of Literary and Artistic Works, and the International and Pan American Copyright Conventions.
Figure 10-14, Figure 10-15, and Figure 10-18 from Bentley-Nevada.
Figure 10-16 and Figure 10-17 from API 541-1995.
First Printing
17 December 2001
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Copyright © 2001 by the Institute of Electrical and Electronics Engineers, Inc.
All rights reserved. Published 17 December 2001. Printed in the United States of America
ISBN 0-7381-2844-9
No part of this publication may be reproduced in any form, in an electronic retrieval system or otherwise,
without the prior written permission of the publisher.

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iv Copyright © 2001 IEEE. All rights reserved.
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Copyright © 2001 IEEE. All rights reserved. v
Introduction
(This introduction is not a part of IEEE Std 242-2001, IEEE Recommended Practice for Protection and
Coordination of Industrial and Commercial Power Systems.)
IEEE Std 242-2001, the IEEE Buff Book™, has been extensively revised and updated since it
was ﬁrst published in 1975. The IEEE Buff Book deals with the proper selection, application,
and coordination of the components that constitute system protection for industrial plants and
commercial buildings. System protection and coordination serve to minimize damage to a
system and its components in order to limit the extent and duration of any service interruption
occurring on any portion of the system.
A valuable, comprehensive sourcebook for use at the system design stage as well as in
modifying existing operations, the IEEE Buff Book is arranged in a convenient step-by-step
format. It presents complete information on protection and coordination principles designed
to protect industrial and commercial power systems against any abnormalities that could
reasonably be expected to occur in the course of system operation.
Design features are provided for
— Quick isolation of the affected portion of the system while maintaining normal
operation elsewhere
— Reduction of the short-circuit current to minimize damage to the system, its
components, and the utilization equipment it supplies
— Provision of alternate circuits, automatic throwovers, and automatic reclosing devices
Participants
At the time this recomended practice was approved, the IEEE Working Group on Protection
and Coordination of Industrial and Commercial Power Systems had the following members
and contributors:
Carey Cook, Chair
Chapter 1: First principles—Robert G. Hoerauf, Chair; R. G. (Jerry) Irvine
Chapter 2: Short-circuit calculations—Louie J. Powell, Chair; David S. Baker, Chet Davis,
John F. Witte
Chapter 3: Instrument transformers—James D. Bailey and David S. Baker, Cochairs;
B. J. Behroon, Louie J. Powell, Marcelo Valdes
Chapter 4: Selection and application of protective relays—Keith R. Cooper, N. T. (Terry)
Stringer, John F. Witte, Cochairs; Bruce G. Bailey, David S. Baker,
James W. Brosnahan, Carey J. Cook, David D. Shipp, John F. Witte
Chapter 5: Low-voltage fuses—Vincent J. Saporita, Chair; Robert L. Smith, Alan F.
Wilkinson
Chapter 6: High-voltage fuses—John R. Cooper, Chair; Carey J. Cook, Herb Pﬂanz,
Kris Ranjan, John F. Witte

vi Copyright © 2001 IEEE. All rights reserved.
Chapter 7: Low-voltage circuit breakers—George D. Gregory, Chair; Bruce G. Bailey,
John Chiloyan, Keith R. Cooper, R. G. (Jerry) Irvine, Steve Schaffer
Chapter 8: Ground-fault protection—Shaun P. Slattery, Chair; James P. Brosnahan,
John Chiloyan, Edward Gaylon, Daniel. J. Love, Elliot Rappaport, Steven
Schaffer, S. I. Venugopalan
Chapter 9: Conductor protection—William Reardon, Chair; John Chiloyan, George D.
Gregory, Alan C. Pierce, Vincent J. Saporita
Chapter 10: Motor protection—Daniel J. Love, Chair; Al Hughes, Alan C. Pierce,
Lorraine K. Padden, Joseph S. Dudor, R. G. (Jerry) Irvine
Chapter 11: Transformer protection—Alan C. Pierce, Chair; Carey J. Cook, John R. Cooper,
Jerry Frank, Vincent J. Saporita, N. T. (Terry) Stringer, Ralph H. Young
Chapter 12: Generator protection—Alan C. Pierce, Chairs; Jay D. Fisher, Robert G.
Hoerauf, Danial J. Love, Robert L. Simpson, Ralph H. Young
Chapter 13: Bus and switchgear protection—Robert L. Smith, Jr., Chair; Edward Gaylon,
Steve Schaffer, John Steele
Chapter 14: Service supply line protection—Lorraine K. Padden, Chair; Consumer
Interface Protection and Relaying Practices Subcommittees of the IEEE Power
Systems Relaying Committee
Chapter 15: Overcurrent coordination—N. T. (Terry) Stringer, Chair; Bruce G. Bailey,
Keith R. Cooper, Joseph S. Dudor, Douglas Durand, Tim Fink, Jay D. Fisher,
George D. Gregory, William M. Hall, Steve Schaffer, John F. Witte, Ralph H.
Young
Chapter 16: Maintenance, testing, and calibration—R. G. (Jerry) Irvine, Chair; Donald J.
Akers, Jerry S. Baskin, Roderic L. Hageman, Ted Olsen, Gabe Paoletti, Elliot
Rappaport, David, L. Swindler, Neil H. Woodley
The following members of the balloting group voted on this standard. Balloters may have
voted for approval, disapproval, or abstention:
Bruce G. Bailey
James D. Bailey
David S. Baker
Ray M. Clark
Carey J. Cook
John R. Cooper
Chet Davis
George D. Gregory
Robert G. Hoerauf
R. G. (Jerry) Irvine
Daniel J. Love
Lorraine K. Padden
Alan C. Pierce
Louie J. Powell
William Reardon
Vincent J. Saporita
David D. Shipp
Shaun P. Slattery
Robert L. Smith, Jr.
N. T. (Terry) Stringer
John F. Witte
Ralph H. Young

Copyright © 2001 IEEE. All rights reserved. vii
When the IEEE-SA Standards Board approved this standard on 14 June 2001, it had the fol-
lowing membership:
Donald N. Heirman, Chair
James T. Carlo, Vice Chair
Judith Gorman, Secretary
*Member Emeritus
Also included is the following nonvoting IEEE-SA Standards Board liaison:
Alan Cookson, NIST Representative
Donald R. Volzka, TAB Representative
Noelle D. Humenick
IEEE Standards Project Editor
IEEE Color Book Series and IEEE Buff Book are both registered trademarks of the Institute of Electrical and Elec-
tronics Engineers, Inc.
National Electrical Code and NEC are both registered trademarks of the National Fire Protection Association, Inc.
National Electrical Safety Code and NESC are both registered trademarks and service marks of the Institute of Elec-
trical and Electronics Engineers, Inc.
Satish K. Aggarwal
Mark D. Bowman
Gary R. Engmann
Harold E. Epstein
H. Landis Floyd
Jay Forster*
Howard M. Frazier
Ruben D. Garzon
James H. Gurney
Richard J. Holleman
Lowell G. Johnson
Robert J. Kennelly
Joseph L. Koepﬁnger*
Peter H. Lips
L. Bruce McClung
Daleep C. Mohla
James W. Moore
Robert F. Munzner
Ronald C. Petersen
Gerald H. Peterson
John B. Posey
Gary S. Robinson
Akio Tojo
Donald W. Zipse

Copyright © 2001 IEEE. All rights reserved. ix
Contents
Chapter ...................................................................................................................................1
First principles ........................................................................................................................1
1.1 Overview.............................................................................................................1
1.2 Protection against abnormalities.........................................................................3
1.3 Planning system protection.................................................................................4
1.4 Preliminary design ..............................................................................................5
1.5 Basic protective equipment.................................................................................7
1.6 Special protection................................................................................................8
1.7 Field follow-up....................................................................................................8
1.8 References...........................................................................................................8
Chapter 2
Short-circuit calculations ......................................................................................................11
2.1 Introduction.......................................................................................................11
2.2 Types of short-circuit currents..........................................................................12
2.3 The nature of short-circuit currents...................................................................13
2.4 Protective device currents.................................................................................15
2.5 Per-unit calculations..........................................................................................19
2.6 Short-circuit current calculation methods.........................................................19
2.7 Symmetrical components..................................................................................20
2.8 Network interconnections.................................................................................28
2.9 Calculation examples........................................................................................33
2.10 Specialized faults for protection studies ...........................................................41
2.11 References.........................................................................................................44
2.12 Bibliography .....................................................................................................45
Chapter 3
Instrument transformers........................................................................................................47
3.1 Introduction.......................................................................................................47
3.2 Current transformers (CTs)...............................................................................47
3.3 Voltage (potential) transformers (VTs) ............................................................62
3.4 References.........................................................................................................65
3.5 Bibliography .....................................................................................................65
Chapter 4
Selection and application of protective relays ......................................................................67
4.1 General discussion of a protective system........................................................67
4.2 Zones of protection ...........................................................................................69
4.3 Fundamental operating principles.....................................................................70
4.4 Functional description—application and principles .........................................71
4.5 References.......................................................................................................119
4.6 Bibliography ...................................................................................................119

x Copyright © 2001 IEEE. All rights reserved.
Chapter 5
Low-voltage fuses...............................................................................................................129
5.1 General discussion ..........................................................................................129
5.2 Definitions.......................................................................................................129
5.3 Documentation................................................................................................133
5.4 Standard dimensions.......................................................................................138
5.5 Typical interrupting ratings.............................................................................146
5.6 Achieving selectivity with fuses.....................................................................147
5.7 Current-limiting characteristics ......................................................................151
5.8 Special applications for low-voltage fuses .....................................................155
5.9 References.......................................................................................................166
5.10 Bibliography ...................................................................................................168
Chapter 6
High-voltage fuses (1000 V through 169 kV) ....................................................................169
6.1 Definitions.......................................................................................................169
6.2 Fuse classification...........................................................................................173
6.3 Current-limiting and expulsion power fuse designs .......................................177
6.4 Application of high-voltage fuses...................................................................183
6.5 References.......................................................................................................197
6.6 Bibliography ...................................................................................................198
Chapter 7
Low-voltage circuit breakers ..............................................................................................199
7.1 General............................................................................................................199
7.2 Ratings ............................................................................................................200
7.3 Current limitation............................................................................................202
7.4 Typical ratings ................................................................................................203
7.5 Trip unit ..........................................................................................................203
7.6 Application......................................................................................................216
7.7 Accessories .....................................................................................................226
7.8 Conclusions.....................................................................................................226
7.9 References.......................................................................................................227
7.10 Bibliography ...................................................................................................228
Chapter 8
Ground-fault protection ......................................................................................................231
8.2 Types of systems relative to ground-fault protection .....................................232
8.3 Nature, magnitudes, and damage of ground faults .........................................239
8.4 Frequently used ground-fault protective schemes ..........................................249
8.5 Typical applications........................................................................................255
8.6 Special applications ........................................................................................269
8.7 References.......................................................................................................281
8.8 Bibliography ...................................................................................................281

Copyright © 2001 IEEE. All rights reserved. xi
Chapter 9
Conductor protection ..........................................................................................................285
9.2 Cable protection..............................................................................................285
9.3 Definitions.......................................................................................................287
9.4 Short-circuit current protection of cables .......................................................288
9.5 Overload protection of cables.........................................................................307
9.6 Physical protection of cables ..........................................................................321
9.7 Code requirements for cable protection..........................................................324
9.8 Busway protection ..........................................................................................325
9.9 References.......................................................................................................336
9.10 Bibliography ...................................................................................................337
Chapter 10
Motor protection339
10.2 Factors to consider in protection of motors ....................................................339
10.3 Types of protection .........................................................................................344
10.4 Low-voltage motor protection ........................................................................350
10.5 Medium-voltage motor protection..................................................................358
10.6 References.......................................................................................................389
10.7 Bibliography ...................................................................................................390
Chapter 11
Transformer protection .......................................................................................................393
11.2 Need for protection .........................................................................................393
11.3 Objectives in transformer protection ..............................................................394
11.4 Types of transformers .....................................................................................395
11.5 Preservation systems.......................................................................................395
11.6 Protective devices for liquid preservation systems.........................................398
11.7 Thermal detection of abnormalities ................................................................408
11.8 Transformer primary protective device ..........................................................415
11.9 Protecting the transformer from electrical disturbances .................................415
11.10 Protection from the environment ....................................................................436
11.11 Conclusion ......................................................................................................437
11.12 References.......................................................................................................437
11.13 Bibliography ...................................................................................................438
Chapter 12
Generator protection ...........................................................................................................441
12.1 Introduction.....................................................................................................441
12.2 Classification of generator applications..........................................................441
12.3 Short-circuit performance...............................................................................444
12.4 Generator grounding.......................................................................................451
12.5 Protective devices ...........................................................................................454
12.6 References.......................................................................................................512
12.7 Bibliography ...................................................................................................512

xii Copyright © 2001 IEEE. All rights reserved.
Chapter 13
Bus and switchgear protection............................................................................................515
13.2 Types of buses and arrangements ...................................................................516
13.3 Bus overcurrent protection..............................................................................518
13.4 Medium- and high-voltage bus differential protection...................................519
13.5 Backup protection...........................................................................................525
13.6 Low-voltage bus conductor and switchgear protection ..................................525
13.7 Voltage surge protection.................................................................................526
13.8 Conclusion ......................................................................................................528
13.9 References.......................................................................................................528
13.10 Bibliography ...................................................................................................529
Chapter 14
Service supply-line protection ............................................................................................531
14.2 Service requirements.......................................................................................532
14.3 System disturbances........................................................................................535
14.4 Supply-line protection.....................................................................................547
14.5 Examples of supply-system protective schemes.............................................558
14.6 References.......................................................................................................571
14.7 Bibliography ...................................................................................................573
Chapter 15
Overcurrent coordination....................................................................................................575
15.2 General considerations....................................................................................576
15.3 Overcurrent protection guidelines...................................................................580
15.4 TCC plots........................................................................................................590
15.5 CTIs.................................................................................................................596
15.6 Initial planning and data required for a coordination study............................604
15.7 Procedure ........................................................................................................607
15.8 Ground-fault coordination on low-voltage systems........................................626
15.9 Phase-fault coordination on substation 600 V or less.....................................627
15.10References......................................................................................................636
15.11Bibliography ..................................................................................................636
Chapter 16
Maintenance, testing, and calibration .................................................................................639
16.1 Overview.........................................................................................................639
16.2 Definitions.......................................................................................................640
16.3 Safety of personnel .........................................................................................641
16.4 Safety provisions for maintenance operations................................................643
16.5 Frequency of maintenance operations ............................................................648
16.6 Maintenance of switchgear for voltages up to 1000 V ac and 1200 V dc ......652
16.7 Maintenance of air-magnetic switchgear for
voltages above 1000 V ac and 1200 V dc.......................................................659

Copyright © 2001 IEEE. All rights reserved. xiii
16.8 Maintenance of oil switchgear........................................................................669
16.9 Maintenance of vacuum circuit breaker switchgear .......................................675
16.10 Maintenance of sulfur hexafluoride (SF6) circuit breaker and
load-interrupter switchgear.............................................................................679
16.11 Diagnostic testing............................................................................................682
16.12 Maintenance of auxiliary items.......................................................................689
16.13 Maintenance of protective apparatus ..............................................................695
16.14 Maintenance and testing of insulation ............................................................696
16.15 Maintenance of industrial molded-case circuit breakers (MCCBs)................699
16.16 References.......................................................................................................701
16.17 Bibliography ...................................................................................................704
Index ...................................................................................................................................711

Copyright © 2001 IEEE. All rights reserved. 1
IEEE Recommended Practice for
Protection and Coordination of
Industrial and Commercial
Power Systems
Chapter 1
First principles
1.1 Overview
1.1.1 Scope
IEEE Std 242-2001, commonly known as the IEEE Buff Book™, is published by the Institute
of Electrical and Electronics Engineers (IEEE) as a reference source to provide a better
understanding of the purpose for and techniques involved in the protection and coordination
of industrial and commercial power systems.
IEEE Std 242-2001 has been prepared on a voluntary basis by engineers and designers
functioning as a working group within the IEEE, under the Industrial and Commercial Power
Systems Department of the Industry Applications Society. This recommended practice is not
intended as a replacement for the many excellent texts available in this ﬁeld. IEEE Std 242-
2001 complements the other standards in the IEEE Color Book Series™, and it emphasizes
up-to-date techniques in power system protection and coordination that are most applicable
to industrial and commercial power systems. Coverage is limited to system protection and
coordination as it pertains to system design treated in IEEE Std 141-19931
and IEEE
Std 241-1990. No attempt is made to cover utility systems or residential systems, although
much of the material presented is applicable to these systems.
This publication presents in a step-by-step, simpliﬁed, yet comprehensive, form the
principles of system protection and the proper application and coordination of those
components that may be required to protect industrial and commercial power systems against
abnormalities that could reasonably be expected to occur in the course of system operation.
The principles presented are applicable to both new electrical system design and to the
changing, upgrading, or expansion of an existing electrical distribution system.
1Information on references can be found in 1.8.

IEEE
FIRST PRINCIPLES Std 242-2001
plant or commercial business. Some operations can afford limited service interruptions to
minimize the possibility of equipment repair or replacement costs, while others would regard
such an expense as small compared with even a brief interruption of service.
In most cases, electrical protection should be designed for the best compromise between
equipment damage and service continuity. One of the prime objectives of system protection is
to obtain selectivity to minimize the extent of equipment shutdown in case of a fault. There-
fore, many protection engineers would prefer that faulted equipment be de-energized as soon
as the fault is detected.
However, for certain continuous process industry plants, high-resistance grounding systems
that allow the first ground fault to be alarmed instead of automatically cleared are employed.
These systems are described in Chapter 8.
1.1.2.3 Economic and reliability considerations
The cost of system protection determines the degree of protection that can be feasibly
designed into a system. Many features may be added that improve system performance, reli-
ability, and flexibility, but incur an increased initial cost. However, failure to design into a
system at least the minimum safety and reliability requirements inevitably results in unsatis-
factory performance, with a higher probability of expensive downtime. Modifying a system
that proves inadequate is more expensive and, in most cases, less satisfactory than initially
designing these features into a system.
The system should always be designed to isolate faults with a minimum disturbance to the
system and should have features to give the maximum dependability consistent with the plant
requirements and justifiable costs. Evaluation of costs should also include equipment mainte-
nance requirements. In many instances, plant requirements make planned system outages for
routine maintenance difficult to schedule. Such factors should weigh into the economic-
versus-reliability decision process.
When costs of downtime and equipment maintenance are factored into the protection system
cost evaluation, decisions can then be based upon total cost over the useful life of the
equipment rather than simply the first cost of the system. In-depth coverage of reliability-
versus-economic decisions can be found in IEEE Std 493-1997.
1.2 Protection against abnormalities
The principal electrical system abnormalities to protect against are short circuits and over-
loads. Short circuits may be caused in many ways, including failure of insulation due to
excessive heat or moisture, mechanical damage to electrical distribution equipment, and fail-
ure of utilization equipment as a result of overloading or other abuse. Circuits may become
overloaded simply by connecting larger or additional utilization equipment to the circuit.
Overloads may also be caused by improper installation and maintenance, such as misaligned
shafts and worn bearings. Improper operating procedures (e.g., too frequent starting,

IEEE
Std 242-2001 CHAPTER 1
4 Copyright © 2001 IEEE. All rights reserved.
extended acceleration periods, obstructed ventilation) are also a cause of equipment overload
or damage.
Short circuits may occur between two-phase conductors, between all phases of a polyphase
system, or between one or more phase conductors and ground. The short circuit may be solid
(or bolted) or welded, in which case the short circuit is permanent and has a relatively low
impedance. The extreme case develops when a miswired installation is not checked prior to
circuit energization. In some cases the short circuit may burn itself clear, probably opening
one or more conductors in the process. The short circuit may also involve an arc having
relatively high impedance. Such an arcing short circuit can do extensive damage over time
without producing exceptionally high current. An arcing short circuit may or may not
extinguish itself. Another type of short circuit is one with a high-impedance path, such as dust
accumulated on an insulator, in which a flashover occurs. The flashover may be harmlessly
extinguished or the ionization produced by the arc may lead to a more extensive short circuit.
These different types of short circuits produce somewhat different conditions in the system.
Electrical systems should be protected against the highest short-circuit currents that can
occur; however, this maximum fault protection may not simultaneously provide adequate
protection against lower current faults, which may involve an arc that is potentially
destructive.
Ground faults comprise the majority of all faults that occur in industrial and commercial
power systems. Ground-fault currents may be destructive, even though the magnitude may be
reduced by a high impedance in the fault and return path. Several methods of grounding are
available; and the appropriate selection for the particular voltage level, combined with proper
detection and relaying, can help achieve the goals of reduced damage and service continuity.
For this reason, Chapter 8 is devoted to ground-fault protection.
With the increasing use of nonlinear system loads and devices, harmonics have become an
ever-increasing system abnormality to contend with. Electrical system design, whether new
or through changes or additions to an existing system, should take into account the possible
effects of harmonic current and voltages on system equipment and protective devices. In
many cases, harmonics may cause excessive heating in system components; improper opera-
tion of control, metering, and protective devices; and other problems.
Other sources of abnormality, such as lightning, load surges, and loss of synchronism, usually
have little or no effect on system overcurrent selectivity, but should not be ignored. These
abnormalities usually can be best handled on an individual protective basis for the specific
equipment involved (e.g., transformers, motors, generators).
1.3 Planning system protection
The designer of electrical power systems has available several techniques to minimize the
effects of abnormalities occurring on the system or in the utilization equipment that the sys-
tem supplies. One can design into the electric system features that

IEEE
a) Quickly isolate the affected portion of the system and, in this manner, maintain
normal service for as much of the system as possible. This isolation also minimizes
damage to the affected portion of the system.
b) Minimize the magnitude of the available short-circuit current and, in this manner,
minimize potential damage to the system, its components, and the utilization equip-
ment it supplies.
c) Provide alternate circuits, automatic transfers, or automatic reclosing devices, where
applicable, in order to minimize the duration or the extent of supply and utilization
equipment outages.
System protection encompasses all of the above techniques; however, this text deals mainly
with the prompt isolation of the affected portion of the system. Accordingly, the function of
system protection may be defined as the detection and prompt isolation of the affected
portion of the system whenever a short-circuit or other abnormality occurs that might cause
damage to, or adversely affect, the operation of any portion of the system or the load that it
supplies.
Coordination is the selection and/or setting of protective devices in order to isolate only the
portion of the system where the abnormality occurs. Coordination is a basic ingredient of a
well-designed electrical distribution protection system and is mandatory in certain health care
and continuous process industrial systems.
System protection is one of the most basic and essential features of an electrical system and
should be considered concurrently with all other essential features. Too often system protec-
tion is considered after all other design features have been determined and the basic system
design has been established. Such an approach may result in an unsatisfactory system that
cannot be adequately protected, except by a disproportionately high expenditure. The
designer should thoroughly examine the question of system protection at each stage of plan-
ning and incorporate into the final system a fully integrated protection plan that is capable of,
and is flexible enough, to grow with the system.
In planning electric power systems, the designer should endeavor to keep the final design as
simple as would be compatible with safety, reliability, maintainability, and economic
considerations. Designing additional reliability or flexibility into a system may lead to a more
complex system requiring more complex coordination and maintenance of the protective
system. Such additional complexity should be avoided except where the requisite personnel,
equipment, and know-how are available to adequately service and maintain a complex
electric power system.
1.4 Preliminary design
The designer of an electrical power system should first determine the load requirement,
including the sizes and types of loads, and any special requirements. The designer should also
determine the available short-circuit current at the point of delivery, the time-current curves
and settings of the nearest utility protective devices, and any contract restrictions on ratings
and settings of protective relays or other overcurrent protective devices in the user’s system.

IEEE
(See Figure 1-1.) The designer can then proceed with a preliminary system design and prepa-
ration of a one-line diagram.
Chapter 2 covers the fundamentals of short-circuit analysis and the calculation of short-
circuit duty requirements that permit evaluation of the preliminary design for compatibility
with available ratings of circuit breakers, fuses, and other devices. At this point, some
modiﬁcation of the design may be necessary because of economic considerations or
equipment availability, or both.
The preliminary design should be evaluated from the standpoint of system coordination, as
covered in Chapter 15. If the protective devices provided in the preliminary design cannot be
selectively coordinated with utility protective device settings and contractual restrictions on
protective device settings, the design should be modiﬁed to provide proper selective
coordination.
Ground-fault protection is an essential part of system protection and is given detailed
coverage in Chapter 8 for two reasons. First, although many of the devices used to obtain
ground-fault protection are similar to those covered in Chapter 3 through Chapter 7, the need
for such protection and the potential problems of improper application of ground-fault
protection are frequently not fully appreciated. Second, proper selective coordination of
Figure 1-1—Sequence of steps in system protection and coordination

IEEE
ground-fault protection seldom causes any change to overall system selectivity, although its
effect should be taken into consideration in the same general manner covered in Chapter 15.
In-depth coverage of system grounding can also be found in IEEE Std 142-1991.
Throughout the preliminary and final design process, the personal computer has become an
indispensable tool in power system planning, analysis, and simulation of day-to-day opera-
tions. A number of power system software programs are available to assist the designer in
evaluating protective device application and to assist in the proper selection and coordination
of protective devices. Available software includes programs to evaluate and perform short
circuit, protective device coordination, load flow, harmonic analysis, system stability, motor
starting, and grounding. In-depth coverage of power system analysis can be found in IEEE
Std 399-1997.
The designer of the protective system should bear in mind that the design consumes two crit-
ical and limited resources, space and money, and should take practical steps to ensure that
these needs are fully recognized by the overall project team.
1.5 Basic protective equipment
The isolation of short circuits and overloads requires the application of protective equipment
that senses when an abnormal current flow exists and then removes the affected portion from
the system.
The three primary protective equipment components used in the isolation of short circuits and
overloads are fuses, circuit breakers, and protective relays.
A fuse is both a sensing and interrupting device, but not a switching device. It is connected in
series with the circuit and responds to thermal effects produced by the current flowing
through it. The fusible element is designed to open at a predetermined time depending upon
the amount of current that flows. Different types of fuses are available having time-current
characteristics required for the proper protection of the circuit components. Fuses may be
noncurrent-limiting or current-limiting, depending upon their design and construction. Fuses
are not resetable because their fusible elements are consumed in the process of interrupting
the current flow. Fuses and their characteristics, applications, and limitations are described in
detail in Chapter 5 and Chapter 6.
Circuit breakers are interrupting and switching devices that require overcurrent elements to
fulfill the detection function. In the case of medium-voltage (1–72.5 kV) circuit breakers, the
sensing devices are separate current transformers (CTs) and protective relays or combinations
of relays. These devices are covered in Chapter 4. For most low-voltage (under 1000 V)
circuit breakers, (molded-case circuit breakers or low-voltage power circuit breakers) the
sensing elements are an integral part of the circuit breaker. These trip units may be thermal or
magnetic series devices; or they may be integrally mounted, but otherwise separate electronic
devices used with CTs mounted in the circuit breaker. Low-voltage circuit breakers, their
applications, characteristics, and limitations are covered in Chapter 7.

IEEE
Overcurrent relays used in conjunction with medium-voltage circuit breakers are available
with a range of different functional characteristics. Relays may be either directional or
nondirectional in their action. Relays may be instantaneous and/or time-delay in response.
Various time-current characteristics (e.g., inverse time, very inverse time, extremely inverse
time, definite minimum time) are available over a wide range of current settings. Overcurrent
relays and their selection, application, and settings are covered in detail in Chapter 4. Numer-
ous other types of protective relays, used for specific protective purposes, are also discussed
throughout this publication. Relays generally are used in conjunction with instrument trans-
formers, which are covered in Chapter 3.
1.6 Special protection
In addition to developing a basic protection design, the designer may also need to develop
protective schemes for specific equipment or for specific portions of the system. Such
specialized protection should be coordinated with the basic system protection. Specialized
protection applications include
— Conductor protection (see Chapter 9)
— Motor protection (see Chapter 10)
— Transformer protection (see Chapter 11)
— Generator protection (see Chapter 12)
— Bus and switchgear protection (see Chapter 13)
— Service supply-line protection (see Chapter 14)
1.7 Field follow-up
Proper application of the principles covered in the first 15 chapters of this recommended
practice should result in the installation of system protection capable of coordinated selective
isolation of system faults, overloads, and other system problems. However, this capability
will be useless if the proper field follow-up is not planned and executed. Field follow-up has
three elements: proper installation, including testing and calibration of all protective devices;
proper operation of the system and its components; and a proper preventive maintenance pro-
gram, including periodic retesting and recalibration of all protective devices. A separate
chapter, Chapter 16, has been included to cover testing and maintenance.
1.8 References
This recommended practice shall be used in conjunction with the following standards. When
the following standards are superseded by an approved revision, the revision shall apply.

IEEE
ASC C2-2002, National Electric Safety Code® (NESC®).2
IEEE Std 80-2000, IEEE Guide for Safety in AC Substation Grounding.3
IEEE Std 141-1993 (Reaff 1999), IEEE Recommended Practice for Electric Power Distribu-
tion for Industrial Plants (IEEE Red Book).
IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and Commer-
cial Power Systems (IEEE Green Book).
IEEE Std 241-1990 (Reaff 1997), IEEE Recommended Practice for Electric Power Systems
in Commercial Buildings (IEEE Gray Book).
IEEE Std 399-1997, IEEE Recommended Practice for Industrial and Commercial Power Sys-
tems Analysis (IEEE Brown Book).
IEEE Std 493-1997, IEEE Recommended Practice for the Design of Reliable Industrial and
Commercial Power Systems (IEEE Gold Book).
NFPA 70-1999, National Electrical Code® (NEC®).4
NFPA 70E-2000, Electrical Safety Requirements for Employee Workplaces.5
2The NESC is available from the Institute of Electrical and Electronics Engineers, 445 Hoes Lane, P.O. Box 1331,
Piscataway, NJ 08855-1331, USA (http://standards.ieee.org/).
3IEEE publications are available from the Institute of Electrical and Electronics Engineers, 445 Hoes Lane, P.O. Box
1331, Piscataway, NJ 08855-1331, USA (http://standards.ieee.org/).
4The NEC is published by the National Fire Protection Association, Batterymarch Park, Quincy, MA 02269, USA
(http://www.nfpa.org/). Copies are also available from the Institute of Electrical and Electronics Engineers,
445 Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331, USA (http://standards.ieee.org/).
5NFPA publications are published by the National Fire Protection Association, Batterymarch Park, Quincy, MA
02269, USA (http://www.nfpa.org/).

IEEE-242-BUFF-Recommended-practice-for-protection-and-coord-2.pdf

Chapter 2
Short-circuit calculations
2.1 Introduction
Short-circuit currents can create massive destruction to the power system. Short circuits typi-
cally have magnitudes many times greater than load currents. The consequences of these
high-magnitude currents can be catastrophic to normal operation of the power system. First,
the presence of short-circuit currents in system conductors results in additional heating,
which the system is usually not designed to sustain continuously. These currents also intro-
duce severe mechanical forces on conductors, which can break insulators, distort transformer
windings, or cause other physical damage. The flow of high-magnitude short-circuit currents
through system impedances may also result in abnormally low voltages, which in turn lead to
otherwise healthy equipment being forced to shut down. Finally, at the point of the short cir-
cuit itself, generally the release of energy in the form of an arc, if left uncorrected, can start a
fire, which may spread well beyond the point of initiation.
Much of the effort of power system engineers and planners is directed toward minimizing the
impact of short circuits on system components and the industrial process the system serves. It
has been said that the only part of a power system that actually works is the protective devices
that are called upon to detect and react to short circuits—and they only do something when
something else goes wrong! This has led to the observation that power system engineers
focus only on catastrophes. It is true that a great deal of power system engineering is devoted
to the analysis of undesirable events, and nowhere is that statement more correct than in the
application of protective devices.
Lord Kelvin observed that knowledge of a subject is incomplete until the subject can be accu-
rately quantified. Of all the demands placed upon the power system protection engineer, the
most analytical is to determine the magnitude of voltages and currents that the system can
produce under various short-circuit conditions. Only when these quantities are understood
can the application of protective devices proceed with confidence that they will perform their
intended function when short circuits occur.
The most fundamental principle involved in determining the magnitude of short-circuit cur-
rent is Ohm’s Law: the current that flows in a network of impedances is related to the driving
voltage by the relationship
(2-1)
The general procedure for applying this principle entails the three steps involved in Theve-
nin’s Theorem of circuits.
a) Develop a graphical representation of the system, called a one-line (or single-line)
diagram, with symbolic voltage sources and circuit impedances.
I
E
Z
---
=

IEEE
b) Calculate the total impedance from the source of current (i.e., the driving voltage) to
the point at which a hypothetical short-circuit current is to be calculated. This value is
the Thevenin equivalent impedance, sometimes called the driving point impedance.
c) Knowing the open circuit prefault voltage, use Ohm’s Law to calculate the short-
circuit current magnitude.
Of course, the actual application of these basic principles is more involved, and the remainder
of this chapter is devoted to a treatment of the specific details of short-circuit current
calculations.
2.2 Types of short-circuit currents
From the point of view of functional application, four or more distinct types of short-circuit
current magnitudes exist. The current of greatest concern flows in the system under actual
short-circuit conditions and could (at least theoretically) be measured using some form of
instrumentation. In reality, it is not practical to attempt to predict by calculation the magni-
tude of actual current because it is subject to a great many uncontrollable variables. Power
system engineers have developed application practices, some of which are discussed in the
following paragraphs, that predict worst-case magnitudes of current sufficient for application
requirements.
The analyst or engineer may have several objectives in mind when a short-circuit current
magnitude is calculated. Obviously, the worst-case current should be appropriate to the
objective, and a set of assumptions that leads to a worst-case calculation for one purpose may
not yield worst-case results for another purpose.
Short-circuit current magnitudes often must be calculated in order to assess the application of
fuses, circuit breakers, and other interrupting devices relative to their ratings. These currents
have labels (e.g., interrupting duty, momentary duty, close and latch duty, breaking duty),
which correlate those magnitudes with the specific interrupter rating values against which
they should be compared to determine whether the interrupting device has sufficient ratings
for the application. ANSI standard application guides define specific procedures for calculat-
ing duty currents for evaluating fuses and circuit breakers rated under ANSI standards. Like-
wise, the International Electrotechnical Commission (IEC) publishes a calculation guide for
calculating duty currents for IEC-rated interrupting devices. In either case, the important
thing is that the basis for calculating the current be consistent with the basis for the device rat-
ing current so that the comparison is truly valid.
Related to interrupter rating currents are the currents used to evaluate the application of
current-carrying components. Transformers, for example, are designed to have a fault with-
stand capability defined in terms of current, and transformer applications should be evaluated
to assure that these thermal and mechanical limitations are being observed. Likewise, bus
structures should be designed structurally to withstand the forces associated with short cir-
cuits, and this requires knowledge of the magnitude of available fault currents. Similarly,
ground grids under electrical structures should be designed to dissipate fault currents without

IEEE
SHORT-CIRCUIT CALCULATIONS Std 242-2001
causing excessive voltage gradients. In each case, it is necessary to calculate a fault magni-
tude in a fashion that is consistent with the purpose for which it is needed.
Another type of short-circuit current magnitude is used by protection engineers to assess the
time-current performance of protective devices. Here, again, consistency is needed between
the calculated currents and the currents that the protective devices measure. No universally
accepted standards define how protective devices make measurements, and in fact measur-
able differences exist among manufacturers, among technologies, and even among design
vintages of the same manufacturer and technology. However, protection engineers have
evolved a series of generally accepted guidelines for which currents apply to which kinds of
protective devices, and these guidelines are detailed in subsequent chapters.
Other references in the IEEE Color Book Series™ treat the application of interrupting
devices. Accordingly, this chapter discusses only the calculation of short-circuit currents for
evaluating the time-current performance of relays, fuses, low-voltage circuit breaker trip
devices, and other protective equipment.
Another way of looking at short circuits is to consider the geometry of faults. Most modern
power systems are three-phase and involve three power-carrying conductors. A fourth con-
ductor, the neutral, may or may not carry load current depending upon the nature of the loads
on the system. The number of conductors involved in the short circuit has a bearing on the
severity of the fault as measured by the magnitude of short-circuit current; normally, a fault
involving all three-phase conductors (called the three-phase fault) is considered the most
severe. Other geometries include single phase-to-ground faults, phase-to-phase faults, double
phase-to-ground faults, and open conductors.
2.3 The nature of short-circuit currents
Under normal system conditions, the equivalent circuit of Figure 2-1 may be used to calculate
load currents. Three impedances determine the flow of current. Zs and Zc are the impedances
of the source and circuit, respectively, while Zl is the impedance of the load. The load imped-
ance is generally the largest of the three, and it is the principle determinant of the current
magnitude. Load impedance is also predominantly resistive, with the result that load current
tends to be nearly in phase with the driving voltage.
A short circuit may be thought of as a conductor that shorts some of the impedances in the
network while leaving others unchanged. This situation is depicted in Figure 2-2. Because Zs
and Zc become the only impedances that restrict the flow of current, the following observa-
tions may be made:
a) The short-circuit current is greater than load current.
b) Because Zs and Zc are predominately inductive, the short-circuit current lags the driv-
ing voltage by an angle approaching the theoretical maximum of 90°.

IEEE
The change in state from load current to short-circuit current occurs rapidly. Fundamental
physics demonstrate that the magnitude of current in an inductor cannot change
instantaneously. This conﬂict can be resolved by considering the short-circuit current to con-
sist of two components:
— A symmetrical ac current with the higher magnitude of the short-circuit current
— An offsetting dc transient with an initial magnitude that is equal to the initial value of
the ac current, but which decays rapidly
The initial magnitude of the dc transient is directly controlled by the point on the voltage
wave at which the short circuit occurs. If the short circuit occurs at the natural zero crossing
of the driving voltage sinusoid, the transient is maximized. However, the transient is a
minimum if the fault occurs at the crest of the voltage sinusoid. At any subsequent time, the
magnitude of the dc transient is determined by the time constant of the decay of the dc, which
is controlled by the ratio of reactance to resistance in the impedance limiting the fault.
Equation (2-2) can be used to calculate the instantaneous magnitude of current at any time.
For the protection engineer, the worst case initial current includes the full dc transient.
Figure 2-1—Equivalent circuit used to calculate load current
in a normal circuit
Figure 2-2—Equivalent circuit used to calculate short-circuit current

IEEE
(2-2)
The driving voltage depicted in Figure 2-1 and Figure 2-2 is the Thevenin equivalent open-
circuit voltage at the fault point prior to application of the short circuit. This voltage includes
sources such as remote generators with voltage regulators that maintain their value regardless
of the presence of a short circuit on the system as well as nearby sources whose voltages
decay when the short circuit is present. The amount of decay is determined by the nature of
the source. Nearby generators and synchronous motors with active excitation systems sustain
some voltage, but because the short circuit causes their terminal voltage to drop, the current
they produce is gradually reduced as the fault is allowed to persist. At the same time,
induction motors initially participate as short-circuit current sources, but their voltages decay
rapidly as the trapped flux is rapidly drained. Figure 2-3 shows the generic tendencies of
various kinds of short-circuit current sources and a composite waveform for the symmetrical
ac current decay. Figure 2-4 depicts the most realistic case of the decaying symmetrical ac
current combined with the decaying dc transient. From this figure, a generalized short-circuit
current may be described in the following terms:
— High initial magnitude dc transient component of current, which decays with time
— High initial magnitude symmetrical ac current, which diminishes gradually with time
— Symmetrical ac current lags driving voltage by a significant angle, approaching 90°
2.4 Protective device currents
It is the general practice to recognize three magnitudes of short-circuit current in applying
protective devices. These magnitudes are fundamentally time-dependent and can be thought
of as three points on the generic curve in Figure 2-4.
The first point is the initial magnitude and is considered by protection engineers to be the
magnitude of current to which fast-acting protective devices respond. Instantaneous relays,
fuses, and low-voltage circuit breaker trip devices are characterized as fast acting. In some
instances this initial point includes the dc transient; in other instances, it does not. Whether
the dc transient is recognized is determined by whether the protective device in question
responds to dc quantities. For example, instantaneous relays operating on the induction
principle, and static devices with dc filtering, respond only to the symmetrical ac component
of this initial current, while fuses and plunger and hinged-armature relays sense the total
magnitude of current. How the dc transient is treated is also subject to some interpretation.
One traditional, conservative approach is to treat the initial current as though the magnitude
i t
( )
v
Zs Zc
+
----------------
-
 
  wt ϕ θ
–
+
( )
sin ϕ θ
–
( )e
R
L
--
-
 
  t
–
sin
–
=

IEEE
Figure 2-3—Generic components of fault current categorized according to
decrement

IEEE
exists 0.5 cycle into the fault and, for typical systems where the X/R ratio is 25 or less, the
root-mean-square (rms) total current does not exceed 1.6 times the symmetrical rms current.
Some protection engineers choose instead to calculate an approximate asymmetry factor
using the formula
(2-3)
The second point is traditionally considered to be the magnitude of current at the time when
time-delay overcurrent protective devices (e.g., overcurrent relays, delayed-action low-
voltage trip devices) make their ﬁnal measurement and operate. General practice assumes
that the dc transient will have disappeared entirely by this time and to recognize only the rms
symmetrical current.
The third current magnitude commonly calculated by protection engineers is the long-time
current. Some protection engineers use the term “thirty (30) cycle current” because it is an
estimate of the current that exists long after inception of the fault. This magnitude is used to
evaluate performance of extremely long-time devices, such as generator backup overcurrent
relays or second- or third-zone distance relays.
Determining the rates of decay of current to calculate these three time-based currents in exact
form is difﬁcult. The procedure that protection engineers have evolved is to represent the
system using different impedances that result in short-circuit current magnitudes that are
approximately close to the theoretically correct values. Table 2-1 summarizes common
practices in this regard.
Figure 2-4—Typical fault current sinusoid with both ac and dc decrement
Asymmetry factor 1 2e
2π
–
X R
⁄
-----------
+
=

IEEE
For conservatism, the usual practice is to employ saturated or rated-voltage reactances for
rotating machines. These reactances are denoted by v on machine data sheets, e.g., X≤dv .
Direct axis quantities are indicated by d, while " and ' indicate subtransient and transient val-
ues, respectively. Full data sheets are not always available for induction machines, and in this
instance using locked-rotor reactance Xlr is common practice.
While including both the resistive and reactive components of impedance is classically cor-
rect, protection engineers sometimes employ the shortcut of ignoring resistance because the
X/R ratio of impedances is typically quite high. This shortcut is especially common in higher
voltage applications and when hand calculations are employed to arrive at answers quickly.
Analysts are cautioned that in lower voltage systems, however, X/R ratios are low and to
ignore resistance may lead to calculation of unacceptably high current magnitudes.
Earlier, the distinction was made between short-circuit currents calculated to evaluate the
application of interrupting devices against their ratings and calculations needed to assess pro-
tective device performance. Many engineers bring these calculations together, using so-called
momentary application calculations instead of performing a separate instantaneous calcula-
tion. Likewise, 5-cycle-to-8-cycle interrupting duty calculations are frequently used instead
of doing a separate calculation of time-delay currents.
NOTE—Some of the impedances given in Table 2-1 differ slightly from prevailing practices employed
in calculating short-circuit currents for interrupting device evaluations. Such discrepancies suggest that
the calculations are not exact and room for judgment exists.
In addition to time considerations, short circuits vary by topography. In some instances, all
three phases of the power system are involved in the short circuit while, under other
conditions, the fault may consist of only one phase shorting to ground. It is possible for
phase-to-phase faults to occur; and, in yet other instances, the phase-to-phase fault may also
involve a current flow to ground. Any of these four geometric variants may or may not be
bolted faults, that is, short circuits in which the conductors are shorted together with
essentially no external impedance. In the real world, most faults involve some external
impedance (and in fact arcing introduces external resistance), but protection engineers
usually consider bolted faults as the worst case for determining fault current magnitude.
Table 2-1—Short-circuit impedances for protective device application and
evaluation
Impedance
Instantaneous
currents
Time-delay
currents
Long-time
currents
Remote system equivalent R + jX R + jX R + jX
Local synchronous generators R + jX"d R + jX'd R + jX
Synchronous motors R + jX"d R + jX'd infinite
Induction motors R + jXlr infinite infinite
Passive components R + jX R + jX R + jX

IEEE
At times, determining the minimum currents available to system protective devices is neces-
sary. No generally accepted procedure exists for determining minimum currents. One
approach is to perform a system calculation considering only the electric utility source and
any synchronous generators, with the latter represented by their synchronous reactance’s
(Xd), with allowance for presumed fault-point arcing represented by fault resistance.
In addition to short circuits, protection engineers may be called upon to evaluate performance
of protective devices under other abnormal system conditions, such as open conductors.
2.5 Per-unit calculations
Power system calculations can be done using actual voltages and currents or using per-unit
representations of actual quantities. While performing a calculation in actual quantities
makes sense occasionally, the vast majority of calculations are done in per-unit. The discus-
sion in this chapter assumes a familiarity with the per-unit method; but, to avoid confusion,
definitions of important parameters are given in Table 2-2. The table presents strict (textbook)
definitions and defines all per-unit values on a single-phase basis. Equivalent three-phase val-
ues are usually used in practice, but an understanding of the mathematics presented in
Table 2-2 relies on a careful interpretation of base values as single-phase quantities.
2.6 Short-circuit current calculation methods
2.6.1 Symmetrical components method of analysis
A variety of methods are commonly used for calculating short-circuit current magnitudes. All
of these methods are ultimately traceable to the method of symmetrical components, and an
Table 2-2—Per unit base parameters
Parameter
Strict definition
(single-phase basis)
Common usage
(three-phase basis)
Frequency Steady state operating frequency Nominal system frequency
Voltage System line-to-neutral voltage at a
chosen reference bus; voltage at
other buses related by turns ratios
of transformers
Nominal line-to-line voltage
MVA Any defined arbitrary reference,
per phase
10 or 100 MVA, 3φ
Base current Base voltamperes divided by base
voltage
Base 3φ kVA/(Line-to-line kV × )
Base impedance Base line to neutral voltage divided
by base current
(Line-to-line kV)2/Base 3φ MVA
3

IEEE
understanding of symmetrical components permits a quick adoption of any of the short-hand
procedures. The symmetrical components method of analysis is also completely general, can
treat any form of fault or phase unbalance (with or without external impedances), and has
become the one universal language among protection engineers. In the interest of exactness,
only symmetrical components are treated in this chapter. The bibliography in 2.12 references
papers and texts that discuss derivative approaches.
Almost all protective device short-circuit currents today are calculated by computer. It is well
beyond the scope of this recommended practice to address the methods by which computers
model electrical systems. Furthermore, each computer software program has unique features
for which an adequate program users manual is the best reference text. A thorough under-
standing of symmetrical components should lead to comprehension of the intention of the
computer software writer and maximize the functionality of most commercial programs.
2.6.2 Mathematical notation
Two mathematical symbols are used in this chapter. Most engineers recognize j as the square
root of –1, but it also is used in power engineering as a mathematical operator that forces an
angular shift of 90° upon whatever quantity to which it is applied. In treating three-phase
power systems, also having an operator that introduces a 120° angular shift is convenient.
This operator is conventionally known as a.
With either operator, the convention considers the positive direction of phase rotation to be
counterclockwise. This convention is depicted in Figure 2-5.
2.7 Symmetrical components
The method of symmetrical components was ﬁrst described in an AIEE paper by Fortescue
[B5]1. This paper proposed a general theory for analysis of multi-phase systems. Fortescue’s
1The numbers in brackets correspond to the numbers of the bibliography in 2.12.
Figure 2-5—Phase designation and rotation conventions
Direction of rotation

IEEE
original thesis applied to a general n phase system, and its application on the more common
three-phase systems is a simplification.
Phasors are complex time-dependent quantities used in analyzing linear systems that are
described by both magnitude and angle. The voltage and current phasors on a three-phase
power system can be represented by three sets of balanced three-phase symmetrical compo-
nent phasors (voltage and current) when the symmetrical component phasors are defined
according to a set of rules. Positive-sequence phasors (denoted by 1) are equal to each other in
magnitude, are 120° apart, and have the same phase rotation sequence as the power system
being represented. The negative-sequence phasors (indicated by 2) are equal to each other in
magnitude and are 120° apart, but the phase rotation sequence is opposite to that of the power
system under analysis. Zero-sequence phasors (which traditionally carry 0) are equal to each
other in magnitude and are 360° apart; phase sequence rotation is the same as the power
system.
For the three-phase application, phase-to-neutral voltages are defined in terms of the symmet-
rical components of voltage:
(2-4)
and conversely, the symmetrical components of voltage can be derived from the phase-to-
neutral voltages,
(2-5)
Similar equations can be written relating phase currents and the symmetrical components of
current. The subscript convention used in Equation (2-4) and Equation (2-5) is that 1, 2, and 0
indicate positive, negative, and zero sequence, respectively, whereas ag, bg, and cg denote
phase-to-ground.
Relating the sequence component current and voltage phasors are sequence component
impedances. These impedances are not physical impedances, but as shown in 2.7.1, deriving
values for them from known physical parameters of equipment is possible. Thus, for each of
the three symmetrical components, drawing a system equivalent circuit is possible. By appro-
priately interconnecting these sequence impedance networks, making relatively simple
network calculations, and then applying the fundamental relationships [Equation (2-4)],
Vag Va1 Va2 Va0
+ +
=
Vbg a
2
Va1 aVa2 Va0
+ +
=
Vcg aVa1 a
2
Va2 Va0
+ +
=
Va1
1
3
--
- Vag aVbg a
2
Vcg
+ +
( )
=
Va2
1
3
--
- Vag a
2
Vbg aVcg
+ +
( )
=
Va0
1
3
--
- Vag Vbg Vcg
+ +
( )
=

IEEE
answers can be calculated for almost all unbalanced conditions on the original three-phase
system.
When the base quantities are properly chosen, symmetrical components can be applied to a
system of any frequency. However, using this analytical procedure in a single system to deal
with multiple frequencies, as in harmonic or transient studies, is not strictly correct.
2.7.1 Sequence impedance representation of electrical apparatus
In order to use symmetrical components as a tool in analyzing systems and the performance
of protective devices, constructing system models using symmetrical component representa-
tions is necessary. This step entails two considerations: It is necessary to determine, first, how
each component of the actual power system should be represented in symmetrical component
terms and, second, how these components are related together. Representation of system
components is conceptually simple although some portions of the system may require time-
consuming calculations.
The representation of electrical apparatus in symmetrical component terms involves determi-
nation of appropriate positive-, negative-, and zero-sequence impedances.
2.7.1.1 Generators
Positive-, negative-, and zero-sequence impedances are usually provided as identified values
on the generator manufacturer’s data sheet for the machine. If negative and zero are not
readily available, a couple of guidelines may be used to approximate values.
The negative-sequence reactance of a synchronous generator is defined in Park’s equations as
the mean of the direct and quadrature axis subtransient reactances. For smooth rotor
machines (i.e., 3600 r/min machines on 60 Hz systems), the direct and quadrature reactances
are nearly equal; and in the absence of better data, the negative-sequence reactance may be
assumed to be equal to the subtransient reactance.
Zero-sequence reactance is also defined in Park’s equations, but the definition is more com-
plex. For most machines, its value is on the order of one half of the subtransient reactance.
When looking into the terminals of a generator (in the figurative sense), the actual zero-
sequence impedance is a combination of the zero-sequence impedance of the generator plus
the zero-sequence representation of the generator’s neutral grounding device. Neutral
grounding devices are treated separately.
Positive-sequence reactance is also usually available from the generator manufacturer’s data
sheet, but normally several values exist from which to choose. As noted in Table 2-1, the
value to be used in a calculation of short-circuit currents depends upon the intended use of the
result of that calculation.
The definitions given in Equation (2-5) for positive-, negative-, and zero-sequence voltage
and current phasor sets also suggest another important consideration in the representation of
synchronous machines in symmetrical component terminology. Positive-sequence voltages

IEEE
correspond to actual system voltages and currents, whereas negative- and zero-sequence volt-
ages are physically fictitious. Generators are a source of voltage on the power system, and the
only sequence to include a voltage source is the positive sequence.
Induction generators are finding their way more commonly into both industrial and utility
applications. Induction generators should be treated as induction motors for fault
calculations.
2.7.1.2 Motors
Motors can be thought of as closely related to generators, and the impedances used to
represent them in symmetrical components are derived similarly to those of generators. For
synchronous motors, negative-sequence impedances values are readily available from
manufacturer’s data sheets; or if no better data are known, the value of the subtransient
reactance may be used. For induction motors, however, negative-sequence values are harder
to obtain. A common assumption, which is usually satisfactory, is that the negative-sequence
reactance is equal to the locked-rotor reactance for induction motors.
As for generators, the zero-sequence impedance seen looking into the terminals of a motor is
a combination of the zero-sequence impedance of the machine and the zero-sequence imped-
ance of the neutral grounding devices. Consequently, because the neutral of motors is almost
inevitably ungrounded, an infinite zero-sequence impedance for motors would be seen.
Table 2-1 also lists positive-sequence impedance values for motors. As for generators, the
magnitude of impedance may vary depending on the use intended for the calculated values.
2.7.1.3 Transmission lines
Determining impedances for transmission lines is more challenging and generally involves
making calculations from the physical parameters of the line and its conductors. The
algorithm and equations given in this subclause describe the procedure, and experienced
protection engineers find understanding the theoretical basis for this procedure helpful. All
the equations given in this subclause are for 60 Hz systems; impedances for systems at other
frequencies can be determined by ratio or by modifying the formulae. Alternatively, computer
programs are available to calculate line impedances.
The first consideration is that the positive- and negative-sequence impedances of transmission
lines are equal. A transmission line is a passive component that responds in the same way to
positive- and negative-sequence excitation. Because sequence impedances are the
relationships between respective sequence voltages and currents, calculation of one
impedance suffices for both needs.
The positive-sequence reactance of a transmission line can be thought of as the impedance
that would relate voltage and current when the three conductors or a transmission line are
shorted together at one end, while excited by a positive-sequence source of voltages at the
other end. This impedance can be calculated using the following equation:

IEEE
(2-6)
where
GMD is the geometric mean spacing between phase conductors (e.g., the cube root of the
product of the three-phase spacings) (m),
GMR is the geometric mean radius of the phase conductor (m).
GMD should be calculated for the specific spacings of the array of conductors making up the
transmission line, while GMR is a parameter for the conductor that is available from the con-
ductor manufacturer.
Positive-sequence resistance can be read directly from conductor tables.
Calculating the zero-sequence impedance of a transmission line is more challenging. The
concept can be viewed as follows: All three phases of a transmission line are shorted together
to ground at the source end, while all three conductors are shorted together and to both
ground and the overhead ground wire (OHGW) at the other end. When a single phase source
of voltage is then applied at the source end, a current flows. The ratio of the single-phase driv-
ing voltage to the resulting current flow is the zero-sequence impedance of the line.
Physically, current flows from the faulted conductor into both ground and the OHGW as
depicted in Figure 2-6a; the current flows from the source out through the phase conductors
and returns through a complex path consisting of the OHGW and the earth. From this physi-
cal picture, it is apparent that the zero-sequence impedance should, therefore, consist of three
branches as indicated in Figure 2-6b: the zero-sequence impedance of the phase conductors,
the zero-sequence impedance of the static wire return (OHGW), and the zero-sequence
impedance of the earth return.
Values can be calculated for the various branches of Figure 2-6b using the following
equations:
(2-7)
(2-8)
(2-9)
(2-10)
(2-11)
X1 j0.1737 log10
GMD
GMR
-------------
- Ω km
⁄
=
Ra0
1
3
--
- Ra
( )Ω km
⁄
=
Xa0 j0.1737 log10
GMD2
GMR
----------------
- Ω km
⁄
=
Rm 0.05928 Ω km
⁄
=
Xm j0.1737 log10
De
GMD2
----------------
- Ω km
⁄
=
De 658.4
r
f
------
- m
=

IEEE
(2-12)
(2-13)
where
Ra is the resistance of the phase conductor (Ω/km),
GMD2 is the geometric mean spacing of all conductors—phase and static (OHGW) wires
(m),
GMR2 is the geometric mean radius of k static (OHGW) wires (m),
Figure 2-6a—Illustration of insulation ﬂashover on open wire line showing
return current ﬂowing through OHGW of transmission line and through earth
Rg
Rgw
k
--------
-Ω km
⁄
=
Xg j0.1737 log10
GMD2
GMR2
----------------
- Ω km
⁄
=

IEEE
k is the number of static (OHGW) wires,
r is the earth resistivity (typically 100) (Ω⋅m),
Rgw is the resistance of one ground wire (Ω/km),
f is the system frequency.
2.7.1.4 Cables, busway, and bus duct
Most analysts are satisfied to rely on the impedance data on cables, busway and bus duct that
are provided by manufacturers. Two situations exist, however, where this reliance may not
be adequate. For systems consisting of an array of single conductor cables, Equation (2-6) or
Equation (2-7) should be used, with the spacing between individual conductors accounted for
as the GMD. If multiple conductors exist per phase, care should be taken to evaluate the
impact of the arrangement of conductors and to consider that the GMR of each phase is a
composite of the true conductor GMR and the spacing of the conductors making up the phase.
Zero-sequence reactances for cables, bus, and busway are difficult to determine because they
depend on the return path impedance as shown in Figure 2-6a and Figure 2-6b. Obviously, no
OHGW return exists, but consideration should be given to the cable sheath, shield wire,
conduit, cable tray, earth path, and other conducting paths involving building steel and fluid
piping in the vicinity. An exact calculation is generally not possible. When low-resistance
grounding is used in medium-voltage systems, determining the exact zero-sequence
impedance of a cable or bus system is seldom necessary because it is negligible when
compared to the grounding resistor.
2.7.1.5 Transformers
As a passive device, the positive- and negative-sequence impedance magnitudes for
transformers are identical and are equal to the nameplate leakage reactance provided by the
manufacturer. However, in modeling transformers in symmetrical components, recognizing
Figure 2-6b—Zero-sequence equivalent circuit that accounts for
self impedance of transmission line and the impedances of
earth and OHGW return paths

IEEE
that an inherent phase shift is associated with delta-connected windings is sometimes
necessary. Wye-delta and delta-wye transformers built under ANSI standards are designed so
that high-voltage quantities always lead the corresponding low-voltage quantities by 30°. The
complete positive-sequence model for a delta-wye or wye-delta transformer, therefore,
should include a 30° phase shift. Negative-sequence quantities, however, are shifted in the
opposite direction, and so the negative-sequence representation should include a phase shift
opposite to the shift considered in positive sequence. These relationships are illustrated in
Figure 2-7a. Inclusion of these phase shifts is important only if a rigorous calculation is
needed to determine exact phase currents and voltages on both sides of the transformer,
including phase angles. Analysts often take the shortcut of neglecting phase shifts if the
calculations are restricted to determining information on only one side of the transformer. No
inherent phase shift occurs in wye-wye transformers; therefore, the positive- and negative-
sequence equivalent circuits for these transformers also do not require phase shifts.
The zero-sequence impedance of a transformer is controlled by a number of factors. The best
way to determine a magnitude of this impedance is by an actual test, but the following
comments, supplemented by information in some of the references, may be used to predict a
value that is close enough for many applications. First, the zero-sequence impedance seen
looking into a transformer depends upon the configuration of the winding. The zero-sequence
impedance of a delta winding is infinite (an open circuit), whereas the zero-sequence
impedance of a wye-connected winding is a series composite of the zero-sequence impedance
of the transformer and the impedance of any neutral grounding devices that might be present.
Thus, an ungrounded wye winding would present an infinite zero-sequence impedance
because the absence of a neutral grounding connection appears as an open circuit in series
with the zero-sequence impedance of the transformer winding itself (see Figure 2-7b). The
impedance of the transformer itself depends upon several factors in the construction of the
transformer. Three-phase transformers, which are constructed so that a closed, low-impedance
NOTES
1—The phase shift in positive sequence is in the same direction as in the physical trans-
former: high voltage leads low voltage by 30° for ANSI standard transformers.
2—The phase shift in the negative-sequence circuit is opposite in direction.
Figure 2-7a—Positive- and negative-sequence equivalent circuits for
delta-wye or wye-delta transformer

IEEE
path exists for the flow of zero-sequence flux within the transformer, have a lower zero-
sequence impedance than transformers without such a path. One such path is the transformer
core. Transformers with core-form construction have lower zero-sequence impedances than
units with shell-form cores. Three-phase transformers with delta windings have the lowest
zero-sequence impedance, and in the absence of actual test data, it is often assumed that the
zero-sequence impedance of core-form transformers with delta windings is about 0.85 times
the positive-sequence leakage reactance of such transformers. The zero-sequence impedance
of shell-form transformers has about the same magnitude as the positive-sequence leakage
reactance of such transformers. Conversely, a three-phase transformer bank consisting of
three, single-phase transformers connected wye-wye has a very high zero-sequence
impedance.
2.7.1.6 Neutral grounding devices
Neutral grounding devices such as resistors and reactors appear only in zero sequence.
Figure 2-8 shows that if zero-sequence current I0 is flowing in each phase conductor, then the
current in the neutral device is 3I0. Representing the neutral device in zero sequence with a
resistance or reactance equal to three times the actual device impedance accounts for the cor-
rect sequence voltage from neutral to ground.
2.8 Network interconnections
The most critical aspect of using symmetrical components is in interconnecting the system
sequence impedance networks. The form that this interconnection should take is determined
by the type of fault to be calculated. Many possible interconnections exist, and several of the
references in 2.11 include extended discussions of how these interconnections are derived as
well as tables of many of the possible combinations. For this recommended practice,
however, presenting only the four interconnections representing the fault interconnections
most commonly of interest is sufficient.
NOTE—The circuit is open on the side corresponding to the delta winding on
the physical transformer.
Figure 2-7b—Zero-sequence equivalent circuit for
delta-wye-grounded transformer

IEEE
Each of these interconnections relate how the positive-, negative-, and zero-sequence net-
works should be connected together to represent the desired system condition. The sequence
impedance networks themselves are the one-line diagrams of the system showing the imped-
ances of the respective sequence. An important concept is that positive sequence is deﬁned as
the balanced phasors rotating in the direction of rotation of the actual phase quantities on the
power system; in the vast majority of cases, only the positive-sequence network includes
voltage sources.
2.8.1 Balanced three-phase conditions
Balanced three-phase condition is by far the most common sequence interconnection because
not only can it be used to analyze three-phase short circuits, it also is the correct representa-
tion for balanced three-phase load conditions.
Figure 2-9 is the interconnection for balanced three-phase conditions. Because the system
condition of interest is balanced, nothing of interest takes place in the negative- and zero-
sequence networks of the system and they may be ignored.
The impedance indicated Zf is the fault impedance. In a true bolted fault situation, this imped-
ance is negligibly small. In other cases, this impedance may be the impedance of a load, and
the calculation would represent balanced three-phase load conditions.
NOTE—Because zero sequence, by definition, is equal in magnitude and displaced 360° in the
three phases, the current that shall flow in a neutral grounding circuit is 3I0. Therefore, to assure
that the zero-sequence voltage drop in the equivalent circuit is correct, the physical impedance
of the neutral circuit shall be multiplied by 3 in the zero-sequence equivalent circuit:
Vdrop = 3I0 × Zn = I0 × 3Zn
Figure 2-8—Zero sequence representation of neutral grounding devices

IEEE
2.8.2 Phase-to-phase short circuits
Faults involving abnormal conduction from one phase to another without involving ground
may be represented using the interconnection of Figure 2-10. The zero-sequence network is
not involved and may be ignored.
As for the three-phase condition, Zf would normally be the fault impedance, but it could also
be a phase-to-phase load impedance if the problem of interest is the response of the system to
a phase-to-phase-connected single-phase load.
Figure 2-9—Sequence interconnections for a balanced three-phase fault,
which involve only positive-sequence quantities
Figure 2-10—Sequence interconnections for a phase-to-phase fault
not involving ground

IEEE
An interesting and often useful relationship develops from Figure 2-10. In the special case of
a zero-impedance phase-to-phase fault, if the negative-sequence impedance of nearby syn-
chronous machines is approximately equal to the positive-sequence impedances of such
machines or if no synchronous generators are nearby at all, then the phase-to-phase fault cur-
rent will be , or 0.87 times the corresponding three-phase fault current. This relation-
ship can be proven by calculating sequence currents in Figure 2-10 for the speciﬁed condition
and then converting them to phase currents using Equation (2-4).
2.8.3 Phase-to-ground short circuits
The phase-to-ground short circuit is perhaps the most used interconnection because the line-
to-ground fault is statistically the most common fault geometry. Figure 2-11 shows that to
represent a single line-to-ground condition, the three sequence networks are connected in
series at the point of the fault.
Several important observations exist about the use of this interconnection. First, because the
zero-sequence network contains an open-circuit anywhere the actual system has a delta-
connected or ungrounded-wye transformer winding, examining the zero-sequence network is
necessary only for the portion of the system associated with the fault and bounded by delta-
connected or ungrounded-wye transformer windings. Second, because the positive- and
negative-sequence impedances are equal for almost every device, the negative-sequence net-
work is often not represented in detail. Instead, once a value for the positive-sequence imped-
ance at the point of fault is determined, this value is substituted for the negative sequence
also. From this substitution, the current in the interconnected circuit becomes
3 2
⁄
NOTE—To account for neutral grounding equipment, 3Zn has been included. In a solidly grounded
system, Zn = 0.
Figure 2-11—Sequence interconnections for a single phase-to-ground fault

IEEE
(2-14)
(2-15)
A second consideration is that on systems where the neutral is grounded through a resistor
designed to limit the fault current to a low value, the magnitude of the resistance in terms of
zero sequence is so large that all other impedances in the network are insignificant by com-
parison. Thus, in these cases, calculating a formal symmetrical component to determine
ground-fault current magnitudes is usually not necessary.
2.8.4 Open phase
Open phase is not a short-circuit condition, but it does fall under the generic definition of a
fault. Figure 2-12 shows that interconnecting the positive- and negative-sequence networks at
the point of the open phase, with the networks complete on both sides of the discontinuity,
enables simplified calculations of the condition.
I
V
2Z1 Z0 3Zn
+ +
( )
-----------------------------------------
-
=
Igf 3I0
3V ]
2Z1 Z0 3Zn
+ +
( )
-----------------------------------------
-
= =
NOTE—The sequence networks on the right and left are the respective Thevenin equivalents
looking in those directions.
Figure 2-12—Sequence interconnection used to model
a single open-phase condition

IEEE
2.9 Calculation examples
IEEE Std 399-19972
introduced a composite one-line diagram for a typical power system to
illustrate a variety of analytical principles on a single system (see Figure 2-13 in this recom-
mended practice).
The process of calculating protective device fault levels requires a series of steps. Today, most
analysts choose to perform these calculations using computers, and the procedure outlined in
Item a) through Item h) assumes that computers are used. However, the basic principles apply
to manual calculations although the analyst in that instance should be more careful to decide
up front precisely what information is needed in order to minimize the amount of tedious
work to be done.
a) State the problem to be solved. The nature of the problem determines the type of cal-
culation to be done and, in turn, dictates what speciﬁc data are required. In the
present context, the calculation is of fault currents for protective devices. However,
unlike fault calculations for breaker applications, protective device calculations gen-
erally are not done for every bus. For illustration, the following examples should be
calculated:
1) Example A: Maximum three-phase instantaneous relay current in the 2 Mvar
13.8 kV power factor capacitor feeder on Bus 4.
2) Example B: Phase-to-ground-fault current at the receiving end of one of the
69 kV incoming circuits from the utility (i.e., a fault on the primary bushings of
Transformer T-1).
3) Example C: Phase-to-ground-fault current at the secondary terminals of
1.5 MVA Unit Substation T-5.
b) Collect data. This step entails understanding the interconnection of the various
components that make up the system, as well as collecting data on each of the
components. For example, Figure 2-13 includes information on transformer
connection that is essential in determining ground fault levels. A one-line diagram is
usually an essential tool in correlating system data, and some analysts choose to use
the one-line diagram as the principal tool for recording all the data.
c) Put aside information that does not apply to the immediate problem. Generally,
power factor capacitors, surge arresters, and surge capacitors do not contribute to the
distribution of fault current as recognized by protection engineers, so these compo-
nents may be ignored.
More generally, however, some information may affect the magnitude of protective
device currents, but not necessarily the currents of interest in the immediate problem;
and in the interest of saving time, ignoring these data may be possible. A good exam-
ple of this type of data is zero-sequence data. Delta-connected transformers establish
boundaries for zero-sequence calculations; and, if the problem statement calls for
ground-fault data in only one area of the system, entanglement with zero-sequence
data in other areas may be avoided. In the illustration, ground-fault data are required
at the 69 kV bus at the secondary of Substation T-5; therefore, the analyst may, if
desired, choose to ignore zero-sequence data elsewhere in the system.

IEEE
Figure
2-13—Composite
one-line
diagram
for
a
typical
power
system

IEEE
d) Decide on a common base for the per-unit calculations. Base quantities selected for
this sample system are as follows:
e) Convert component impedances to per-unit values on the appropriate base quanti-
ties. These per-unit values should be arranged in the fashion required by the computer
software. For a manual calculation, they should be recorded on a one-line diagram.
Computer software usually accepts nominal nameplate parameters and performs this
tedious and exacting task.
f) Perform the network reduction calculations necessary to arrive at driving-point
positive- and zero-sequence impedance values at each point of interest defined by the
original statement of the problem. Using these driving-point impedances, the
sequence impedance network interconnections discussed in 2.8 should be set up to
calculate per-unit magnitudes of sequence currents. Finally, these per-unit values
should be converted into ampere values. Again, this tedious, time-consuming calcula-
tion is most often done with the computer today.
g) Set up the sequence impedance connections needed for the desired currents. Again,
many computer programs can do this step automatically, but it is instructive to take
raw driving-point impedances and perform this step by hand. For illustration, the
phase-to-ground-fault current at the secondary of Transformer T-5 [see Example C in
2.9 a) Item 3)] is calculated manually in 2.9.1 and 2.9.2.
h) Record the calculated currents. This step is often overlooked although it is extremely
important.
2.9.1 Computer model of the example system
For the sample one-line diagram in Figure 2-13, the system data were modeled using a com-
puter program to calculate relay currents. The program used to develop these illustrations
offers graphical output, showing relay currents and necessary system information directly on
segments of the one-line diagram. The practice of displaying current magnitudes, and direc-
tion of flow, on the one-line diagram is especially useful to the protection engineer and was
commonly done even when the primary tools for performing calculations were the pencil and
a slide rule.
Rather than provide sample hand calculations, which are difficult to follow, subclause 2.9.2
indicates only the input data for the system of Figure 2-13. The system can then be modeled
using a computer, and the sample problems can be calculated. Data for the sample
system are presented in Table 2-3a through Table 2-3h.
MVA base: 100 MVA three phase
KV Base: 69 kV line to line at 69 kV buses
13.8 kV line to line at 13.8 kV buses
0.480 kV line to line at 480 V buses
Frequency base: 60 Hz

IEEE
Table 2-3a—Sample system input: utility data
Ident Bus kV 3f MVA X/R f -G MVA X/R
UTIL-1 100:UTIL-6 69.000 1000.00 22.20 765.00 9.70
Table 2-3b—Sample system input: generator data
Ident Bus MVA kV RPM pf %X" f-G %X X/R
GEN-1 50: GEN-1 15.625 13.800 3600 0.80 11.2 5.70 35.7
GEN-2 04: MILL-2 12.5 13.800 3600 0.80 12.8 5.80 37.4
Table 2-3c—Sample system input: motor data
Ident Bus hp kVA Type RPM pF kV %X X/R EZ-Code
M-30 51: AUX 200 200 IND 1800 0.48 16.7 7.0 >50
M-31 51: AUX 600 600 IND 1800 0.48 16.7 12.0 <50
M-FDR-L 08: FDR L 9000 9000 SYN 1800 0.80 13.80 20.0 34.0 Synch
M-T10-1 28: T10 SEC 400 400 IND 1800 0.48 16.7 10.0 >50
M-T10-2 28: T10 SEC 500 500 IND 1800 0.48 16.7 5.0 >50
M-T1--3 33: T10MCC 300 300 IND 1800 0.48 16.7 12.0 <50
M-T11-1 29: T11 SEC 625 625 IND 1800 0.48 16.7 10.0 >50
M-T11-2 29: T11 SEC 465 465 IND 1800 0.48 16.7 5.0 <50
M-T11-3 34: T11MCC 110 110 IND 1800 0.48 16.7 7.0 <50
M-T12-1 30: T12 SEC 400 400 IND 1800 0.48 16.7 12.0 >50
M-T12-2 30: T12 SEC 500 500 IND 1800 0.48 16.7 5.0 <50
M-T12-3 35: T12MCC 300 300 IND 1800 0.48 16.7 12.0 <50
M-T13-1 36: T13 SEC 2500 2500 IND 1800 2.30 16.7 32.85 >50
M-T14-1 37: T14 SEC 700 700 IND 1800 0.48 16.7 12.0 >50
M-T14-2 37: T14 SEC 300 300 IND 1800 0.48 16.7 5.0 <50
M-T17-1 49: RECT 1200 1200 IND 1800 0.46 29.9 8.0 <50
M-T3-1 39: T3 SEC 1750 1662.5 IND 1800 4.16 16.7 29.74 Ind > 1000
M-T4-1 11: T4 SEC 500 475 IND 1800 2.4 16.7 12.0 >50

IEEE
Ident Bus hp kVA Type R/min pF kV %X X/R EZ-Code
M-T5-1 17: T5 SEC 850 824.2 IND 1800 0.48 16.7 10.0 <50
M-T5-2 17: T5 SEC 500 500 IND 1800 0.48 16.7 5.0 >50
M-T5-3 22: T5MCC 150 142.5 IND 1800 0.48 16.7 14.0 <50
M-T6-1 18: T6 SEC 850 824.2 IND 1800 0.48 16.7 10.0 <50
M-T6-2 18: T6 SEC 500 500 IND 1800 0.48 16.7 5.0 >50
M-T6-3 23: T6MCC 150 142.5 IND 1800 0.48 16.7 14.0 <50
M-T7-1 19: T7 SEC 1250 1125 IND 1800 2.4 16.7 26.10 Ind > 1000
M-T7-2 19: T7 SEC 2500 2375 IND 1800 2.4 16.7 15.0 Ind > 1000
M-T8-1 20: T8 SEC 1750 1662.5 IND 1800 2.4 16.7 15.0 Ind > 1000
M-T8-2 20: T8 SEC 2000 1800 IND 1800 2.4 28.0 26.0 Ind > 1000
M-T9-1 21: T9 SEC 750 727.3 IND 1800 0.48 16.7 12.0 <50
Table 2-3d—Sample system input: transformer data
Ident kVA %Z1 X/R %Z0 X/R
From
kV
To
kV
Tap From bus To bus
T-1 15000 8.00 17.0 7.20 17.0 69 13.8 69.000 01: 69-1 03: MILL-1
T-10 1500 5.75 6.5 5.75 6.5 13.8 0.48 13.800 25: T10 PRI 28: T10 SEC
T-11 1500 5.75 6.5 5. 50 6.5 13.8 0.48 13.800 26: FDR G 29: T11 SEC
T-12 1500 5.75 6.5 5.50 6.5 13.8 0.48 13.800 27: T12 PRI 30: T12 SEC
T-13 2500 5.75 10.0 50.0 10.0 13.8 2.4 13.800 31: FDR P 36: T13 SEC
T-14 1000 5.75 5.50 50.0 10.0 13.8 0.48 13.800 32: FDR Q 37: T14 SEC
T-17 1250 4.50 6.0 4.50 6.0 13.8 0.48 13.800 05: FDR F 49: RECT
T-18 1500 5.75 5.91 5.75 5.91 13.8 0.48 13.800 50: GEN 1 51: AUX
T-2 15000 8.00 17.0 7.40 17.0 69 13.8 69.000 02: 69-2 04: MILL-2
T-3 1725 6.00 8.0 6.00 8.0 13.8 4.16 13.800 05: FDR F 39: T3 SEC
T-4 1500 5.75 6.5 5.50 6.5 13.8 0.48 13.800 06: FDR H 11: T4 SEC
T-5 1500 6.75 6.5 6.75 6.5 13.8 0.48 13.800 12: T5 PRI 17: T5 SEC
T-6 1500 5.75 6.5 5.75 6.5 13.8 0.48 13.800 13: T6 PRI 18: T6 SEC
Table 2-3c—Sample system input: motor data (Continued)

IEEE
Ident kVA %Z1 X/R %Z0 X/R
From
kV
To
kV
Tap From bus To bus
T-7 3730 5.50 12.0 5.50 12.0 13.8 2.4 13.800 06: FDR H 19: T7 SEC
T-8 3730 5.50 12.0 5.50 12.0 13.8 2.4 13.800 15: FDR I 20: T8 SEC
T-9 750 5.75 5.0 5.50 5.0 13.8 0.48 13.800 16: T9 PRI 21: T9 SEC
Table 2-3e—Sample system input: cable data
Ident Conﬁg Cable/φ Size Mtl Conduit
Length
(m)
kV From bus To bus
C-E1 3/c 1 250 Kcmil Cu PVC 198.12 13.8 03: MILL-1 09: FDR-E
C-E2 3/c 1 250 Kcmil Cu PVC 558.6984 13.8 09: FDR-E 25: T10 PRI
C-F1 3/c 1 250 Kcmil Cu PVC 99.06 13.8 03: MILL 1 05: FDR-F
C-G1 3/c 1 250 Kcmil Cu PVC 207.264 13.8 03: MILL 1 26: FDR-G
C-H1 3/c 1 250 Kcmil Cu PVC 143.5608 13.8 03: MILL 1 06: FDR-H
C-I1 3/c 1 250 Kcmil Cu PVC 298.704 13.8 04: MILL 2 15: FDR-I
C-J2 3/c 1 250 Kcmil Cu PVC 188.6712 13.8 04: MILL 2 27: FDR-J
C-J3 3/c 1 250 Kcmil Cu PVC 361.7976 13.8 16: T9 PRI 04: MILL-2
C-J4 3/c 1 250 Kcmil Cu PVC 60.96 13.8 10: EMERG 13: T6 PRI
C-J5 3/c 1 250 Kcmil Cu PVC 3.048 13.8 10: EMERG 12: T5 PRI
C-J6 3/c 1 250 Kcmil Cu Steel 144.78 13.8 10: EMERG 27: T12 PRI
C-L1 3/c 1 250 Kcmil Cu PVC 155.448 13.8 04: MILL 2 08: FDR-L
C-M1 3/c 1 400 Kcmil Cu PVC 155.448 13.8 04: MILL 2 24: FDR-M
C-M2 3/c 1 250 Kcmil Cu PVC 103.632 13.8 24: FDR-M 31: FDR-P
C-M3 3/c 1 250 Kcmil Cu PVC 147.828 13.8 24: FDR-M 32: FDR-Q
C-T10-1 3/c 1 250 Kcmil Cu PVC 15.24 13.8 28: T10 SEC 38: 480 TIE
C-T10-2 3/c 2 400 Kcmil Cu PVC 6.096 0.48 33: T10 MCC 28: T10 SEC
C-T11-1 3/c 1 250 Kcmil Cu PVC 20.1168 0.48 29: T11 SEC 38: 480 TIE
Table 2-3d—Sample system input: transformer data (Continued)

IEEE
2.9.2 Computer analysis of the example system
A computer analysis of the sample system and areas of interest are presented and discussed
from a protection viewpoint. Equipment duty veriﬁcation and the application of ANSI or IEC
multipliers are not considered.
In a computer analysis of a power system, the mathematical model of the system is developed
from a bus or node structure describing the system. This relationship allows for easy
Ident Conﬁg Cable/φ Size Mtl Conduit
Length
(m)
kV From bus To bus
C-T12-1 3/c 1 250 Kcmil Cu PVC 15.24 0.48 38: 480 TIE 30: T12 SEC
C-T12-2 3/c 1 400 Kcmil Cu PVC 6.096 0.48 35:T12 MCC 30: T12 SEC
C1A 1/c 2 500 Kcmil Cu PVC 609.60 13.8 50: GEN1 03: MILL-1
Table 2-3f—Sample system input: current-limiting reactor data
Ident
Thru
kVA
Amps Ohms Mtl kV %Z X/R From bus To bus
CLR-3 23903 1000 0.800 Cu 13.800 3.35 100 04: MILL-2
Table 2-3g—Sample system input: busway data
Ident Manuf
Length
(m)
Amps kV R/100 X/100 Mtl From bus To bus
BWY-1 SQD-I-Li 15.24 1000 0.48 0.0016 0.0010 Cu 28: T10 SEC 41: LGTS
Table 2-3h—Sample system input: transmission line data
Ident
Cond/
phase
Size
(Kcmil L)
Mtl
GMD
(m)
Length
(km)
kV From bus To bus
L-1 1 266.8 ACSR 2.1336 3.0474 69.000 100: UTIL-69 01: 69-1
L-2 1 266.8 ACSR 2.1336 3.0474 69.000 100: UTIL-69 02: 69-2
Table 2-3e—Sample system input: cable data (Continued)

IEEE
calculation of the fault current at any bus in the system. Unfortunately, bus currents are not
the currents seen by protective devices; instead, these devices measure the current that flows
in the circuit into which they are connected. The appropriate current for evaluating these
devices is called, in the terminology of computer analysis, a branch current.
Protection engineers should be careful to evaluate protective devices using correct branch
currents and not bus currents, which generally are much larger in magnitude. This distinction
is extremely important and cannot be overemphasized.
Similarly, protection engineers are often concerned about the performance of ground relays
or other protective devices that are designed to detect single phase-to-ground-fault condi-
tions. In interpreting the output from a computer program, the analyst should keep in mind
that what the program calculates and what the analyst’s protective relay measures may be two
different things. Many ground relays are wired to receive the residual current from a set of
three-phase current transformers (CTs) and, as such, measure a physical current that can be
described in the language of symmetrical components as three times the zero-sequence
branch current. Often, computer programs produce the zero-sequence current distribution
without the three multiplier.
Example A: Calculate the maximum three-phase current measured by an instantaneous
relay, fuse, or series trip device on the 13.8 kV feeder serving the 2 Mvar power factor
capacitor on Bus 4.
Figure 2-14 depicts a portion of the system one-line diagram and shows a fault in the 13.8 kV,
2 Mvar capacitor feeder on Bus 4. The calculated current magnitudes are
— 19 203 A, rms asymmetrical
— 12 410 A, rms symmetrical
A moderate asymmetrical offset (X/R = 15.65) is present due primarily to the close proximity
of the generator, which contributes 4080 A of symmetrical current. The largest contributor, of
course, is the utility, with other sources making up the difference. Because this figure is only
a portion of the sample one-line diagram (in Figure 2-13), the details of all the source flows
do not appear in the graphical representation. The capacitor itself does not contribute current
to the fault. Present practice ignores any capacitor contribution to system short-circuit cur-
rents on the basis that it occurs so quickly and is out of phase with system currents. In this
instance, also, a protective device in the capacitor feeder would detect currents flowing from
the system to a fault on the feeder, or current flowing from the capacitor to the system, but not
both, again illustrating that the analyst should carefully consider what constitutes the branch
current measured by the protective device of interest.
Figure 2-15 shows this same fault condition, but with the impedances adjusted to calculate
the long-time fault magnitude. The current has decayed to less than 9185 A symmetrical and
the generator contribution is down to 2721 A. Also, the contributions from motors on the sys-
tem have dropped to zero.

IEEE
Example B: Calculate the phase-to-ground fault on the primary of 69 kV
Transformer T-1.
Figure 2-16 shows the phase-to-ground-fault current (3I0) at the receiving end of tie line #1
(at Bus 1). The long-time fault current of 5468 A flows exclusively from the utility source
because both transformers in the plant have delta-connected primary windings.
Example C: Calculate the phase-to-ground fault at the secondary of Transformer T-5.
For illustration, this problem is calculated the old fashioned way, by hand. Figure 2-17
depicts the sequence network interconnections for this problem.
Based on the observation that an open circuit exists in the zero-sequence equivalent circuit,
no current flows for this fault condition; therefore, nothing is to be calculated.
2.10 Specialized faults for protection studies
For detailed protection studies, a simple bus fault, even with a full branch display, is not suffi-
cient to meet the needs of the protection engineer. As noted in Example A, the analyst should
know how much of the branch current the analyst’s protective device actually measures.
Because the mathematical model of a power system is developed in terms of buses, or nodes,
NOTE—A significant dc offset exists. (Asymmetrical current is 19.02 kA. The symmetrical current
is 12.41 kA.)
Figure 2-14—Distribution of instantaneous currents for fault on capacitor
feeder in sample system
X

IEEE
evaluating faults at points other than buses can be difﬁcult. For these reasons, protection engi-
neers have developed additional computer methods that more realistically simulate exact
real-world conditions.
NOTE—The current is purely symmetrical and the contributions from sources other than the
generator and utility have decayed away.
Figure 2-15—Calculated distribution of long-time relay current to fault on
capacitor feeder in sample system
NOTE—This sketch shows the current that would be seen by a typical ground fault relay that mea-
sures 3 ∞ I0.
Figure 2-16—Phase-to-ground fault on high-voltage bushings
of Transformer T-1

IEEE
The line-end fault is deﬁned as the fault at the end of a line with that line end open. Normally
applied to long transmission circuits where the line impedance may cause an appreciable
difference between the near-end and far-end currents, line-end faults may also be used to
examine faults inside transformers or reactors, to study minimum fault conditions with
downed lines or other high-impedance returns, and, in more complex situations, to study
mutual coupling between adjacent lines.
View (a) in Figure 2-18 shows a line fault at the end of a pair of parallel circuits. The magni-
tude of this fault can be determined by calculating a bus fault at the far-end bus and carefully
determining the branch current ﬂows. View (b) in Figure 2-18 shows a line-end fault at the
same location. Obviously, both fault conditions are possible. In fact, a fault might begin as in
View (a) and progress to the distribution of currents shown in View (b) when the circuit
breaker at the far end of the faulted circuit trips.
The line-out fault illustrated in View (c) in Figure 2-18 is similar to the line-end fault except
that the fault of interest is not at the end of the open line. Instead, faults are calculated at one
or more locations for the special case of a circuit of interest being removed for such calcula-
tion. Running a sequence of line-out cases is the same as repeating the system calculation
with various lines removed from service; the difference is that computer programs that are
designed to calculate line-out faults do so automatically based on line-switching logic estab-
lished prior to starting the computer. Line-out calculations are especially important when
studying the performance of protective devices in network applications.
In evaluating the application of interrupting devices, taking a line out of service in either a
line-end or line-out calculation normally reduces the magnitude of calculated bus fault cur-
NOTE—Because this transformer is connected delta-delta, the zero-sequence network is open
circuited.
Figure 2-17—Sequence interconnections for single-line-to-ground fault
at secondary of Transformer T-5

IEEE
rent. However, branch currents can actually increase when line-end or line-out contingencies
are evaluated. This is especially true in determining branch residual (3I0) relay currents.
2.11 References
tion for Industrial Plants (IEEE Red Book).3
IEEE Std 399-1997, IEEE Recommended Practice for Industrial and Commercial Power Sys-
tems Analysis (IEEE Brown Book).
IEEE Std C37.010-1999, IEEE Application Guide for AC High-Voltage Circuit Breakers
Rated on a Symmetrical Current Basis.
IEEE Std C37.5-1979, IEEE Guide for Calculation of Fault Currents for Application of AC
High-Voltage Circuit Breakers Rated on a Total Current Basis.
NOTE—These distinctions become important if sources of fault current exist at both the source end
and the far end of the parallel circuits.
Figure 2-18—Distinctions between normal bus faults, line-end faults, and
line-out fault conditions

IEEE
2.12 Bibliography
The following publications may provide information of interest to readers wishing to pursue
the subject of this chapter in further detail. Many of the more classic books on this list are no
longer in print, but may be found in well-stocked technical libraries.
[B1] Beeman, D. L., ed., Industrial Power System Handbook. NewYork: McGraw-Hill, 1955,
Chapter 2.
[B2] Blackburn, J. L., Symmetrical Components. New York: Marcel Dekker, 1994.
[B3] Clarke, E, Circuit Analysis of AC Power Systems, Vol. 1, “Symmetrical and Related
Components.” New York: Wiley, 1943.
[B4] Electrical Transmission and Distribution Reference Book. East Pittsburgh, PA: Westing-
house Electric Corporation, 1964.
[B5] Fortescue, C. L., “Method of Symmetrical Coordinates Applied to the Solution of
Polyphase Networks,” AIEE Transactions, vol. XXXVII, part II, pp. 1027–1140, July-Dec.
1981.
[B6] Kerchner, R. M., and Corcoran, G. F., Alternative-Current Components, 4th ed. New
York: Wiley, 1960, Chapter 12.
[B7] Ohlson, R. O., “Procedure for Determining Maximum Short-Circuit Values in Electrical
Distribution Systems at Medium-Voltage Levels,” IEEE Transactions on Industry and Gen-
eral Applications, vol. IGA-3, pp. 97-120, Mar./Apr. 1967.
[B8] Prabhakara, F. S., Smith, R. L., Jr., and Stratford, R. P., Industrial and Commercial
Power Systems Handbook. New York: McGraw Hill, 1995.
[B9] Reed, M. B., Alternating Current Circuit Theory, 2nd ed. New York: Harper and Row,
1956.
[B10] Stevenson, W. D., Jr., Elements of Power System Analysis. New York: McGraw Hill,
1982.
[B11] Wagner, C. F., and Evans, R. D., Symmetrical Components. New York: McGraw-Hill,
1933.

Chapter 3
Instrument transformers
3.1 Introduction
This chapter discusses instrument transformers as they relate to protection. Design of these
devices is discussed only to the extent that it relates to the application and use of instrument
transformers in protection applications.
3.2 Current transformers (CTs)
A CT transforms line current into values suitable for standard protective relays and isolates
the relays from line voltages. A CT has two windings, designated as primary and secondary,
which are insulated from each other. The various types of primary windings are covered in
3.2.1. The secondary is wound on an iron core. The primary winding is connected in series
with the circuit carrying the line current to be measured; and the secondary winding is con-
nected to protective devices, instruments, meters, or control devices. The secondary winding
supplies a current in direct proportion and at a ﬁxed relationship to the primary current.
3.2.1 Types of CTs
The four common types of CTs are as follows:
a) A wound CT has a primary winding consisting of one or more turns mechanically
encircling the core or cores. The primary and secondary windings are insulated from
each other and from the core(s) and are assembled as an integral structure (see
Figure 3-1).
Figure 3-1—Wound CT

IEEE
b) A bar CT has a ﬁxed, insulated, straight conductor in the form of a bar, rod, or tube
that is a single primary turn passing through the magnetic circuit and is assembled to
the secondary, core and winding (see Figure 3-2).
c) A window CT has a secondary winding insulated from and permanently assembled
on the core, but has no primary winding as an integral part of the structure. Primary
insulation is provided in the window through which one or more turns of the line con-
ductor can be passed to provide the primary winding (see Figure 3-3).
d) A bushing CT has an annular core and a secondary winding insulated from and per-
manently assembled on the core, but has no primary winding or insulation for a
Figure 3-2—Bar CT
Figure 3-3—Window CT

IEEE
INSTRUMENT TRANSFORMERS Std 242-2001
primary winding. This type of CT is used with a fully insulated conductor as the pri-
mary winding and used typically in equipment where the primary conductor is a
component part of other apparatus, for example, on bushings of a transformer or cir-
cuit breaker.
The secondary windings of bushing CTs are usually fully distributed around the core.
Typically they are multiratio with each winding tap also being fully distributed.
3.2.2 Ratios
IEEE Std C57.13-19931 designates certain ratios as standard. These ratios are shown in
Table 3-1 and Table 3-2. The standard rated secondary current in all instances is 5 A.
Table 3-1—CT ratings, multiratio bushing
Current ratings
(A)
Secondary taps
Current ratings
(A)
Secondary taps
600:5 50:5
100:5
150:5
200:5
250:5
300:5
400:5
450:5
500:5
600:5
X2-X3
X1-X2
X1-X3
X4-X5
X3-X4
X2-X4
X1-X4
X3-X5
X2-X5
X1-X5
3000:5 300:5
500:5
800:5
1000:5
1200:5
1500:5
2000:5
2200:5
2500:5
3000:5
X3-X4
X4-X5
X3-X5
X1-X2
X2-X3
X2-X4
X2-X5
X1-X3
X1-X4
X1-X5
1200:5 100:5
200:5
300:5
400:5
500:5
600:5
800:5
900:5
1000:5
1200:5
X2-X3
X1-X2
X1-X3
X4-X5
X3-X4
X2-X4
X1-X4
X3-X5
X2-X5
X1-X5
4000:5 500:5
1000:5
1500:5
2000:5
2500:5
3000:5
3500:5
4000:5
X1-X2
X3-X4
X2-X3
X1-X3
X2-X4
X1-X4
X2-X5
X1-X5
2000:5 300:5
400:5
500:5
800:5
1100:5
1200:5
1500:5
1600:5
2000:5
X3-X4
X1-X2
X4-X5
X2-X3
X2-X4
X1-X3
X1-X4
X2-X5
X1-X5
5000:5 500:5
1000:5
1500:5
2000:5
2500:5
3000:5
3500:5
4000:5
5000:5
X2-X3
X4-X5
X1-X2
X3-X4
X2-X4
X3-X5
X2-X5
X1-X4
X1-X5

IEEE
3.2.3 Application
The general considerations for the application of CTs are as follows:
a) Continuous-current rating. The maximum continuous-current rating should be equal
to or greater than the rating of the circuit in which the CT is used. The magnitude of
inrush current should also be considered, particularly with respect to its effect upon
meters, relays, and other connected devices. For example, a 600:5 CT would be rec-
ommended for use on a circuit with a full-load current of 400 A.
b) Continuous-thermal-current rating factor. The continuous-thermal-current rating
factor is supplied by the CT manufacturer. It identiﬁes the amount of current that can
be carried continuously without exceeding the limiting temperature rise from 30 °C
ambient air temperature. The continuous current is multiplied by the rating factor to
determine the maximum current. (When a CT is incorporated internally as part of a
larger transformer or power circuit breaker, it shall meet allowable average winding
and hot-spot temperature limits under speciﬁc conditions of the larger apparatus.)
The rating factors are 1.0, 1.33, 1.5, 2.0, 3.0, or 4.0: for example, a 100:5 CT with a
rating factor equal to 1.5 may be operated up to current levels of 150:7.5 (150 A pri-
mary current: 7.5 A secondary current).
Table 3-2—Ratings for CTs with one or two ratios
Single
ratio
(A)
Double ratio with
series—parallel primary
windings
(A)
Double ratio
with taps in
secondary
winding
(A)
10:5
15:5
25:5
40:5
50:5
75:5
100:5
200:5
300:5
400:5
600:5
800:5
1200:5
1500:5
2000:5
3000:5
4000:5
5000:5
6000:5
8000:5
12 000:5
25 × 50:5
50 × 100:5
100 × 200:5
200 × 400:5
400 × 800:5
600 × 1200:5
1000 × 2000:5
2000 × 4000:5
25/50:5
50/100:5
100/200:5
200/400:5
300/600:5
400/800:5
600/1200:5
1000/2000:5
1500/3000:5
2000/4000:5

IEEE
The secondary devices should be checked for continuous load capability before a CT
is operated above 5 A secondary current. Damage can occur in meters and relays if
operated above their limits.
c) Short-time thermal rating. The short-time thermal rating is the symmetrical root-
mean-square (rms) primary current that the CT can carry for 1 s with the secondary
winding short-circuited, without exceeding the limiting temperature in any winding.
d) Short-time mechanical rating. The short-time mechanical rating is the maximum
current the CT is capable of withstanding without damage with the secondary short-
circuited. It is the rms value of the ac component of a completely displaced
(asymmetrical) primary current wave.
e) Nominal system voltage. CTs are typically designed to operate continuously at 10%
above rated nominal system voltage. Standard nominal system voltages for most
industrial applications are 480 V, 600 V, 2400 V, 4160 V, 12 470 V, 13 800 V, and
14 400 V. It is common practice to apply window CTs rated 600 V to systems with
higher voltages. This practice is done by passing fully insulated conductors through
the window. The conductor insulation functions as the CT primary insulation provid-
ing a fully rated installation.
f) Basic impulse insulation levels (BILs) versus nominal system voltage. The values are
given in Table 3-3.
3.2.4 Accuracy
Protective-relay performance depends on the accuracy of the CTs not only at load currents,
but also at all fault current levels. Accuracy can be visualized as how closely the secondary
wave shape resembles the primary wave shape. Wave shape and phase difference are both
components of the accuracy classification. The CT accuracy at high overcurrents depends on
the cross section of the iron core and the number of turns in the secondary winding. The
greater the cross section of the iron core, the more flux can be developed before saturation.
Saturation results in a rapid decrease in transformation accuracy. The greater the number of
secondary turns, the less flux that is required to force the secondary current through the relay.
This factor influences the burden the CT can carry without loss of accuracy.
Table 3-3—BILs for CTs
Nominal system voltage
(kV)
Maximum line-to-
ground voltage
(kV)
BIL and full wave crest
(kV)
0.6
2.4
5.0
8.7
15.0
25.0
34.5
0.38
1.53
3.06
5.29
8.9
16.0
22.0
10
45
60
75
110 or 95
150 or 125
200

IEEE
IEEE Std C57.13-1993 designates the relaying accuracy class by use of one letter, either C or
T, and the classification number. C means that the percent ratio correction can be accurately
calculated, and T means that it has been determined by test. The classification number indi-
cates the secondary terminal voltage that the transformer delivers to a standard burden (as
listed in Table 3-4) at 20 times normal secondary current without exceeding a 10% ratio cor-
rection. The ratio correction should not exceed 10% at any current from 1 to 20 times rated
current at standard burden. The standard designated secondary terminal voltages are 10 V,
20 V, 50 V, 100 V, 200 V, 400 V, and 800 V. For instance, a transformer with a relaying accu-
racy class of C200 means that the percent ratio correction can be calculated and that it does
not exceed 10% at any current from 1 to 20 times the rated secondary current at a standard
burden of 2.0 Ω . (Maximum terminal voltage = 20 × 5 A × 2 Ω = 200 V.)
Some industrial power systems may have relatively small individual loads that are connected
to a bus with inherently high short-circuit currents. The CT ratio tends to be low because the
maximum current for each load tends to be small. The low-ratio CTs typically chosen result
in a low accuracy class (i.e., less than C100). A low ratio CT may provide satisfactory perfor-
mance at moderate overloads, but is inadequate at the high short-circuit levels. The working
group paper chaired by Linders [B3]2 and the article by Dudor and Padden [B3] discuss this
problem and present some solutions.
Table 3-4—Standard burdens for CTs with 5 A secondariesa
Burdenb
designation
Resistance
(Ω)
Inductance
(mH)
Impedance
(Ω)
Volt-
amperes
(at 5 A)
Power
factor
Metering burdens
B-0.1
B-0.2
B-0.5
B-0.9
B-1.8
0.09
0.18
0.45
0.81
1.62
0.116
0.232
0.580
1.04
2.08
0.1
0.2
0.5
0.9
1.8
2.5
5.0
12.5
22.5
45
0.9
0.9
0.9
0.9
0.9
Relaying burdens
B-1
B-2
B-4
B-8
0.5
1.0
2.0
4.0
2.3
4.6
9.2
18.4
1.0
2.0
4.0
8.0
25
50
100
200
0.5
0.5
0.5
0.5
aIf a CT is rated at other than 5 A, ohmic burdens for specification and rating may be derived by
multiplying the resistance and inductance in the table by [5/(ampere rating)]2, the voltamperes at
rated current and the power factor remaining the same.
bThese standard burden designations have no significance at frequencies other than 60 Hz.

IEEE
3.2.5 Burden
Burden, in CT terminology, is the load connected to the secondary terminals and is expressed
as
— Voltamperes and power factor at a speciﬁed value of current,
— Total ohms impedance and power factor, or
— Ohms of the resistance and reactive components.
The term burden is used to differentiate the CT load from the primary circuit load. The power
factor referred to is that of the burden and not of the primary circuit. To compare various
transformers, ANSI has designated standard burdens to be used in the evaluation process (see
Table 3-4).
3.2.6 Secondary excitation characteristics and overcurrent ratio curves
Secondary excitation characteristics, as published by the manufacturers, are in the form of
excitation current versus secondary rms voltage (see Figure 3-4). The values are obtained
either by calculation from the transformer design data and core-loss curves or by average test
values from a sample of CTs. The test is an open-circuit excitation current test on the second-
ary terminals, using a variable rated frequency sine wave voltage and recording rms current
versus rms voltage.
Figure 3-4—Secondary excitation curves for various turn ratios
of a speciﬁc CT

IEEE
For Class T transformers, typical overcurrent ratio curves are plotted between primary and
secondary current over the range from 1 to 22 times normal primary current for all the
standard burdens (except B-0.9 and B-1.8) up to the standard burden that causes a ratio cor-
rection of 50% (see Figure 3-5).
3.2.7 Polarity
Polarity marks designate the relative instantaneous directions of currents. At the same instant
that the primary current is entering the marked primary terminal, the corresponding
secondary current is leaving the similarly marked secondary terminal, having undergone a
magnitude change within the transformer (see Figure 3-6). The primary H1 and secondary X1
terminals are marked with white dots, or with a ± symbol, or with H1 and X1. As illustrated in
Figure 3-6, the marked secondary conductor can be considered a continuation of the marked
primary line as far as instantaneous current ﬂow is concerned.
Figure 3-5—Typical overcurrent ratio curves for Class T transformers for
burdens of 0.1 Ω through 8.0 Ω (except for B-0.9 and B-1.8)

IEEE
3.2.8 Connections
CTs are usually connected on three-phase circuits in one of three ways, as follows:
a) Wye connection. In the wye connection, a CT is placed in each phase with time-
overcurrent relays (Device 51) placed in either two or three CT secondaries to detect
phase faults. On grounded four-wire systems, a time-overcurrent relay (Device 51N)
in the CT common wire known as a residually connected relay detects any ground
fault or neutral load currents. If neutral load currents are not to be detected by the
Device 51N relay as ground-fault currents, a fourth CT is placed in the neutral
conductor to cancel the neutral load currents. Secondary currents are in phase with
primary currents (see Figure 3-7).
b) Vee connection. A vee connection is basically a wye with one leg omitted, using only
two CTs. Applied as shown in Figure 3-8, this connection detects three-phase and
phase-to-phase faults. A zero-sequence CT (window or bushing) and a ground
overcurrent relay (Device 50GS or Device 51GS) are required to detect ground-fault
currents. All three-phase conductors and the neutral (if present) shall pass through the
CT.
c) Delta connection. A delta connection uses three CTs with the secondaries connected
in delta before the connections are made to the relays. The delta connection shown in
Figure 3-9 is typically used for power transformer differential relay protection
schemes where the power transformer has delta-wye-connected windings. The CTs
on the delta side are connected in wye, and the CTs on the wye side are connected in
delta. This connection is described in detail in Chapter 4. The delta connection is also
used for overcurrent protection of grounding transformers where ﬁltering out the
third-harmonic currents is desirable. When connected in delta, the current in the
relays is equal to times the CT secondary current. This fact should be considered
when selecting the primary ratings of CTs and the secondary device ratings of delta-
connected CTs.
Figure 3-6—CT polarity diagram
3

IEEE
3.2.9 Examples of accuracy calculations
Example A and Example B illustrate the calculation technique for determining whether the
CT provides satisfactory operation under short-circuit conditions with the burden of the
connected devices. The devices used in the calculation are typical, and representative burden
values are used. In speciﬁc situations, the number and burden of devices installed may vary,
so the actual values of each device should be used. The examples assume no residually
connected relay (Device 51N in Figure 3-7) present. Calculations to account for this relay are
shown in Chapter 5 of Protective Relaying (see Blackburn [B2]).
Figure 3-7—Wye-connected CTs
Figure 3-8—Vee- or open-delta-connected CTs

IEEE
3.2.9.1 Example A: Calculation using a 600:5 multiratio bushing CT
Consider a 600:5 multiratio bushing CT with excitation characteristics as shown in
Figure 3-4. It is connected for a 600:5 ratio (C200 accuracy class) and to a secondary circuit
containing a phase overcurrent relay with an instantaneous element, a watthour meter, and an
ammeter. The circuit contains approximately 50 ft of No. 12 wire, and the primary circuit has
a capability of 24 000 A of fault current.
From instruction books for the devices and wire resistance tables, the following data are
obtained:
— Phase relay, time unit, 1 A to 12 A, has a burden of 2.38 VA at 0.375 power factor at
tap setting of 4 A (520 VA at 0.61 power factor at 100 A).
— Phase relay, instantaneous unit, 20 A to 80 A, has a burden of 4.5 VA at 20 A setting
(150 VA at 0.20 power factor at 100 A).
— Watthour meter has a burden of 0.77 W at 0.54 power factor at 5 A.
— Ammeter has a burden of 1.04 VA at 0.95 power factor at 5 A.
— Wire resistance equals 1.72 Ω per 1000 ft at 25 °C and 1.0 power factor.
— CT secondary resistance equals 0.298 Ω at 25 °C and 1.0 power factor.
The steps for determining the performance of the CT for this application are as follows:
a) Determine the CT secondary burden.
b) Determine the voltage necessary to pass 100 A through the relay.
c) Determine whether the CT can develop this voltage and whether the excitation cur-
rent from Figure 3-4 is less than 10% of the secondary current, as discussed in 3.2.4.
Figure 3-9—Delta-connected CTs

IEEE
3.2.9.1.1 Step a)
As stated previously, the burden is expressed in voltamperes at a given power factor or as
total ohms impedance given by its resistance and reactance components. Because most of the
devices connected to CTs contain magnetic paths that become saturated, the burden should be
calculated for the maximum current involved. In this example, operation is evaluated at
100 A secondary current (20 times rated) and at the actual fault current available.
Device 1,
Relay, time unit
520 VA at 100 A at 52.4° Z = 520/(100)2 = .052 Ω
= 0.052<52.4° = 0.0317 + j0.0412 Ω
Device 2, Relay,
instantaneous unit
150 VA at 100 A at 78.5° Z = 150/(100)2 = 0.015 Ω
= 0.015<78.5° = 0.003 + j0.0147 Ω
Device 3,
Watthour meter
0.77 W at 5 A at 57.3° VA = W/PF = 0.77/0.54 = 1.43 VA
Z = 1.43/(5)2 = 0.057 Ω
= 0.057<57.3° = 0.031 + j0.048
Because a watthour meter also has an
iron-core magnetic circuit, the power
factor at 20 times current is approxi-
mately 0.96. Thus, at 100 A,
Z = resistance/power factor
= 0.031/0.96 = 0.0323 Ω
R + jX = 0.031 + j0.009
VA = (100)2 × 0.0323 = 323 VA
Device 4,
Ammeter
1.04 VA at 5 A at 18° Z = 1.04/(5)2 = 0.042 Ω
= 0.042/18° = 0.040 + j0.013
Because an ammeter applies basically an
air-core magnetic circuit, no saturation is
present at 20 times current. Thus, at
100 A,
VA = I2Z = (100)2 × 0.042 = 420 VA
Device 5, Wire 1.72 Ω per 1000 ft at 25 °C,
l.0 power factor
Thus, at 100 A,
VA = I2R = (100)2 × (1.72 × 50 ÷ 1000)
= 860 VA
The one-way distance is used for a three-
phase circuit, and the two-way distance
is used for a single-phase circuit.
Device 6, CT
secondary resistance
0.298 Ω at 1.00 power factor Thus, at 100 A,
VA = I2R = (100)2 × 0.298 = 2980 VA

IEEE
Totaling the burden for Device 1 through Device 6 at 100 A:
Using the approximate VA Method, Z1 = 5253/(100)2 = 0.5253 Ω.
Using the accurate R + jX Method, Z2 = 0.4897 + j0.0779 = 0.4952 Ω.
NOTE—The approximate Z1 compares favorably with the more accurate Z2.
3.2.9.1.2 Step b) at 100 A
The CT voltage Es necessary to produce a secondary current of 100 A through the burden in
Step a) is IZ.
IZ1 = 100 × 0.5253 = 52.5 V
IZ2 = 100 × 0.495 = 49.5 V
3.2.9.1.3 Step c) at 100 A
From Figure 3-4, ﬁnd the secondary excitation current Ie at the voltage of 52.5 V.
At Es = 52.5 V, Ie = 0.06 A. This voltage is less than 10 A (10% of 100 A), and the relays
should operate as expected.
3.2.9.1.4 Further consideration
If any doubt exists, Step b and Step c should be repeated using the maximum primary current
of 24 000 A (200 A in secondary).
3.2.9.1.4.1 Step b) at 200 A
The CT voltage Es necessary to produce a secondary current of 200 A through the burden in
Step a) is IZ.
Device Voltamperes Impedance
1 520 0.0317 + j0.0412
2 150 0.003 + j0.0147
3 323 0.031 + j0.009
4 420 0.040 + j0.013
5 860 0.086
6 2980 0.298
5253 0.4897 + j0.0779

IEEE
IZ1 = 200 × 0.525 = 105 V
IZ2 = 200 × 0.495 = 99 V
3.2.9.1.4.2 Step c) at 200 A
From Figure 3-4, ﬁnd the secondary excitation current at the voltage of 105 V. At Es = 105 V,
Ie = 0.11 A. Again, this voltage is less than 10 A.
Thus, for this application the CT is more than adequate. The result, however, is essentially the
same regardless of the calculation method used.
3.2.9.2 Example B: Using the 200:5 A tap on the 600:5 multiratio CT
Where the load current is small, selecting a lower ratio CT may be desirable. Using a 200:5
ratio tap provides the same pickup current when the time-overcurrent relay is set for 12 A.
Figure 3-4 demonstrates that the accuracy class at 200:5 ratio is no longer C200, but closer to
C20. The CT secondary resistance is lower, but all other burden values are assumed to be the
same. From Figure 3-4, the CT secondary resistance is now only 0.114 Ω at 25 °C.
Recalculating the burden of the devices, but using the lower CT resistance:
The voltage required for the 200:5 ratio tap is 0.3155 × 100 = 31.6 V.
From Figure 3-4 for 31.6 V, the excitation current Ie = 0.4 A is less than the maximum error
current of 10 A (10% of 100 A).
For this application at 100 A secondary fault current (4000 A in the primary), the 200:5 ratio
appears to be adequate with operation slightly above the knee of the excitation curve for the
relaying involved. However, because the actual fault current is 24 000 A (120 times CT rat-
ing), the calculation should be repeated using this value.
Isec = 24 000/200:5 = 600 A
Device Impedance
1 0.0317 + j0.0412
2 0.003 + j0.0147
3 0.031 + j0.009
4 0.040 + j0.013
5 0.086
6 0.114
Total Z = 0.3057 + 0.0779 = 0.3155 Ω

IEEE
The voltage required by the burden for the 200:5 ratio is 0.3155 × 600 = 189 V. The CT goes
into saturation because this voltage is beyond the ability of the 200:5 ratio. A higher CT ratio
should be used.
3.2.10 Saturation
Abnormally high primary fault currents, primary fault currents having a dc offset, residual
flux, high secondary burden, or a combination of these factors results in the creation of high
flux density in the CT iron core. When this density reaches or exceeds the design limits of the
core, saturation results. At this point, the accuracy of the CT becomes poor, and the output
waveform may be distorted by harmonics. Saturation results in the production of a secondary
current lower in magnitude than would be indicated by the CT ratio. The severity of this
transformation error varies with the degree of saturation. With total saturation, virtually no
secondary current flows past the first quarter cycle.
For example, selective coordination of protective devices may not occur if CTs on a branch
circuit saturate. Tripping of the branch circuit breaker may be delayed or may not even occur.
Such an event would result in the operation of the line-side main circuit breaker and result in
an more extensive outage than should have occurred. Instantaneous overcurrent relays may
not even trip (see Linders, et al. [B3]) where the fault currents are high, and bus differential
relays may falsely trip on through faults.
To avoid or minimize saturation effects, the secondary burden should be kept as low as possi-
ble. Where fault currents of more than 20 times the CT nameplate rating are anticipated, a
different CT, different CT ratio, or a lower burden may be required. A comprehensive review
of saturation and its effect on the transient response of CTs is presented in IEEE Special Pub-
lication 76CH1130-4PWR.
3.2.11 Auxiliary CTs
Auxiliary CTs may be required to
— Match the winding ratio of another CT,
— Provide different ratios from those that are available,
— Provide a phase shift in the current, or
— Isolate the circuit
They should be used only to step-down the current, where possible, as this connection or
action reflects a lower burden into the main CT. For a burden ZB in the secondary of an auxil-
iary CT, the corresponding burden Z′B in the secondary of the main CT (see Figure 3-10) is
given by the expression,
Z′B
ZB
N
2
------
=

IEEE
where
N is the ratio of the auxiliary CT.
Thus for a step-down ratio of 10:5, N = 2 and Z′B = 0.25 ZB. However, for a step-up ratio of
5:10, N = 0.5 and Z′B = 4.0 ZB. The step-down CT should be used whenever possible because
it reduces the burden of the connected devices on the main CT (see Dudor and Padden [B3]).
3.2.12 Safety precautions
An important precaution with respect to CTs is that they should never be operated with the
secondary circuit open because hazardous voltages may result. Any CT that has been sub-
jected to open secondary circuit operation should be examined for possible damage before
being placed back in service. A voltage-limiting device may be installed to reduce the hazards
of open secondary circuits.
3.3 Voltage (potential) transformers (VTs)
A VT is basically a conventional transformer with primary and secondary windings on a
common core. Standard VTs are single-phase units designed and constructed so that the
secondary voltage maintains a ﬁxed relationship with primary voltage. The required rated
primary voltage of a VT is determined by the voltage of the system to which it is to be
connected and by the way in which it is to be connected (e.g., line to line, line to neutral).
Most VTs are designed to provide 120 V at the secondary terminals when nameplate-rated
voltage is applied to the primary. Standard ratings are shown in Table 3-5 and Table 3-6.
Special ratings are available for applications involving unusual connections.
VTs are capable of continuous and accurate operation when the voltage applied across the
primary is within ±10% of the rated primary voltage.
Figure 3-10—Auxiliary CTs

IEEE
Table 3-5—Ratings and characteristics of VTs with 100% of rated primary
voltage across the primary winding when connected line to line or line to
ground
Rated primary voltage for
rated voltage line to line
(V)
Marked ratio
Basic impulse insulation level
(kV crest)
120 for 208 Y
240 for 416 Y
300 for 520 Y
120 for 208 Y
240 for 416 Y
300 for 520 Y
480 for 832 Y
600 for 1040 Y
2400 for 4160 Y
4200 for 7280 Y
4800 for 8320 Y
7200 for 12 470 Y
8400 for 14 560 Y
1:1
2:1
2.5:1
1:1
2:1
2.5:1
4:1
5:1
20:1
35:1
40:1
60:1
70:1
10
10
10
30
30
30
30
30
60
75
75
110 or 95
110 or 95
Table 3-6—Ratings and characteristics of VTs primarily for line-to-line servicea
Rated primary voltage for
rated voltage line to line
(V)
Marked ratio
Basic impulse insulation level
(kV crest)
120 for 120 Y
240 for 240 Y
300 for 300 Y
480 for 480 Y
600 for 600 Y
2400 for 2400 Y
4800 for 4800 Y
7200 for 7200 Y
12 000 for 12 000 Y
14 000 for 14 000 Y
24 000 for 24 000 Y
34 500 for 34 500 Y
1:1
2:1
2.5:1
4:1
5:1
20:1
40:1
60:1
100:1
120:1
200:1
300:1
10
10
10
10
10
45
60
75
110 or 95
110 or 95
150 or 125
200 or 150
aMay be applied line to ground or line to neutral at a winding voltage equal to the primary
voltage rating divided by .
3

IEEE
Standard accuracy classifications of VTs range from 0.3 to 1.2, representing percent ratio
corrections to obtain a true ratio. These accuracies are high enough so that any standard
transformer is adequate for most industrial protective relaying purposes as long as it is
applied within its open-air thermal and voltage limits. Standard burdens for VTs with a
secondary voltage of 120 V are shown in Table 3-7.
Thermal burden limits, as given by transformer manufacturers, should not be exceeded in
normal practice because transformer accuracy and life will be adversely affected. Thermal
burdens are given in voltamperes and may be calculated by simple arithmetic addition of the
voltampere burdens of the devices connected to the transformer secondary. If the sum is
within the rated thermal burden, the transformer should perform satisfactorily over the range
of voltages from 0% to 110% of the nameplate voltage.
Polarity on VTs is normally identified by marking a primary terminal H1 and a secondary ter-
minal X1. Alternatively, these points may be identified by distinctive color markings. The
standard voltage relationship provides that the instantaneous polarities of H1 and X1 are the
same.
Where balanced system load and, therefore, balanced voltages are anticipated, VTs are usu-
ally connected in open delta. Where line-to-neutral loading is expected, VTs are more often
connected wye-wye, particularly where metering is required. Many protective devices require
specific delta or wye voltages; therefore, specific requirements should be studied before
choosing the connection scheme. Wye-delta or delta-wye connections are occasionally used
with certain special relays, but these connections are infrequent in industrial use. Where
ungrounded power systems are used, VTs connected wye-broken-delta are sometimes used
for ground detection. When so connected, the transformers can seldom be used for any other
purpose. Broken-delta connections used on ungrounded systems should normally include a
loading resistor in the secondary to mitigate possible ferroresonance between the system
capacitance and the VT. (See Fink and Beaty [B5] and Linders, et al.[B3])
Table 3-7—Standard burdens for VTs
Characteristics on standard burdensa Characteristics on 120 V basis
Designation
Volt-
amperes
Power
factor
Resistance
(Ω)
Inductance
(mH)
Impedance
(Ω)
W
X
Y
Z
ZZ
M
12.5
25
75
200
400
35
0.10
0.70
0.85
0.85
0.85
0.20
115.2
403.2
163.2
61.2
30.6
82.3
3.04
1.09
0.268
0.101
0.0503
1.07
1152
576
192
72
36
411
aThese burden designations have no significance except at 60 Hz.

IEEE
The application of fuses to VT circuits has been a subject of discussion for many years. The
main purpose of a VT primary fuse is to protect the power system by de-energizing failed
VTs. General practice now calls for a current-limiting fuse or equivalent in the system.
Figure 3-11 shows a typical VT with fuses.
VT secondary fusing practices cannot be so clearly deﬁned. It is usually impossible to select
primary fuses that protect the transformer from most overloads or faults in the external
secondary circuit. Secondary fuses selected to interrupt at loadings below the thermal burden
rating can provide such protection. Where branch circuits are tapped from VT secondaries to
supply devices located at a distance from the VT, it may be desirable to fuse the branch at a
reduced rating.
3.4 References
IEEE Std C57.13-1993, IEEE Standard Requirements for Instrument Transformers.
3.5 Bibliography
[B1] Applied Protective Relaying. Newark, NJ: Westinghouse Electric Corporation, 1976.
[B2] Blackburn, J. L., Protective Relaying, Principles and Applications, 2nd ed. New York:
Marcel Dekker, Inc., 1998.
[B3] Dudor, J. S., and Padden, L. K., “Protective Relay Applications for Generators and
Transformers,” IEEE Industry Applications Magazine, pp. 22–35, Jul./Aug. 1997.
[B4] Electric Utility Engineering Reference Book: Vol. 3, Distribution Systems. Trafford, PA:
Westinghouse Electric Corporation, 1965.
Figure 3-11—Typical VT

IEEE
[B5] Fink, D. G., and Beaty, H. W., Standard Handbook for Electrical Engineers. New York:
McGraw-Hill, 1993.
[B1] IEEE Special Publication 76CH1130-4PWR, “Transient Response of Current
Transformers,” A summary report and discussion, IEEE Transactions on Power Apparatus
Systems, PAS 96, pp. 1809–1814, Nov./Dec. 1977.3
[B2] Instrument Transformer Burden Data. Schenectady, NY: General Electric Company,
GET-1725, 1961.
[B3] Linders, J. R., et al., “Relay Performance Considerations with Low-Ratio CT’s and
High-Fault Currents,” IEEE IAS Transactions on Industry Applications, vol. 31, pp. 392–404,
Mar./Apr. 1995.
[B4] Manual of Instrument Transformers. Schenectady, NY: General Electric Company,
GET-97, 1975.
[B5] Mason, C. R., The Art and Science of Protective Relaying. New York: John Wiley &
Sons, 1956. Reprinted by General Electric Company, GER-3738.
[B6] Powell, L. J., Jr., “Current Transformer Burden and Saturation,” IEEE IAS Transactions
on Industry Applications, vol. 15, pp. 294–303, May/June 1979.
[B7] West, D. J., “Current Transformer Application Guidelines,” Conference Record, IAS-
I&CPS Technical Conference, Pittsburgh, Paper 77CH1198-11A, May 1977.

Chapter 4
Selection and application of protective relays
4.1 General discussion of a protective system
Power systems should be designed so that protective relays operate to sense and isolate faults
quickly to limit the extent and duration of service interruptions. Protective relays are impor-
tant in industrial power systems because they can prevent large losses of production due to
unnecessary equipment outages or unnecessary equipment damage occurring as a result of a
fault or overload. Other considerations are safety, property losses, and replacements. Protec-
tive relays have been called the watchdogs or silent sentinels of a power system.
Protective relays are classified by the variable they monitor or by the function they perform.
For instance, an overcurrent relay senses current and operates when the current exceeds a pre-
determined value. Another example is a thermal overload relay that senses the temperature of
a system component, either directly or indirectly (as a function of current), or both, and oper-
ates when the temperature is above a rated value.
The application of relays is often called an art rather than a science because judgment is
involved in making selections. The selection of protective relays requires compromises
between conflicting objectives, while maintaining the capability of operating properly for
several system operating conditions. These compromises include providing
a) Maximum protection
b) Minimum equipment cost
c) Reliable protection
d) High-speed operation
e) Simple designs
f) High sensitivity to faults
g) Insensitivity to normal load currents
h) Selectivity in isolating a minimum portion of the system
Planning for the protection system should be considered in the power system design stage to
ensure that a good system can be implemented. The cost of applying protective relays should
be balanced against the potential costs of not providing protection.
Electromechanical relays have been used for over 60 years to provide power system
protection. They are known for their reliability, low maintenance, and long life of operation.
However, since the early 1960s, static relays have been used in an increasing number of
applications. Static relays provide the advantages of lower burden, improved dynamic
performance characteristics, high seismic withstand capability, self-monitoring,
multifunctionality, system monitoring, and reduced panel space requirements.
Many of the protection functions can be accomplished equally well by either electromechan-
ical or static relays. The specific application should dictate which type of relay is used.

IEEE
The various protective relay functions have been given identifying device function numbers,
with appropriate suffix letters when necessary. All of these numbers are listed in
IEEE Std C37.2-19961 and are used in diagrams, instruction books, and specifications. Many
possible numbers can be used; but, for convenience, only the ones most commonly used are
listed in Table 4-1, along with the function that each number represents.
Table 4-2 lists the commonly used suffix letter applied to each number denoting the circuit
element being protected or the application. Each of the relay types listed in Table 4-1 is dis-
cussed in some detail in this chapter, along with their operating principles and applications.
1Information about references can be found in 4.5.
Table 4-1—Abbreviated list of commonly used relay device function numbers
Relay device
function number
Protection function
21 Distance
24 Volts/hertz (overexcitation)
25 Synchronizing
27 Undervoltage
32 Directional power
40 Loss of excitation (field)
46 Phase balance (current balance, negative-sequence current)
47 Phase-sequence voltage (reverse phase voltage)
49 Thermal (generally thermal overload)
50 Instantaneous overcurrent
51 Time-overcurrent
59 Overvoltage
60 Voltage balance (between two circuits)
67 Directional overcurrent
81 Frequency (under and overfrequency)
86 Lockout
87 Differential

IEEE
SELECTION AND APPLICATION OF PROTECTIVE RELAYS Std 242-2001
4.2 Zones of protection
A separate zone of protection is normally established around each system element. This prac-
tice logically divides the system into protective zones for generators, transformers, buses,
transmission lines, distribution lines or cable circuits, and motors. Any failure occurring
within a protection zone sends a trip signal to circuit breakers serving that zone to isolate the
faulted equipment from the rest of the system.
Protection zones are classified as primary and/or backup. The primary protective relays are
the first line of defense against system faults and operate first to isolate the fault. Typically,
high-speed relays (i.e., 1 cycle to 3 cycles exclusive of breaker operating time) with high
drop-out rates are applied in these applications.
When a fault is not isolated after some time delay, backup protection clears the faulted equip-
ment by retripping the primary circuit breakers or by tripping circuit breakers in adjacent
zones. When adjacent zones are tripped by backup protective relays, more of the power sys-
tem is removed from service.
Backup protection can be either local or remote. Local backup protection is located within
the zone in which the fault occurs, and trips either the primary circuit breaker or circuit break-
ers in adjacent zones. Remote backup protection is located in adjacent zones and generally
only trips circuit breakers in their zone.
Table 4-2—Commonly used suffix letters applied to relay function numbers
Suffix letter Relay applicationa
A Alarm only
B Bus protection
G Ground-fault protection [relay current transformer (CT) in a system neutral cir-
cuit] or generator protection
GS Ground-fault protection (relay CT is toroidal or ground sensor)
L Line protection
M Motor protection
N Ground-fault protection (relay coil connected in residual CT circuit)
T Transformer protection
V Voltage
aExamples:
(1) 87T, transformer differential relay
(2) 51G, time-overcurrent relay used for ground-fault protection
(3) 49M, motor winding overload (or over-temperature) relay
(4) 87B, bus differential relay or partial bus differential relay (also called summation differential)

IEEE
The protection zones generally overlap to ensure no portion of the power system is left unpro-
tected. Also, primary and backup protection systems should be selectively coordinated by
current magnitude, time, fault type, direction, temperature, etc.
4.3 Fundamental operating principles
Protective relays generally operate in response to one or more electrical quantities to open or
close contacts or to trigger thyristors. (An exception is a thermal relay, which operates in
response to temperature levels.) Relays are constructed using either electromechanical or
static principles.
4.3.1 Electromechanical relay operating principle
Electromechanical relays have only two operating principles:
— Electromagnetic attraction
— Electromagnetic induction
Electromagnetic attraction relays operate by having either a plunger drawn by a solenoid or
an armature drawn to a pole of an electromagnet. This type of relay operates from either an ac
or a dc current or voltage source and is used for instantaneous or high-speed tripping.
Electromagnetic induction relays use the principle of the induction motor, where torque is
developed by induction into a rotor. This principle is used in an electromechanical watthour
meter, where the rotor is a disk. The actuating force developed on the rotor is a result of the
interaction of the electromagnetic fluxes applied and the flux produced by eddy currents that
are induced in the rotor.
Induction relays can only be used in ac applications, and the rotor is normally a disk or a cyl-
inder. Time-overcurrent, time-undervoltage, and time-overvoltage relays commonly are of
the disk design, while cup (cylinder) structures are often found in high-speed overcurrent,
directional, differential, and distance relays.
4.3.2 Static relay operating principle
Static relays are either analog or digital. Static analog relays were first introduced in the early
1960s and were typically designed to emulate the characteristics of their electromechanical
counterparts. Soon, digital technology was implemented in relay design with characteristics
available that were outside the capabilities of the electromechanical design.
Operation of the static design converts input signals to an appropriate magnitude for measure-
ment within the relay, which is in direct proportion to the system signal. The measured value
is then compared against a predetermined setting. Timing and other characteristics are
derived from either the analog circuit design or algorithms within a microprocessor.

IEEE
4.4 Functional description—application and principles
4.4.1 Distance relay (Device 21)
4.4.1.1 Application
Distance relays are widely used for primary and backup protection on subtransmission and
transmission lines where high-speed relaying is desired, normally on circuits having voltages
above 34.5 kV. Other applications include generator backup protection for faults on the sys-
tem and startup of large motors with high inertia (see Chapter 10).
4.4.1.2 Operation principles
Distance relay is a generic term applied to impedance relays that use voltage and current
inputs to provide an output signal if a fault is within a predetermined distance from the relay
location. Distance to the fault is calculated from the voltage-to-current ratio as a measure of
impedance, from the imaginary component of the voltage-to-current ratio as a measure of
reactance, or from the current-to-voltage ratio as a measure of the admittance. The major
advantage of a distance relay is that it responds to system impedance instead of the
magnitude of current. Thus, the distance relay has a fixed distance reach as contrasted with
overcurrent relays for which the reach varies as short-circuit levels and system configurations
change.
Electromechanical distance relays utilize an induction cup construction to achieve operating
times of 1 cycle to 1.5 cycles. Static distance relays have an inherent operating time of
0.25 cycle to 0.5 cycle. A fixed time delay is added when required for selectivity.
Distance relay characteristics can be shown graphically in terms of two variables, R and X (or
Z and θ), where R is the resistance, X is the reactance, Z is the impedance, and θ is the angle
by which current lags voltage. The relay characteristics and the line impedance can be plotted
on the same R-X diagram for analysis. In examining R-X diagrams, it should be recalled that
regions of positive R and X represent impedances in a defined tripping direction, while the
third quadrant (negative R and X) contain impedance behind the relay, or in the nontripping
direction. The origin of the R-X diagram is placed at the relay location, which is defined by
the location of its CTs and voltage transformers (VTs).
4.4.1.3 Reactance distance relay
Reactance relays measure the reactive component of system complex impedance. A generic
reactance relay characteristic appears on the R-X diagram as a straight line parallel to the
R-axis, as shown in Figure 4-1.
Operation of the generic reactance relay occurs when the reactance from the relay to the point
of fault, X2 in Figure 4-1, is less than or equal to the reactance X1. Reactance X1 is the reac-
tance setting of the relay. The relay also responds to any reactance in the negative direction.
Reactance relays are inherently nondirectional. Operation is practically unaffected by arc
resistance, but reactance relays may operate on load current and hence should be used in

IEEE
conjunction with other relays to restrict their reach along the R-axis and in the reverse,
negative-reactance direction.
4.4.1.4 Impedance distance relay
The impedance relay measures the magnitude of the complex impedance. The generic imped-
ance relay characteristic is a circle on the R-X diagram as shown in Figure 4-2.
Operation of the generic impedance relay occurs when the resistance and reactance (imped-
ance) from the relay to the point of fault, Z2 = R2 + JX2 in Figure 4-2, lies within the circle
having radius , impedance Z1 = R1 + JX1, is the setting on the relay.
To make the impedance relay directional, the generic impedance relay should be used in con-
junction with other relays to restrict their reach in the reverse direction (i.e., third quadrant of
the R-X diagram).
Figure 4-1—R-X diagram for the generic reactance relay
Figure 4-2—R-X diagram for the generic impedance relay
R1
2
X1
2
+

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4.4.1.5 Mho distance relay
An mho relay measures complex admittance, but unlike impedance relays, mho relays are
directional. The mho distance relay has a circular characteristic, as shown in Figure 4-3.
Relay operation occurs when the impedance from the relay to the fault, Z2 = R2 + JX2 in
Figure 4-3, lies inside the mho characteristic. Because the circular characteristic falls mainly
in the first quadrant of the R-X diagram, the mho relay is directional.
For special applications, a mho characteristic may be shifted in either forward or reverse
directions. For loss of field applications (see 4.4.5), the mho relay characteristic is centered
on the X-axis, with its center offset in the negative direction from the R-axis, as shown in
Figure 4-4a.
Figure 4-3—R-X diagram for the mho relay
Figure 4-4a—R-X diagram for mho relay being applied as
a loss-of-field relay for a synchronous generator

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4.4.1.6 Mho-supervised reactance relay characteristic
For applications on short lines, a composite consisting of an ohm (reactance) unit and a mho
unit in one case is often used. The mho unit, called the starting unit, provides a directional
function. The tripping contacts of the mho unit and ohm unit are in series so that relay trip-
ping is conﬁned to the areas where both characteristics overlap (see Figure 4-4b).
A trip signal occurs if the reactance from the relay to the point of fault is less than or equal to
X1 and the impedance from the relay to the fault is within the mho characteristic.
4.4.1.7 Directional impedance relay characteristic
One type of directional impedance relay that is sometimes used is shown in Figure 4-5. The
origin of the relay’s circular characteristic is shifted into the ﬁrst quadrant, and a directional
element is added. Breaker tripping occurs when the impedance between the relay and the
fault is within the relay’s unshaded circular characteristic. Many other characteristic shapes
have been used over the past several years. Many of these shapes are known by the name of
the item that they resemble (e.g., ice cream cone, tomato). Each of these various characteris-
tics were developed to more closely match the characteristics of the line to eliminate
unwanted operations.
4.4.2 Synchronism check and synchronizing relays (Device 25)
4.4.2.1 Application
Synchronism check and automatic synchronizing relays are applied when two or more
sources of power are to be connected to a common bus (see Figure 4-6a and Figure 4-6b).
The success of connecting two sources together depends largely upon securing small and
preferably diminishing differences in the voltage magnitudes, phase angles, and frequencies
of the two sources at the time they are to be connected together.
Figure 4-4b—R-X diagram for the mho-supervised reactance relay

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Synchronism check (also called sync-check or syncro-veriﬁer) relays permit automatic or
manual closing of a circuit breaker or switches only when the systems on each side of the
devices are within the setting criteria of the relay (see Figure 4-6a). Sync-check relays are
typically applied for supervision of manual closing on small generators, as backup protection
for automatic synchronizing of larger generators, and at locations where the system may
become separated and loss of synchronism between the two resulting systems may occur.
Automatic synchronizing relays may be used to automatically close or supervise the closing
of a circuit breaker whose function is to connect a generator to a system or to connect two
separate systems (see Figure 4-6b). The same automatic synchronizing relay may be used to
control more than one circuit breaker at a station by switching the relay wiring to the poten-
tial and control circuits of the unit being synchronized.
Figure 4-5—R-X diagram for a directional impedance relay
Figure 4-6a—Application of synchronism check relay to connect
two systems together

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Manual synchronization requires training, use of good judgment, experience, and the careful
attention of the operator. Switchgear and generating equipment have been damaged as a
result of misjudgment by an operator. Bent shafts of industrial-size turbine generators occur
all too often when operators close circuit breakers when the systems are too far out of phase.
Therefore, manual synchronizing is not recommended unless it is supervised with a relay that
performs a synchronizing verification.
4.4.2.2 Synchronism check (sync-check) relays
Recommended practice promotes the use of a sync-check relay as a permissive device to
supervise manual or automatic closing of a circuit breaker or switch between two systems. In
this scheme, as shown in Figure 4-6a, a normally open contact of a sync-check relay in series
with the circuit breaker’s or switch’s closing circuit prohibits the closing of the device when
system conditions are outside the setting criteria of the relay and minimizes the risk of equip-
ment damage.
Relay supervision of manual synchronism is accomplished in the following way: The opera-
tor performs all the normal manual synchronizing functions, but cannot complete the circuit
breaker close circuit until the relay senses that the systems are in synchronism. When the
operator is satisfied that the systems are in synchronism, the device’s closing switch is oper-
ated to connect the two sources together. The relay monitors the voltages on each side of the
device; and when the phase-angle and voltage difference between the two systems are within
the preset values for a defined period, the relay’s normally open contact closes and allows
closure of the device.
The period, which is adjustable on the relay, defines the allowable system slip rate. The
shorter the period, the higher the slip rate allowed. High slip rates or a late closing signal
could permit the sources to be connected at an angle greater than the desired closing angle.
This situation can lead to possible equipment damage because the system may be out of
Figure 4-6b—Application of synchronizing relay to connect a generator onto
a system bus

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synchronism by the time the device actually closes its contacts. Therefore, a longer period is
normally used to require a lower slip rate between the two systems.
Sync-check relays are available with ﬁxed and adjustable closing angles. Adjustable closing
angles are typically set between 10° and 30° and are centered around 0° phase angle (i.e., a
phase-angle setting of 20º would produce a total window of 40º centered about zero). How-
ever, static synch-check relays are available, which provide dynamic phase-angle window
settings. In this case (Figure 4-6c), the phase angle can be selected from one of four options:
— Phase-angle window only on the fast side
— Phase-angle window only on the slow side
— Phase-angle window on either side with the window dynamically changing based on
the rotational direction of the synchroscope needle
— The traditional method with the total phase-angle window centered about zero,
regardless of rotational direction
Limiting the phase-angle window to only one side of the synchroscope limits the possible
damage caused as the result of a slow-closing device receiving a close signal just prior to
exiting the trailing edge of the window. For example, in Figure 4-6d, the phase-angle setting
is ±20º with a time-delay setting of 1.388 s. These parameters provide for a slip setting of
0.08 Hz, derived as follows:
Figure 4-6c—Application of synchronizing relay dynamic characteristic

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T = 40º × 60 s/min
360º × 4.8 rpm
T = 1.388
where
Slip (Hz) = Cycle/s = Rev/s
Rev × 60 s = Rev
s min min
Slip × 60 = rpm (rev/min)
Assuming 0.08 Hz slip,
rpm = 0.08 × 60 = 4.8
and
360º × Rev × 1 min × T = Angle (º)
1 Rev min 60 s
Therefore,
360º × 4.8 × T = 40º
60 s
T = 40º × 60 = 1.388 s
360º × 4.8
These settings mean that the two systems should be no further than 20º apart with a slip of not
more than 0.08 Hz.
Sync-check relays can also be programmed to provide automatic closing under certain condi-
tions. Most sync-check relays have the capability of providing automatic closing when one or
more of the following conditions occur:
— Live line/dead bus
— Dead line/live bus
— Live line/live bus
— Dead line/dead bus
If any of these condition switches are selected, and that condition occurs, the relay provides a
close signal without the function of synchronism veriﬁcation. These condition switches allow

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greater system ﬂexibility to regain load quickly where no danger exists in closing without
synchronization. Care should be taken when selecting these condition switches to ensure that
proper synchronization is applied elsewhere when a dead line or bus is automatically ener-
gized.
4.4.2.3 Automatic synchronizing relays
An automatic synchronizing relay is used for synchronizing an incoming generator to a
power system.
Automatic synchronizing is applied to generating equipment where the station is unattended;
where the element of human error should be ruled out in the start-up procedures of a generat-
ing unit; or where consistent, accurate, and rapid synchronization is preferred. The relays
used are multifunctional devices that sense the differences in phase angle, voltage magnitude,
and frequency of the sources on both sides of an incoming generator breaker and initiate cor-
rective signals to the prime mover and ﬁeld in order to adjust the generator frequency and
voltage until the systems are in synchronism.
Most automatic synchronizing relays can anticipate an advance angle at which to initiate
breaker closing so that, when the circuit breaker is closed, the systems is as close to exactly in
synchronism as possible. A synchroscope is used to visualize the synchronizing process.
From the time the relay initiates a close signal until the breaker’s contacts actually close, the
needle travels a certain distance (measured in degrees) around the scope. The distance trav-
eled can be determined based on the speed of rotation and how long it was permitted to rotate.
The scope’s needle rotates at a speed that is directly proportional to the slip frequency
between the generator and the system. Therefore, given the circuit breaker’s closing time and
the desired slip rate, the rotational distance traveled (or advance closing angle) can be
determined.
Figure 4-6d—Application of synchronizing relay

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When the generator is to be connected to the system, the appropriate synchronizing switch is
selected and closed. The synchronizing equipment performs the following functions
automatically:
a) A speed-matching relay element senses the frequency difference between the sources
and adjusts the governor with raise or lower signals to control the speed of the incom-
ing generator and thereby matches the frequency of the generator with the frequency
of the running system bus.
b) A voltage-matching relay element compares the running system and incoming gener-
ator voltages and provides raise or lower signals to the excitation system of the
incoming generator so that its voltage matches the running system voltage.
c) As the phase angle between the two systems approaches zero, the relay energizes the
circuit breaker's closing circuit at an advance angle determined by the relay so that
when the circuit breaker contacts close, the two systems are in synchronism. The
synchronizing relay itself has at least two adjustable settings that should be made for
correct performance. One adjustment permits the relay to accommodate breaker
closing time, for example, 0.05 s to 0.4 s, and one adjustment sets the maximum
phase-angle advance, from 0° to 30-40°. The advance closing angle is calculated by
the following expression:
θ = 360(st)
where
θ is advance angle (˚),
s is slip frequency (cycles/s),
t is breaker closing time (s).
For example, for systems coming into synchronism rapidly, that is, s = 0.5 cycles/s, the clos-
ing circuit should be energized well in advance of synchronism. If the circuit breaker has a
0.15 s closing time, the advance angle required would be 27°. If the slip frequency is much
lower, then the advance angle is much smaller. For a 0.1 cycle/s slip frequency, the closing
angle is now 5.4°. Thus, precise control of the point of synchronism can be obtained.
Several different schemes for automatic synchronizing can be developed depending on
economics, reliability, and operating system requirements. By using electromagnetic relays,
several relays are required to perform all functions. Static relays provide all the functions in
one unit.
4.4.3 Undervoltage relays (Device 27)
4.4.3.1 Application
An undervoltage relay is calibrated on decreasing voltage to close a set of contacts at a
speciﬁed voltage. The typical uses for this relay function include

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a) Bus undervoltage protection. The undervoltage relay may either alarm or trip
voltage-sensitive loads, such as induction motors, whenever the line voltage drops
below the calibrated setting. A time-delay relay is normally used to enable it to ride
through momentary sags and thus prevent nuisance operation. For electromechanical
relays, to prevent the inertia (or overtravel) of the time-delay relay from tripping the
circuit, an instantaneous undervoltage relay with its contacts connected in series with
the time undervoltage relay contacts may also be used to provide a fast reset time.
b) Source transfer scheme. The undervoltage relay is used to initiate the transfer and,
when desired, retransfer of a load from its normal source to a standby or emergency
power source. Due to the possibility of a motor load, this relay has a time delay in
order to preclude out-of-synchronism closures.
c) Permissive functions. An instantaneous undervoltage relay is used as a permissive
device to initiate or block certain action when the voltage falls below the dropout
setting.
d) Backup functions. A time-undervoltage relay may be used as a backup device follow-
ing the failure of other devices to operate properly. For example, a long time-delay
relay may be used to trip an isolated generator and its auxiliaries if the primary pro-
tective devices fail to do so.
e) Timing applications. A time-undervoltage relay can be used to insert a precise
amount of time delay in an operating sequence. Certain protective functions, such as
a negative-sequence overvoltage relay, may require a time delay to prevent nuisance
tripping.
Undervoltage relays may be either electromechanical or static.
4.4.3.2.1 Electromechanical design
Time-undervoltage relays of the electromechanical design generally use the induction disk
principle. When the applied voltage is above the pickup, the normally closed contacts open
and are maintained open as long as the voltage remains above the dropout voltage. When the
voltage is reduced to the dropout value and below, the relay contacts begin to close. The oper-
ating time is inversely related to the applied voltage, and several ranges of time delay are
available. Typical operating characteristics are shown in Figure 4-7. Frequency-compensated
models are available that maintain constant operating characteristics over a specified range of
frequency variation.
Instantaneous undervoltage relays of the electromechanical design are built in two basic
types. The first is a high-speed cylinder design that has a dropout time of less than 1.5 cycles
and a dropout voltage that can be accurately set over a wide calibration range. In a three-
phase design, the relay may also respond to a reverse phase-sequence condition. The second
type consists of a dc hinged-armature telephone relay rectified by a full-wave bridge for ac
operation. A Zener diode provides for an accurate operating point, the value of which is
determined by a rheostat. The dropout voltage is adjustable over a specified range, and the
operating time is approximately 1 cycle at 0 V.

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AC electromechanical hinged-armature relays cannot generally be used as undervoltage
relays because they would have to remain continuously picked up when voltage is nominal.
AC relays operated in this fashion would attempt to drop out every half-cycle (at voltage 0),
and the resulting vibration could cause early relay fatigue failure.
The voltage setting for time-delay electromechanical relays is typically adjustable by discrete
taps over a specified range. Various tap ranges are available depending on the application.
The operating time is adjustable by a time-dial setting. In the induction disk design, it is
continuously adjustable. Several ranges of time delay are available. The operating time is
specified at zero applied voltage when set on the maximum time-dial setting.
Instantaneous relays have dropout settings that are adjustable over a specified voltage range
depending on the application. The method of adjustment varies depending on the construc-
tion of the relay.
4.4.3.2.2 Static design
Time-undervoltage relays of the static design provide similar inverse time-operating charac-
teristics as the electromechanical design. Definite time characteristic timing is also available
with static relay designs. When the applied voltage is above the pickup (in the de-energized
position), a normally open contact is open and remains open as long as the voltage remains
above the pickup setting. When the voltage falls below the pickup setting, the relay begins its
timing operation. When the time delay has elapsed, based on the time-voltage operating char-
Figure 4-7—Typical time-voltage characteristic of an undervoltage relay

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acteristic, the output contacts close. Similar to the electromechanical design, the operating
time is inversely related to the applied voltage with several ranges of time delay available.
The typical operating characteristics shown in Figure 4-7 also apply to the static design.
These relays are also frequency compensated and are capable of withstanding high levels of
seismic stress without malfunction.
Voltage settings of static relays vary by manufacturer. They may be adjustable by discrete
taps or continuously over a specified range. Various tap ranges may also be available for
various applications. The operating time is adjustable by either a time-dial or definite time
setting. The definite time setting is typically in units of cycles or seconds.
4.4.4 Directional-power relay (Device 32)
4.4.4.1 Application
As the name implies, a directional-power relay functions when the real power component
(watts) flow in a circuit exceeds a preset level in a specified direction. Typical uses for this
relay function include
a) Source power flow control. On systems having in-plant generation operating in paral-
lel with the utility supply, a reverse-power relay sensing the incoming power from the
utility can be set to detect (and alarm or trip) when the generator begins to supply
power to the utility company. Plants designed to sell surplus power to the utility
would not use a reverse-power relay for this purpose, unless it was blocked by an
under-frequency relay.
b) Antimotoring of generators. This relay is used to detect the motoring power into a
generator that has not been disconnected from the system following a shutdown of its
driver. See Chapter 11 for further information.
c) Reverse power flow. A sensitive high-speed relay can be used to detect line-to-ground
faults on the delta side of a transformer bank (see the examples in Figure 4-8 and
Figure 4-9) by detecting the in-phase component of the transformer magnetizing
current. This occurs when another relay in the system trips the transformer’s primary
breaker and the transformer is energized through its secondary circuit.
In applying this relay, the relay operation should be delayed to prevent undesired operations
resulting from generator swings relative to the utility. The relay only need be fast enough to
permit a successful reclosure from the remote end of the line.
Directional-power relays may be either electromechanical or static.
Electromechanical units are available in three types:

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a) A single-phase induction cup power directional unit with or without an auxiliary tim-
ing element
b) A single-phase induction disk power directional element that provides an inherent
time delay
c) A polyphase directional unit consisting of three induction disk elements on a com-
mon vertical shaft
Maximum torque on the relay element occurs when the relay current is at a designated angle
relative to relay voltage; the maximum torque angle depends on the relay design. The relay is
connected to the VTs and CTs so the maximum relay torque occurs at unity power factor of
the load in the designated tripping direction. Figure 4-10 shows the proper connection for a
directional-power relay having a maximum torque angle of 90°.
Static directional-power relays are also designed in single- and three-phase versions.
Although a static relay does not develop rotational torque, the operating characteristics typi-
cally replicate that of the electromechanical design with the function of maximum relay
Figure 4-8—Application of directional power relay used to detect
line-to-ground faults (Example 1)
Figure 4-9—Application of directional power relay used to detect
line-to-ground faults (Example 2)

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torque occurring at unity power factor of the load in the designated tripping direction. Some
designs have the capability of adjusting for different angles of maximum torque.
4.4.5 Loss-of-excitation relay (Device 40)
4.4.5.1 Application
The loss-of-excitation relay is used to protect a synchronous motor or generator against
damage due to loss of excitation. Loss of excitation or severely reduced excitation can cause
generator heating, large voltage drops, and unstable operation. In severe cases, loss of
synchronism can occur. Common protection used for smaller motors consist of two types:
— An instantaneous dc undercurrent relay that monitors ﬁeld current
— A relay that monitors the relative angle between voltage and current and thereby
responds to power factor
On large synchronous motors (normally above 2200 kW) and most generators, an
impedance-measuring or var-measuring relay operating from current and voltage at the
machine stator terminals is used. The distance unit has either an impedance or mho character-
istic. When excitation to the generator is lost, the apparent impedance seen by the relay traces
a path into the relay’s tripping zone. See Figure 4-4a for the type of mho unit characteristic
used for protection of a generator. Additional discussion is given in Chapter 12.
The var relay provides an operating characteristic that is plotted in the complex power plane
as shown in Figure 4-11. The characteristic is represented by a line that is shifted 8º from the
horizontal axis. When converted to the impedance plane, this characteristic provides a mho
characteristic that has its diameter shifted 8º from the X axis as shown in Figure 4-12. The
relay is set in per-unit rated vars of the generator so that the characteristic falls above the
steady state stability limit.
NOTE—I leads E by 90°.
Figure 4-10—Directional power relay connection diagram

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4.4.5.2 Construction
The undercurrent relay is a dc polarized relay or a highly sensitive D’Arsonval
contact-making dc millivoltmeter. The power factor relay is static. The impedance-measuring
Figure 4-11—Var relay operating characteristic in the complex power plane
Figure 4-12—Var relay operating characteristic converted to
the impedance plane

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relay is an induction cylinder unit having directional characteristics. The var relay is also of
static design.
4.4.6 Phase balance current relay (Device 46)
4.4.6.1 Application
Phase balance relays provide motor or generator protection against unbalanced phase cur-
rents. Unbalanced currents are caused by
— An open fuse or conductor in a motor branch circuit or in the primary of a delta-wye-
connected transformer serving a group of motors,
— Unbalanced load conditions, or
— Single-phase switching in the distribution and transmission systems.
Two types of phase balance relays are normally applied: current balance and negative-
sequence overcurrent. The current balance relay operates when the difference in the
magnitude of root-mean-square (rms) currents in two phases exceeds a given percentage
value. The negative-sequence current relay operates on magnitude of negative-sequence
current, but is set in terms of I2
2
t, the thermal energy produced by this current. In order to set
the negative-sequence relay, the I2
2
t characteristic (or K factor) of the machine should be
specified.
4.4.6.2 Operation principles for a current balance relay
The electromechanical relay consists of two or three induction disk elements, each having
two current coils, as shown in View (a) and View (b) of Figure 4-13. These coils are con-
nected to different phases so that a closing torque is produced on the disk that is proportional
to the difference or unbalance between the currents in the two phases. The amount of unbal-
ance current required to close the contacts may be a fixed percentage, typically 25%, or it
may be a variable percentage, as shown by the operating characteristic in Figure 4-14.
The static relay is designed as an individual unit for motor or generator protection or may be
a part of an ac motor protective device that has several protective functions within the same
unit. The relay determines the difference between line currents and trips when the difference
exceeds a preset percentage of full-load current or when the difference exceeds a preset
ampere value (depending on the relay manufacturer). Tripping time is either inversely propor-
tional to the phase unbalance current or definite time.

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4.4.6.3 Operation principles of a negative-sequence relay
The electromechanical relay consists of an induction disk overcurrent relay and a negative-
sequence ﬁlter so that the relay responds only to negative-sequence currents. The relay
characteristics are extremely inverse, which provide essentially a constant I2
2t line. The
typical operating characteristic is shown in Figure 4-15.
Figure 4-13—Current balance relay connection diagrams
Figure 4-14—Typical current balance relay operating characteristic

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The static relay performs similarly to the electromechanical design. A typical connection dia-
gram is shown in View (c) of Figure 4-13. This relay typically provides two set points, which
allows an alarm signal at a sensitive, pretrip value of I2
2
t in addition to the trip setting.
Figure 4-15 shows typical characteristics of this relay.
4.4.7 Phase-sequence voltage relay (Device 47)
4.4.7.1 Application
The phase-sequence relays are used to protect ac machines from undervoltage and to prevent
starting on open or reverse phase sequence. Phase-sequence relays may also provide over-
voltage protection. Some phase-sequence relays do not give single-phase protection once the
motor is running because the dynamic action of the motor supports the open phase voltage at
or near its rated value. Often, a phase-sequence relay monitors the bus voltage and thus pro-
tects a group of motors.
The electromechanical version is an induction disk polyphase voltage relay. All units nor-
mally have an undervoltage pickup tap setting; some units are also available with time-dial
and overvoltage tap settings. Operating time is inversely related to applied voltage.
Figure 4-15—Typical n-s overcurrent relay operating characteristic

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4.4.8 Machine or transformer thermal relay (Device 49)
4.4.8.1 Application
Thermal relays are used to protect motors, generators, and transformers from damage due to
excessive long-term overloads.
Three types of thermal relays are available:
— Replica temperature relays, operating from CTs
— Bridge relays, operating from resistance temperature detectors (RTDs) located in the
protected equipment
— A combination relay, operating from a current signal biased by an RTD signal
Replica temperature relays usually consist of a coiled thermostatic metal spring mounted on a
shaft and a heater element that monitors the output of a CT in a power circuit. The character-
istics of the heater element and metal spring approximate the heating curve of the machine or
transformer. These relays may or may not be ambient compensated. This type of thermal
relay is normally applied to small (less than 1100 kW) motors where motor RTDs are not
generally included in the protected motor. However, if the motor is important, a more com-
plex protection scheme, discussed in Chapter 10, should be used.
Bridge temperature relays operate on the Wheatstone bridge principle using an RTD as a sen-
sor to precisely measure the temperature in a certain part of a motor or generator stator. This
relay may be applied to larger, more important motors, generators, and transformers where
monitoring the actual temperature in the windings is desirable. Static thermal relays, some
using microprocessor technology, also generate the motor heating curves. In some cases, the
heating curves are modiﬁed by inputs from winding RTDs; this provides precise protection
for motors and combines the best features of both relay types. The relay is available either as
an individual module or combined with other functions to provide complete motor protection
in a multifunction module. See Chapter 10 on motor protection for more details.
4.4.9 Time-overcurrent and instantaneous overcurrent relays
(Device 50, Device 51, Device 50/51, and Device 51V)
4.4.9.1 Application
By far, the most commonly used protective relays are the time-overcurrent and instantaneous
overcurrent relays. They are used as both primary and backup protective devices and are
applied in every protective zone in the system. Speciﬁc application information can be found
in Chapter 8 through Chapter 15, which describe the protection of major system components.
The time-overcurrent relay is selected to give a desired time-delay tripping characteristic ver-
sus applied current, whereas instantaneous overcurrent relays are selected to provide
high-speed tripping. The instantaneous unit may be applied by itself or included in the same

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enclosure as the time-overcurrent relay. For electromechanical relays, this is referred to as an
instantaneous trip attachment.
4.4.9.2 Time-delay overcurrent relay
The most commonly used time-delay relays for system protection use the induction disk
principle. Using the same principle as ac watthour meters, when applied to relay design, it
provides many varieties of time-current characteristics.
The principal component parts of an electromechanical induction disk overcurrent relay are
shown in Figure 4-16.
The elements of an induction disk relay are shown in Figure 4-17. The disk is mounted on a
rotating shaft, restrained by a spring. The moving contact is fastened to the shaft. The operat-
ing torque on the disk is produced by an electromagnet having a main (or operating current)
coil and a lag coil, which produce the out-of-phase magnetic ﬂux. A damping magnet pro-
vides restraint after the disk starts to move and contributes to the desired time characteristic.
Two adjustments exist: the pickup current tap and the time dial. The pickup current is deter-
mined by a series of discrete taps that are furnished in several current ranges. The time-dial
setting determines the initial position of the moving contact when the coil current is less than
the tap setting. Its setting controls the time necessary for the relay to close its contact. A relay
constructed on these principles has an inverse time characteristic. As a result, the relay oper-
ates slowly on small values of current above the tap setting. As the current increases, the time
of operation decreases. When the primary current is above the knee of the CT saturation
curve, the secondary current becomes less proportional to the primary current. The effect is
further complicated when the relay magnetic circuit also saturates; thus, the time delay
remains constant as a result. Different time-current curves can be obtained by modiﬁcations
of electromagnetic design; some of these typical curves are shown in Figure 4-18.
Figure 4-16—Induction disk overcurrent relay with instantaneous
attachment (relay removed from drawout case)

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An auxiliary seal-in relay is incorporated into the relay case to lighten the current-carrying
duty of the moving contact. It also operates the target indicator.
An inherent characteristic with induction disk relay design is that of disk overtravel. As the
disk rotates, it develops an inertia. As such, when the fault current is removed, the disk
Figure 4-17—Elementary induction disk relay
Figure 4-18—Comparison of typical curve shapes for overcurrent relays

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continues to rotate for some distance. Referred to as overtravel, the continued travel distance
is dependent on the torque and inertia developed during operation. Depending on the distance
the disk has traveled and the magnitude of the disk inertia when the fault current is removed,
it is possible the inertia will cause sufficient rotation to result in the contact closure. Thus, an
unnecessary trip operation is produced. Typically, an additional 0.1 s is added to the time sep-
aration between the electromechanical relay time-current curve and the adjacent upstream
device time-current curve. The purpose of this additional separation is to avoid unnecessary
tripping of the upstream device after the primary device has cleared the fault.
Time-current characteristic curves for static relays are obtained through the use of analog or
digital circuits. Time-current characteristic curves and tap ranges are similar to the curves and
ranges provided in induction disk relays. Static overcurrent relays have the same application
as induction disk relays and are particularly useful where severe vibration specifications or
seismic shock is imposed. In addition, static overcurrent relays can provide faster reset times
and have no significant overtravel.
4.4.9.3 Instantaneous overcurrent relay
Instantaneous overcurrent relays are designed to operate without any intentional time delay.
Typical operating times are in the range of 0.5 cycle to 2 cycles. In the electromechanical
design, the reset of the unit integrates over a specific time and is dependent upon dynamics
within the design of the relay. Static designs typically provide instantaneous reset
capabilities. Newer static designs provide the user with a selection of either instantaneous or
integrating reset. This design gives the user the flexibility to utilize this relay in various
applications.
Two types of electromechanical instantaneous relays exist and use the principle of electro-
magnetic attraction: solenoid (or plunger) and clapper (or hinged-armature) (see Figure 4-19
and Figure 4-20, respectively). The basic elements of the solenoid relay are a solenoid and a
movable plunger of soft iron. The pickup current is determined by the position of the plunger
in the solenoid. A calibration screw may be provided to adjust the position of the plunger.
These relays are of single-phase design with up to three relays mounted in a common
enclosure.
In a clapper relay, a hinged armature that is held open by a restraining spring is attracted to
the pole face of an electromagnet. The magnetic pull of the electromagnet is proportional to
the coil current. The pickup current is the coil current required to overcome the tension of the
spring, and it may be calibrated over a specified range. In some applications, the pickup
current can be varied by adjusting the position of a slug in the pole. The clapper relay is
normally the one found in an induction relay case when a “50/51” (i.e., time-overcurrent with
instantaneous) function is specified. For some electromechanical relays, separate Device 50
relays may be required when low pickup settings (e.g., 0.5 A) are desired because these low
pickup settings may not be available in a combination Device 50/51 relay.

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In static designs, instantaneous overcurrent functions are normally combined with the time-
overcurrent units and provided with all three phases in one enclosure. This configuration
provides space savings and is generally more cost efficient. Individual instantaneous units are
available where applications do not warrant the additional functions of time-overcurrent.
4.4.9.4 Overcurrent relay types and their characteristic curves
Time-overcurrent relays are available with many different current ranges and tap settings.
The range of tap settings that are typically available are shown in Table 4-3.
The relays can be specified to have either single or double circuit closing contacts.
Figure 4-19—Solenoid (or plunger) instantaneous relay
Figure 4-20—Clapper (or hinged-armature) instantaneous relay

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Figure 4-18 compares the basic shapes of ﬁve typical relay curves at the No. 5 time dial.
Manufacturer’s published time-current curves show the relay operating times for a full range
of time-dial settings and multiples of tap current applied to the relay.
4.4.9.5 Special types of overcurrent relays
By adding different elements to the basic overcurrent relay, special types of overcurrent
relays are derived, in particular, the voltage-dependent overcurrent relay.
Voltage-dependent overcurrent relays are used in generator circuits for backup during exter-
nal faults. When an external fault occurs, the system voltage collapses to a relatively low
value; but when an overload occurs, the voltage drop is relatively small. These relays utilize
the voltage to modify the time-current characteristics so that the relay rides out permissible
power swings, but gives fast response when tripping due to faults. This overcurrent relay has
two variations: voltage-controlled and voltage-restrained. Electromechanical and static relays
use the same principles in the design of voltage-dependent overcurrent relays. The main dif-
ference is in the methods used to accomplish this task.
In the voltage-controlled overcurrent relay, an auxiliary undervoltage element controls the
operation of the induction disk element. When the applied voltage drops below a predeter-
mined level, an undervoltage contact is closed in a shaded pole circuit, permitting the relay to
develop torque and operate as a conventional overcurrent relay. Thus, the undervoltage unit
supervises the operating coil and permits it to operate only when the voltage is below a preset
value.
The voltage-restrained relay has a voltage element that provides restraining torque propor-
tional to voltage and thus actually shifts the relay pickup current. Hence, the relay becomes
more sensitive the larger the voltage drop (during faults), but is relatively insensitive at nomi-
nal voltage. The relay is set so it rides through permissible power swings at nominal voltage.
Table 4-3—Typical tap ranges and settings of time-overcurrent relays
Tap range Tap settings
0.5-2.5 (or 0.5-2) 0.5, 0.6, 0.8, 1.0, 1.2, 1.5, 2.0, 2.5
0.5-4 0.5, 0.6, 0.7, 0.8, 1.0, 1.2,
1.5, 2.0, 2.5, 3.0, 4.0
1.5-6 (or 2-6) 1.5, 2, 2.5, 3, 3.5, 4, 5, 6
4-16 (or 4-12) 4, 5, 6, 7, 8, 10, 12, 16
1-12 1.0, 1.2, 1.5, 2.0, 2.5, 3.0,
3.5, 4, 5, 6, 7, 8, 10, 12

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See Chapter 12 for additional discussion on the application of this relay for generator
protection.
The characteristics of the static voltage-dependent relays are similar to the characteristics
described in 4.4.9.5.1 for electromechanical devices. These functions are accomplished
through either analog or digital circuits. Voltage-controlled relays inhibit the overcurrent
function from producing an output based on the voltage magnitude. If the voltage drops
below the setpoint of the relay, the overcurrent function operates as normal. If the current
increases above the setpoint without a decrease in voltage below its setpoint, the relay does
not operate. This voltage supervision prevents nuisance tripping for any power swings that
may cause the current to rise momentarily above the relay’s overcurrent setpoint.
The voltage-restrained relay similarly reduces the overcurrent pickup setting proportional to
the voltage drop. If the voltage drops to 50% of nominal, the overcurrent pickup point also
decreases to 50% of its original value.
4.4.10 Overvoltage relay (Device 59)
4.4.10.1 Application
Overvoltage relays are typically used to monitor voltage levels on buses or generators to ini-
tiate switching or tripping operations. Other applications for this relay are as follows:
a) Simple overvoltage bus protection. The relay may either alarm or trip voltage-
sensitive loads or circuits in order to protect them against sustained overvoltage
conditions.
b) Ground-fault detection. Two methods are currently used to detect ground faults:
1) One method measures the zero-sequence voltage across the corner of a broken
delta secondary of three VTs that are connected grounded wye-broken delta. A
low-pickup relay is used because normally no voltage exists across the relay.
During a ground fault on a high-resistance grounded-neutral or ungrounded sys-
tem, the applied voltage causes the relay to operate in a predetermined period. A
resistor may be required across the relay to prevent damage to the VT due to fer-
roresonance.
2) The second method measures the actual voltage across a high ohmic value resis-
tance that is connected between the system neutral and ground. The voltage
appearing across the relay (and the resistor) during a ground fault may be sev-
eral times the pickup voltage so that the relay can be set to operate in a speciﬁc
time. The maximum continuous operating voltage limit of the relay should not
be exceeded. In medium-voltage systems, a stepdown transformer is used with
windings rated 120 V or 240 V. Using a 240 V secondary of a 4160 V/240 V
transformer produces a maximum of 139 V on the secondary during a ground
fault. Often, a 150 V meter is used with this relay.

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An overvoltage relay is designed to operate on voltage magnitude. When the voltage rises
above the pickup setting of the relay, output contacts close to provide a trip signal. Overvolt-
age relays may be either electromechanical or static.
The pickup (or tap) voltage is adjustable by discrete taps over a specified range. Various tap
ranges are available depending on the relay design. In addition, some static relays provide
continuous adjustment of the voltage pickup across the specified tap range.
Time-overvoltage relays of the electromechanical design generally use the induction disk
principle. When the applied voltage is above the pickup voltage, the normally open contacts
begin to close at a rate dependent on the percentage of voltage above the pickup value. This
action results in a typical inverse operating characteristic. Frequency-compensated models
are available that maintain constant operating characteristics over a specified range of fre-
quency variation.
The low-pickup relays used in ground-fault applications have filters in the coil circuits tuned
to filter out third harmonic voltages when applied to generator neutrals. This makes them less
sensitive to third harmonic voltages that may be present under normal conditions.
Instantaneous overvoltage relays are typically plunger relays where the armature is adjustable
on the plunger rod to vary the pickup over the adjustment range. The operating time is
approximately 1 cycle for voltage greater than 1.5 times the pickup setting. This type of relay
may be used either as an overvoltage or an undervoltage relay simply by calibrating the relay
at the desired pickup or dropout voltage, although operation in the undervoltage mode is not
normally recommended. Many of these relays have a dropout-to-pickup ratio of 90% to 98%.
Care should be taken in applying these plunger relays because of the possibility of contact
chatter when the pickup setting is near the normal voltage. Relays experience increased wear
under those conditions.
Time-overvoltage relays of the static design provide similar inverse operating characteristics
to the electromechanical design. These relays are frequency compensated and are capable of
withstanding high levels of seismic stress without malfunction. The capability to filter third
harmonic current is also available in the static design relays.
4.4.11 Voltage balance relay (Device 60)
A voltage balance relay may be used to block relays or other devices that operate incorrectly
when a VT fuse blows. Two sets of VTs are required that are normally connected to the same
primary source during the time when blown fuse protection is required. The relay is
connected as shown in Figure 4-21. Normally, open contacts are used to ring an alarm, and
normally closed contacts are used to open trip circuits of relays subject to misoperation, such

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as voltage-restrained relays, synchronizing relays, impedance relays, negative-sequence
relays, and in general any relay that operates from both current and voltage inputs. Typical
examples include to prevent incorrect operation of the loss-of-excitation relay (Device 40) or
the backup overcurrent relay (Device 51V) in a generator circuit because of loss of voltage on
a VT. Another application may be to inhibit the operation of a voltage regulator on a
generator. The operating time is adjusted at the factory (e.g., 200 ms is typical), and it is
sufﬁciently fast to disable these relays before they have a chance to trip the circuit breaker.
A voltage balance relay may also be used to detect a small voltage unbalance in a three-phase
system. The principal application of this relay is to protect three-phase motors from the
damage that may be caused by single-phase operation. The relay can detect single-phase
conditions for light loads as well as heavy loads by detecting the negative-sequence
component of voltage. Typically, an external timer relay is also required.
4.4.12 Directional overcurrent relay (Device 67 and Device 67G)
Directional overcurrent relays are used to provide sensitive tripping for fault currents in one
(tripping) direction and not trip for load or fault currents in the reverse (normal) direction.
Typical applications of this relay include
a) Protection of a network of distribution lines (not radial feeders) where tripping in a
given direction to provide selective operation is required. In View (a) of Figure 4-22,
the tripping direction is for faults within the line section that are above the pickup
setting of the relay. For faults on other lines from the bus at Substation A, the operat-
ing current in the relay at Substation A reverses, and the relay does not operate. Both
phase and ground relays are normally used.
b) Detection of uncleared faults on the utility line where fault current can be back-fed
through the industrial system from in-plant generation or a second utility line, as
illustrated in View (b) of Figure 4-22. The fault current magnitude fed from in-plant
Figure 4-21—Voltage balance relay

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generators and motors to the utility line normally is smaller than when it is fed from
the utility line to the plant; therefore, a sensitive relay setting is required to respond to
faults on the utility system.
c) Sensitive high-speed ground-fault protection of transformers and generators, as
shown in View (c) and View (d) of Figure 4-22. The directional control gives the
relay the characteristics of the differential protective scheme described in 4.4.15 and
makes it particularly useful. Product directional relays may be used for this
application.
d) Applications required by Article 450 of the National Electrical Code®
(NEC®
)
(NFPA 70-1999) [B66]2
, where transformers are applied in parallel with a closed sec-
ondary bus tie circuit breaker.
e) Other applications where the desired objectives can be achieved by distinguishing
between the direction of current ﬂow.
(a) Line protection using directional phase relays
(b) Protection of industrial plant bus from uncleared utility line faults
(c) Directional ground-fault protection of transformer using product relays
(d) Directional ground-fault protection of generator using product relays
Figure 4-22—Typical applications for directional current relays

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In all applications, a reference or polarizing input is required to provide the directional con-
trol. The polarizing input may be a current or voltage, or both. Current polarizing input is
obtained from a CT in the neutral-grounding conductor of a generator or transformer, as
shown in View (c) and View (d) of Figure 4-22. An auxiliary CT may be required to match
the CT ratio of the operating current when the relay is connected for differential protection.
The auxiliary CT is used to provide sufficient operating current during faults within the
protection zone and sufficient restraint for faults outside the protection zone. Potential polar-
izing input for phase relays is obtained from VTs, either two units connected line to line in
open delta or three units connected line to ground in wye-wye, as shown in View (a) of
Figure 4-22. The zero-sequence potential required for polarizing ground relays is obtained
using three VTs connected wye-delta, with the potential coil connected in series with the
secondary windings. This configuration is referred to as the broken delta or corner-of-the-
delta connection. Three auxiliary VTs may be used, connected as shown in View (b) of
Figure 4-22, or fully rated VTs may be used.
Directional overcurrent relays consist of an overcurrent function and a directional function.
Operation of the overcurrent function is controlled by the directional function, which deter-
mines its direction of operation from a polarizing input. The polarizing input can be current
or voltage, or both. The directional overcurrent relay shown in Figure 4-18 comprises an elec-
tromechanical induction disk element and an instantaneous directional power element. When
the current is flowing in the tripping direction, the directional function enables the overcur-
rent function to operate when the current exceeds its tap setting. If the fault current is flowing
in the reverse direction, the directional function inhibits the overcurrent function and prevents
operation.
The electromagnetic relay consists of a conventional induction disk time-overcurrent element
and an instantaneous power directional element arranged as shown in Figure 4-23. The vari-
ous time-delay characteristics may be selected as described in 4.4.9.4.
The directional element has an operating current coil and a polarizing coil. The latter is ener-
gized by either voltage or current in order to determine the direction of current flow. Some
units are dual polarized, having both a voltage and current coil. Maximum positive torque is
produced (in tripping direction) when the angle between the operating coil current and the
polarizing coil quantity is equal to the maximum torque angles of the relay. This characteris-
tic of the directional element is shown in Figure 4-24.
For example, maximum torque may be produced when the operating current leads the voltage
by 45°. In a current-polarized relay, maximum torque may occur when the two currents are
in-phase (i.e., zero-phase angle). The angles of maximum torque vary; therefore, manufactur-
ers’ data should be obtained. The relay is then connected to the CT and VT circuits so that
during the fault conditions being protected, the relay produces maximum torque for tripping.

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Figure 4-23—Directionally controlled overcurrent relay
Figure 4-24—Characteristics of a directional element

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A directional instantaneous overcurrent element is optionally available for mounting within
the enclosure. Its operation is supervised by the same directional element used for the time-
overcurrent element.
The static relay functions similarly to its electromechanical counterpart using analog or
digital circuit designs similar to the design shown in Figure 4-25. The relay has a current
input for the overcurrent and current-polarizing circuit and a voltage input for the voltage-
polarizing circuit. The input quantities are generally supplied to a comparator or
microprocessor, which determines whether the measured values are above the pickup settings
and in the tripping direction. If both conditions are satisﬁed for the preset time delay, then a
signal is sent to the output to provide contact closure.
The directional operating characteristic for the static relay is also adjustable over a range to
allow matching to the line and system conditions. Because no torque is developed to turn a
disk, the characteristic setting is referred to as the angle of sensitivity. Similarly, maximum
sensitivity is produced (in tripping direction) when the angle between the current and the
polarizing quantity is equal to the maximum angle setting of the relay.
The directional characteristic of a static relay is also depicted by a line (180º angle) through
the origin of an R-X diagram that is perpendicular to the angle of maximum sensitivity. Some
static relays have the capability to reduce the angle of the characteristic line (or region of
operation) to something less than 180º, as shown in Figure 4-26. This capability helps prevent
false tripping for certain power system conditions, such as mutual coupling on adjacent lines.
Figure 4-25—Block diagram of a static directional overcurrent relay

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Static relays also typically have an option available for an instantaneous overcurrent function
controlled by the directional function.
The time-delay characteristics are similar to the electromechanical as described in 4.4.9.4
4.4.12.3 Instantaneous directional overcurrent relay
An electromagnetic relay has an instantaneous induction cup element that is controlled by an
instantaneous power directional element, as described in 4.4.12.2. The operating current is
adjustable over a selected range, and the directional characteristics should be identiﬁed and
applied in the same manner as described in 4.4.12.2.
4.4.12.4 Product directional ground relay
The product directional ground relay operates on the product of the current in the operating
coil and the voltage/current in the polarizing coil. It provides sensitive protection in the
desired direction of current ﬂow. The operating element of an electromagnetic relay may be
either an induction disk element having an adjustable time delay for selectivity or an induc-
tion cup element for high-speed operation. The directional characteristics of the relay should
be determined in order to assure correct application. The application of product relays in
directional applications on a network system is generally complex; this kind of relay is
normally reserved for use in ground-fault protection of wye-connected generator and trans-
former windings.
Figure 4-26—Region of operation characteristic for
a static direction overcurrent relay

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4.4.13 Frequency relays (Device 81)
A frequency relay is a device that operates at a predetermined value of frequency: either
under or over normal system frequency or rate of change of frequency. When it is used to
operate on a predetermined value below nominal frequency, it is generally called an
underfrequency relay. When it operates on a predetermined value above nominal, it is called
an overfrequency relay. Both functions are often included in the same case, but are utilized
for different purposes.
Underfrequency relays should be applied when the loads are supplied either by local genera-
tors exclusively or by a combination of local generation and utility tie (see Figure 4-27a,
Figure 4-27b, and Figure 4-27c). When a major generator drops off line unexpectedly in a
system supplied only by local generation (see Figure 4-27a), the underfrequency relays auto-
matically open plant load circuit breakers so the load matches, or is less than, the remaining
generation. Otherwise, moderate to severe overloads on the remaining generators could
plunge the plant into a blackout before the operator can react. This application also applies
when the utility disconnects a plant system that has local generation (see Figure 4-27b).
When the utility does not disconnect the plant during an underfrequency condition, the
plant’s generators begin to supply the utility system loads, causing overloading of the local
generators. To prevent this event from happening, an underfrequency relay may be used to
supervise an extremely sensitive directional power relay (see Figure 4-27c). The underfre-
quency and reverse-power relay trip contacts are connected in series in the trip circuit of the
incoming circuit breaker so that both relays would have to operate together in order to trip the
incoming circuit breaker.
Figure 4-27a—Load-shedding scheme for system with only local generation

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When an overload exists (i.e., the load exceeds the available generation), the generators begin
to slow down and the frequency drops. The underfrequency relay operates at a specific (i.e.,
preset) frequency below nominal to trip off a predetermined amount of load so the most criti-
cal load remains running with the available generation. More than one underfrequency relay
may be used to permit a number of steps of load shedding, depending on the severity of the
overload. For instance, X% of the load may be removed at 59.5 Hz, Y% of the load removed
at 59 Hz, and Z% of the load removed at 58.5 Hz, for a three-step load-shedding scheme. The
number of load-shedding steps, the amount of load shed at each step, and the frequency set-
tings for each step should be determined by a system study. Also, assigning a priority to each
load is necessary so that the loads are removed on a priority basis, with the lowest priority
loads being removed first.
Overfrequency relays are often applied to generators. These relays protect against overspeed
during startup or when the unit is suddenly separated from the system with little or no load.
Figure 4-27b—Load-shedding scheme for loss of an external system
Figure 4-27c—Tripping incoming breaker for power outflow to external loads

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Relay contacts either sound an alarm or remove fuel input to the prime mover. In other words,
for gas or diesel engines or turbines, the fuel line supply would be closed; for steam turbines
or steam engines, the steam supply valves would be closed; and for hydro turbines, the wicket
gates would be closed and the water supply would then be closed off.
Two types of electromechanical frequency relays are available: induction disk and induction
cup (or cylinder).
The induction disk relay is subjected to two ac fluxes whose phase relationship changes with
frequency to produce contact-opening torque above the frequency setting and closing torque
below it. A time dial is used to adjust the initial contact separation that determines the operat-
ing time for a given applied frequency. The greater the rate at which the frequency drops, the
faster the relay operates for a given time-dial setting. The induction disk underfrequency
relay is accurate to within 0.1 Hz to 0.2 Hz and is designed for applications where high trip-
ping speed is not essential.
The induction cup underfrequency relay is more accurate and faster than the induction disk
model. The operating principle is the same as the induction disk relay. Two ac fluxes, whose
phase relationship changes with frequency, produce contact-closing torque in the cup unit
when the frequency drops below the setting. The contacts have a fixed initial separation; the
greater the rate of frequency decline, the faster the contacts close. The contacts may close in
as little as 5 cycles to 6 cycles after application of the underfrequency potential. Because
phase shifts in the ac potential supply due to faults or fault clearing may cause incorrect oper-
ation, at least 6 cycles of intentional delay should be added before tripping.
The frequency accuracy of this relay is about ±0.1 Hz. Induction disk and induction cup
underfrequency relays usually may be adjusted at 90% to 100% of rated frequency; overfre-
quency relays, from 100% to 110%.
Electromechanical frequency relays are typically available with only one set point per relay.
In applications where multiple setpoints are required, additional relays would be necessary
for each set point.
Some static or microprocessor relays operate on a specific frequency with definite or inverse
characteristic operating times. Other static relays operate on the rate of change of frequency.
Static relays typically measure once each cycle at a zero crossing on the input voltage wave-
form. The relay calculates the frequency based on the time between measurement points each
cycle. If the frequency is outside the set range of operation for the set time delay, the output
contacts close and provide a trip signal.

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Static frequency relays can also inhibit operation when the voltage falls below a preset value.
This action reduces the probability of operation under fault conditions when the voltage, and
possibly the frequency, may drop.
In addition, static frequency relays are available with multiple set points (up to four set
points) in one relay, each selectable to operate for underfrequency or overfrequency
conditions.
4.4.14 Lockout relay (Device 86)
Although a lockout relay is not a protective relay, it is included in this chapter because it is
used widely in conjunction with relaying schemes. This relay is a high-speed, multicontact,
manually or electrically reset auxiliary relay for multiplying contacts, increasing contact rat-
ing, isolating circuits, and tripping and locking out circuit breakers. The relay is operated by
differential relays, such as a transformer or bus differential, and other protective relays. The
lockout relay in turn trips all the source and feeder circuit breakers as required to isolate the
fault. The relay must be reset before any of the circuit breakers can be reenergized. The man-
ual reset prevents reclosing the breakers before the fault is repaired.
In general, the contacts can carry and interrupt higher values of control power current than
the protective relay can. In addition to tripping functions with the normally open (NO)
contacts, the relay normally closed (NC) contacts are opened when tripped, and these NC
contacts prevent any automatic reclosure until Device 86 has been manually reset.
4.4.15 Differential and pilot wire relays (Device 87)
4.4.15.1 Application of differential relays
A differential relay operates by summing the current flowing into and out of a protected cir-
cuit zone. Normally, the current flowing into a circuit zone equals the current flowing out, and
no differential current flows in the relay. If a fault occurs in the circuit zone, part of the cur-
rent flowing in is diverted into the fault; and the current flowing out of the circuit element is
less than the current flowing in. As a result, a differential current flows in the relay. If this dif-
ferential current is above a preset value, the relay operates. Differential protection may be
applied to any section of a circuit and is used extensively to detect and initiate the isolation of
internal faults in large motors, generators, lines or cables, transformers, and buses. It detects
these faults immediately and is designed to be insensitive to overloads or faults outside the
differentially protected section.
Differential relays generally do not detect turn-to-turn coil failures on motors, generators, or
transformers.
Differential relays provide high-speed, sensitive, and inherently selective protection. The
types of relays are
a) Overcurrent differential
b) Percentage differential

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1) Fixed percentage (restraint) differential
2) Variable percentage (restraint) differential
3) Harmonic-restraint percentage differential
c) High-impedance differential relay
d) Pilot wire differential
The correct selection and application of CTs used in differential protection schemes are
critical to the proper operation of these schemes. The proper matching of relay and CT
characteristics is a prime design requirement (see Chapter 3).
4.4.15.2 Overcurrent differential relays (Device 87)
An overcurrent differential relay operates on a fixed current differential and can be easily
affected by CT errors. It is the least expensive form of differential relaying, but it has the least
sensitive settings compared to other forms, especially for detecting low-level ground faults.
Figure 4-28a shows differential protection applied on one phase. (Three relays—one per
phase—are required.) Both ends of the protection zone should be available for the installation
of the CTs. Under normal conditions, the current flowing in each CT secondary winding is
the same, and the differential current flowing through the relay operating winding is zero. For
an internal fault in the zone, the CT currents are no longer the same, and the differential cur-
rent flows through the relay operating circuit. When the current through the relay’s operating
circuit exceeds its pickup setting, the relay provides an output to trip the circuit breakers.
Under normal operating conditions, circumstances may produce a differential current to flow
through the operating winding of the relay. One example of this situation is CT performance.
CTs do not always perform exactly in accordance with their ratios. This difference is caused
by minor variations in manufacture, differences in secondary loadings, and differences in
magnetic history. Where a prolonged dc component exists in the primary fault current, such
Figure 4-28a—Overcurrent relay used for differential protection,
one phase shown

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as invariably occurs close to generators, the CTs do not saturate equally, and a substantial
relay operating current can be expected to flow. Hence, if overcurrent differential relays are
used, they have to be set so that they do not operate on the maximum error current, which can
flow in the relay during an external fault. Because of the sensitiveness of this circuit, the over-
current relay pickup should be set high enough to allow for these minor variations. However,
while increasing its security, the higher pickup settings reduce the sensitivity of this circuit.
To address this problem without sacrificing sensitivity, the percentage differential relay is
usually used. A high-speed, economical overcurrent differential relay can be applied to motor
protection for phase-to-phase and phase-to-ground faults. Figure 4-28b shows how one toroi-
dal CT per phase measures the phase current and produces a differential current to the relay
for a fault. Fault currents as low as 2 A may be detected, and this application should follow
the manufacturer’s recommendations concerning the CTs and the relay.
4.4.15.3 Percentage differential relays (Device 87T, Device 87B, Device 87M,
and Device 87G)
4.4.15.3.1 Application
Percentage differential relays are generally used in transformer, bus, motor, or generator
applications. The advantage of this relay is its insensitivity to high currents flowing into faults
outside its protection zone when CT errors are more likely to produce erroneous differential
currents. However, the relay is highly sensitive to faults within its zone of protection.
The three types of percentage differential relays are fixed percentage, variable percentage,
and harmonic-restraint percentage. The fixed percentage and variable percentage relays are
used for all the applications mentioned in the previous paragraph, but the harmonic-restraint
percentage differential relay is used primarily for transformer applications.
Figure 4-28b—Differential protection of a motor using donut CTs and
overcurrent relays

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The variable percentage differential relay is more sensitive and can detect low-level faults
within its protection zone and is less likely to have nuisance tripping for severe faults outside
its protection zone than the fixed percentage relay. Generator protection relays are usually
variable percentage. Less sensitive variable percentage differential relays should be selected
for transformer protection compared with the fixed percentage differential relays used for
bus, motor, or generator applications. This distinction is made to prevent nuisance tripping
due to magnetizing inrush current that flows through only the power transformer’s primary
circuit CTs during energization. For transformers, the standard sensitivities of these relays
approach current values that may be as high as 50% of the transformer’s full load current.
The harmonic-restraint percentage differential relay has the feature of offering more restraint
to tripping when transformer inrush currents are present compared to the standard percentage
differential relay. Hence, the relay can achieve fault current sensitivities (or slope settings) of
between 15% and 60% of the transformer’s rated current. Because the inrush currents are rich
in harmonics, with second harmonic predominant, a combination of the second and higher
order harmonic currents is used to restrain the relay on inrush.
Because of the different voltage levels and CT ratios, matching the secondary currents from
the transformer into the relay becomes necessary when applying percentage differential pro-
tection to power transformers. The relay accomplishes this task by providing a range of taps
that scale the current into each input to the desired magnitude for internal comparison. The
current from the input circuits should be matched typically to within 5%. This normally can
be accomplished by selecting the appropriate combination of relay taps. However, in cases
where the range of tap settings is too limited, tapped auxiliary CTs are required. Figure 4-29
shows a connection diagram for a fixed percentage differential relay applied to protect a
transformer.
Electromechanical percentage differential relays used for bus protection applications typi-
cally do not have taps. Therefore, all CTs should have the same ratio and characteristics.
Static relays, however, are available with taps for use with CTs that have different ratios.
4.4.15.3.2 Operating principles
4.4.15.3.2.1 Electromechanical design
The electromechanical differential relay uses the induction principle. It is connected as
shown in Figure 4-30. Under normal conditions, current circulates through the CTs and relay-
restraining coils R1 and R2; no current flows through the operating coil O. The current in the
relay-restraining coils produces a restraining or contact-opening torque. An internal fault in
the protected machine unbalances the secondary currents and forces a differential current I0
through the relay-operating coil.
For a fixed percentage differential relay, the amount of differential or operating current
required to overcome the restraining torque and close the relay is a fixed (or constant)
percentage of the restraining current. The operating characteristic for this relay is shown in
Figure 4-31a. As an example, for a setting of 10% on a fixed percentage differential relay, the
relay would trip if the operating current were greater than or equal to 10% of the restraint

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current. In a variable percentage relay, the operating current required to operate the relay is a
variable percentage of the restraining current, having a higher percentage at high fault-current
levels. The operating characteristic for this relay is shown in Figure 4-31b.
Figure 4-29—Basic relay connections (one phase) for ﬁxed percentage
restraint differential relay
Figure 4-30—Basic relay connections (one phase) for ﬁxed percentage

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The number of restraint elements in the relay is a function of application for which the relay
is designed. A generator or motor differential relay contains two restraint elements, where a
relay intended for bus or transformer protection may have multiple restraint elements. All
relays are single-phase units and thus require three relays for a complete installation.
4.4.15.3.2.2 Static design
The static percentage differential relay consists of various functions, as shown in the block
diagram of Figure 4-32. Because of the flexibility of the static technology, these functions can
be configured for a single-phase unit or connected together to provide a three-phase relay.
The relay generally consists of restraint, operating, sensing, trip, and indicating functions. If
the relay is a microprocessor-based design, the restraint and operating functions are accom-
plished with the microprocessor.
Figure 4-31a—Typical operating characteristic of a fixed percentage
Figure 4-31b—Typical operating characteristic of a variable percentage

IEEE
The input current is normally scaled to the appropriate magnitude based on the tap setting of
each input circuit. Depending on relay design, these scaled quantities are then input to a
phase-shifting circuit or directly into the restraining functions. The restraint function senses
the phase current and selects its reference value. The restraint reference level, typically a
function of the input current, may vary between different manufacturers. The operating
current for each phase is then compared to the percentage slope setting and the restraint
reference levels. If the magnitude of current in the operating circuit is in excess of the set
percentage restraint, the relay closes its contact to trip the circuit breakers.
4.4.15.3.3 Harmonic-restraint percentage differential relays (Device 87T)
The connection diagram for delta-wye transformer protection using a harmonic-restraint
percentage differential relay is shown in Figure 4-33. Harmonic-restraint relays use the
harmonic content of transformer energization current to inhibit differential operation. When a
transformer is energized, the current on one side increases, producing a difference current
that would cause the differential relay to operate. This energization current contains a
signiﬁcant magnitude of certain harmonic currents. The relay measures the magnitude of
various harmonic currents and, when above a preset percentage of fundamental, inhibits
operation. Protection for faults during transformer energization is provided by an
unrestrained overcurrent function.
Figure 4-32—Functional block diagram for a static percentage differential
relay

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The electromechanical relay consists of transformer and rectifier units connected in restraint
and operating configurations. The output of these units is applied to the differential unit and
causes it to close its trip contact when the operating current exceeds the restraint current by
an amount greater than the relay characteristic.
The harmonic-restraint element is constructed similarly, except that filters block the funda-
mental frequency current to the restraint unit while directing harmonic current to the restraint
unit. The operating unit of this element receives only fundamental frequency current, while
harmonics are blocked. This design causes the relay to be insensitive to the harmonic current
that flows during transformer energization. An instantaneous trip unit is included in the oper-
ating circuit to provide fast operating times on very high internal faults. These relays have
current taps that are used to correct for mismatch between the currents from the CTs in the
power transformer’s primary and secondary circuits. Relay sensitivity can be adjusted by
selecting an appropriate slope tap unless the relay has a variable percentage characteristic.
Tap changers should be considered in the selection of the slope. A tap changer range of ±5%
would add 10% to the slope of whatever else is considered.
The overall relay operating time is between 1 cycle and 2 cycles.
Static relays similarly filter the input currents to the relay for various harmonic currents. The
output is then compared to the reference setting and, if in excess, provides a signal to inhibit
relay operation during transformer energization. This situation is shown in Figure 4-32.
Figure 4-33—Harmonic-restraint percentage differential relay connection
diagram for a delta-wye connected transformer

IEEE
4.4.15.4 High-impedance differential relays (Device 87B)
The high-impedance differential relay, used primarily for bus protection, avoids the problem
of unequal CT performance by loading transformers with a high-impedance relay unit. For
faults outside the protected zone (i.e., external faults), there is a high degree of error in the
CTs in the faulted circuit. A higher-than-normal voltage is developed across the relay (typi-
cally having an impedance of 1700 Ω to 2600 Ω), and hence a higher voltage is impressed
across the CT, which increases the CT excitation current. As a result, CT error currents are
forced through the equivalent magnetizing impedance of the CTs rather than through the high
impedance of the relay. However, for faults within the protected zone, the CT error currents
are small, the CT magnetizing impedances appear to be almost infinite, and the current flows
through the relay coil.
The connection diagram for the high-impedance differential relay, designed to operate on bus
circuits, is shown in Figure 4-34. The electromechanical relay consists of an overvoltage unit
and an instantaneous overcurrent unit (either plunger or clapper). The overvoltage unit is con-
nected across the paralleled secondaries of the CTs. The magnitude of voltage across the
relay is a function of the fault location (i.e., internal or external to the protected zone), the
resistance of the CT secondary leads and CT, the CT performance, the CT ratio, and the mag-
nitude of fault current. The overvoltage unit operates when the voltage exceeds the pickup
setting. When a fault occurs in the relay’s protection zone, the CT current is directed to the
high-impedance relay. A nonlinear resistor in the relay limits the voltage developed across the
relay to a value that does not overstress the relay’s insulation. This nonlinear element limits
the voltage by permitting a large current to flow through it. The instantaneous overcurrent
unit in the relay is connected in series with the nonlinear resistor and operates when the cur-
rent exceeds its pickup setting. This relay provides fast tripping times of 0.5 cycle to
1.5 cycles on very severe faults within its protection zone.
Figure 4-34—High-impedance differential relay used in bus protection,
one phase shown

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4.4.15.5 Pilot wire differential relays (Device 87L)
4.4.15.5.1 Application
The differential relays discussed thus far in 4.4.15 cannot be used to protect long lines or
cables because of the distances required to bring CT leads and breaker tripping wires to the
relay from both ends of the line. Therefore, a special type of relay called a pilot wire differen-
tial relay is used to protect lines.
The pilot wire differential relay is a high-speed relay designed for phase and ground protec-
tion for two- and three-terminal transmission and distribution lines. They are generally
applied on short lines, normally less than 40 km long. Their operating speed is approximately
20 ms. One of the typical pilot wire relays is discussed in 4.4.15.5.2.
4.4.15.5.2 Operating principles of a current pilot wire relay
Pilot wire differential relaying is a relay system consisting of two identical relays located at
each end of a line (see Figure 4-35). The relays are connected together with a two-conductor
pilot wire. The output from three individual phase CTs is applied to a sequence network that
produces a composite current that is proportional to the line current and has a polarity related
to line current flow direction. Each relay contains a restraint element and an operate element.
The restraint elements are in series with the pilot wire, while the operate elements of each
relay are in parallel with the pilot wire. The circuit is basically that of the percentage
(restraint) differential relay with the operating circuit broken into parallel circuits separated
by pilot wires. This relay is available in both electromechanical and static designs.
When the fault is external to the relay’s protective zone (see Figure 4-35), current flows in the
pilot wire through each relay’s restraint coils, but not through the relay’s operating coil. If the
fault is within the relay’s protective zone and current is flowing into the fault from both direc-
tions, the direction of pilot wire current IPA remains the same; but the direction of current IPB
Figure 4-35—Simplified connections for a pilot wire differential relay

IEEE
reverses and forces current to flow into each relay’s operating coil. If the fault current flows
through circuit breaker A only, the relay at A still passes sufficient current through the pilot
wire to operate the relay at circuit breaker B.
The relay is designed to give complete phase and ground-fault protection. The ground protec-
tion is derived from the residual connection of the line CTs, and its sensitivity depends on the
CT ratio. A static pilot wire relay is available that accepts an input from a low-ratio zero-
sequence CT. This feature allows for a sensing low-level ground current that is useful when
applied on a low-resistance grounded system.
Compliance with the manufacturer’s application instructions is necessary to provide a total
system of protection.
4.4.15.5.3 Pilot wire specifications
To insure the pilot relay system is reliable, details should be specified on the construction and
installation of the pilot wires. Construction requirements should include wire size, insulation,
twist length, shielding, and jacketing. Installation instructions should include whether over-
head or underground (if overhead, include spacing below any power lines), splicing, where to
ground the shield, protection of pilot wire shield against excessive currents, protection of
cable and relays from overvoltages, and how to treat spare wires that are in the same conduc-
tor bundle as the pilot wires.
Much controversy exists on what the exact specifications should be because many variations
have worked successfully.
A sample specification that has proved satisfactory at a number of industrial sites, for both
overhead and underground applications, is given in 4.4.15.5.3.1 and 4.4.15.5.3.2.
4.4.15.5.3.1 Pilot wire construction requirements
a) Wire size. Six pairs of AWG No 19 solid annealed copper conductors shall be used.
(Maximum pilot wire loop resistance should be less than 2000 Ω and maximum
capacitance is 1.5 µF for a two-terminal system.)
b) Insulation. Each conductor shall be insulated with 0.381 mm polyethylene. The con-
ductor shall be bound with a nonhydroscopic binder tape, over which shall be
extruded a high-dielectric polyethylene inner jacket. The jacket shall have a nominal
thickness of 1.143 mm.
c) Twist length. The pairs shall be twisted with a minimum twist length of 178 mm. The
twist length of each pair shall be different.
d) Shield. Over the inner jacket shall be applied a spiral-wound shield tape with a mini-
mum overlap of 20% of the tape width. The tape shall be 0.127 mm thick copper or
0.203 mm thick aluminum.
e) Overall jacket. An overall jacket shall be applied over the shield tape. The thickness
of the jacket over the shield tape shall be 0.152 mm. The overall jacket shall encom-
pass the cable and messenger in a Figure-8 configuration. The jacket compound shall
be applied so that it completely floods the interstices of the messenger. The outer

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jacket material shall be pigmented for protection from radiation and may be either
polyvinyl chloride or polyethylene.
f) Messenger. The messenger shall be 6.35 mm, 7-strand, extra strength steel (minimum
breaking strength, 30 kN) with Class A zinc coating. Messenger shall comply with
ASTM A-475-69.
g) Cable. The cable shall comply with the requirements of ICEA S-61-402 for Type D
control cable for pilot wire duty.
h) DC high-potential test. In addition to the testing required by the reference specifica-
tions, the completed cable shall be subjected to a 20 000 V dc high-potential test in
accordance with IEEE Std C37.??? between conductors and shield and between
shield and the messenger.
4.4.15.5.3.2 Pilot wire installation instructions
a) Ground the messenger wire at each pole.
b) Ground the shield at each terminal.
1) Connect shield to station ground.
2) Shield should be continuous end to end.
3) Protect shield from possible transient overcurrent during system faults with
parallel power conductor. Because potential differences in grounds may exist
during fault conditions, a conductor should be connected in parallel with the
shield to carry the current that may flow between grounds rather than permit the
current to flow through the shield.
c) Splices (if required) shall be in line using Scotchmold Epoxy splice kits or equal.
d) Insulating transformers shall not have a midpoint grounded on a high-voltage side.
e) Neutralizing transformers shall not be used.
f) Carbon gaps shall not be used.
g) Mutual drainage reactors or gas discharge tubes, or both, shall not be used.
h) If any pair in cable is used for purposes other than pilot wire, it shall be
1) Twisted pair with twist length different from pilot wire pair,
2) Ungrounded,
3) Terminated at each end in 10 kV (minimum) insulating transformers or
equivalent.
i) Unused pairs in cable shall be short-circuited and grounded at only one end.
j) Terminal blocks are acceptable only if they are mounted on suitable standoff insula-
tors and only if suitable clearances to ground and to shields are maintained.
k) Line clearances shall comply with the National Electrical Safety Code®
(NESC®
)
(ASC C2-2002).
4.4.15.5.4 Application guidelines
Other devices are required and applied with each relay terminal to provide a complete sys-
tem. These devices include a milliammeter, switch, and auxiliary transformer for testing;
insulating transformer for pilot wire isolation; and pilot wire supervision relays for detection
and alarm of pilot wire problems. An optional neutralizing reactor is applied where the differ-
ence between station ground and remote ground can exceed 600 V rms during power system
faults. This rise in ground potential appears across the neutralizing transformer inserted in the

IEEE
pilot wire. In addition, an optional drainage reactor is applied to drain off longitudinally
induced voltages that may occur by lightning surges (not a direct stroke) or the parallel asso-
ciation of the pilot wire with faulted power circuits. By forcing equal current flow from the
two wires into ground, it minimizes wire-to-wire voltages.
4.4.15.5.5 Taps
Current taps are provided to give adjustable minimum trip selection and sequence filter cir-
cuit taps that permit phase and ground sensitivity selection.
4.5 References
ASC C2-2002, National Electrical Safety Code®
(NESC®
).3
ASTM A-475-69, Specification for Zinc-Coated Steel Wire Strand.4
ICEA S-61-402, Thermalplastic-Insulated Wire and Cable for the Transmission and Distribu-
tion of Electrical Energy.5
IEEE Std C37.2-1996, IEEE Standard Electrical Power System Device Function Numbers
and Contact Designations.
4.6 Bibliography
[B9] AIEE Committee Report, “Bibliography of Industrial System Coordination and Protec-
tion Literature, IEEE Transactions on Industry Applications, vol. IA-82, pp. 1–2, Mar. 1963.
[B1] Anderson, P. M., Analysis of Faulted Power Systems. Ames, IA: Iowa State University
Press, 1973.
[B2] Andrichak, J. G., “Polarizing Sources for Directional Ground Relays,” Presented to the
Electric Council of New England, South Portland, ME, Oct. 11, 1973.
3The NESC is available from the Institute of Electrical and Electronics Engineers, 445 Hoes Lane, P.O. Box 1331,
Piscataway, NJ 08855-1331, USA (http://standards.ieee.org/).
4ASTM publications are available from the American Society for Testing and Materials, 100 Barr Harbor Drive,
West Conshohocken, PA 19428-2959, USA (http://www.astm.org/).
5ICEA publications are available from ICEA, P.O. Box 20048, Minneapolis, MN 55420, USA (http://www.icea.org).

IEEE
[B1] Applied Protective Relaying. Newark, N.J.: Westinghouse Electric Corporation, 1976.
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IEEE
[B23] Glassburn, W. E., and Sharp, R. L., “A Transformer Differential Relay with
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[B25] Gleason, L. L., and Elmore, W. A., “Protection of 3-Phase Motors Against
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[B34] Horowitz, S. H., and Phadke, A. G., Power System Relaying. New York: John Wiley &
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1978-1979,” Presented at IEEE PES Winter Meeting, Atlanta, GA, Feb. 1-6, 1981.

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[B37] IEEE Committee Report 81WM-121-3, “Review of Recent Practices and Trends in
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[B38] IEEE Project P490, Generator Ground Protection Guide (in preparation: PES Power
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[B40] IEEE Std 241-1990 (Reaff 1997), IEEE Recommended Practice for Electric Power
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[B46] IEEE Std C37.99-1980, IEEE Guide for Protection of Shunt Capacitor Banks.
[B47] IEEE Std C37.103 (in preparation: P815), IEEE Guide for Differential and Polarizing
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[B49] IEEE Std C57.105-1978, IEEE Guide for Application of Transformer Connections in
Three-Phase Distribution Systems.
[B50] IEEE Working Group Report, “Application Considerations of Static Overcurrent
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Induction Motor Under Normal and Abnormal Operation,” AIEE Transactions, vol. 80,
pt. III, pp. 66–76, 1961.
[B64] Mathur, Bal K., “A Closer Look at the Application and Setting of Protective Devices,”
IEEE I&CPS Technical Conference, Paper 79CH1460-51A, pp. 107–118, 1979.
[B65] Mentler, S., “A Half-Cycle Static Bus Protection Relay Using Instantaneous Voltage
Measurement,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-94, no. 3,
pp. 939–944, May/June 1975.

IEEE
[B66] NFPA 70-1999, National Electrical Code®
(NEC®
).7
[B67] Nochumson, C. J., and Schwartzburg, W. E., “Transfer Considerations in Standby Gen-
erator Application,” Conference Record, IEEE IAS Annual Meeting, pp. 1190–1198,
Oct. 1-5, 1978.
[B68] Oakes, P. A., “Special Circuits for Ground Relay Current Polarization from Autotrans-
formers Having Delta Tertiary,” AIEE Transactions on Power Apparatus and Systems,
vol. 78, pt. III, pp. 1191–1196, Dec. 1959.
[B69] Pope, J. W., “PURPA and the Customer-Utility Interconnections,” Presented at the
Conference for Protective Relay Engineers, Texas A&M University, Apr. 13-15.
[B70] Powell, L. J., “Current Transformer Burden and Saturation,” Conference Record, IEEE
IAS Annual Meeting, pp. 127–137, 1977.
[B1] “Power System Protection—Use of R-X Diagram,” General Electric Company, Philadel-
phia, 1966, Bulletin GET-2230B.
[B2] Protective Relays Application Guide. Stafford, England: GEC Measurements Ltd, 1975.
[B3] Rook, M. J., Goff, L. E., Potochney, G. J., and Powell, L. J., “Application of Protective
Relays on a Large Industrial-Utility Tie with Industrial Cogeneration,” Presented at IEEE
PES Winter Meeting, Atlanta, GA, Paper 81WM158-5, Feb. 1-6, 1981.
[B4] Rothe, F. S., and Concordia, C., “Transient Characteristics of Current Transformers
During Faults—II,” AIEE Transactions, vol. 66, pp. 731–734, 1947.
[B5] Seeley, H. T., Von Roeschlaub, F., “Instantaneous Bus-Differential Protection Using
Bushing Current Transformers,” AIEE Transactions, vol. 67, pp. 1709–1718, 1948.
[B6] Shulman, J. M., Elmore, W. A., and Bailey, K. D., “Motor Starting Protection by Imped-
ance Sensing,” IEEE Transactions on Power Apparatus and Systems, vol. PAS-97, no. 5, pp.
1689–1695, Sept./Oct. 1978.
[B7] Smith, D. H., “Problems Involving Industrial Plant-Utility Power System Interties,”
IEEE Transactions on Industry Applications, vol. IA-11, no. 6, Nov./Dec. 1975.
[B8] Sonnemann, W. K., “Phasors for Directional Relays,” Presented at 21st Annual Confer-
ence for Protective Relay Engineers, Texas A&M University, Apr. 22-24, 1968.
[B9] Sonnemann, W. K., “A Study of Directional Element Connections for Phase Relays,”
AIEE Transactions, vol. 69, pp. 1438–1451, 1950.
(http://www.nfpa.org/). Copies are also available from the Institute of Electrical and Electronics Engineers, 445
Hoes Lane, P.O. Box 1331, Piscataway, NJ 08855-1331, USA (http://standards.ieee.org/).

IEEE
[B10] Stoller, S., “In-Plant Generator-Design Considerations for Industrial Facilities,” IEEE
Transactions on Industry Applications, vol. IA-12, no. 3, pp. 226–231, May/June 1976.
[B11] Tremaine, R. L., and Blackburn, J. L., “Loss-of-Field Protection for Synchronous
Machines,” AIEE Transactions, vol. 73, pt. III-A, pp. 765–777, 1954.
[B12] UL 1053-1976, Safety Standard for Ground-Fault Sensing and Relaying Equipment.8
[B13] Wagner, C. F., and Evans, R. D., Symmetrical Components. New York: McGraw-Hill,
1933.
[B14] Waldron, J. E., “Motor Characteristics and Protection,” Presented at 29th Conference
for Protective Relay Engineers, Texas A&M University, Apr. 12-14, 1976.
[B15] Waldron, J. E., “Innovations in Solid-State Protective Relays,” IEEE Transactions on
Industry Applications, vol. IA-14, no. 1, pp. 39–47, Jan./Feb. 1978.
[B16] Waldron, J. E., and Zocholl, S. E., “Design Considerations for a New Solid-State
Transformer Differential Relay with Harmonic Restraint,” Presented at 5th Annual Western
Protective Relay Conference, Sacramento, CA, Oct. 15-18, 1978.
[B17] Walsh, G. F., “The Effects of Reclosing on Industrial Plants,” Proceedings of the Amer-
ican Power Conference, vol. 23, pp. 768–778, 1961.
[B18] Warrington, A. C., “Application of the OHM and MHO Principle to Protective Relay-
ing,” AIEE Transactions, vol. 65, pp. 378–386, 490, 1946.
[B19] Warrington, A. C., Protective Relays—Their Theory and Practice. New York: Wiley,
1968.
[B20] Wentz, E. C., and Sonnemann, W. K., “Current Transformers and Relays for
High-Speed Differential Protection, with Particular Reference to Offset Transient Currents,”
AIEE Transactions, vol. 59, pp. 481–488, 1144–1148, Aug. 1940.
[B21] West, D. J., “Current Transformer Application Guidelines,” Conference Record, IEEE
IAS Annual Meeting, pp. 110–126, 1977.
[B22] Wilson, J. R., “Power-Reactive Versions of R-X Diagrams,” Presented at the 21st
Annual Conference for Protective Relay Engineers, Texas A&M University, Apr. 22-24,
1968.
[B23] Zocholl, S. E., “Solid-State Overcurrent Relay with Conventional Time Current
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8UL standards are available from Global Engineering Documents, 15 Inverness Way East, Englewood, CO 80112,
USA (http://global.ihs.com/).

IEEE
[B24] Zocholl, S. E., and Pencinger, C. J., “Analysis of Overcurrent Relay Testing,” Pre-
sented at Pennsylvania Electric Association Relay Committee Meeting, Wilkes-Barre, PA,
Oct. 6, 1977.
[B25] Zocholl, S. E., and Waldron, J. E., “Solid-State Relays for Generator Protection,” Pre-
sented at 6th Annual Western Protective Relay Conference, Spokane, WA, Oct. 16-18, 1979.

IEEE
LOW-VOLTAGE FUSES Std 242-2001
Chapter 5
Low-voltage fuses
5.1 General discussion
A low-voltage fuse is a device that protects a circuit by opening its current-responsive
element when an overcurrent passes through it. A fuse, as defined in The Authoritative
Dictionary of IEEE Standards, Seventh Edition,1
is an overcurrent protective device with a
circuit-opening fusible part that is heated and severed by the passage of the overcurrent
through it.
NOTE—A fuse comprises all the parts that form a unit capable of performing the prescribed functions.
It may or may not be the complete device necessary to connect it into an electric circuit.
A fuse has these functional characteristics:
a) It combines both the sensing and interrupting elements in one self-contained device.
b) It is direct acting in that it responds to a combination of magnitude and duration of
circuit current flowing through it.
c) It normally does not include any provision for manually making and breaking the
connection to an energized circuit, but requires separate devices (e.g., a disconnect
switch) to perform this function.
d) It is a single-phase device. Only the fuse in the phase or phases subjected to overcur-
rent responds to de-energize the affected phase or phases of the circuit or equipment
that is faulty.
e) After having interrupted an overcurrent, it is renewed by the replacement of its
current-responsive element before restoration of service.
5.2 Definitions
The following terms may be found in other industry publications on fuses, but are included in
this recommended practice for convenience.
5.2.1 ampere rating: The root-mean-square (rms) or dc current that the fuse carries continu-
ously without deterioration and without exceeding temperature rise limits specified for that
fuse.
5.2.2 arcing time: The time elapsing from the melting of the current-responsive element
(e.g., the link) to the final interruption of the circuit. This time is dependent upon such factors
as voltage and reactance of the circuit. (See Figure 5-1.)

IEEE
5.2.3 bridge: The narrowed portion of a fuse link that is expected to melt first. One link may
have two or more bridges in parallel and in series as well. The shape and size of the bridge is
a factor in determining the fuse characteristics under overload and fault current conditions.
5.2.4 current limiter: A device intended to function only on fault currents and not on lesser
overcurrents regardless of time. Such a device is often used in series with a circuit breaker,
which protects against overloads and low-level short circuits. However, cable limiters are
types of current limiters that are used to provide short-circuit protection for cables, without
being in series with another type of device.
5.2.5 current-limiting fuse: A fuse that interrupts all available currents above its threshold
current and below its maximum interrupting rating, limits the clearing time at rated voltage to
an interval equal to or less than the first major or symmetrical loop duration, and limits peak
let-through current to a value less than the peak current that would be possible with the fuse
replaced by a solid conductor of the same impedance. Only Class G, Class J, Class L,
Class R, Class CC, and Class T may be marked “current limiting.” Class K fuses are, in fact,
current limiting, but may not be marked “current limiting.” Article 240-60b of the National
Electrical Code® (NEC®) (NFPA 70-1999) prohibits fuse clips for current-limiting fuses
from accepting noncurrent-limiting fuses. (See Figure 5-1.)
5.2.6 delay: A term usually applied to the opening time of a fuse when in excess of 1 cycle,
where the time may vary considerably between types and manufacturers and still be within
established standards. This word, in itself, has no specific meaning other than in manufactur-
ers’ claims unless published standards specify delay characteristics. See: time delay.
Figure 5-1—Typical current limitation showing peak let-through current and
total clearing time

IEEE
5.2.7 dual-element fuse: A cartridge fuse having two or more current-responsive elements of
different fusing characteristics in series in a single cartridge. The dual-element design is a
construction technique frequently used to obtain a desired time-delay response characteristic.
Labeling a fuse as dual-element means this fuse meets Underwriters Laboratories (UL) time-
delay requirements (i.e., can carry ﬁve times rated current for a minimum of 10 s for Class J,
Class H, Class K, and Class R, except for the 0 A to 30 A, 250 V case size Class H, Class K,
and Class R fuses, where minimum opening time can be reduced to 8 s for ﬁve times the rated
current).
5.2.8 ferrule: The cylindrical-shaped fuse terminal that also encloses the end of the fuse. In
low-voltage fuses, the design is only used in fuses rated up to and including 60 A. The ferrule
may be made of brass or copper and may be plated with various materials.
5.2.9 fuse-link: [British Standards Association (BSA) terminology] A complete enclosed car-
tridge fuse. The addition of a carrier, or holder, completes the fuse. [In the United States] A
replaceable part or assembly that comprises entirely or principally the conducting element
and is required to be replaced after each circuit interruption to restore the fuse to operating
conditions. See: link.
5.2.10 high rupturing capacity (HRC): [British Standards Association (BSA) and Canadian
Standards Association (CSA) terminology] A term equivalent to National Electrical Manu-
facturers Association (NEMA) high interrupting rating and generally indicating capability of
interruption of at least 100 000 A root-mean-square (rms) for low-voltage fuses.
5.2.11 I2t (ampere-squared seconds): A factor of heat energy developed within a circuit dur-
ing the fuse’s melting or arcing. The sum of melting and arcing I2t is generally stated as total
clearing I2t. Actual energy is I2rt, but r (resistance) is assumed as a constant for comparison
(see Figure 5-2).
Figure 5-2—Graphic representation of I 2
t

IEEE
5.2.12 interrupting rating: The rating based upon the highest root-mean-square (rms) ac or
dc current that the fuse is tested to interrupt under the conditions specified. The interrupting
rating, in itself, has no direct bearing on any current-limiting effect of the fuse.
5.2.13 link: The current-responsive element in a fuse that is designed to melt under overcur-
rent conditions and interrupt the circuit. A renewal link is one intended for use in Class H
low-voltage renewable fuses.
5.2.14 melting time: The time required to melt the current-responsive element on a specified
overcurrent. Where the fuse is current limiting, the melting time may be approximately half
or less of the total clearing time. (Sometimes referred to as pre-arcing time.) (See Figure 5-1.)
5.2.15 NEC® dimensions: Dimensions once stated in the National Electrical Code® (NEC®)
(NFPA 70-1999), but now found in Underwriters Laboratories (UL) and Canadian Standards
Association (CSA) standards. These dimensions are common to Class H and Class K fuses
and provide interchangeability between manufacturers for fuses and fusible equipment of a
given ampere and voltage range.
5.2.16 one-time fuse: Strictly speaking, any nonrenewable fuse, but generally accepted and
used to describe any Class H or Class K nonrenewable cartridge fuse, with a single (as
opposed to dual) fusing element.
5.2.17 overload: An overcurrent, or more current than normal, that stays in the normal cur-
rent path.
5.2.18 peak let-through current (IP): The maximum instantaneous current through a
current-limiting fuse during the total clearing time. Because this value is instantaneous, it
exceeds the root-mean-square (rms) available current, but is less than the peak current
available without a fuse in the circuit if the fault level is high enough for it to operate in its
current-limiting mode. (See Figure 5-1.)
5.2.19 plug fuses: Fuses that are rated 125 V and available with current ratings up to 30 A.
Their use is limited to circuits rated 125 V or less. However, they may also be used in circuits
supplied from a system having a grounded neutral and in which no conductor operates at
more than 150 V to ground. The National Electrical Code®
(NEC®
) (NFPA 70-1999)
requires Type S fuses in all new installations of plug fuses because they are tamper resistant
and size limiting and thus make overfusing difficult.
5.2.20 pre-arcing time: See: melting time.
5.2.21 renewable fuse: A fuse in which the element, usually a zinc link, may be replaced
after the fuse has opened. Once a popular item, this fuse is gradually losing popularity due to
the possibility of using higher ampere-rated links or multiple links in the field.
5.2.22 selectivity: A general term describing the interrelated performance of protective
devices. Complete selectivity is obtained when a minimum amount of equipment is removed
from service for isolation of a fault or other abnormality.

IEEE
5.2.23 short-circuit current: An overcurrent, or more current than normal, that goes outside
the normal current path when it is shunted around the load. See: overload.
5.2.24 threshold current: The magnitude of current at which a fuse becomes current limit-
ing, specifically, the symmetrical root-mean-square (rms) available current at the threshold of
the current-limiting range, where the fuse total clearing time is less than 0.5 cycle at rated
voltage and rated frequency, for a symmetrical closing, at a power factor of less than 20%.
The threshold ratio is simply the ratio of the threshold current to the fuse’s continuous-current
rating.
5.2.25 time delay: A term now used by National Electrical Manufacturers Association
(NEMA), American National Standards Institute (ANSI), Underwriters Laboratories (UL),
and Canadian Standards Association (CSA) to mean, in Class H, Class K, Class J, and
Class R cartridge fuses, a minimum opening time of 10 s on an overload current five times
the ampere rating of the fuse, except for Class H, Class K, and Class R, 0 A to 30 A, 250 V
case size where the minimum opening time can be reduced to 8 s for five times the rated
current. Such time-delay is particularly useful in allowing the fuse to pass the momentary
starting overcurrent of a motor, yet not hindering the opening of the fuse should the overload
persist. In Class G, Class CC, and plug fuses, the phrase time-delay requires a minimum
opening time of 12 s on an overload of twice the fuse’s ampere rating. The time-delay
characteristic does not affect the fuse’s short-circuit current clearing ability. Time-delay is in
contrast with the term nontime-delay or fast-acting as applied to other fuse types.
5.2.26 total clearing time: The total time between the beginning of the specified overcurrent
and the final interruption of the circuit, at rated voltage. It is the sum of the minimum melting
time plus tolerance and the arcing time. For clearing times in excess of 0.5 cycle, the clearing
time is substantially the maximum melting time for low-voltage fuses. (See Figure 5-1.)
5.2.27 tube: The cylindrical enclosure of a fuse. It may be made of laminated paper, special
fiber, melamine impregnated glass cloth, bakelite, ceramic, glass, plastic, or other materials.
5.2.28 voltage rating: The root-mean-square (rms) ac (or the dc) voltage at which the fuse is
designed to operate. All low-voltage fuses function on any lower voltage, but use on higher
voltages than rated is hazardous. For high short-circuit currents, increasing the voltage
increases the arcing and clearing times and the clearing I2
t values.
5.3 Documentation
The various electrical industry standards about fuses are highlighted in this clause. Each is
available from its source and should be studied for detailed requirements.
5.3.1 Standards from Underwriters Laboratories (UL) and Canadian Standards
Association (CSA)
UL 248-1-2000 and CSA C22.2 No. 248.1-2000 provide general requirements for low-
voltage fuses (1000 V or less). Subsequent, detailed parts, along with the general

IEEE
requirements, are described in 5.3.1.1 through 5.3.1.8. Figure 5-3 shows the classification of
low-voltage fuses covered by the standards.
5.3.1.1 Class H fuses
UL 248-6-2000 and CSA C22.2 No. 248.6-2000 cover nonrenewable Class H fuses. UL 248-
7-2000 and CSA C22.2 No. 248.7-2000 cover standard renewable Class H fuses. These fuses
are rated 250 V or 600 V, 600 A or less, and are in accordance with the National Electrical
Code® (NEC®) (NFPA 70-1999). These fuses are not recognized as being current limiting.
They shall not bear a marking that states or implies that they are current limiting. Neither a
fuse nor its carton may be marked “direct current” or “dc” unless found suitable for use on
both ac and dc. (See 5.3.1.8.) Fuses marked “time-delay,” “D,” “dual element,” or any phrase
of similar significance should not open in less than 10 s at five times their rating, except for
the 250 V, 30 A case size, which has a minimum 8 s opening time at five times their rating.
The principal requirements are dimension, design, construction, performance, and markings.
Under performance, the fuses are tested for the following:
a) Continuous-current-carrying ability and temperature rise.
b) Overload operation within prescribed maximum times at 135% and 200% of the
fuse’s continuous-current rating.
c) Time-delay test (optional) for a minimum opening time of 10 s at five times the con-
tinuous-current rating, except for fuses of 0 A to 30 A, 250 V, minimum clearing time
may be reduced to 8 s at 500%. A fuse may be labeled “time delay,” “dual element,”
etc. only if it passes this test.
d) Short-circuit interrupting capability at 10 000 A root mean square (rms) (ac). DC
testing is optional.
Figure 5-3—Low-voltage fuses covered by UL and CSA

IEEE
5.3.1.2 Class G, Class J, Class L, Class CC, Class C, Class CA, and Class CB
The following standards cover the indicated fuses:
These requirements cover nonrenewable cartridge fuses that limit the peak let-through cur-
rent and the total I2
t and that exhibit current-limiting characteristics above specified values of
current. These fuses have different dimensional characteristics than Class H and Class K
fuses to meet noninterchangeability requirements of current-limiting fuses. (See NEC
Article 240-60b and Figure 5-2.)
Class G fuses have an ac rating to interrupt 100 000 A rms. They are labeled as “current-lim-
iting,” have an ac rating of 480 V (25–60 A) and 6000 V (0–20A), and may have an addi-
tional optional dc rating up to 480 V. Their dimensions are not interchangeable with other
classes of fuses. Class G fuses may be either fast-acting or time-delay. Class G fuses are
available up through 60 A in four different body sizes (0–15 A, 20 A, 25 and 30 A, and 35–
60 A).
Class J fuses have an ac rating to interrupt 200 000 A rms. They are labeled as “current-
limiting,” have an ac rating of 600 V, and may have an additional optional dc rating up to
600 V. Their dimensions are not interchangeable with other classes of fuses. Class J fuses
may be either fast-acting or time-delay. Class J fuses that have a time delay of at least 10 s at
five times rated current may have “time delay” or the equivalent written on the label.
Class L fuses have ratings in the range of 601 A to 6000 A, have an ac rating to interrupt
200 000 A, have an ac rating of 600 V, and have specified dimensions larger than those of
other fuses rated 600 V (or less). They are intended to be bolted to bus bars and are not used
in clips. UL has no definition of time delay for Class L fuses; however, many Class L fuses
have substantial overload time-current carrying capability. Class L fuse standards do not
include 250 V ratings.
Class CC fuses have an ac rating to interrupt 200 000 A rms. They are labeled as “current-
limiting,” have an ac rating of 600 V, and may have an additional optional dc rating up to
600 V. Rejection features in fuse clips for Class CC fuses reject all but Class CC fuses. They
Fuse class Standard
G UL 248-5-2000 and CSA C22.2 No. 248.5-2000
J UL 248-8-2000 and CSA C22.2 No. 248.8-2000
L UL 248-10-2000 and CSA C22.2 No. 248.10-2000
CC UL 248-4-2000 and CSA C22.2 No. 248.4-2000
C UL 248-2-2000 and CSA C22.2 No. 248.2-2000
CA and CB UL 248-3-2000 and CSA C22.2 No. 248.3-2000

IEEE
may be either fast-acting or time-delay. Class CC fuses are available up through 30 A in one
case size.
Class C fuses have an ac rating to interrupt 200 000 A rms. They may be marked “current-
limiting” if they pass a threshold current test. Class C fuses have an ac rating of 600 V and
may have an additional optional dc rating up to 600 V. Class C fuses are available up through
1200 A in four case sizes (0–100 A, 101–200 A, 201–800 A, and 801–1200 A).
Class CA and Class CB fuses have an ac rating to interrupt 200 000 A rms. They are labeled
as “current-limiting,” have an ac rating of 600 V, and may have an additional optional dc rat-
ing up to 600 V. Class CA fuses are available up through 30 A and have mounting holes in
their end blades. Class CB fuses are available up through 60 A, without mounting holes in
their end blades. Class CB fuses have two body sizes (0–30 A and 35–60 A).
5.3.1.3 Class K
UL 248-9-2000 and CSA C22.2 No. 248.9-2000 cover fuses made in the same dimensions as
Class H fuses, but which have an ac rating to interrupt 50 000 A, 100 000 A, or 200 000 A
rms. Class K fuses have prescribed values of peak let-through current and I2t for each case
size (0–30 A, 31–60 A, 61–100 A, 101–200 A, 201–400 A, and 401–600 A). Because they
have no required threshold ratio and are interchangeable with Class H fuses, they are not
labeled as current limiting. See NEC Article 240-60(b). They are rated up to 600 A in both
250 V and 600 V sizes. Class K fuses are tested for continuous-current-carrying ability,
temperature rise, overload opening, and an optional time-delay test of 10 s (8 s for 250 V,
30 A case size) at five times the current rating in order to be labeled as “time delay,” “dual
element,” etc. They are also tested at various short-circuit levels up to their maximum
interrupting rating and for compliance with prescribed maximum values of peak let-through
current and I2t for each of the three divisions: K-1, K-5, and K-9 . K-1 fuses are required to
have the lowest I2t and IP let-through values. K-5 fuses are allowed to have higher values, and
K-9 fuses have the highest I2t and IP limits. They are labeled for the class subdivision,
interrupting rating, amperes, and maximum voltage.
NOTE—Any one manufacturer may produce two or three Class K-5 fuses with different interrupting
ratings or with the same interrupting rating and differing peak let-through and I2t values distinguished
by catalog numbers, but all within the requirements of that class.
5.3.1.4 Class R
UL 248-12-2000 and CSA C22.2 No. 248.12-2000 cover Class R fuses. They have ac ratings
to interrupt 200 000 A. The standard has prescribed values for maximum peak let-through
currents, I2t and threshold current, with subclass RK-1 having the lowest (or most restrictive)
values as compared to subclass RK-5. Fuseholders designed to accept Class R fuses do not
accept Class H or Class K fuses or any other class. However, Class R fuses do fit into Class H
or Class K fuseholders. Class R fuses are available with or without time delay. If marked
“time delay” or similarly, they are required to have a minimum opening time of 10 s when
subjected to a load of five times rated current, except for the 0 A to 30 A, 250 V case size,
where minimum opening time can be reduced to 8 s for five times the rated current.

IEEE
5.3.1.5 Plug fuses
UL 248-11-2000 and CSA C22.2 No. 248.11-2000 cover Edison base and Type S base plug
fuses, which may or may not be provided with time-delay characteristics. Type S base plug
fuses have rejection features that limit the ampere rating of fuses that may be installed in a
particular fuseholder.
5.3.1.6 Supplemental fuses
UL 248-14-2000 and CSA C22.2 No. 248.14-2000 cover glass, miniature, micro, and other
miscellaneous fuses for supplementary protection. These standards do not pertain to branch
circuit fuses.
5.3.1.7 Class T
UL 248-15-2000 and CSA C22.2 No. 248.15-2000 cover Class T current-limiting fuses.
These fuses have characteristics similar to Class J fuses, but are dimensionally smaller. They
are available in ac ratings up to 1200 A at both 300 V and 600 V. As current-limiting fuses,
they are not dimensionally interchangeable with any other class of fuse. Class T fuses have an
ac rating to interrupt 200 000 A rms.
5.3.1.8 DC fuses
Optional requirements for dc are found in UL 248-1-2000, CSA C22.2 No. 248.1-2000, and
UL 198L-1995. Preferred dc voltage ratings are 60 V, 125 V, 160 V, 250 V, 300 V, 400 V,
500 V, and 600 V. Preferred dc interrupting ratings are 10 000 A, 20 000 A, 50 000 A,
100 000 A, 150 000 A, and 200 000 A. These requirements cover Class C, Class CA,
Class CB, Class CC, Class G, Class H, Class J, Class K, Class L, Class R, and Class T fuses.
UL 198M-1995 covers requirements for Class K and Class R fuses intended for use in pro-
tecting trailing cables in dc circuits in mines. The standard follows the requirements of the
US Department of Labor’s Mine Safety and Health Administration (MSHA). These fuses
have a maximum rating of 600 A, with a voltage rating of 300 V or 600 V. The maximum dc
interrupting rating is 20 000 A.
5.3.2 NEMA FU-1-1986
NEMA FU-1-1986 covers low-voltage cartridge fuses with requirements that are similar to
the requirements found in the UL and CSA standards given in 5.3.1.
5.3.3 The NEC
NEC articles that apply to fuses include
— 110-9, Interrupting Rating Requirements
— 110-10, Circuit Impedance and Other Characteristics
— 240-02, List of Articles Covering Overcurrent Protection for Speciﬁc Equipment

IEEE
— 240-6, Standard Ampere Ratings
— 240-11, Definition of Current-Limiting Protective Device
— 240-50, Plug Fuses, Fuseholders, and Adapters
— 240-51, Edison Base Fuses
— 240-53, Type S Fuses
— 240-54, Types S Fuses, Adapters, and Fuseholders
— 240-60b, Noninterchangeability
— 240-60c, Marking on Fuses
— 240-61, Fuse Classification
5.4 Standard dimensions
UL and CSA have established the dimensional requirements for the various classifications of
low-voltage fuses. Figure 5-4 through Figure 5-10 show typical dimensions (see fuse manu-
facturer’s data for actual dimensions) for Class H, Class K, Class L, Class G, Class J,
Class T, Class CC, and Class R fuses.

IEEE
Figure 5-4—Class H and Class K dimensions
A.DIMENSIONS OF KNIFE-BLADE TYPE FUSES IN INCHES (mm)
Rating
Overall
Length
of
Fusea
Maximum
Outside
Diameter
of
Tube
Minimum
Length of
Ferrule
or
Blade
Outside
Diameter
of
Ferruleb
Thickness
of
Bladec
Width
of
Bladed
Maximum
Dimensions Over
Projectionse
Minimum
Distance
From
Midpoint
of Fuse
to
Nearest
Live Part
Minimum
Overall
Length
of
Cylindrica
Bodyf
Measured
Parallel
to
Blade
Measured
at Right
Angles
to Blade
Volts Amperes A B C D E F G H I J
250
0–30 2.00
(50.8)
0.53
(13.5)
0.50
(12.7)
0.562
(14.27)
31–60 3.00
(76.2)
0.78
(19.8)
0.625
(15.9)
0.812
(20.62)
61–100 5.87
(149.2)
1.00
(25.4)
0.125
(3.18)
0.750
(19.05)
0.66
(16.7)
0.59
(15.1)
1.03
(26.2)
101–200 7.12
(181.0)
1.37
(34.9)
0.188
(4.78)
1.125
(28.58)
0.94
(23.8)
0.84
(21.4)
1.19
(30.2)
4.12
(104.8)
201–400 8.62
(291.1)
1.87
(47.6)
0.250
(6.35)
1.625
(41.28)
1.20
(30.6)
1.20
(30.6)
1.19
(30.2)
4.62
(117.5)
401–600 10.37
(263.5)
2.25
(57.1)
0.250
(6.35)
2.000
(50.80)
1.45
(36.9)
1.45
(36.9)
1.53
(38.9)
5.19
(131.8)
600
0–30 5.00
(127.0)
0.78
(19.8)
0.50
(12.7)
0.812
(20.62)
31–60 5.50
(139.7)
1.03
(26.2)
0.62
(15.9)
1.062
(26.97)
61–100 7.87
(200.0)
1.00
(25.4)
0.125
(3.18)
0.750
(19.05)
0.78
(19.8)
0.72
(18.3)
1.75
(44.4)
101–200 9.62
(244.5)
1.37
(34.9)
0.188
(4.78)
1.125
(28.58)
1.06
(27.0)
0.98
(25.0)
2.25
(57.1)
6.12
(155.6)
201–400 11.62
(295.3)
1.87
(47.6)
0.250
(6.35)
1.625
(41.28)
1.45
(36.9)
1.45
(36.9)
2.50
(63.5)
7.12
(181.0)
401–600 13.37
(339.7)
2.25
(57.1)
0.250
(6.35)
2.000
(5.08)
1.72
(43.7)
1.72
(43.7)
2.69
(68.3)
8.18
(208.0)
aTolerances: 0–60 A, ±0.03 in (±0.8 mm); 61–200 A, ±0.06 in (±1.6 mm); 201–600 A, ±0.09 in (±2.4 mm).
bColumn D tolerance: ±0.020 in (±0.020 mm).
cColumn E tolerance: ±0.003 in (±0.08 mm).
dColumn F tolerance: ±0.035 in (±0.89 mm).
eThe maximum overall dimension of a screw ring for a renewable fuse, the position of which with respect to the position of the knife blad
cannot be predetermined, shall be no more than the value speciﬁed for dimension H.
f The length of the cylindrical body may be less than the indicated value if other acceptable interference means, pins through the blades
collars, and the like, are provided to prevent mounting the fuse in a fuseholder that will accommodate a fuse rated in the next lower bracke
of current ratings.
NOTE—The dashed line represents the limit of the maximum projection of a screw, rivet head, or
the like. It becomes a circle for a fuse rated more than 200

IEEE
Figure 5-5—Class L fuse dimensions
ALL DIMENSIONS ARE IN INCHES
ALL TOLERANCES ARE ±1/64 INCH UNLESS OTHERWISE NOTED
5/8 ± 1/32 INCH SLOTS OR HOLES MAY BE USED. SHADED HOLES INDICATE DRILLING REQUIRED FOR CLASS “L” FUSE
MOUNTING.
Inches 1/64
1/32
1/16
1/2
5/8
3/4
13/16
7/8
15/16 13/8 15/8 13/4 31/4 4 53/4
mm 0.4 0.8 1.6 12.7 15.9 19.0 20.6 22.2 23.8 34.9 41.3 44.4 82.6 101.6 146.0
DIMENSIONS OF CLASS L FUSES IN INCHES (mm)a
Cartridge
Size in
Amperes
Maximum
Diameter
Width of
Blades
Thickness of
Blades
Overall
Length
A B C D
601–800 2.53
(64.3)
2.0
(50.8)
0.375
(9.5)
8.63
(219.1)
801–1200
2.78
(70.6)
2.0
(50.8)
0.375
(9.5)
10.75
(273.0)
1201–1600
3.03
(77.0)
2.38
(60.3)
0.44
(11.1)
10.75
(273.0)
1601–2000
3.53
(89.7)
2.75
(69.8)
0.50
(12.7)
10.75
(273.0)
2001–2500
5.03
(127.8)
3.50
(88.9)
0.75
(19.0)
10.75
(273.0)
2501–3000
5.03
(127.8)
4.0
(101.6)
0.75
(19.0)
10.75
(273.0)
3001–4000
5.78
(146.8)
4.75
(120.6)
0.75
(19.0)
10.75
(273.0)
4001–5000
7.16
(181.8)
5.25
(133.4)
1.0
(25.4)
10.75
(273.0)
5001–6000
7.16
(181.8)
5.75
(146.0)
1.0
(25.4)
10.75
(273.0)
aTolerances: B, ±0.06 in (±1.6 mm); C, ±0.03 in (±0.8 mm);
D, ±0.09 in (±2.4 mm).

IEEE
Figure 5-6—Class G fuse dimensions
DIMENSIONS OF CLASS G FUSES IN INCHES (mm)a
Rating
Overall
Length of
Fuse
Maximum
Outside
Diameter of
Tube
Minimum
Length of
Ferrule
Outside
Diameter of
Ferrule
Volts Amperes A B C D
300 0–15 1.31
(33.3)
0.38
(9.5)
0.28
(7.1)
0.406
(10.31)
300 16–20 1.41
(35.7)
0.38
(9.5)
0.28
(7.1)
0.406
(10.31)
300 21–30 1.62
(41.3)
0.38
(9.5)
0.28
(7.1)
0.406
(10.31)
300 31–60 2.25
(57.1)
0.38
(9.5)
0.50
(12.7)
0.406
(10.31)
a
Tolerances: A, ±0.03 in (±0.8 mm); D, ±0.006 in (±0.15 mm).

IEEE
Figure 5-7—Class J fuse dimensions
KNIFE-BLADE TYPE CLASS J FUSES—61–600 AMPERES
DIMENSIONS OF FERRULE-TYPE CLASS J FUSES IN INCHES (mm)2
Cartridge
Size in
Amperes
Overall
Length
Minimum
Length of
Ferrule
Outside
Diameter of
Ferrule
A B C
0–30 2.25
(57.1)
0.50
(12.7)
0.812
(20.62)
31–60
2.37
(60.3)
0.63
(15.9)
1.062
(26.97)
aTolerances: A, ±0.03 in (±0.8 mm); C, ±0.008 in (±0.20 mm).
DIMENSIONS OF KNIFE-BLADE TYPE CLASS J FUSES IN INCHES (mm)a
Cartridge
Size in
Amperes
Overall
Length
Distance
Between
Centers of
Slot
Maximum
Diameterb
Width of
Blades
Thicknessof
Blades
Length of
Blades
Distance
From End
of Blade to
Center of
Slot
Width of
Slot
Length of
Slot
Length of
Tube
A B C D E F G H J K
61–100 4.62
(117.5)
3.62
(92.1)
1.13
(28.6)
0.750
(19.05)
0.125
(3.18)
1.00
(25.4)
0.50
(12.7)
0.281
(7.14)
0.375
(9.52)
2.62
(66.7)
101–200
5.75
(146.0)
4.38
(111.1)
1.63
(41.3)
1.125
(28.58)
0.188
(4.78)
1.37
(34.9)
0.69
(17.5)
0.281
(7.14)
0.375
(9.52)
3.00
(76.2)
201–400
7.12
(181.0)
5.25
(133.4)
2.13
(54.0)
1.625
(41.28)
0.250
(6.35)
1.87
(47.6)
0.94
(23.8)
0.406
(10.32)
0.531
(13.49)
3.37
(85.7)
401–600
8.00
(203.2)
6.00
(152.4)
2.63
(66.7)
2.000
(50.80)
0.375
(9.52)
2.12
(54.0)
1.00
(25.4)
0.531
(13.49)
0.688
(17.48)
3.75
(95.2)
Tolerances: A, ±0.09 in (±2.4 mm); B, ±0.06 in (±1.6 mm); D, ±0.035 in (±0.89 mm); E, ±0.003 in (±0.08 mm); F, ±0.03 in (±0.8 mm);
G, ±0.03 in (±0.8 mm); H, ±0.005 in (±0.13 mm); J, plus 0.062, minus 0.000 in (plus 1.57 mm, minus 0.00 mm); K, ±0.03 in (±0.08 mm).
C/2 includes maximum dimension over projection.

IEEE
DIMENSIONS OF FERRULE-TYPE FUSES IN INCHES (mm)
Rating
Overall
Length
of
Fusea
Length
of
Ferruleb
Outside
Diameter
of
Ferrulec
Thickness
of
Rejection
Featured
Width
of
Rejection
Featured,e
Diameter
of
Rejection
Featuree,f
Volts Amperes A B C D E F
300
0–30 0.880
(22.35)
0.280
(7.11)
0.406
(10.31)
— — —
31–60 0.880
(22.35)
0.280
(7.11)
0.563
(14.30)
— — —
600
0–30 1.500
(38.10)
0.280
(7.11)
0.563
(14.30)
— — —
31–60 1.560
(39.62)
0.410
(10.41)
0.812
(20.62)
0.062
(1.57)
0.812
(20.62)
0.994
(25.25)
aTolerances: 0–60 A, 300 V, ±0.020 in (±0.51 mm); 0–60 A, 600 V, ±0.40 in
(±1.02 mm).
bColumn B tolerance: ±0.020 in (±0.51 mm).
cColumn C tolerance: ±0.006 in (±0.15 mm). Diameter of tube is less than ferrules.
dColumns D and E tolerance: ±0.006 in (±0.15 mm).
e
Rejection feature may be either square or round.
f
Column F tolerance: minus 0.006 in plus 0.016 in (minus 0.15 mm plus 0.41 mm).
DIMENSIONS OF KNIFE-BLADE TYPE FUSES IN INCHES (mm)
Rating
Overall
Length of
Fusea
Distance
Between
Mounting
Centersb
Maximum
Length of
Body
Width of
Bladec
Diameter
of
Mounting
Holesd
Maximum
Diameter
of Fuse
Minimum
Length of
Insulated
Body
Thickness
of Bladee
Minimum
Length
of Blade
Distanceof
Mounting
Holes from
Endc
Volts Amperes A B C D E F G H I J
300
61–100 2.156
(54.76)
1.556
(39.52)
0.850
(21.59)
0.750
(19.05)
0.281
(7.14)
0.828
(21.03)
0.250
(6.35)
0.125
(3.18)
0.646
(16.41)
0.300
(7.62)
101–200
2.438
(61.93)
1.895
(43.05)
0.850
(21.59)
0.875
(22.22)
0.344
(8.74)
1.078
(27.38)
0.250
(6.35)
0.188
(4.78)
0.787
(19.99)
0.372
(9.45)
201–400
2.750
(69.85)
1.844
(46.84)
0.860
(21.84)
1.000
(25.40)
0.406
(10.31)
1.344
(34.14)
0.250
(6.35)
0.250
(6.35)
0.926
(23.52)
0.453
(11.51)
401–600
3.063
(77.80)
2.031
(51.59)
0.880
(22.35)
1.250
(31.75)
0.484
(12.29)
1.625
(41.28)
0.250
(6.35)
0.312
(7.92)
1.074
(27.28)
0.516
(13.11)
601–800
3.375
(85.73)
2.219
(56.36)
0.891
(22.63)
1.750
(44.45)
0.547
(13.89)
2.078
(52.78)
0.250
(6.35)
0.375
(9.53)
1.222
(31.04)
0.578
(14.68)
801–1200
4.000
(101.6)
2.531
(64.29)
1.078
(27.38)
2.000
(50.8)
0.609
(15.48)
2.516
(63.90)
0.250
(6.35)
0.438
(11.11)
1.441
(36.60)
0.735
(18.67)
600
61–100 2.953
(75.01)
2.352
(59.74)
1.640
(41.66)
0.750
(19.05)
0.281
(7.14)
0.828
(21.03)
0.500
(12.70)
0.125
(3.18)
0.646
(16.41)
0.300
(7.62)
101–200
3.250
(82.55)
2.507
(63.67)
1.660
(42.16)
0.875
(22.22)
0.344
(8.74)
1.078
(27.38)
0.500
(12.70)
0.188
(4.78)
0.787
(19.99)
0.372
(9.45)
201–400
3.625
(92.08)
2.719
(69.06)
1.730
(43.94)
1.000
(25.40)
0.406
(10.31)
1.625
(41.28)
0.500
(12.70)
0.250
(6.35)
0.926
(23.52)
0.453
(11.51)
401–600
3.984
(101.19)
2.953
(75.01)
1.780
(45.21)
1.250
(31.75)
0.484
(12.29)
2.094
(53.19)
0.500
(12.70)
0.312
(7.92)
1.074
(27.28)
0.516
(13.11)
601–800
4.328
(109.93)
3.172
(80.57)
1.875
(47.63)
1.750
(44.45)
0.547
(13.89)
2.516
(63.91)
0.500
(12.70)
0.375
(9.53)
1.207
(30.66)
0.578
(14.68)
aTolerances: 61–200 A, 300 V, ±0.020 in (±0.51 mm); 201–1200 A, 300 V and 61–800 A, 600 V, ±0.40 in (±1.02 mm).
bColumn B tolerance: ±0.015 in (±0.38 mm).
cColumns D and J tolerance: ±0.020 in (±0.51 mm), except J tolerance ±0.028 in (±0.71 mm) for 801–1200 A, 300 V.
dTolerances: minus 0.000 in (minus 0.00 mm); 61–100 A, plus 0.005 in (plus 0.13 mm); 101–200 A, plus 0.006 in (plus 0.15 mm); 201–400 A,
plus 0.007 in (plus 0.18 mm); 401–1200 A, plus 0.008 in (plus 0.20 mm).
eColumn H tolerance: ±0.006 in (±0.15 mm).
Figure 5-8—Class T fuse dimensions

IEEE
Figure 5-9—Class CC fuse dimensions
DIMENSIONS OF CLASS CC FUSES IN INCHES (mm)
Rating
Ferrule
Diametera
Ferrule
Lengtha
Ferrule
Lengtha
Rejection
Length a
Overall
Lengthb
Rejection
Diametera
Volts Amperes A B C D E F
600 0–30 0.405
(10.29)
0.375
(9.53)
0.375
(9.53)
0.125
(3.18)
1.500
(38.10)
0.250
(6.35)
a
Tolerance: ±0.005 in (±0.13 mm).
b
Tolerance: ±0.31 in (±0.79 mm).

IEEE
Figure 5-10—Class R fuse dimensions
DIMENSIONS OF BLADE-TYPE CLASS R FUSES IN INCHES (MM)
Rating
Overall
length
of fusea
aTolerances: 61–200 A, ±0.062 in (±1.57 mm); 201–600 A, ±0.094 in (±2.39 mm).
Minimum
length of
bladeb
bThe length of one blade shall not be more than 0.062 in (1.57 mm) longer than the other blade.
Thickness
of bladec
cColumn E tolerance: ±.003 in (0.08 mm).
Width
of
bladed
dColumn F tolerance: ±0.035 in (0.89 mm).
Maximum dimensions
over projections Minimum
distancefrom
midpoint of
fuse to
nearest live
part
Minimum
maximum
overall
length of
cylindrical
bodye
eThe length of the cylindrical body may be less than the indicated value if other acceptable interference means (pins through the blades, collars,
or the like) are provided to prevent mounting the fuse in a fuseholder that will accomodate a fuse rated in the next lower bracket of current rating.
Distance of
rejection
feature
from endf
fColumn K tolerance: ±0.008 in (±0.20 mm).
Width of
rejection
featureg
gColumn L tolerance: –0.005, +0.025 in (–0.13, +0.64 mm). Dimension is diameter of slot at semicircle. Maximum rounding of corner at end of
slot 0.125 in (3.18 mm) radius.
Web width
of blade at
rejection
featureh
hColumn N tolerance: ±0.031 in (±0.79 mm).
Volts Amperes
Measured
parallel to
blade
Measured
at right
angles to
blade
A C E F G H I J K L N
250
61–100 5.875
149.22
1.000
(25.40)
0.125
(3.18
0.750
(19.05)
0.656
(16.66)
0.594
(15.09)
1.031
(26.19)
3.376–3.781
(85.72–
96.04)
0.500
(12.70)
0.281
(7.14)
0.250
(6.38)
101–200 7.125
(180.98)
1.375
(34.92)
0.188
(4.78)
1.125
(26.58)
0.938
(26.83)
0.844
(21.44)
1.188
(30.18)
4.125–4.281
(104.78–
108.74)
0.688
(17.48)
0.281
(7.14)
0.438
(11.13)
201–400 8.625
(219.08)
1.875
(47.62)
0.250
(6.35)
1.625
(41.28)
1.203
(30.56)
1.203
(30.56)
1.188
(30.18)
4.625–4.813
(117.48–
122.25)
0.938
(22.83)
0.406
(10.31)
0.625
(15.68)
401–600 10.375
(263.52)
2.250
(57.15)
0.250
(6.35)
2.000
(50.80)
1.453
(36.91)
1.453
(36.91)
1.531
(38.69)
5.188–5.813
(131.78–
147.55)
1.125
(28.68)
0.531
(13.49)
0.750
(19.06)
600
61–100 7.875
(200.02)
1.000
(25.40)
0.125
(3.18)
0.750
(19.05)
0.781
(19.84)
0.719
(18.26)
1.750
(44.45)
5.375–5.781
(136.52–
146.84)
0.500
(12.70)
0.281
(7.14)
0.250
(6.35)
101–200 9.625
(244.48)
1.375
(34.92)
0.188
(4.78)
1.125
(28.58)
1.062
(26.97)
0.984
(24.99)
2.250
(57.15)
6.125–6.781
(155.58–
172.24)
0.688
(17.48)
0.281
(7.14)
0.438
(11.13)
201–400 11.625
(295.28)
1.875
(47.62)
0.250
(6.35)
1.625
(41.28)
1.453
(36.91)
1.453
(36.91)
2.500
(63.50)
7.125–7.831
(180.98–
198.90)
0.938
(23.83)
0.406
(10.31)
0.625
(15.88)
401–600 13.375
(339.72)
2.250
(57.15)
0.250
(6.35)
2.000
(50.80)
1.719
(43.66)
1.719
(43.66)
2.688
(68.28)
8.188–8.844
(207.98–
224.64)
1.125
(28.58)
0.531
(13.49)
0.750
(19.05)

IEEE
5.5 Typical interrupting ratings
Interrupting ratings of low-voltage fuses expressed in rms symmetrical amperes are as
follows:
Some fuses that meet the dimensional and performance requirements of Class RK-1, Class J,
and Class L fuses have been listed or certiﬁed as “special purpose” with interrupting ratings
of 300 000 A.
Fuse
Typical interrupting rating
(kA)
Class H 10
Class K 50, 100, or 200
Class RK-1 and Class RK-5 200
Class J, Class CC, Class T, and Class L 200
Class G 100
Plug fuses 10
DIMENSIONS OF FERRULE-TYPE CLASS R FUSES IN INCHES (MM)
Rating
Overall
length of
fusea
a
Column A tolerance: ±0.031 in (±0.79 mm).
Maximum
outside
diamter of
tube
Minimum
length of
ferrule
Outside
diameter of
ferruleb
b
Column D tolerance: ±0.008 in (±0.20 mm). To provide proper contact, the diameter of rejection ferrule end shall be equal to or not more than
0.050 in (1.27 mm) smaller than actual diameter of main contact area for any fuse, and no part of rejection ferrule end shall protrude beyond the
diameter of the main part of the ferrule.
Distance of
rejection
feature from
endc
c
Column K tolerance: +0.008, –0.016 in (+0.20, –0.41 mm).
Minimum
width of
rejection
featured
d
Dimension column L: Distance between centers of 0.031 in (0.79 mm) radius fillets. Shape of rejection groove is not specified but shall be com-
pletely within solid and dashed lines regardless of shape.
Minimum-
maximum
depth of
rejection
feature
Maximum
width
toward
end
Maximum
width
toward body
Volts Amperes
A B C D K L M L2 L1
250
0–30 2.000
(50.80)
0.531
(13.49)
0.500
(12.70)
0.562
(14.27)
0.156
(3.96)
0.070
(1.78)
0.085–0.130
(2.16–3.30)
0.115
(2.92)
0.150
(3.81)
31–60 3.000
(72.60)
0.781
(19.84)
0.625
(15.88)
0.812
(20.62)
0.188
(4.78)
0.086
(2.18)
0.085–0.130
(2.16–3.30)
0.123
(3.12)
0.170
(4.32)
600
0–30 5.000
(127.00)
0.781
(19.84)
0.500
(12.70)
0.812
(20.62)
0.188
(4.78)
0.086
(2.18)
0.085–0.130
(2.16–3.30)
0.123
(3.12)
0.170
(4.32)
31–60 5.500
(139.70)
1.031
(26.19)
0.625
(15.88)
1.062
(26.97)
0.250
(6.35)
0.086
(2.18)
0.085–0.130
(2.16–3.30)
0.154
(3.91)
0.180
(4.57)
Figure 5-10—Class R fuse dimensions (continued)

IEEE
5.6 Achieving selectivity with fuses
5.6.1 Basic considerations
Because the electrical distribution system is the heart of most industrial, commercial, and
institutional installations, preventing any unnecessary shutdowns of electrical power is
imperative. Such incidents can be avoided by the proper selection of overcurrent protective
devices. Selectivity (often referred to as selective coordination) is obtained when a minimum
amount of equipment is removed from service for isolation of an overcurrent condition.
Figure 5-11 shows a selective system. Figure 5-12 illustrates the general principle by which
current-limiting fuses coordinate for any value of short-circuit current sufﬁcient for them to
operate in the current-limiting mode. For selectivity, the total clearing I2
t of Fuse B should be
less than the minimum melting I2
t of Fuse A. In low-voltage fuse applications, coordination
may sometimes be determined through the use of selectivity ratio tables (see 5.6.3).
5.6.2 Time-current characteristic (TCC) curves
TCC curves of fuses show the relationship between various overcurrrent values and their
respective opening times. They are plotted on transparent log-log paper so they may be easily
traced. The current values are normally represented on the abscissa (or bottom of the curve).
The time values are shown on the ordinate (or vertical side) and may represent the minimum
Figure 5-11—Selective operation of overcurrent protective devices

IEEE
melting time, average melting time, or total clearing time, as specified on the curve. The
average melting time is assumed to be represented unless otherwise stated. It represents an
opening characteristic having a maximum tolerance of ±15% in current for any given time.
Thus the –15% boundary represents the minimum melting characteristic, and the +15%
boundary usually represents the total clearing time. For times greater than 0.1 s, the
maximum melting time is essentially the same as the total clearing time. For times less than
0.01 s, the arcing time may be equal to or greater than the maximum melting time. In these
short periods, the I2
t (or fault energy) becomes of increasing importance. The curves in
Figure 5-13 and Figure 5-14 show the average melting time characteristics for RK-5 time-
delay fuses (30–600 A) and Class L current-limiting fuses (800–6000 A), respectively.
5.6.3 Selectivity ratio tables
Table 5-1 shows a typical selectivity schedule for various combinations of fuses. This sched-
ule is general and is different for each fuse manufacturer. Specific data are available from the
fuse manufacturers. An example of using Table 5-1 is found in Figure 5-15, where a 1200 A
Class L fuse is to be selectively coordinated with a 400 A Class J current-limiting fuse.
Selectivity schedules or tables are used as a simple check for selectivity, assuming that identi-
cal or reduced fault currents flow through the circuits in descending order, that is, from main,
to feeder, to branch. Where closer fuse sizing than indicated is desired, the fuse manufacturer
should be consulted as the ratios may be reduced for lower values of short-circuit current. A
coordination study may be desired when the simple check as outlined is not sufficient and can
be accomplished by plotting fuse TCC curves on standard log-log graph paper. If fuse ratios
for high- or medium-voltage fuses to low-voltage fuses are not available, it is recommended
that the fuse curves in question be plotted on log-log paper. Also, fuse ratios cannot be used
with fuses at different voltages or from different manufacturers. Fuse manufacturers can fur-
nish selectivity tables showing actual ampere ratings.
Figure 5-12—Selectivity of current-limiting fuses

IEEE
Figure 5-13—Time-delay fuses, Class RK-5

IEEE
Figure 5-14—Current-limiting fuse, Class L

IEEE
NOTE—At short-circuit power factors greater than 15%, peak and equivalent rms let-through currents
are less than the values that can be determined from a let-through chart. However, no acceptable method
has been developed to determine these lower values. Therefore, the line with a slope of 2.3 may not be
moved to the right or left to account for power factors other than 15%. These charts then provide worst
case values for power factors of 15% or greater.
5.6.4 Example selectivity study
A typical example showing selectivity between a high-voltage and a low-voltage fuse using
this graphic analysis is shown in Figure 5-16. The total clearing curve of the 1200 A low-
voltage fuse and the minimum melting curve of the 125E-rated 5 kV fuse are separated by
clear space and thus are said to be selective. The curves are referred to 240 V because this
study is of secondary faults.
5.7 Current-limiting characteristics
Due to the speed of response to short-circuit currents, current-limiting fuses have the ability
to cut off the current before it reaches its full prospective short-circuit value. Figure 5-1,
Figure 5-2, and Figure 5-12 show the current-limiting action of fuses. The available short-
circuit current would ﬂow if no fuse were in the circuit or if a noncurrent-limiting protective
device were in the circuit. In its current-limiting range, a current-limiting fuse limits the peak
current to a value less than the available value; opens in 0.5 cycle or less in its current-
limiting range; and, therefore, lets through only a portion of the available short-circuit energy.
Table 5-1—Typical selectivity schedulea
for low voltage fuses
Line side
Load side
Class L
fuse
601–
6000 A
Class K1
fuse
0–600 A
Class J
fuse
0–600 A
Class K5
time-delay
fuse
0–600 A
Class J
time-delay
fuse
0–600 A
Class G
fuse
0–60 A
Class L fuse
601–6000 A
2:1 2:1 2:1 6:1 2:1
Class K1 fuse
0–600 A
2:1 3:1 8:1 4:1 4:1
Class J fuse
0–600 A
3:1 3:1 8:1 4:1 4:1
Class K5 time-
delay current-
limiting fuse
0–600 A
1.5:1 1.5:1 2:1 1.5:1 2:1
Class J time-
delay fuse
0–600 A
1.5:1 1.5:1 8:1 2:1 2:1
NOTE—For illustration only. Refer to fuse manufacturer for specific and up-to-date data.
aExact ratios vary with ampere ratings, system voltage, and short-circuit current.

IEEE
The degree of current limitation is usually represented in the form of peak let-through current
charts.
5.7.1 Peak let-through current charts
Peak let-through current charts (sometimes referred to as current-limiting effect curves) are
useful for determining the degree of short-circuit protection that a current-limiting fuse
provides to the equipment beyond it. These charts show fuse peak let-through current as a
function of available symmetrical rms current, as shown in Figure 5-17. The straight line
running from the lower left to the upper right shows a 2.3 relationship (based on a 15% power
factor; see UL 248-1-2000 and CSA C22.2 No. 248-1-2000) between the peak current that
would occur without a current-limiting devise in the circuit and the available symmetrical
rms current. Peak let-through current and apparent equivalent rms let-through current can be
determined from the let-through current charts and are useful in relating to equipment
withstandability.
Let-through data may be compared to short-circuit ratings of the ﬁxed components that are
static and have a time rating of 0.5 cycle or longer at a test circuit power factor of 15% or
greater. Examples include wire, cable, and bus. An example showing the application of the
let-through current charts is represented in Figure 5-18, where the load-side component is
protected by an 800 A current-limiting fuse.
Example: Determine the fuse let-through current values with 40 000 A rms symmetrical
available at the line side of the fuse. Enter the let-through current chart of Figure 5-17 at an
available current of 40 000 A rms symmetrical, and ﬁnd a fuse peak let-through current of
Figure 5-15—Typical application of selective coordination (see Table 5-1)

IEEE
38 000 A and an effective rms current of 16 500 A. The clearing time is less than 0.5 cycle.
The load-side circuit components is not subjected to an I2
t duty greater than the total clearing
let-through I2
t of the fuse.
Magnetic forces vary with the square of the peak current IP
2
and can be severe. These forces
can be reduced considerably when current-limiting fuses are used.
Figure 5-16—Typical coordination study of primary and secondary fuses
showing selective system

IEEE
Figure 5-17—Typical 60 Hz peak let-through current as a function of
available rms symmetrical current (15% power factor)
Figure 5-18—Example for applying fuse let-through charts

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5.7.2 Maximum clearing I 2t
I2
t is a measure of the energy that a fuse lets through while clearing a fault. Every piece of
electrical equipment is limited in its capability to withstand energy. The equipment I2
t with-
stand rating can be compared with maximum clearing I2
t values for fuses. These maximum
clearing I2
t values are available from fuse manufacturers.
5.8 Special applications for low-voltage fuses
5.8.1 Bus-bracing requirements
Reduced bus-bracing requirements may be attained when current-limiting fuses are used.
Figure 5-19 shows an 800 A motor-control center being protected by 800 A Class L fuses.
The maximum available fault current to the motor-control center is 40 000 A rms symmetri-
cal. If a noncurrent-limiting device were used ahead of the motor-control center, the bracing
requirement would be a minimum of 40 000 A rms symmetrical, with a peak value of
92 000 A (2.3 × 40 000 A). For this example with current-limiting fuses, the maximum peak
current has been reduced from 92 kA to 38 kA with a corresponding reduction in effective
rms available current from 40 kA to 16.5 kA. As a result, bus bracing of 16.5 kA or greater is
possible rather than requiring the full 40 kA bracing. Most bus is now listed for maximum
short-circuit currents with speciﬁc types and sizes of current-limiting fuses. The bus manu-
facturer should be consulted for these speciﬁc combination ratings.
5.8.2 Circuit breaker protection
Molded case, insulated case, and power circuit breakers protected by current-limiting fuses
may be applied in circuits where the available short-circuit current exceeds the interrupting
rating of the circuit breakers alone. The short-circuit interrupting rating for older style
Figure 5-19—Example for determining bus-bracing requirements of
800 A motor-control center

IEEE
nondynamic impedance circuit breakers can be compared to fuse let-through current values
to determine the degree of protection provided. Using present methods, engineering protec-
tion for modern circuit breakers exhibiting dynamic impedance through the use of repulsion
(or blow-apart) contacts is not possible.
However, nationally recognized testing laboratories have developed a set of tests that do
establish that a particular fuse and circuit breaker combination will successfully clear a fault.
These successful combinations are given a series rating and are typically published in recog-
nized component directories. These recognized combinations should be speciﬁed for use in
load centers, panelboards, and switchboards that have been tested, listed, and marked for their
use. The circuit breaker and fuse manufacturers should be consulted for proper applications.
An example of applying fuses to protect molded-case circuit breakers is given in Figure 5-20,
where an older 225 A lighting panel has circuit breakers with an interrupting rating of
14 000 A rms symmetrical. The available fault current at the line side of the lighting panel
is 40 000 A rms symmetrical. A 400 A RK-1 fuse would reduce the current at the circuit
breakers to an effective 8000 A rms available. With this signiﬁcant level of current limitation
by the fuse ahead of the circuit breaker, the circuit breaker will interrupt an effectively lower
short circuit that is within its interrupting rating.
5.8.3 Wire and cable protection
Fuses should be sized for conductor protection according to the NEC. When noncurrent-
limiting overcurrent protective devices are used, reference should be made to the insulated
cable thermal damage charts for short-circuit withstands of copper and aluminum cable in
ICEA P-32-382-1999. (Also, see Chapter 9.)
Figure 5-20—Application of fuses to protect molded-case circuit breakers
WARNING—The use of circuit breakers with repulsion contact designs must be limited to systems
listed for the fuse/circuit breaker combination.

IEEE
When current-limiting fuses are used, small conductors are protected from high-magnitude
short-circuit currents even though the fuse may be 300% to 400% of the conductor ampacity
rating as allowed by the NEC for nontime-delay fuses for motor branch circuit protection.
5.8.4 Motor starter short-circuit protection
UL tests motor starters under short-circuit conditions (see UL 508-1999). The short-circuit
test performed may be used to establish a withstand rating for motor starters. UL tests motor
starters of 50 hp 37 kW and under with a minimum of 5000 A of available short-circuit cur-
rent. Starters over 50 hp 37 kW in size are tested in similar fashion, except with greater avail-
able fault currents.
When applying motor starters in systems with high available fault currents, current-limiting
fuses are often used to reduce the let-through energy to a value within the withstand of the
motor starter. The motor starter manufacturer should be contacted for proper applications.
Figure 5-21 is a typical one-line diagram of a motor circuit, where the available short-circuit
current has been calculated to be 40 000 A rms symmetrical at the motor-control center and
the fuses are to be selected so that short-circuit protection is provided. The fuse selected
should limit the fault current to within the withstand rating of the motor starter. In this case
the starter has been investigated and found acceptable for fault levels through 100 000 A
when protected by Class J fuses. IEC 60947-4-1 describes two types of motor controller pro-
tection in terms of the extent of damage to which the motor controller is subjected during a
short circuit. Type 1 is similar to the requirements for listing in UL 508-1999, but the control-
ler may still need to be replaced because of the significant amount of damage allowed. Type 2
is much more restrictive and allows no permanent damage to the controller. Many motor con-
troller manufacturers have had UL verify their controllers with Class J, Class RK-1, and
Class CC fuses for Type 2 protection in compliance with IEC 60947-4-1. The motor control-
ler manufacturers or fuse manufacturers should be consulted for lists of specific fuses to use
with specific controllers.
5.8.5 Transformer protection
Low-voltage distribution transformers are often equipped on the primary side (above 600 V)
with medium-voltage fuses sized for short-circuit protection. Transformer overload protec-
tion may be provided by fusing the low-voltage secondary with appropriate fuses sized at
100% to 125% of the transformer secondary full-load amperes. Figure 5-22 shows a proper
size of low-voltage fuse for a 1000 kVA transformer to provide overload protection.
Transformers are frequently used in low-voltage electrical distribution systems to transform
480 V to 208Y/120 V. For these types of transformers, appropriate time-delay fuses should
be provided, sized at 100% to 125% of the primary full-load current. Consideration should be
given to the magnetizing inrush current because dry- and liquid-immersed transformers have
inrush currents equivalent to about 12, or even as high as 18, times full-load rating with a
duration of 0.1 s (also about 20 to 25 times rating for 0.01 s).

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Inrush currents can be easily checked against the minimum melting curve so that needless
opening may be avoided. If necessary, a larger size time-delay fuse may need to be selected.
Figure 5-23 shows a 225 kVA lighting transformer with time-delay fuses. See Chapter 11 for
transformer protection.
Figure 5-21—Application of fuses to provide short-circuit protection and
backup protection for motor starters
Figure 5-22—Sizing of low-voltage fuses for transformer secondary
protection

IEEE
5.8.6 Motor overcurrent protection
Single- and three-phase motors can be protected by specifying time-delay fuses for motor-
running overload protection according to the NEC. These ratings depend on service factor,
temperature rise, and application (e.g., jogging). Where motor overload relays are used in
motor starters, a larger size time-delay fuse may be used to coordinate with the motor over-
load relays and provide short-circuit protection.
Combination motor starters that employ overload relays sized for motor-running protection
(maximum of 115% for 1.0 service factor and 125% for 1.15 service factor) can incorporate
time-delay fuses sized at 115% (1.0 service factor) or 125% (1.15 service factor) or the next
larger size to serve as backup protection. (Larger time-delay fuses, sized up to 175%, may be
used for branch circuit protection only.) A combination motor starter with backup fuses pro-
vides excellent protection, motor control, and ﬂexibility. Figure 5-24 illustrates the use of
fuses for protection of a typical motor circuit.
When motors are operated near full-load, single-phasing protection may be provided by time-
delay fuses sized at approximately 125% of the motor full-load current. Loss of one phase,
either primary or secondary, results in an increase in the line current to the motor. This
change is sensed by the motor fuses because they are sized at 125%, and the single-phasing
current opens the fuses. If the motors are operated at less than full load, the overload relays
and time-delay fuses should be sized to the actual running amperes of the motor. For exam-
ple, if a motor with a full-load rating of 10 A is being used in a situation where it is drawing
only 8 A, the time-delay fuses should be sized at 10 A instead of 12 A. Another option is to
utilize antisingle-phasing motor overload relays.
Figure 5-23—Application of time-delay fuses for transformer protection

IEEE
5.8.7 DC applications
Most dc systems require some form of overcurrent and/or short-circuit protection (see
Brozek). These systems include dc motor drives and controllers, semiconductor components,
telecommunication switching stations (both power and signal), electrical relay and control
circuits for medium-voltage circuit breakers, and transit substations. Battery-powered appli-
cations from automobiles and factory warehouse vehicles to more sophisticated loads such as
uninterruptible power supply (UPS, or battery backup) systems also require dc overcurrent
protection. As with any fuse selection, the three elements of system voltage, normal load cur-
rent, and available short-circuit current should be considered. For proper application, the
fuse’s ratings should equal or exceed the system parameters. The user should always obtain
the proper dc data from the manufacturer.
Furthermore, the manufacturer’s dc test data may not necessarily apply to the dc system at
hand. Factors including circuit time constant, voltage, and available short-circuit current may
preclude the use of certain dc-rated fuses.
A common misconception is that all published ac fuse data may be used for those same fuses
on dc systems. Time-current curves that predict a fuse’s opening time under overload condi-
tions can be used for ac and sometimes dc current. These curves are typically based on rms
current, which is thermally equivalent to dc current. However, dc applications have an added
twist in that the time constant of the system should also be considered. The dc time constant
affects the melting and clearing time of the fuse under overload and short-circuit conditions.
The net result is typically a lower voltage rating for the fuse. For a better understanding of
how fuses are rated for dc, see UL 198L-1995.
5.8.7.1 UL 198L-1995
UL 198L-1995 deﬁnes the requirements and test procedures for dc-rated fuses for industrial
use in accordance with the NEC. Fuses that are tested to UL 198L-1995 should ﬁrst meet the
requirements of their respective ac standard.
Figure 5-24—Application of time-delay fuses for typical motor circuit

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5.8.7.2 Overload test
Fuse selection for the overload test is based on internal construction and case size (see
UL 198L-1995). The largest ampere rating for each internal design and/or case size is sam-
pled. These fuses should open a circuit adjusted to obtain 200% of the current rating at rated
dc voltage. For fuses with current ratings greater than 600 A, the test circuit can deliver 200%
to 300% of the current rating at rated dc voltage. The time constant for this test cannot be less
than the value given by
(5-1)
where
T is the time constant (ms),
I is the test current (A).
The time constant is the time required for the current to reach 63.2% of the test current and is
shown in Figure 5-25.
Additionally, fuses marked with “D,” “time delay,” “dual element” or similar designations
and in compliance with time-delay fuse requirements are to be tested on a circuit adjusted to
900% of the fuse rating at rated dc voltage. (This test is not required for Class L fuses.) For
both the 200% and 900% test, the test voltage is maintained for 1 min after circuit
interruption to insure that the fuse has permanently cleared the circuit. To pass the test, the
fuse casing cannot char or rupture, and external solder connections cannot melt. The time
required for the fuse to clear is not speciﬁed.
5.8.7.3 Interrupting ability test
To establish the short-circuit interrupting rating, fuses are tested at one of the following dc
voltage levels: 60 V, 125 V, 160 V, 250 V, 300 V, 400 V, 500 V, or 600 V (see UL 198L-
1995). A Class H fuse has a maximum dc interrupting rating of 10 000 A. All other classes
rated 600 A or less have maximum dc interrupting ratings of 10 000 A, 20 000 A, 50 000 A,
or 100 000 A. Class L and Class T fuses greater than 600 A have maximum interrupting
T
I
0.3
2
-------
=
Figure 5-25—Time constant for dc circuits per UL 198L-1995

IEEE
ratings of 20 000 A, 50 000 A, or 100 000 A. The time constant for these heavy short-circuit
tests cannot be less than 10 ms. As in the overload test, the largest ampere rating for each
internal design and/or case size is sampled. To pass, the fuse should remain intact and
permanently clear the circuit. The overall length of the cylindrical portion of the fuse cannot
be deformed more than 3.2 mm, and molten solder cannot be emitted. After interruption, the
recovery voltage is continuously applied for 30 s to ensure that the fuse has become
quiescent. Evidence of smoking, unusual heating, or internal arcing during this period is
unacceptable. When the interrupting ability test is conducted above 10 000 A, the peak let-
through current and clearing I2
t cannot exceed the established ac values for the respective
fuse class. DC listed Class L fuses have a minimum interrupting rating of 20 kA. However,
UL 248-10-2000 and CSA C22.2 No. 248.10-2000 have 50 kA as the lowest fault level for
which maximum clearing I2
t and I peak are deﬁned. Table 5-2 indicates these values for
50 kA available short-circuit current.
Maximum values taken from various fuse classes are shown in Table 5-3. The clearing values
shown in Table 5-2 and Table 5-3 are the maximum allowable to meet UL 198L-1995. Actual
values of clearing I2
t and Ip may be much less than the maximums and can be obtained from
the fuse manufacturer.
5.8.7.4 Maximum energy test
The ﬁnal short-circuit test for fuse types with interrupting ratings greater than 10 000 A is the
maximum energy test (see UL 198L-1995). These fuses should interrupt short-circuit current
of at least 10 000 A and limit the peak let-through current to 60% to 80% of the peak avail-
able. The largest amperage size of each fuse case size is sampled. Before testing, fuses are
preconditioned in a high-humidity environment for 5 days.
Fuses listed to UL 198L-1995 typically are rated at a dc voltage level lower than the ac rating.
The lower voltage rating is a direct result of the time constant requirement within the
standard.
Table 5-2—Short-circuit values for Class L fuses
Amperage range Clearing I2t × 106 a IP × 103b
601–800 10 80
801–1200 12 80
1201–1600 22 100
1601–2000 35 110
aUnits are rms amperes2seconds × 106
bUnits are peak amperes × 103

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5.8.7.5 Mine duty fuses
UL 198M-1995 is an additional procedure to list Class K and Class R fuses intended for use
in protecting trailing cables in dc circuits in mines. The standard follows MSHA require-
ments. Fuses tested to UL 198M-1995 should ﬁrst comply with their respective ac standard.
The dc voltage ratings for UL 198M-1995 are 300 V or 600 V. The largest ampere rating for
each internal design and/or case size is sampled after temperature and humidity conditioning.
The overload and short-circuit requirements are given in Table 5-4.
The minimum time constants for this test are shown in Table 5-5. The time constants required
for UL 198M-1995 are greater than the time constants in UL 198L-1995. Fuses are tested
both in open fuse clips and in trolley-tap fuseholders. After the fuse interrupts the circuit, the
test voltage is applied for 30 s. Performance is acceptable if the fuse clears without excessive
smoking or excessive venting of gases.
Table 5-3—Maximum clearing I2
t and Ip for various fuse classes:
available short-circuit current between threshold and 50 kA rms
Amperage
range
Class CC Class J Class RK5
Clearing
I2t × 103 a Ip × 103 b Clearing
I2t × 103 a Ip × 103 b
0–20 2 3 7 6 50 11
21–30 7 6 7 6 50 11
31–60 – – 30 8 200 20
61–100 – – 60 12 500 22
101–200 – – 200 16 1600 32
210–400 – – 1000 25 5000 50
401–600 – – 2500 35 10 000 65
601–800 – – – – – –
801–1200 – – – – – –
Amperage
range
Class RK1 Class T (600 V) Class T (300 V)
Clearing
I2t × 103 a Ip × 103 b
0–20 10 6 7 6 3.5 5
21–30 10 6 7 6 3.5 5
31–60 40 10 30 8 15 7
61–100 100 14 60 12 40 9
101–200 400 18 200 16 150 13
210–400 1200 33 1000 25 550 22
401–600 3000 43 2500 35 1000 31
601–800 – – 4000 50 1500 37
801–1200 – – – – 3500 50
aUnits are rms amperes2seconds× 103
bUnits are peak amps × 103

IEEE
Superﬁcial damage to the fuse is allowable, that is, a maximum of 1.588 mm hole in any
metal part of fuse or a maximum of one 3.175 mm opening in any nonmetal part of the fuse.
Restrike is allowable within 30 ms of initial current interruption. If a restrike occurs, the test
voltage is again applied for 30 s, and no further restriking is allowable. Fuses tested in the
trolley tap fuseholder cannot damage the fuseholder. UL 198M-1995 does not specify peak
allowable let-through current or maximum I2t values. It is exceedingly difﬁcult for fuses to
just survive this test because of the voltage constraints and relatively long time constants. For
a better understanding of how these parameters affect the fuse, an explanation of circuit time
constant is given in 5.8.7.6.
Table 5-4—Tests of fuses
200% clearing at rated voltagea
300% clearing at rated voltageb
900% overload at rated voltage
Interrupting ability at 10 000 A
Interrupting ability at 20 000 A
Source: UL 198M-1995.
aFor fuses with a rating 200 A or less
bFor fuses with a rating greater than 200 A
Table 5-5—Circuit time constants
Test current
(A)
Time constant
(ms)
0–99 2
100–999 6
1000–9999 8
+10 000 16

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5.8.7.6 DC time constant
The circuit time constant is the time required for the current to reach 63.2% of the peak cur-
rent and may be stated as
(5-2)
where
I is current at one time constant,
Ip is maximum peak current.
The time constant can be calculated by taking the ratio of inductance to resistance L/R in the
circuit. In simple terms, magnetic energy is stored in the inductance (in henrys) and opposes
any change in current. The relationship between energy and inductance is shown in
Equation (5-3).
(5-3)
where
U is magnetic energy,
L is inductance,
i is current.
For a circuit with a given resistance, a large inductance causes a slow rate of current rise, and
negligible inductance has a fast current rise. The maximum value to which the current rises is
limited by the circuit resistance. As a rule of thumb, fuses applied at rated voltage on dc cir-
cuits, having time constants less than 2 ms, have short-circuit melting and clearing
characteristics similar to fuses applied on ac circuits with short-circuit power factors of 15%
or greater. This assumption can be made because the current rise time di/dt is comparable.
5.8.7.7 DC voltage ratings
To meet the requirements in UL 198L-1995 or UL 198M-1995, the dc voltage ratings of
industrial power fuses are typically derated to about one half of the ac voltage rating. The
voltage derating decreases the arcing time needed to equalize to the system voltage, decreases
the arcing I2
t, and maintains clearing I2
t to below the allowable levels. Semiconductor fuses
that are designed primarily for dc systems typically have voltage derating charts for a given
time constant. One manufacturer’s voltage derating table is shown in Table 5-6.
For most battery protection applications, fuse operation is straightforward and reliable.
Batteries contain little inductance and, as stated by one large UPS manufacturer, a shorted
battery is similar to a fault through a resistor. A shorted battery drains rapidly and gives rise to
high di/dt. Fuses listed to UL 198L-1995 (and certainly UL 198M-1995) are generally
I 1 e
1
–
–
( )IP
=
U
1
2
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-
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IEEE
applicable for UPS battery protection. Proper placement of the fuse in a battery circuit is
beyond the scope of this recommended practice (see Nailen). For applications where
inductive loads are present (e.g., in motors, solenoids, any other coil loads), the circuit time
constant should be determined to ensure proper application of the fuse. By specifying fuses
with a rated dc voltage beyond the system voltage, the user incorporates more leeway into the
allowable time constants. If the dc voltage capability in a particular fuse application is
uncertain, the fuse manufacturer should be consulted.
5.9 References
CSA C22.2 No. 248.1-2000, Low Voltage Fuses—Part 1: General Requirements.2
CSA C22.2 No. 248.2-2000, Low Voltage Fuses—Part 2: Class C Fuses.
CSA C22.2 No. 248.3-2000, Low Voltage Fuses—Part 3: Class CA and CB Fuses.
CSA C22.2 No. 248.4-2000, Low Voltage Fuses—Part 4: Class CC Fuses.
CSA C22.2 No. 248.5-2000, Low Voltage Fuses—Part 5: Class G Fuses.
CSA C22.2 No. 248.6-2000, Low Voltage Fuses—Part 6: Class H Fuses, Nonrenewable.
Table 5-6—Voltage derating vs time constanta
Time constant
(L/R) ms
Percentage of rated voltage (rms)
700 V fuses 1000 V fuses
5 80–90% 85–95%
10 70–80% 80–90%
20 60–70% 70–85%
30 55–70% 65–80%
40 50–65% 60–75%
50 50–65% 55–70%
60 45–60% 50–65%
aBased on fuse opening time of 25–300 ms
2CSA publications are available from the Canadian Standards Association (Standards Sales), 178 Rexdale Blvd.,
Etobicoke, Ontario, Canada M9W 1R3 (http://www.csa.ca/).

IEEE
CSA C22.2 No. 248.7-2000, Low Voltage Fuses—Part 7: Class H Fuses, Renewable.
CSA C22.2 No. 248.8-2000, Low Voltage Fuses—Part 8: Class J Fuses.
CSA C22.2 No. 248.9-2000, Low Voltage Fuses—Part 9: Class K Fuses.
CSA C22.2 No. 248.10-2000, Low Voltage Fuses—Part 10: Class L Fuses.
CSA C22.2 No. 248.11-2000, Low Voltage Fuses—Part 11: Plug Fuses.
CSA C22.2 No. 248.12-2000, Low Voltage Fuses—Part 12: Class R Fuses.
CSA C22.2 No. 248.14-2000, Low Voltage Fuses—Part 14: Supplemental Fuses.
CSA C22.2 No. 248.15-2000, Low Voltage Fuses—Part 15: Class T Fuses.
ICEA P-32-382-1999, Short-Circuit Characteristics of Insulated Cable.3
IEC 60947-4-1, Low-Voltage Switchgear and Controlgear, Part 4: Contactors and Motor-
Starters, Section One—Electromechanical Contactors and Motor-Starters.4
NEMA FU 1-1986, Standard for Low-Voltage Cartridge Fuses 600 Volts or Less.5
NFPA 70-1999, National Electrical Code®
(NEC®
).6
UL 198L-1995, Safety Standard for DC Fuses for Industrial Use.7
UL 198M-1995, Safety Standard for Mine-Duty Fuses.
UL 248-1-2000, Safety Standards for Low Voltage Fuses—Part 1: General Requirements.
UL 248-2-2000, Safety Standard for Class C Fuses.
UL 248-3-2000, Safety Standard for Class CA and CB Fuses.
UL 248-4-2000, Safety Standard for Class CC Fuses.
3ICEA publications are available from ICEA, P.O. Box 20048, Minneapolis, MN 55420, USA (http://www.icea.org).
4IEC publications are available from the Sales Department of the International Electrotechnical Commission, Case
Postale 131, 3, rue de Varembé, CH-1211, Genève 20, Switzerland/Suisse (http://www.iec.ch/). IEC publications are
also available in the United States from the Sales Department, American National Standards Institute, 11 West 42nd
Street, 13th Floor, New York, NY 10036, USA.
5NEMA publications are available from Global Engineering Documents, 15 Inverness Way East, Englewood, CO
80112, USA (http://global.ihs.com/).

IEEE
UL 248-5-2000, Safety Standard for Class G Fuses.
UL 248-6-2000, Safety Standard for Class H Nonrenewable Fuses.
UL 248-7-2000, Safety Standard for Class H Renewable Fuses.
UL 248-8-2000, Safety Standard for Class J Fuses.
UL 249-9-2000, Safety Standard for Class K Fuses.
UL 248-10-2000, Safety Standard for Class L Fuses.
UL 248-11-2000, Safety Standard for Plug Fuses.
UL 248-12-2000, Safety Standard for Class R Fuses.
UL 248-14-2000, Fuses for Supplementary Overcurrent Protection.
UL 248-15-2000, Safety Standard for Class T Fuses.
UL 508-1999, Safety Standard for Industrial Control Equipment.
5.10 Bibliography
[B1] Brozek, J. P., “DC Overcurrent Protection—Where We Stand,” IEEE Conference Paper,
I&CPS 92-20 IEEE Log Number 9212380.
[B2] IEEE 100, The Authoritative Dictionary of IEEE Standards Terms, Seventh Edition.8
[B3] Nailen, R. L., “Battery Protection—Where Do We Stand?” IEEE Transactions, vol. 27,
no. 4, pp. 658–667, Jul./Aug. 91.

Chapter 6
High-voltage fuses (1000 V through 169 kV)
6.1 Definitions
Except for definitions specifically referring to low-voltage fuses, the general discussion in
5.1 and definitions in 5.2 apply to high-voltage fuses. In addition, the terms in 6.1.1 through
6.1.10 apply to high-voltage fuses:
6.1.1 applicable standards: Standards from the American National Standards Institute
(ANSI) and Institute of Electrical and Electronics Engineers (IEEE) define high-voltage
fuses as fuses rated above 1000 V. High-voltage fuses are available in voltages through
169 kV maximum rating. ANSI C84.1-1989 [B1]1 defines medium-voltage systems as having
a nominal voltage greater than 1000 V and less than 100 000 V. High-voltage systems are
defined as having a nominal voltage equal to or greater than 100 000 V and equal to or less
than 230 000 V. High-voltage fuses are, therefore, used on both medium- and high-voltage
systems up to their maximum voltage ratings. The following standards apply to high-voltage
fuses:
— IEEE Std C37.40-19932
— IEEE Std C37.41-2000
— ANSI C37.42-1996
— ANSI C37.44-1981
— ANSI C37.46-1981
— ANSI C37.47-1981
— IEEE Std C37.48-1987
— ANSI C37.53.1-1989
6.1.2 backup current-limiting fuse: A fuse capable of interrupting all currents from its max-
imum rated interrupting current down to its rated minimum interrupting current. (IEEE
Std C37.40-1993) The rated minimum interrupting current for backup current-limiting fuses
may be obtained from the manufacturer.
The backup current-limiting fuse requires another device in series (e.g., an expulsion fuse, a
relayed-controlled motor contractor) capable of interrupting currents below its minimum
interrupting current. The characteristics of both devices should be coordinated so that the
series device and the backup current-limiting fuse protect each other at currents above or
below their interrupting capabilities.
6.1.3 current-limiting fuse: A fuse unit that, when its current-responsive element is melted
by a current within the fuse’s specified current-limiting range, abruptly introduces a high
resistance to reduce current magnitude and duration resulting in subsequent current interrup-
tion. (IEEE Std C37.40-1993) This fuse interrupts the circuit at a natural current zero for all
1Numbers in brackets correspond with the numbers in the bibliography in 6.6.

IEEE
currents below the specified current-limiting range. However, the fuse interrupts in less than
half a cycle in its current-limiting mode by producing a high arc voltage across its terminals.
The specified current-limiting range normally occurs above approximately 25 times the rat-
ing of the fuse and limits the let-through energy as well as the available peak current.
6.1.4 expulsion fuse: A vented fuse (unit) in which the expulsion effect of the gases produced
by internal arcing, either alone or aided by other mechanisms, results in current interruption.
(IEEE Std C37.40-1993) Expulsion fuses interrupt the circuit at a natural current zero,
without limiting the peak of the available fault current or the available energy. Expulsion
fuses do not produce high arc voltages during fault interruption.
6.1.5 full-range current-limiting fuse: A fuse capable of interrupting all currents from its
rated interrupting current down to the minimum continuous current that causes melting of the
fusible element(s), with the fuse applied at the maximum ambient temperature specified by
the fuse manufacturer. (IEEE Std C37.40-1993)
6.1.6 general purpose current-limiting fuse: A fuse capable of interrupting all currents
from the rated interrupting current down to the current that causes melting of the fusible ele-
ment in no less than 1 h. (IEEE Std C37.40-1993) Care should be exercised to ensure that no
circuit conditions exist to cause melting of the fusible element from a current less than the
fuse’s 1 h melting current.
6.1.7 I 2
t (ampere-squared seconds) or let-through energy: In fuse terminology, a repre-
sentation for energy because, for most cases, I 2
t has approximately a linear relationship to
energy. Current-limiting fuse manufacturers publish minimum-melting and maximum total-
clearing I 2
t values for their products. In fuse application considerations where the user wants
to minimize damage to protected equipment, a fuse with the lowest let-through I 2
t is gener-
ally chosen.
6.1.8 peak arc voltage: When a current-limiting fuse interrupts a current, a voltage that
appears across its terminals during the arcing interval. For expulsion fuses, this voltage is
normally substantially lower than the system voltage regardless of the fault current magni-
tude and, therefore, is not a consideration in their application. However, when a current-limit-
ing fuse is interrupting a current in its current-limiting mode, the voltage across the fuse
exceeds the system voltage. However, modern current-limiting fuse elements, such as perfo-
rated ribbon, hold the arc voltage to within the levels defined by standards. ANSI C37.46-
1981 and ANSI C37.47-1981 specify the maximum for these voltages for current-limiting
power fuses, and Table 6-1 shows these values. In some designs, the current-limiting fuse’s
peak arc voltage is dependent on the system voltage. If such a fuse is applied in a system
whose voltage is less than the fuse’s rated voltage, the peak arc voltage is lower than its pub-
lished value. The manufacturer should be consulted for these peak arc voltages.
The peak arc voltage resulting from the operation of current-limiting fuses should be
considered when applying these fuses. The voltages are transitory. As such, they mimic other
transient voltages such as those produced by lightning strokes or switching surges. Even
though they exceed the nominal system voltage, the voltages typically are within normal
equipment voltage withstand levels. Experience has shown that current-limiting fuses can be

IEEE
HIGH VOLTAGE FUSES (1000 V THROUGH 169 KV) Std 242-2001
used with other equipment on the electric power distribution systems, such as metal oxide
varistor or silicon carbide surge arresters. See 6.4.2.6 for further discussion of current-
limiting fuses and peak arc voltage.
6.1.9 peak let-through current: For expulsion fuses, the prospective peak value of current
based on the fault impedance of that system. For a current-limiting fuse, the same definition
is true for all currents below its specified current-limiting range. However, in the specified
current-limiting range, the fuse limits the peak value of the available fault current to a lower
value depending on the fuse size.
The mechanical forces in a system are proportional to the square of the peak current, hence,
the peak let-through current may be an important consideration in certain applications. Peak
let-through currents for typical current-limiting fuses are shown in Figure 6-1.
6.1.10 time-current characteristics (TCCs): Specifically, minimum-melting and total-
clearing TCCs of fuses, which are plotted on a log-log scale with time on the Y axis and
current on the X axis. The fuse operates within the area between the two curves. Minimum-
melting curves are used for selecting fuses to provide maximum protection without operating
unnecessarily. The total-clearing curves are used when upstream device coordination is
required. Figure 6-2 and Figure 6-3 show typical minimum-melting and total-clearing
characteristics for high-voltage fuses. The fuse characteristics are different for each fuse type
and design and for each manufacturer. Thus, in a coordinated protective scheme, fuses cannot
be substituted without first matching their characteristics, conducting a coordination study, or
consulting the fuse manufacturer.
Table 6-1—Maximum permissible overvoltages for
current-limiting power fuses
Rated maximum voltage
(kV, rms)
Maximum peak overvoltages (kV, crest)
0.5 A to 12 A Over 12 A
2.8 13 9
5.5 25 18
8.3 38 26
15.0 68 47
15.5 70 49
22.0 117 70
25.8 117 81
27.0 123 84
38.0 173 119

IEEE
Figure 6-1—Peak let-through currents for
medium-voltage current-limiting fuses
Figure 6-2—Typical TCC curves for a current-limiting fuse

IEEE
6.2 Fuse classification
IEEE Std C37.40-1993 defines high-voltage fuses as above 1000 V; therefore, the definition
covers fuses used in both medium- and high-voltage systems. It also classifies fuses as power
fuses and distribution fuses, depending on the intended location of the fuses in the power sys-
tem. In addition, fuses may be classified for
— Outdoor application only, or
— Application indoors or in enclosures
Additionally, fuses using new technologies have been available since the early 1980s, but
have not yet been addressed by standards.
6.2.1 Power fuses
According to ANSI C37.42-1996, a power fuse is identified by the following characteristics:
— Dielectric withstand [i.e., basic impulse insulation level (BIL)] strengths at power
levels
— Application primarily in stations and substations
— Mechanical construction basically adapted to station and substation mountings
Power fuses have other characteristics that differentiate them from distribution fuses in that
they are available in higher voltage ratings, higher continuous-current ratings, higher inter-
rupting-current ratings, and in forms suitable for indoor and enclosure application and for all
types of outdoor applications.
Figure 6-3—Typical TCC curves for an expulsion fuse

IEEE
A power fuse consists of a fuse support (commonly called a mounting) plus a fuse unit or,
alternately, a fuse holder that accepts a refill unit or fuse link.
Power fuses are rated as E or R depending on their melting characteristics. They are defined
as follows:
— E rating. The current-responsive element for ratings 100 A or below shall melt in
300 s at a root-mean-square (rms) current within the range of 200% to 240% of the
continuous-current rating of the fuse unit, refill unit, or fuse link. The current-respon-
sive element for ratings above 100 A shall melt in 600 s at an rms current within the
range of 220% to 264% of the continuous-current rating of the fuse unit, refill unit, or
fuse link.
— R rating. The fuse shall melt in the range of 15 s to 35 s at a value of current equal to
100 times the R number.
When interchanging E-rated fuses of one manufacturer with another, coordination should be
carefully checked because the time-current characteristics (TCCs) may be different. The
same guidance applies to R-rated fuses. E-rated fuses are available as both expulsion and
current-limiting, and R-rated fuses are available only as current-limiting.
6.2.1.1 New designs of fuses
Power fuses employing new technology, such as vacuum or sulfur hexafluoride (SF6) as the
interrupting medium, have recently been developed. In general, these fuses have melting and
clearing characteristics similar to expulsion fuses. Other new technology fuses feature built-
in sensing and electronics to develop special melting characteristics. These fuses ordinarily
carry current through a bus bar. When the built-in sensing calls for operation, current is trans-
ferred almost instantaneously to a current-limiting fuse section for interruption by physically
separating the bus bar element sufficiently to prevent restrike from the system voltage and the
transient impulse created during the current-limiting interruption process. Some designs can
take a command from other protective systems located remotely from the fuse.
6.2.2 Distribution fuses
6.2.2.1 Distribution current-limiting fuses
According to IEEE Std C-37.40-1993, a distribution current-limiting fuse contains a fuse
support and a current-limiting fuse unit and is identified by the following characteristics:
a) Dielectric withstand (BIL) strengths at distribution levels
b) Application primarily on distribution feeders and circuits
c) Operating voltage limits corresponding to distribution system voltages
The specification for current-limiting distribution fuses is detailed in ANSI C37.47-1981.
Depending on the melting time characteristics, they may be given a C rating, which is defined
as follows: The current-responsive element shall melt in 1000 s at an rms current within the
range of 170% to 240% of the continuous-current rating of the fuse unit.

IEEE
The C rating specifies but one point on the TCC curve. While interchanging a C-rated fuse of
one manufacturer with another, coordination should be carefully checked because the TCCs
may be different.
The current-limiting fuse unit may be a disconnecting type or it may fit into a set of clips.
Some fuses rated up to 15.5 kV also have circuit interrupters so they can be used to discon-
nect a live circuit. The principle application is in underground distribution systems and they
are used for the protection of pad-mounted transformers supplying residential areas or small
commercial or industrial plants. Another application is in small, enclosed capacitor banks.
Both the clip and disconnecting styles may be used to provide an open point on loop feeds.
Backup fuses and some general purpose and full range fuses are also used in overhead sys-
tems where current limitation is desired. These types are also applied as under-oil fuses in
distribution transformers for the same reason. Because current-limiting fuses do not emit any
exhaust, they are also used in enclosures or vaults. Special types are used for the protection of
individual capacitors in outdoor capacitor banks.
6.2.2.2 Distribution fuse cutouts
According to IEEE Std C37.40-1993, a distribution fuse cutout is defined by the following
characteristics:
a) Dielectric withstand (BIL) strength at distribution levels
b) Application primarily on distribution feeders and circuits
c) Mechanical construction basically adapted to pole or crossarm mounting, except for
distribution oil-fused cutouts
d) Operating voltage limits corresponding to distribution system voltages
Characteristically, a distribution fuse cutout consists of a special insulating support and a fuse
holder. The fuse holder, normally a disconnecting type, engages contacts supported on the
insulating support and is fitted with a simple inexpensive fuse link (see Figure 6-4). This type
of fuse is normally an expulsion fuse; the holder is lined with a gas-evolving material, histor-
ically bone fiber. Interruption of an overcurrent takes place within the fuse holder by the
action of deionizing gases liberated when the lining is exposed to the heat of the arc estab-
lished when the fuse link melts in response to an overcurrent.
Distribution fuse cutouts were developed many years ago for use in overhead distribution
circuits. They are commonly applied on such circuits along with distribution transformers
supplying residential areas or small commercial or industrial plants. Fuse cutouts provide
protection to the distribution circuit by de-energizing and isolating a faulted transformer.
They are also used for protecting pole-mounted capacitor banks used for power factor
correction or voltage regulation.
ANSI C37.42-1996 details the specifications for the distribution cutouts and fuse links. Dis-
tribution fuse cutouts are available up to a continuous current of 200 A at 15 kV and up to
100 A at 38 kV. The maximum interrupting ratings, expressed in rms symmetrical amperes,
are given in Table 6-2.

IEEE
ANSI C37.42-1996 also specifies TCCs for Type K and Type T (i.e., fast and slow, respec-
tively) fuse links by means of three points on their time-current characteristic curves. None-
theless, fuses of the same type, but from different manufacturers, cannot be used
interchangeably from a time-current equivalency.
Overhead distribution cutouts, traditionally fitted with an expulsion fuse link, can now also
be fitted with full-range current-limiting dropout fuses. These fuses are designed for
mounting in an industry-recognized interchangeable cutout while offering all of the features
of a current-limiting fuse and the visual indication of operation with the drop open design.
Table 6-2—Maximum short-circuit interrupting ratings for
distribution fuse cutouts
Nominal rating
(kV)
Short-circuit interrupting rating
(A, rms symmetrical)
4.8 12 500
7.2 15 000
14.4 13 200
25.0 8 000
34.5 5 000
Figure 6-4—Open distribution fuse cutout, rated 100 A

IEEE
6.3 Current-limiting and expulsion power fuse designs
6.3.1 Current-limiting power fuses
Current-limiting power fuses generally consist of an insulating support (or mounting) and a
fuse unit. Their principal applications are for protecting voltage (or potential) transformers
(VTs), auxiliary transformers, power transformers, and capacitor banks, and in other
applications where their high interrupting ratings and current-limiting properties are
beneficial. Because current-limiting fuses do not emit any expulsion gases, they can be used
in enclosures or vaults. At present, the application of these types of fuses is in areas where the
voltage is between 2.4 kV and 34.5 kV nominal. The ratings for this style of fuse are given in
Table 6-3.
Current-limiting power fuses have three features that have led to their extensive usage on
medium-voltage power distribution circuits having high fault currents:
— Interruption of overcurrents is accomplished quickly without the expulsion of arc
products or gases, as all the arc energy of operation is absorbed by the sand filler of
the fuse and subsequently released as heat at relatively low temperatures. This feature
enables the current-limiting fuse to be used indoors or in enclosures of small size.
Furthermore, because no hot gases are discharged, only normal electric clearances
need to be provided. The absence of expulsion by-products also permits the fuse to be
immersed in dielectric fluid.
— The operation of a current-limiting fuse causes a reduction in the peak current
through the fuse to a value less than the current available from the power system if
the fault current greatly exceeds the continuous-current rating of the fuse. Such a
Table 6-3—Maximum continuous-current and short-circuit interrupting rating
for current-limiting power fuses
(kV)
Continuous-current ratings
(A) (maximum)
Short-circuit maximum
interrupting ratings
(kA, rms symmetrical)
2.75 225, 450,a 750,a 1350a
aParallel fuses
50.0, 50.0, 40.0, 40.0
2.75/4.76 450a 50.0
5.5 225, 400, 750,a 1350a 50.0, 62.5, 40.0, 40.0
8.25 125, 200a 50.0, 50.0
15.5 65, 100, 125,a 200a 85.0, 50.0, 85.0, 50.0
25.8 50, 100a 35.0, 35.0
38.0 50, 100a 35.0, 35.0

IEEE
reduction in current reduces the stresses and possible damage to the circuit up to the
fault or to the faulted equipment itself. For a current-limiting fuse used with a motor
starter, the contractor is required only to have momentary current and to make current
capabilities equal to the maximum let-though current of the largest current rating of
the fuse that is used in the starter.
— Very high interrupting ratings are achieved by virtue of current-limiting action so that
current-limiting power fuses can be applied on medium-voltage distribution circuits
having very high short-circuit capacity. It should be noted that current-limiting fuses
limit the let-through current by producing an arc voltage in excess of system voltage.
This arc voltage may affect insulation coordination and the application of surge
arresters (see Table 6-1 and 6.4.2.6).
Current-limiting power fuses are typically clip-mounted. Also available are current-limiting
fuses that mount in industry-recognized fiber-lined and solid-material mountings used for
power expulsion fuses described in 6.3.2.
6.3.2 Fiber-lined and solid-material expulsion power fuses
Expulsion power fuses generally consist of an insulating support (i.e., mounting) plus a fuse
unit or, alternately, a fuse holder that accepts a refill unit or a replaceable fuse link.
One form of medium-voltage power fuses is the fiber-lined expulsion fuse, employing longer
and heavier fuse holders (compared to fuse cutouts) to cope with higher circuit voltages and
short-circuit interrupting requirements. Their operating characteristics are similar to the char-
acteristics of a distribution fuse cutout except that the noise and emission of exhaust gases are
greatly magnified as the design evolved to handle higher voltages and fault currents. There-
fore, this type of fuse has been restricted to outdoor applications in substations. Fiber-lined
expulsion power fuses are still used for protection of small and medium power transformers
or substation capacitor banks. Table 6-4 gives the rating for fiber-lined expulsion power fuses.
The solid-material boric acid fuse was developed in the 1930s to improve the interrupting
capacity of early expulsion fuses and for application inside buildings or enclosures. In this
design, the deionizing action necessary to interrupt the fault current was not due to organic
material, but solid boric acid molded into a dense lining for the interrupting chamber. The
advantages of this design are listed below:
— For identical dimensions compared to fiber-lined fuse, the boric acid design can
interrupt higher currents and be applied at higher voltages and with lower arc ener-
gies to reduce emission of gases.
— Because the gas liberated from the boric acid is noncombustible and highly deion-
ized, the fuse design advantageously uses normal clearance distances required in air.
— During the interruption process, the heat of the arc liberates steam from the boric acid
crystals. This steam can be condensed by an exhaust control device (commonly
called an exhaust filter, condenser silencer, or snuffler). This feature allows use
indoors and in small enclosures up to 34.5 kV.

IEEE
These fuses are available in two styles:
— The fuse-unit style in which the fusible element, interrupting media, and arc-
elongating spring assembly are all combined in an insulating tube and the entire unit
being replaceable
— The fuse-holder and refill-unit style of which only the refill unit is replaced after
operation
The fuse-unit style is principally used outdoors at transmission and subtransmission voltages
(see Figure 6-5). However, fuses in this style are also available for use at distribution voltages
up to 34.5 kV, in current ratings up to 400 A. The fuse units are specifically designed for out-
door pole-top or station mountings and for indoor mountings installed in metal-enclosed
interrupter switchgear, indoor vaults, and pad-mounted gear. Indoor mountings incorporate
an exhaust control device that contains most of the arc-interruption products and virtually
eliminates noise accompanying a fuse operation. These exhaust control devices do not
require a reduction of the fuse’s interrupting rating.
Indoor mountings for use with fuse units up to 25 kV can be furnished with an integral hook-
stick-operated load-current-interrupting device, thus providing single-pole live switching in
addition to the fault-interrupting function provided by the fuse.
The ratings of the fuse-unit style are given in Table 6-5. The refill-unit style of fuse is used
either indoors or outdoors at medium voltage, and its ratings are given in Table 6-6.
Table 6-4—Maximum continuous-current and short-circuit interrupting ratings
for fiber-lined expulsion fuses
(kV)
(A) (maximum)
Maximum interrupting
ratinga
8.3 100, 200, 300, 400 12.5
15.5 100, 200, 300, 400 16.0
25.8 100, 200, 300, 400 20.0
38.0 100, 200, 300, 400 20.0
48.3 100, 200, 300, 400 25.0
72.5 100, 200, 300, 400 20.0
121.0 100, 200 16.0
145.0 100, 200 12.5
169.0 100, 200 12.5
aApplies to all continuous-current ratings.

IEEE
6.3.3 Newer types of fuses
Demands on electrical circuits have increased over the years with the growth of industrial and
utility systems. In many instances fuse ratings covered by standards are no longer adequate.
In some cases, the continuous-current requirements exceed existing fuse ratings. In other
for solid-material power fuses (fuse units)
(kV)
(A) (maximum)
5.5 400 25.0
17.0 200,400 14.0, 25.0
27.0 200 12.5
29.0 400 20.0
38.0 100, 200, 300 6.7, 17.5, 33.5
48.3 100, 200, 300 5.0, 13.1, 31.5
72.5 100, 200, 300 3.35, 10.0, 25.0
121.0 100, 250 5.0, 10.5
145.0 100, 250 4.2, 8.75
NOTE—The combination of interrupter switch with shunt trip device and solid-material power fuses
provides three-phase protection for the power transformer.
Figure 6-5—Substation serving large industrial plant at 69 kV

IEEE
cases, the short-circuit interrupting capabilities of the fuses is insufficient. In still other
instances, the low-current interrupting performance of fuses is a problem.
Fuse manufacturers responded to these needs in the early 1980s by combining or integrating
new technologies with existing fuse designs. Thus, a variety of modern fuse-like devices have
been developed, which make use of one or more of the following technologies: electronic
sensing and triggering, pyrotechnics to increase the speed of interruption, and vacuum and
magnetically enhanced SF6 interruption. The use of analog and digital circuitry provides for a
wide variety of TCC curves, and the inherent flexibility of these curves can result in improved
selectivity in tight coordination schemes. These newer devices are described in 6.3.3.1
through 6.3.3.3.
6.3.3.1 Power fuses using vacuum and SF6 interruption technology
6.3.3.1.1 Vacuum power fuses
Vacuum power fuses are an extension of vacuum power interrupters. A short fuse wire is held
axially between two electrodes; hence there is a low arc voltage when the fuse wire is melted
by the overcurrent. Thus the total-clearing characteristic is similar to an expulsion fuse. Inter-
ruption takes place at a current zero, and dielectric recovery is in high vacuum.
for solid-material power fuses (refill units)
(kV)
(A) (maximum)
2.8 200, 400, 720a 19.0, 37.5, 37.5
4.8 200, 400, 720a 19.0, 37.5, 37.5
5.5 200, 400, 720a 19.0, 37.5, 37.5
8.3 200, 400, 720a 16.6, 29.4, 29.4
14.4 200, 400, 720a 14.4, 29.4, 29.4
15.5 200, 400, 720a 14.4, 34.0, 29.4
17.0 200, 400, 720a 14.0, 34.0, 25.0
25.8 200, 300, 540a 10.5, 21.0, 21.0
27.0 200, 300 12.5, 20.0
38.0 200, 300, 540a 8.45, 17.5, 16.8
aParallel fuses

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6.3.3.1.2 SF6 power fuses
This type of fuse has an E characteristic. As the relatively short fuse wire melts, an arc is
formed within an SF6 chamber. This arc is commutated from the lower electrode to the
housing. A coaxial coil is series-connected to the housing. The coil produces an axial
magnetic field. It causes the arc to rotate radially between the housing as the first electrode
and a central arc runner at the second electrode until a current zero is reached, at which point
interruption takes place.
6.3.3.2 Self-triggering fuses that carry high continuous currents
In principle, this fuse design consists of two parallel fuses. The first has a short fusible
element in series with a heavy copper conductor. This combination carries the continuous
current. On overcurrents the fusible element melts and ignites a cutting charge, which cuts
and folds back the copper conductor at several predetermined reduced sections. The arcs
formed at these sections aid in the commutation of the overcurrent into the parallel current-
limiting fuse. This fuse, in turn, melts quickly and interrupts the current in a manner
consistent with the principle of a current-limiting fuse. The parallel fuse may be a full range,
a general purpose, or a backup current-limiting fuse.
These fuses can carry high continuous currents up to 600 A. Their features are low continu-
ous-current losses, current limitation with low let-through currents, and an ability to interrupt
substantially lower currents than their continuous-current rating.
6.3.3.3 Triggerable fuses that interrupt upon command
In this category several novel fuse types can be distinguished. Their common denominator is
a heavy copper conductor in parallel with a current-limiting fuse. The copper conductor car-
ries the continuous current anywhere from 600 A to 3000 A.
In one design, upon command from the sensing or firing logic, which may be integral or
remote, the conductor is severed by a chemical charge at predetermined sections. The arcs
formed at these gaps aid in commutation of the current to the parallel fuse. Its element is
designed to melt quickly and then interrupt the current like a current-limiting fuse.
In another design the fuse consists of a circuit interrupter in parallel with a current-limiting
fuse in one body. The interrupter is actuated to open the circuit by a chemical actuator. While
the interrupter is opening, the current is shunted to the parallel current-limiting fuse, which
interrupts the current in a manner consistent with the principle of a current-limiting fuse. The
interrupter contacts in the meantime move farther apart isolating the circuit. The interrupter
assembly is replaced after each interruption.
These types of fuses are combined typically with a built-in current transformer (CT), an elec-
tronic sensing logic, which may respond to a predetermined current level, rate of rise of
current, an integrated logic, or any combination of these, to provide a trigger signal for the
opening of the copper conductor.

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Some of these logic circuits are combined with additional elements that can delay or shift or
even change the shape of the TCCs and thus form a family of TCCs, much like the functions
of modern protective relays. The accuracy of these TCCs, along with fast clearing times,
provides a narrow band between the minimum operating and total-clearing time, greatly
enhancing the coordination possible with these devices.
The power for these logic devices may be derived from the CT or transmitted from ground by
a small isolation transformer. The trigger signal may also be transmitted from ground to one
or more phases by simple pulse transformers, if the sensing and firing logic is located at
ground potential.
6.4 Application of high-voltage fuses
IEEE Std C37.48-1987 is a guide for the application, operation, and maintenance of high-
voltage fuses, distribution enclosed single-pole air switches, fuse disconnecting switches, and
accessories. It is an extensive document that details the procedures for fuse selection for both
power and distribution systems. IEEE Std C37.40-1993 defines the fuse’s current, voltage,
frequency, and interrupting ratings. In selecting a fuse for a specific application, these ratings
are used frequently and, therefore, are discussed in 6.4.1 and 6.4.2.
6.4.1 Fuse selection
6.4.1.1 Voltage ratings
In industrial applications, where the three-phase load is often delta connected, the maximum
design voltage of the fuse should exceed the maximum line-to-line voltage of the system,
regardless of the system grounding conditions.
For three-phase applications in grounded-wye-grounded-wye systems, some utilities make a
practice of using current-limiting fuses rated for the line-to-ground voltage. This practice
allows use of a smaller fuse that produces a lower arc voltage. Before using fuses with such
ratings, a thorough evaluation is recommended based on the possible malfunction of these
fuses in the event of an ungrounded phase-to-phase fault on a transformer secondary.
The current-limiting fuse functions by developing a back electromotive force, and in fuse
designs using wire elements, this electromotive force is a function of its maximum rated volt-
age rather than the system voltage. In other words, care should be used in selecting the wire
element current-limiting fuse voltage rating while considering the possible overvoltages (see
Table 6-1) to match the system voltage insulating levels. If necessary, the fuse manufacturer
should be consulted on the application of specific fuse types.
Both fiber-lined and solid-material expulsion power fuses are not voltage critical in that they
can safely be applied at voltages less than their rated voltage with no detrimental effects.
These fuses have a constant current-interrupting ability or, at best, a slightly increased cur-
rent-interrupting ability when applied to systems operating one or more voltage levels below
the fuse ratings.

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6.4.1.2 Current ratings
In selecting a fuse, the continuous-current capability of the fuse should be equal to or higher
than the maximum continuous current that might be expected to pass through the fuse. There-
fore, in applications where the equipment being protected by the fuse may be overloaded
(such as when a transformer is operated above its continuous rating, but within published
short-time loading limits), the fuse’s continuous-current rating should be selected on the basis
of maximum anticipated overload current, not the rated current. Solid-material power fuses
have continuous-overload capabilities, and the manufacturer should be consulted if using a
fuse with a continuous-current rating less than the maximum continuous current required for
the application is desired. Fuses of a higher current rating may be required for other reasons,
such as to obtain coordination with other protective devices or to carry higher currents for
shorter periods of time.
The continuous-current capability of fuses is determined at 25 ßC or 30 ßC and can be
increased or decreased in applications where the ambient temperature is above or below these
values. The fuse manufacturer should be contacted for information.
Transient currents of duration approaching the fuse melting time may physically damage
some fuse types and cause a reduction in melting time characteristics. Therefore, when
selecting these fuses for particular installations, proper allowance should be made for
expected short-term conditions. The fuse manufacturer may be consulted for providing the
rules for the “no-damage” boundary for its design (if any).
In the more sophisticated distribution systems, continuity of service is achieved by
automatically switching the loads from a faulted circuit or transformer to another circuit or
transformer until repairs or replacement can be made. It is imperative to consider the effect of
such overloads on the melting TCC of the fuse as it affects selectivity with other overcurrent
protective devices.
Tools for use in selection of the various fuse types are available from fuse manufacturers.
TCC curves, preloading adjustment, and ambient temperature adjustment factors are pro-
vided for each fuse type. In addition, overload capability data for expulsion fuses, and peak
let-through current curves, total-clearing I 2
t charts, and peak arc voltage data are provided
for current-limiting fuses.
6.4.1.3 Interrupting rating
The interrupting rating of a fuse is expressed in rms symmetrical amperes. Standards call for
testing power fuses at an X/R ratio not less than 10, so the asymmetrical rating is 1.55 times
the symmetrical rating. (Some manufacturers test at an X/R ratio greater than 10, for an asym-
metry factor of 1.6.) If a power fuse is to be applied in the unusual case where the X/R ratio
exceeds 15 (or 20), the manufacturer should be consulted for derating factors. Some manu-
facturers also publish higher interrupting ratings at lower X/R ratios.
Distribution fuse cutouts are applied on overhead lines where the X/R ratio is lower than for
cable systems or large substation applications. Therefore, they are tested at an X/R ratio of 8

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or 12 (corresponding to an asymmetry factor of 1.4 or 1.5) depending on the voltage and
interrupting ratings. Most manufacturers publish data for increasing or decreasing the rms
symmetrical interrupting ratings of distribution cutouts for lower or higher X/R ratios.
Equivalent three-phase symmetrical interrupting ratings in MVA are given as a reference for
comparison with circuit breaker capabilities. Also, simpliﬁed short-circuit duty requirements
can be calculated in these terms.
In selecting a fuse for proper interrupting rating, one requirement, of course, is that the fuse
be adequate for the short-circuit duty required. Generally, however, other requirements such
as high load current or a desire for current limitation ensure that the fuses used have inher-
ently more interrupting capability than the system requires.
6.4.2 Special application considerations
The application considerations of high-voltage fuses differ depending on whether they are
used for system protection or protection of equipment such as power transformers, distribu-
tion transformers, motors, and capacitors.
6.4.2.1 System protection
6.4.2.1.1 General
From the basic concept of overcurrent protection applicable to medium- and high-voltage dis-
tribution systems used in industrial plants and commercial buildings, it becomes apparent that
the principle functions of overcurrent protective devices are to detect fault conditions and
interrupt these high values of overcurrent quickly. Fuses provide fast clearing of high-magni-
tude fault currents, usually on the order of one cycle or less. Their secondary function is to act
as backup overcurrent protection if the next overcurrent device closer to the fault either fails
to operate due to a malfunction or operates too slowly due to incorrect (i.e., higher) rating or
settings.
High-voltage power fuses have the capabilities and characteristics to provide this vital over-
current protection for virtually all types and sizes of distribution systems ranging from a sim-
ple radial circuit where power is supplied at medium voltage with a transformer to provide
utilization voltage, up to complex primary-selective circuits supplying feeders connected to a
number of transformer-primary substations (see Figure 6-6 and Figure 6-7). Such fuses, used
with load-interrupter switches, may be applied outdoors, in vaults, or in metal-enclosed
switchgear.
The use of more economical fuses (as compared to circuit breakers) allows segmentation of
radial systems and protection of individual loads. This feature can improve service reliability
by interrupting the least amount of load in order to remove a faulted segment. Fuses are
widely used in switchgear buses where their fast operating times (less than 0.5 cycle for
current-limiting and newer technology fuses when operating in their current-limiting range or
1 cycle for power fuses on high-current faults) reduce damage to faulted equipment and
stresses on the system feeding the fault, including motors. Current-limiting fuses produce

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lower voltage dips (e.g., in magnitude and duration) due to their current-limiting operation
and, as a result, may allow equipment connected to adjacent circuits to ride through the fault-
clearing operation. Fuses discussed in 6.3.3 are especially suitable for main-bus application
because of their high continuous-current ratings and the coordination achievable with their
inverse curves and fast clearing times.
6.4.2.1.2 Selectivity
The minimum-melting TCC curve indicates the time that a fuse carries a designated current
before operating (assuming no initial load). Figure 6-8 illustrates a typical family of
minimum-melting TCCs for current-limiting power fuses. Figure 6-9 shows the minimum-
Figure 6-6—One-line diagram of simple radial system
Figure 6-7—One-line diagram of typical primary-selective system

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melting TCCs for a representative line of solid-material power fuses. These curves should
indicate the tolerance in terms of time or current. These curves should further indicate
whether the fuse is non-damageable, that is, whether it can carry without damage the
designated current for a time that immediately approaches the time indicated by the curve.
Total-clearing TCC curves for these two types of fuses are shown in Figure 6-10 and
Figure 6-11, respectively.
Because the minimum-melting TCC curve is based on no initial load current through the
fuse, this curve should be modiﬁed to recognize the reduction in melting time due to load
current. This modiﬁcation permits more precise coordination with other overcurrent protec-
tive devices nearer the load. Further aids are available in the form of curves that show the
temporary reduction in melting characteristics if the fuse has been carrying a heavy emer-
gency overload, or if the fuse has been applied in a location with an exceptionally high ambi-
ent temperature.
Figure 6-8—Typical minimum-melting TCC curves for
high-voltage current-limiting power fuses

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If the fuse is susceptible to a permanent change in melting TCC when exposed to currents for
times less than the minimum-melting time, the manufacturer’s published “safety-zone”
allowance or “setback curve” should be used in any coordination scheme.
Fuses discussed in 6.3.3.3, which can interrupt upon command, have small tolerances, are
fast-acting at high fault currents, are nondamageable, and do not require modification of the
curves due to pre-loading or ambient temperature. Nonetheless, they should not be installed
in locations where the ambient temperature exceeds 55 ßC without consulting the
manufacturer.
Maximum system protection and maximum backup protection for load-side devices require
use of the smallest ampere rating of fuse that meets the requirements stated in 6.4.1.2. In
addition, the cumulative transformer magnetizing inrush of all transformers downstream of
the fuse should be considered. Fuses having a small tolerance and utilizing nondamageable
Figure 6-9—Typical minimum-melting TCC curves for
medium and high-voltage solid-material power fuses

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elements are best suited to accurate selective application. The effort required to make a
precise selection of fuse ampere rating and speed characteristics is small compared to the
beneﬁts obtained in overall system overcurrent protection.
6.4.2.2 Transformer protection
6.4.2.2.1 Inrush points
In selecting fuses for transformer protection, the following practices are recommended to
avoid nuisance fuse operation:
a) When a transformer is energized, magnetizing inrush current ﬂows through the fuses.
When selecting the current rating, the minimum-melting TCC (adjusted for pre-load,
ambient temperature, and, if applicable, damageability) should lie to the right of the
magnetizing inrush points. The rules of thumb for these points are 12 times the full-
Figure 6-10—Typical total-clearing TCC curves for high-voltage
current-limiting power fuses (see Figure 6-8)

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load current of the transformer at 0.1 s and 25 times at 0.01 s for unloaded
transformers.
b) Magnetizing inrush currents may be slightly higher when transformers carrying load
current are subjected to a momentary interruption. In addition, under these circum-
stances, fuses will have been carrying the load and will melt slightly faster than when
at room temperature. As a rule of thumb, the integrated heating effect of this inrush
should be considered as that of a current having a magnitude of 10 to 14 times the
full-load current for a duration of 0.1 s and 25 to 28 times the full-load current for a
duration of 0.01 s. This effect is referred to as hot-load pickup.
c) Cold-load pickup can be a concern if fuses are sized based on load diversity, i.e., the
utility practice of sizing transformers, conductors, and protective devices such as
fuses to handle the highest normal load current to be expected, rather than the entire
Figure 6-11—Typical total-clearingTCC curves for high-voltage solid-material
power fuses (see Figure 6-9)

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connected load. This practice can cause problems in re-energizing a circuit after a
prolonged (e.g., 4 h) interruption. In this case, all air conditioners or all electric
heating devices start up at the same time rather than randomly. This condition may
result in a current profile that is equivalent to six times the transformer full-load
current for 1 s, three times for 10 s, and two times for 15 min. It is unusual for cold-
load pickup to be a problem on industrial and commercial power systems where the
diversity of many small air conditioners is not a factor and where large loads are
energized one at a time following a prolonged power interruption. However, if all
load on a transformer is picked up at once by closing the primary or main secondary
switching device, a similar inrush will occur. If this event is expected, the fuse should
be selected so that its minimum-melting curve is to the right of the points mentioned
in 6.4.2.2, plus any allowances recommended by the manufacturer for a safety zone.
d) For proper coordination, the secondary protection system’s total-clearing characteris-
tics (e.g., secondary fuses or breakers) converted to the primary side should also lie to
the left of the primary fuse’s minimum-melting curve.
e) Considering the above inrush points, comparison of the steep minimum-melting TCC
of a current-limiting fuse and the curves of an expulsion fuse shows which one
should give better protection than the other for faults on the secondary side of the
transformer. This comparison is particularly true for arcing phase-to-ground faults
where the fault current may be as low as 40% of the current for a bolted fault.
6.4.2.2.2 Through-fault protection
A primary fuse selected for transformer protection should be able to carry overload currents
safely. In addition, it should be large enough to coordinate with secondary-side devices. The
upper limit for the size of fuse selected is a function of the NEC rule that the rating not
exceed three times the transformer’s full-load rating. Fuses can provide excellent protection
to the transformer for such faults when properly selected. Chapter 11 discusses transformer
protection in detail. Because its zone of protection extends only through secondary-side pro-
tective devices, the primary fuse should be selected on the basis of the infrequent fault protec-
tion curve. Frequent faults on the lines emanating from the secondary bus are to be cleared by
feeder protective devices.
6.4.2.2.3 Overload protection
Precise transformer overload protection is commonly required. One means is the use of inter-
nal circuit breakers. Another method for overload protection is available for pad-mounted
transformers, which commonly use bayonet expulsion fusing. Rather than using conventional
copper and tin bayonet fuse elements, which do not react to the transformer oil temperature,
optional eutectic elements may be used to provide both overcurrent and overload protection.
Unlike conventional fuse elements, the eutectic element senses both the thermal effect of
current flow and the oil temperature rise. The oil temperature is due to core and coil losses
combined with ambient temperature conditions. The eutectic element melts at a predeter-
mined temperature and opens the circuit. Thus, the transformer insulation system is protected
from extreme temperatures that significantly reduce its operating life.

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6.4.2.2.4 Two-fuse concept protection
The two-fuse concept is commonly applied to pad-mounted transformers. This protection
scheme consists of a partial-range current-limiting fuse in series with an expulsion fuse
housed in a bayonet through-wall holder. The partial-range current-limiting fuse is sized to
clear high-current, low-impedance internal faults, and its ﬁeld accessibility is optional. Con-
versely, the ﬁeld accessible expulsion fuse is sized to clear lower current, external secondary
faults and/or sustained overloads. Using the two-fuse concept provides assurance that trans-
formers with internal faults remain permanently isolated and allows differentiation between
internal and external faults. Typically, overcurrent conditions that transformers experience
are of lower magnitude and only involve replacement of the accessible expulsion fuse ele-
ment assembly.
6.4.2.3 VT protection
The fuses applied for voltage transformer (VT) protection should withstand inrush currents
during the transformer energization. The VT manufacturer provides these data in the form of
I 2t for their products. Fuses are chosen for protection, depending on the method of trans-
former connection. Figure 6-12 shows two widely used methods of connection: Class I and
Class II. For Class I connections, the inrush current of one transformer passes through the
fuse, and hence the fuse’s melting I 2t should be greater than 1.5 times the I 2t of the inrush of
the transformer. For Class II connections, the inrush currents of two transformers pass
through the fuse. In this case, the fuse’s melting I 2t should be greater than 4.5 times the I 2t
of the inrush of the transformer. With this method of selection, nuisance blowing of fuses can
be avoided.
When possible damage to other equipment or injury to personnel, due to delayed clearing of a
failed transformer, is an important consideration, Class II connection should be avoided if
NOTE—Class I connections are preferred; Class II connections are sometimes employed.
Figure 6-12—Various methods of connecting VTs to bus,
showing fuse positions

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this connection gives rise to a higher fuse ampere rating than the Class I connection. The
inrush I 2
t for the transformers varies rapidly with increases in applied voltage; in requesting
the I 2
t from the transformer manufacturer, the voltage speciﬁed should be the maximum
expected in service.
In some applications, particularly cable circuits, the inherent capacitance of the circuit may
give rise to a discharge current through the primaries of the connected VTs when the circuit is
disconnected from the bus. The magnitude and duration of this discharge current may be cal-
culated from the circuit constants and, in some instances, may result in blowing the primary
fuse. This possibility is a particular concern where the VTs can be suddenly isolated from the
ac source along with long cable runs or capacitor banks.
6.4.2.4 Capacitor protection
Ordinarily, fuses used for the protection of capacitor banks and individual capacitor units are
furnished by the manufacturer of the capacitor bank. Selection of these fuses is complex and
involves consideration of the possibility of capacitor-unit rupture, inrush currents during
switching operations, use of a continuous-current rating large enough to accommodate
higher-than-expected currents due to harmonics and overvoltages, and the amount of energy
that may be fed into a faulted capacitor unit from adjacent units on the same phase. If replac-
ing these fuses with fuses of a different manufacture or type is necessary, all these factors
should be carefully considered when selecting the new fuse.
6.4.2.5 Motor-circuit protection
6.4.2.5.1 Design and selection
Fuses speciﬁcally designed for motor-circuit protection are different from the other types of
fuses. These motor-circuit fuses are subjected to inrush currents constantly during the start
and stop of the motors. Hence the element design is different and takes the mechanical
stresses produced by the inrush currents. They are usually R-rated backup power fuses. They
are applied in series with low-interrupting-capacity contactors or vacuum interrupters located
in motor controllers. These series interrupters are controlled by thermal overload relays or
other motor protection relays (see Figure 6-13). The fuse size selected should allow for short-
circuit protection provided by the fuse and overload protection provided by the motor
overload relays. The following data are required for proper application:
— Motor full-load current rating
— Motor locked-rotor current
— Overload relay TCCs
— R-rated fuse’s minimum-melting characteristics
6.4.2.5.2 Coordination of fuses and motor starters
In applying fuses for motor protection circuits, the fuse and motor-starter components should
be coordinated so that the fuse is protected against unnecessary operation during motor
starting or expected overload conditions. A typical motor branch circuit, and the connected
protective devices, is shown in Figure 6-14. In this example, a 2300 V, 500 Hp, 370 kW,

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three-phase motor is assumed with a full-load current of 125 A and a locked-rotor current of
750 A. It is being started with a suitable contactor having thermal overload relays. The
overload relay is to be sized at 125% of motor full-load current, and system voltages could
vary enough to cause a 10% increase in locked-rotor current. Taking these percentages into
consideration, the overload relays were selected at a rated value of 155 A in terms of the
primary current in the CTs, and the adjusted locked-rotor current is 825 A. The coordination
of the fuse and relay characteristics is shown in Figure 6-15. In this example, the thermal
relay characteristic crosses the minimum-melting characteristic of a 6R fuse at 620 A, 9R
fuse at 980 A, and a 12R fuse at 1350 A. Because the 9R and 12R fuses have the crossover
current greater than the 825 A of adjusted locked-rotor current for this motor, both are
suitable for this condition. Because 9R is the smallest fuse that coordinates with the relay, it is
selected to limit the energy let-through to faults and minimize the damage to the protected
circuit.
6.4.2.6 Coordination of fuses and surge arresters
Surge arresters are overvoltage devices that present a low resistance when the voltage
exceeds a predetermined value, and a high resistance during normal operation. Thus they
clamp the overvoltage to a desired level by diverting the excess energy to earth. Because the
arresters do not have large mass, a thermal limit absorbs the energy during the overvoltage
period.
The current-limiting fuse limits the peak let-through current by producing a high arc voltage
across its terminals (as high as three times the voltage rating of the fuse). This peak arc volt-
age, lasting about 100 µs to 500 µs, is in excess of the system peak voltage and may cause
Figure 6-13—High-voltage R-rated fuses in drawout motor starter, rated 180 A

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Figure 6-14—One-line diagram of motor branch circuit and connected
devices
Figure 6-15—Illustration of a method of checking coordination
of current-limiting fuses and motor overload relays
in a motor branch circuit

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surge arresters on the source side to operate. ANSI C37.46-1981 and ANSI C37.47-1981
specify the limits on peak arc voltages for current-limiting fuses (see Table 6-1).
6.4.2.6.1 Coordination of surge arresters and current-limiting fuses
When current-limiting fuses and surge arresters are used adjacent to each other, care should
be taken to prevent failure of either device.
When the arrester is on the source side of a current-limiting fuse, the high arc voltage caused
by an operation in the current-limiting mode on some types of fuses may cause the arrester to
go into the conducting mode. Some concern exists that energy that the arrester needs to
absorb during operation, if it occurs, is large enough that eventful (or catastrophic) arrester
failure could occur. However, based on fuse and arrester standards and characteristics,
thorough reviews of the application, and numerous tests, it has been concluded that the use of
arresters in this location may be done without undue risk. The probability of damage is low as
long as devices that conform to present standards are used. If a concern exists for a particular
application, the fuse and arrester manufacturers should be consulted.
When the surge arrester is located on the load side of a current-limiting fuse, the fuse opera-
tion under current-limiting mode should not affect the surge arrester. But this method may
lead to fuse operation due to surge arrester operation because the I 2
t of the lightning current
discharged by the arrester also ﬂows through the fuse. The fuse operates if the I 2
t content in
the surge current is greater than the fuse’s minimum-melt I 2
t. In some instances, when the
I 2
t is just below the fuse’s minimum-melt I 2
t, element damage may occur that might cause
the fuse to fail subsequently. The fuse selected using this method should have a melting I 2
t
higher than the maximum estimated lightning surge value at this location. Thus, nuisance
fuse operation can be minimized.
6.4.2.6.2 Coordination of surge arresters and expulsion fuses
Solid-material power fuses and ﬁber-lined cutouts do not produce high arc voltages, so no
need exists for coordination with surge arresters on the source side. Due to the inversity of
their melting curves, fuses rated 15E or larger normally do not operate due to current through
a surge arrester on the load side of the fuse.
6.4.2.7 Special application of new technologies
Some of the new designs of power fuses are unique in combining many of the features of
both triggered relays and fuses. Like relays, they can be furnished with a variety of response
characteristics including instantaneous, time delay, inverse, and combinations of these char-
acteristics. At high current levels, they interrupt in a current-limiting mode within a fraction
of a cycle. They are available with high continuous-current ratings of 400 A, 600 A, 1200 A,
2000 A, and 3000 A. This combination makes them especially suitable for a number of appli-
cations not attainable with other devices:
— Service entrance protection. The accuracy and special response characteristics allow
coordination with line-side and load-side devices not achievable with other forms of

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protection. In addition, they are available in higher continuous ratings than other
fuses.
— Feeder protection. The accuracy and special response characteristics allow coordina-
tion with line-side and load-side devices not achievable with other forms of
protection.
— Bus tie protection. The high continuous-current rating and fast response allow paral-
leling two sources without subjecting feeder protective equipment to excessive fault
currents.
— Reactor bypass. Reactors used to limit fault current introduce losses and voltage reg-
ulation problems to the system. A triggerable power fuse can be used to bypass a
reactor, carrying normal load current and transferring fault current to the reactor for
limitation.
— Protection of underrated equipment. The addition of capacity to electrical systems
sometimes results in raising the available fault-current level above the rating of
equipment. Triggerable power fuses can reduce the potential let-through current to
levels within the equipment ratings.
6.5 References
ANSI C37.42-1996, American National Standard Specification for High Voltage Expulsion
Type Distribution Class Fuses, Cutouts, Fuse Disconnectin Switches, and Fuse Links.3
ANSI C37.44-1981 (Reaff 1992), American National Standard Specification for Special Dis-
tribution Oil Cutouts and Fuse Links.
ANSI C37.46-1981 (Reaff 1992), American National Standard Specifications for Power
Fuses and Fuse Disconnecting Switches.
ANSI C37.47-1981 (Reaff 1992), American National Standard Specifications for Distribution
Fuse Disconnecting Switches, Fuse Supports, and Current-Limiting Fuses.
ANSI C37.53.1-1989 (Reaff 1996), American National Standard Specification for Switch-
gear—High-Voltage Current Motor-Starter Fuses.
3ANSI publications are available from the Sales Department, American National Standards Institute, 11 West 42nd
Street, 13th Floor, New York, NY 10036, USA (http://www.ansi.org/).

IEEE
IEEE Std C37.40-1993, IEEE Standard Service Conditions and Definitions for High-Voltage
Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches, and
Accessories.4
IEEE Std C37.41-2000, IEEE Standard Design Tests for High-Voltage Fuses, Distribution
Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches, and Accessories.
IEEE Std C37.48-1997, IEEE Guide for Application, Operation, and Maintenance of Hi-Volt-
age Fuses, Distribution Enclosed Single-Pole Air Switches, Fuse Disconnecting Switches,
and Accessories.
6.6 Bibliography
[B1] ANSI C84.1-1995, American National Standard for Electric Power Systems And Equip-
ment—Voltage Ratings.
[B2] IEC 291-1969, Fuse Definitions.5
[B3] IEEE Std C37.100-1992, IEEE Standard Definitions for Power Switchgear.
[B4] NEMA SG 2-1981, High-Voltage Fuses.6
[B5] NFPA 70-1999, National Electrical Code® (NEC®).7

Chapter 7
Low-voltage circuit breakers
7.1 General
National Electrical Code®
(NEC®
) (NFPA 70-1999)1
deﬁnes a circuit breaker as “a device
designed to open and close a circuit by non-automatic means and to open the circuit automat-
ically on a predetermined overcurrent without damage to itself when properly applied within
its rating.” Low-voltage circuit breakers are further classiﬁed by IEEE Std C37.100-1992 as
— Molded-case circuit breakers (MCCBs) (each assembled as an integral unit in a sup-
porting and enclosing housing of insulating material)
— Low-voltage power circuit breakers (LVPCBs) (used on circuits rated 1000 V ac and
below or rated 3000 V dc and below, but not including MCCBs)
Figure 7-1a and Figure 7-1b illustrate typical constructions.
Figure 7-1a—MCCB
Figure 7-1b—LVPCB

IEEE
UL 489-1991 further specifies that MCCBs are specifically intended to provide service
entrance, feeder, and branch circuit protection in accordance with the NEC. Present Under-
writers Laboratories (UL) requirements cover MCCBs rated through 600 V and 6000 A.
ANSI C37.16-2000 includes information on ratings, application, and operating conditions
applicable to LVPCBs.
When specifying MCCBs or LVPCBs, the circuit breaker should be applied within its ratings
for circuit protection.
The term insulated-case circuit breaker (ICCB) is commonly used to designate a circuit
breaker with a supportive and enclosing housing of insulating material and with a stored
energy mechanism. ICCBs are typically available in frame sizes of 800 A and above. They
are generally listed under UL 489-1991.
The term air circuit breaker is often used in speaking of LVPCBs. Because the arc interrup-
tion takes place in air in both MCCBs and LVPCBs, this term really applies to both types.
The material in this chapter is limited to general purpose applications of circuit breakers that
provide overcurrent protection on ac power systems through 600 V. Circuit breakers intended
for special purpose applications, such as instantaneous trip only, are not covered. For circuit
breaker ratings, requirements, and recommendations in mining applications, transit systems,
or other special purpose applications, the standards in 7.9 or the manufacturers’ literature
should be consulted.
7.2 Ratings
The ratings that apply to circuit breakers and their assigned numerical values reflect the
mechanical, electrical, and thermal capabilities of the circuit breakers and generally comply
with industry standards published by the National Electrical Manufacturers Association
(NEMA), Underwriters Laboratories (UL), or the American National Standards Institute
(ANSI). A brief description of the basic ratings is given in 7.2.1 through 7.2.7.
7.2.1 voltage: Circuit breakers are designed and marked with the maximum voltage at which
they can be applied. They can be used on any system where the voltage is lower than the
breaker’s voltage rating. Voltage ratings distinguish between delta-connected, three-phase,
three-wire systems and wye-connected, three-phase, four-wire systems, which are more com-
mon. Refer to IEEE Std 141-1993 for system voltages and nomenclature. The NEC provides
the following guideline in Article 240-85(e)(FPN):
A circuit breaker with a straight voltage rating, e.g., 240 V or 480 V may be applied
in a circuit in which the nominal voltage between any two conductors does not
exceed the circuit breaker’s voltage rating; except that a two-pole circuit breaker is
not suitable for protecting a 3-phase corner-grounded delta circuit unless it is marked
1-phase/3-phase to indicate such suitability.

IEEE
LOW-VOLTAGE CIRCUIT BREAKERS Std 242-2001
A circuit breaker with a slash rating, e.g., 120/240 V or 480Y/277 V, may only be
applied in a circuit in which the nominal voltage to ground from any conductor does
not exceed the lower of the two values of the circuit breaker’s voltage rating and the
nominal voltage between any two conductors does not exceed the higher value of the
circuit breaker’s voltage rating.
LVPCBs are all marked, rated, and tested only for the straight voltage system requirements as
are all larger MCCBs. MCCBs rated 250 A or below are rated for either straight or slash volt-
age systems.
7.2.2 frequency: Circuit breakers are normally suitable for use in 50 Hz and 60 Hz electrical
distribution systems. DC ratings are marked on the circuit breaker when they apply.
7.2.3 continuous-current: Standard MCCBs are calibrated to carry 100% of their current
rating in open air at a given ambient temperature (usually 40 °C). In accordance with NEC
Article 210-19, these breakers, as installed in individual enclosures or in other equipment,
should not be continuously loaded over 80% of their current rating.
LVPCBs and certain ICCBs and MCCBs are specifically rated for 100% continuous duty.
These circuit breakers can be continuously loaded to 100% of their current rating in a 40 °C
ambient when installed in their proper enclosures.
7.2.4 poles: Circuit breakers are available in one-, two-, and three-pole versions. Outside
North America, four-pole MCCBs are also available as IEC-rated units for systems in which
the neutral is switched with the disconnect device. Switching neutral circuit breakers are
available in the United States for classified applications such as in gasoline stations.
7.2.5 control voltage: The control voltage rating is the ac or dc voltage designated to be
applied to control devices intended to open or close a circuit breaker. These devices can nor-
mally be supplied with a voltage rating needed to meet a particular control system.
7.2.6 interrupting: As defined in the NEC, interrupting rating is “The highest current at rated
voltage that a device is intended to interrupt under standard test conditions.” The interrupting
rating (or short-circuit current rating, when referring to LVPCBs) is commonly expressed in
root-mean-square (rms) symmetrical amperes. It may vary with the applied voltage and is
established by testing per UL or ANSI standards.
Where the interrupting ratings of conventional MCCBs or LVPCBs are not sufficient for a
particular system application, other options are available, such as current-limiting circuit
breakers, integrally fused circuit breakers, and series-rated combinations. In series-rated
combinations, the load-side circuit breaker is used in a system with a short-circuit availability
above its nameplate interrupting rating while a supply-side circuit breaker or fuse rated at or
above the available short-circuit current is present to protect the load-side circuit breaker.
Certified series ratings are tested and marked on listed equipment in which they are used in
accordance with the NEC.

IEEE
7.2.7 short-time current: The short-time current rating, sometimes referred to as withstand
rating, specifies the maximum capability of a circuit breaker to withstand the effects of short-
circuit current flow for a stated period, typically 0.5 s or less, without opening. This
capability provides time for load-side protective devices closer to the fault to operate and
isolate the circuit.
The short-circuit current rating of an LVPCB without instantaneous trip characteristics is
equal to the circuit breaker’s short-time interrupting rating. Most MCCBs are not provided
with a short-time current rating; however, some higher current rated MCCBs (presently
1200 A and above) are provided with a short-time current rating in addition to the short-
circuit interrupting rating.
To achieve selective coordination, circuit breakers equipped only with long-time and short-
time delay may be used on the supply side of the load protective device.
7.3 Current limitation
Current limitation using circuit breakers can be provided by two types of circuit breakers:
current-limiting and integrally fused. Each type is discussed in 7.3.1 and 7.3.2, respectively.
7.3.1 Current-limiting circuit breakers
Current-limiting circuit breakers are special MCCBs that not only provide high interrupting
capabilities, but also limit let-through current and energy to load-side devices. UL 489-1996
defines a current-limiting circuit breaker as “a circuit breaker that does not employ a fusible
element and that when operating within its current-limiting range, limits the let-through I2t to
a value less than the I2t of a half-cycle wave of the electrical prospective current.”
I2
t, as used in the definition, is an expression related to the energy resulting from current flow.
It is defined as I2
t = ∫i2
(t)dt over the period of consideration (i.e., usually from initiation of
short circuit to clearing). Specific manufacturers’ literature should be consulted for informa-
tion on the current-limiting characteristics of their circuit breakers. Current-limiting circuit
breakers provide the system designer with a means of reducing fault-current energy levels to
load-side system components while still retaining the advantages of circuit breaker construc-
tion, such as common trip and reusability. These breakers can be reset and service restored in
the same manner as conventional thermal-magnetic circuit breakers. Nothing needs to be
replaced, even after clearing maximum rated fault currents. After interruption at high fault
levels, it is required that the faulted equipment including the circuit breaker be checked and
replaced if necessary before being put back into service. Figure 7-2 illustrates the current
waveform resulting from current-limiting operation.
7.3.2 Integrally fused circuit breakers
Integrally fused circuit breakers provide high interrupting capability through the use of cur-
rent-limiting fuses that are assembled into the housing of the circuit breaker. The fuses in
these devices are designed to operate and require replacement only after a high-level fault.

IEEE
The circuit breaker mechanism is interlocked so that when any fuse opens, the circuit breaker
automatically opens.
7.4 Typical ratings
Table 7-1 and Table 7-2 list typical ratings of MCCBs for commercial and industrial applica-
tions. Table 7-1 covers ratings of standard and high interrupting capacity units at several
typical levels, while Table 7-2 covers current-limiting and fused breakers. Table 7-3 and
Table 7-4 show standard ratings for LVPCBs with and without instantaneous overcurrent trip
characteristics, respectively. Although the ratings in Table 7-3 and Table 7-4 are preferred rat-
ings, most commercially available circuit breakers carry higher interrupting ratings. Also,
225 A and 600 A frame sizes are generally no longer manufactured. Table 7-5 covers inte-
grally fused LVPCBs.
7.5 Trip unit
The trip unit continually senses current and initiates tripping according to its time-current trip
curve to provide the automatic overcurrent protection function of the circuit breaker. Depend-
ing on the magnitude of the current, the trip unit initiates an inverse-time response or an
instantaneous response. When tripping is initiated, a direct acting mechanism inside the
circuit breaker opens the primary contacts and interrupts the current ﬂow. The trip unit
considered here is an integral part of the circuit breaker. It may be electromechanical
[thermal-magnetic (see Figure 7-3 and Figure 7-4) or mechanical dashpot] or electronic (see
Figure 7-5).
Figure 7-2—Current-limiting waveform
(fault initiation at t = 0 and V maximum)

IEEE
Trip units may be considered in five basic configurations:
— Nonadjustable. Nonadjustable trip units are most commonly available on smaller
MCCBs. All characteristics are fixed.
— Adjustable instantaneous. Many thermal-magnetic MCCBs are fitted with an
instantaneous (or magnetic trip) adjustment as shown in Figure 7-4. All other
characteristics are fixed. The adjustment may be a single adjustment for all poles or
an individual adjustment for each pole of the circuit breaker.
Table 7-1—Typical interrupting ratings of MCCBs for
commercial and industrial applicationsa
Frame size
(A)
Number of
poles
Interrupting rating at ac voltage
120 240 277 480 600
100 1 10
65 14
65
100, 150 2, 3
2, 3
18
65
100
14
25
65
14
18
25
225, 250 2, 3
2, 3
25
65
100
22
25
65
22
22
25
400, 600 2, 3
2, 3
42
65
100
30
65
22
25
35
800, 1000 42
65
200
30
50
100
22
25
65
1200 42
65
200
30
50
100
22
25
65
1600, 2000 65
125
50
100
42
65
3000, 4000 100
200
100
150
85
100
NOTE—Ratings in this table are typical. Variations among manufacturers or product changes
may result in actual ratings that differ from the table. Specific manufacturers’ literature should
be consulted for guidance.
aDoes not include MCCBs intended primarily for residential applications. Specific manufactur-
ers should be consulted for rating information on those residential circuit breakers.

IEEE
— Mechanical dashpot. A mechanical dashpot trip unit is found on many older LVPCBs
now in service. This trip unit is rare on newer ac products with the advent of elec-
tronic trips. It is found on larger dc-rated circuit breakers. It is not discussed in detail
in this chapter.
— Electronic. Electronic trip units are found as standard on most LVPCBs and ICCBs
and as an option on many MCCBs. They are equipped with adjustments for some or
all of the characteristic adjustments listed in 7.5.1. Not all of the adjustments are used
or required in all installations. In many cases the continuous-current rating is selected
by installing or replacing a rating plug, which is a part identified with a specific cur-
rent rating. An adjustment in addition to the rating plug may be made to achieve finer
adjustment. Other adjustments are made using dials such as indicated in Figure 7-5 or
simple programming steps. Additional functions, such as ground-fault protection, or
combinations of functions that further influence circuit breaker time-current response
are available from specific manufacturers. Ammeters and other visual displays are
optionally available for monitoring the condition of the circuit and circuit breaker.
— Communicating electronic. In addition to the adjusting of the trip characteristic, some
trip units provide communication with each other, with interfacing electronic systems
and with the systems operators. Features may include selective interlocking for fast
Table 7-2—Typical interrupting current ratings of current-limiting MCCBs and
fused circuit breakers
Frame size
(A)
Number of
poles
Interrupting rating at ac voltage
240 V 480 V 600 V
Current-limiting circuit breakers
100–150 2, 3 200 200 100
225–250 2, 3 200 200 100
400–600 2, 3 200 200 100
Fused circuit breakersa
100–150 2, 3 200 200 200
400–600 2, 3 200 200 200
800–1000 2, 3 200 200 200
1600–2000 2, 3 200 200 200
NOTE—Ratings in this table are typical. Variations among manufacturers or product changes
may result in actual ratings that differ from the table. Specific manufacturers’ literature should
be consulted for guidance.
aIncludes circuit breakers with integral fuses within the enclosure or current-limiting fuses
within an approved load-side add-on device.

IEEE
but orderly shutdown, phase balance protection, power monitoring, waveshape
monitoring, and remote monitoring and control. These features vary by product and
manufacturer. Basic trip unit functions are the same as in the electronic trip unit.
Table 7-3—Preferred ratings for low-voltage ac power circuit breakers with
instantaneous direct-acting phase trip elementsa
System
nominal
voltage
(V)
Rated
maximum
voltage
(V)
Insulation
(dielectric)
withstand
(V)
Three-phase
short-circuit
current rating
(symmetrical A)b
Frame size
(A)
Range of trip-
device current
ratings (A)c
600 635 2200 14 000 225 40–225
600 635 2200 22 000 600 40–600
600 635 2200 22 000 800 100–800
600 635 2200 42 000 1600 200–1600
600 635 2200 42 000 2000 200–2000
600 635 2200 65 000 3000 2000–3000
600 635 2200 65 000 3200 2000–3200
600 635 2200 85 000 4000 4000
480 508 2200 22 000 225 40–225
480 508 2200 30 000 600 100–600
480 508 2200 30 000 800 100–800
480 508 2200 50 000 1600 400–1600
480 508 2200 50 000 2000 400–2000
480 508 2200 65 000 3000 2000–3000
480 508 2200 65 000 3200 2000–3200
480 508 2200 85 000 4000 4000
240 254 2200 25 000 225 40–225
240 254 2200 42 000 600 150–600
240 254 2200 42 000 800 150–800
240 254 2200 65 000 1600 600–1600
240 254 2200 65 000 2000 600–2000
240 254 2200 85 000 3000 2000–3000
240 254 2200 85 000 3200 2000–3200
240 254 2200 130 000 4000 4000
aSee IEEE Std C37.13-1990 and ANSI C37.16-2000.
bRatings in this column are rms symmetrical values for single-phase (two-pole) circuit breakers and
three-phase average rms symmetrical values of three-phase (three-pole) circuit breakers. When
applied on systems where rated maximum voltage may appear across a single pole, the short-circuit
current ratings are 87% of these values. See 5.6 in IEEE Std C37.13-1990.
cThe continuous-current-carrying capability of some circuit-breaker-trip-device combinations may
be higher than the trip-device current rating. See 10.1.3 in IEEE Std C37.13-1990.

IEEE
Table 7-4—Preferred ratings for low-voltage ac power circuit breakers
without instantaneous direct-acting phase trip elements
(short-time delay element or remote relay)a
System
nominal
voltage
(V)
Rated
maximum
voltage
(V)
Insulation
(dielectric)
withstand
(V)
Three-phase
short-circuit
current
rating
(symmetrical
A)b,c
Frame size
(A)
Range of trip-device current ratings (A)d
Setting of short-time-delay trip element
Minimum time
band
Intermediate
time band
Maximum time
band
600 635 2200 14 000 225 100–225 125–225 150–225
600 635 2200 22 000 600 175–600 200–600 250–600
600 635 2200 22 000 800 175–800 200–800 250–800
600 635 2200 42 000 1600 350–1600 400–1600 500–1600
600 635 2200 42 000 2000 350–2000 400–2000 500–2000
600 635 2200 65 000 3000 2000–3000 2000–3000 2000–3000
600 635 2200 65 000 3200 2000–3200 2000–3200 2000–3200
600 635 2200 85 000 4000 4000 4000 4000
480 508 2200 22 000 225 100–225 125–225 150–225
480 508 2200 30 000 600 175–600 200–600 250–600
480 508 2200 30 000 800 175–800 200–800 250–800
480 508 2200 50 000 1600 350–1600 400–1600 500–1600
480 508 2200 50 000 2000 350–2000 400–2000 500–2000
480 508 2200 65 000 3000 2000–3000 2000–3000 2000–3000
480 508 2200 65 000 3200 2000–3200 2000–3200 2000–3200
480 508 2200 85 000 4000 4000 4000 4000
240 254 2200 25 000 225 100–225 125–225 150–225
240 254 2200 42 000 600 175–600 200–600 250–600
240 254 2200 42 000 800 175–800 200–800 250–800
240 254 2200 65 000 1600 350–1600 400–1600 500–1600
240 254 2200 65 000 2000 350–2000 400–2000 500–2000
240 254 2200 85 000 3000 2000–3000 2000–3000 2000–3000
240 254 2200 85 000 3200 2000–3200 2000–3200 2000–3200
240 254 2200 130 000 4000 4000 4000 4000
bShort-circuit ratings for breakers without direct-acting trip devices, opened by a remote relay, are the same as
ratings listed in this column.
cRatings in this column are rms symmetrical values for single-phase (two-pole) circuit breakers and three-phase
average rms symmetrical values of three-phase (three-pole) circuit breakers. When applied on systems where
rated maximum voltage may appear across a single pole, the short-circuit current ratings are 87% of these
values. See 5.6 in IEEE Std C37.13-1990.
dThe continuous-current-carrying capability of some circuit-breaker-trip-device combinations may be higher
than the trip-device current rating. See 10.1.3 in IEEE Std C37.13-1990.

IEEE
Table 7-5—Preferred ratings for integrally fused low-voltage ac power circuit breakers with
instantaneous direct-acting phase trip elementsa
Circuit breaker
frame size
(A)b
Rated
maximum
voltage
(V)c
Insulation
(dielectric)
withstand
(V)
Three-phase
short-circuit
current rating
(A, sym)d
Range of continuous-current rating
(A)
Range of trip-
device current
ratings
(A)e
Maximum fuse
ratingf
600 600 2200 200 000 125–600 g
800 600 2200 200 000 125–800 g
1600 600 2200 200 000 200–1600 g
bTwo circuit-breaker fram ratings are used for integrally fused circuit breakers. The continuous-current rating of the in-
tegrally fused circuit breaker is determined by the rating of either the direct-acting trip device or the current-limiting fuse
applied to a particular circuit-breaker frame rating, whichever is smaller.
cListed values are limited by the standard voltage rating of the fuse.
dRatings in this column are rms symmetrical values for single-phase (two-pole) circuit breakers and three-phase average
rms symmetrical values of three-phase (three-pole) circuit breakers. When applied on systems where rated maximum
voltage may appear across a single pole, the short-circuit current ratings are 87% of these values. See 5.6 in IEEE
Std C37.13-1990.
eThe continuous-current-carrying capability of some circuit-breaker-trip-device combinations may be higher than the
trip-device current rating. See 10.1.3 in IEEE Std C37.13-1990. Lower rated trip-device current ratings may be used
when the fuse size is small or the available current is low, or both. The manufacturer should be consulted.
fFuse current ratings may be 300 A, 400 A, 600 A, 800 A, 1000 A, 1200 A, 1600 A, 2000 A, 2500 A, and 3000 A. Fuses
are current-limiting.
gValues have not yet been determined; the manufacturer should be consulted.
Figure 7-3—Thermal-magnetic trip MCCB

IEEE
Zone selective interlocking (ZSI) is deﬁned as a function provided for rapid clearing while
retaining coordination. The function is a communication interconnection between the
electronic trip units of two or more circuit breakers connected in series on multiple levels. By
means of intercommunication between the short-time delay and/or ground-fault elements, the
Figure 7-4—Instantaneous (magnetic) current adjustment provided on
thermal-magnetic circuit breakers
Figure 7-5—Electronic trip unit with long-time, short-time, instantaneous,
and ground-fault adjustments

IEEE
breaker nearest the fault trips with minimum time delay while signaling the supply-side
circuit breakers to delay for a predetermined period. Synonyms are zone interlocking and
selective interlocking.
Contrasted with traditional systems in which short-time delay is set for selective coordination
and should time out before tripping occurs, the selectively interlocked system substantially
reduces the potentially damaging energy delivered to a fault because delay in tripping is not
introduced beyond any setting present on the circuit breaker closest to the fault.
When harmonics or other nonlinear conditions are potentially present, the sensing systems in
the various trip unit types react in different ways. Bimetals and similar thermal elements in
thermal magnetic trip units react directly to I2
R heating and provide true rms current sensing.
Some electronic trip units provide high accuracy in sensing true rms current by combining
high frequency current sampling with internal software that calculates rms values. Such
devices may be preferred where overload protection is a concern. Analog and peak-sensing
digital electronic trip units may not provide an accurate rms measurement where a high
power content of harmonics or other disturbances are present, but may be quite suitable when
high fault protection is of concern. Manufacturers’ speciﬁcations may help in identifying the
capability of a particular trip unit. Trip units that are less accurate in rms sensing are likely to
trip at lower-than-expected 60 Hz fundamental current values due to nonsinusoidal
conditions.
7.5.1 Time-current characteristic (TCC) curves
The TCC curve depicts the time required for a circuit breaker to open automatically versus
the current through it. The curve is principally a function of the type of trip unit and its set-
tings. The inverse-time characteristic is intended to protect conductors. The inverse-time
characteristic derives its name from the inverse proportionality of time to operate versus mag-
nitude of current ﬂowing through the circuit breaker. In other words, opening is faster when
the overcurrent condition is higher.
The curve (see Figure 7-6, Figure 7-7a, and Figure 7-7b) may conveniently be separated into
three regions:
— Long-time, in which opening is timed in minutes up to a maximum of 1 hour or
2 hour—depending on the circuit breaker size and the degree of overcurrent—to pro-
vide an inverse-time characteristic. The provided time delay allows intermittent or
cyclical loads above the pickup current to be carried without causing an interruption.
It trips on sustained overcurrent to protect conductors and other equipment.
— Short-time, in which opening is timed in seconds or tenths of seconds. Overcurrents
might be in the range expected in the case of a motor locked rotor or an arcing ground
fault. Time delay in this region allows for starting and inrush transient currents or for
selective coordination with supply-side or load-side devices.
— Instantaneous, in which opening is not intentionally delayed and is timed in millisec-
onds. Typical operation is a result of short circuit from a bolted fault.

IEEE
Time current curves are excellent engineering tools when time and current are the primary
factors. In the short-circuit region, other factors (e.g., power factor, instant of fault initiation,
number of poles or phases in the fault, behavior of other equipment in the circuit) can also
affect reaction and clearing time. Commonly available curves drawn in accordance with
NEMA AB 1-1986 show a wide band of clearing time for multiple pole interruption that
includes the effect of these factors.
The continuous-current rating may be ﬁxed or adjustable. Some designs may require replac-
ing all or part of the trip unit to change the continuous rating. Overcurrent trip characteristics
are a function, multiple, or percentage of the continuous-current rating.
7.5.1.1 Thermal-magnetic trip unit characteristic
A typical TCC curve for a thermal-magnetic MCCB is depicted in Figure 7-6. This particular
curve is for a 600 A frame in ratings of 125 A to 600 A at the typical rated operating
temperature of 40 °C. It indicates the operating time from a cold (40 °C) start at initiation of
an overcurrent to clearing. The operating time varies inversely with current level. The shaded
band covers manufacturing tolerances and other variables of a typical installation.
Regarding operating temperature, NEMA AB 3-1991 states “Molded-case circuit breakers
are calibrated at 100 percent of rated current in open air for a given ambient temperature usu-
ally 25 °C or 40 °C. Where the ambient temperature is known to differ signiﬁcantly from the
Figure 7-6—Typical TCC curve for a three-pole 600 A frame size MCCB in
open air at rated temperature, usually 40 °C

IEEE
calibration temperature, the breaker used should be specifically calibrated for that ambient or
be re-rated accordingly. When the expected range of ambient air temperature around the cir-
cuit breaker is lower than –5 °C or higher than 40 °C, breaker operation may be affected.”
The long-time region at the upper end of the curve is determined by deflection of a bimetal or
similar thermal element reacting to I2
R heating caused by the overcurrent condition. The
long-time band is fixed, and adjustments are not provided for thermal-magnetic circuit
breakers.
In the instantaneous region at the bottom of the curve, operation is with no intentional delay.
Tripping action of the mechanism is typically caused by an electromagnet in the trip unit
energized by the fault current. The operating time includes mechanical reaction and arc clear-
ing time and is a maximum at the line so labeled on the curve. Contacts of current-limiting
circuit breakers open directly due to forces caused by fault current and are independent of the
multipole operating mechanism. The operating mechanism responds several milliseconds
after the contacts of poles carrying fault current are forced open so that the mechanism opens
all poles of the circuit breaker and holds contacts open after clearing the fault. The mecha-
nism operating time is not a factor in clearing time for these rapidly operating circuit
breakers.
Figure 7-7a—Typical TCC curve for electronic trip circuit breaker (I2
t OUT);
adjustable functions identified

IEEE
For the thermal-magnetic circuit breaker, no true short-time region exists as does for circuit
breakers with electronic trip units. For many thermal-magnetic circuit breakers such as the
one in Figure 7-6, the instantaneous tripping current level (or magnetic tripping level) can be
adjusted higher or lower. A typical adjustment is pictured in Figure 7-4. In Figure 7-6, two
curves are shown, one with adjustment at low (minimum) setting and the second with the
adjustment at high (maximum) setting. This adjustment helps to set instantaneous tripping
above starting or inrush transients.
Some magnetic instantaneous elements are peak sensitive even though rms calibrated. Where
harmonics are present, care should be used.
7.5.1.2 Electronic trip unit characteristic
Figure 7-7a and Figure 7-7b depict typical TCC curves for electronic trip units with the ﬁve
most common adjustments: long-time current pickup, long-time delay, short-time pickup,
short-time delay, and instantaneous pickup.
— For a given frame rating, the long-time current pickup (sometimes called current
setting), in addition to the rating plug selected, determines the current rating of the
circuit breaker. This function determines the current at which the tripping function
Figure 7-7b—Typical TCC curve for electronic trip circuit breaker (I2
t IN);
adjustable functions identiﬁed

IEEE
picks up and begins timing. The means of pickup setting adjustment should be
located behind a sealable cover or otherwise restricted to qualified personnel in order
to be considered the rating under NEC Article 240-6.
— The long-time delay can be adjusted to enable the system to withstand temporary
overloads before tripping. This setting varies the time that the circuit breaker carries a
given overload.
— The short-time pickup determines the current level at which the short-time tripping
function begins timing.
— The short-time delay setting determines the time delay for any current level above the
pickup before tripping. The short-time characteristic is provided primarily for
selective coordination with load-side circuit breakers or fuses. The short-time (or
withstand) rating establishes the capability of the circuit breaker to withstand forces
and heat associated with the time delay with currents above the short-time pickup
current level.
— The instantaneous pickup sets the current level at which the trip unit initiates instan-
taneous tripping. The instantaneous feature may not be provided or may be switched
off on some circuit breakers to make full use of the short-time feature for selective
coordination. Although instantaneous tripping has no intentional delay, time to
pickup is typically .033 s within the instantaneous trip band and .011 s for higher
short-circuit currents. Clearing time is in addition to the pickup time.
Further refinement of the electronic trip unit’s short-time delay characteristic for overcurrent
protection or the ground-fault time-delay characteristic may be obtained by shaping part of
the response curve as an inverse function of the I2t, illustrated by the sloping portion of
Figure 7-7a and Figure 7-7b. This response curve provides greater selectivity with load-side
thermal-magnetic circuit breakers or fuses that have a similarly sloping response curve.
The most full-featured trip units may include the five most common adjustments plus ground-
fault pickup and delay adjustments plus communication features described for the
communicating electronic trip unit (see 7.5). Specifications should call out the functions that
are necessary on a particular installation. Specific manufacturers’ literature should be
consulted for guidance on individual units.
7.5.1.3 Ground-fault TCC
Electronic trip units in low-voltage circuit breakers may also provide TCCs illustrated by
Figure 7-8a and Figure 7-8b for equipment ground-fault protection to meet the requirements
of NEC Article 215-10 and Artcile 230-95. NEC requirements establish the maximum
current setting of the ground-fault device at 1200 A and, in addition, limit the maximum time
delay to 1 s for fault currents equal to or greater than 3000 A. Selectivity is enhanced by the
presence of an optional trip unit adjustment that provides inverse ground-fault TCCs
illustrated by the sloping portion of the curve in Figure 7-8b. While this chapter refers to
ground-fault protection with regard to circuit breaker application, Chapter 8 gives a more
complete treatment of the subject.

IEEE
Typical adjustments are ground-fault current pickup and time delay. Neutral current sensors
are available as an external accessory for most circuit breakers with ground-fault protection
so that neutral current can be summed vectorially with phase current.
Figure 7-8a—Ground-fault TCC curve (I2
t OUT) for electronic trip
circuit breaker
Figure 7-8b—Ground-fault TCC curve (I2
t IN) for electronic trip circuit breaker

IEEE
7.5.1.4 Separate protective relays
LVPCBs are also applied with shunt trip devices and separate protective relays, both for
overcurrent and ground-fault protection. These applications are identical to the applications
covered in Chapter 4 and Chapter 8 and are not discussed further in this chapter.
7.6 Application
Consideration of all the factors related to proper application of a low-voltage circuit breaker
goes beyond voltage, current, and interrupting rating. The performance of a specific type of
circuit breaker may be influenced by nonelectrical factors related to the installation
environment, such as ambient temperature, humidity, elevation, or presence of contaminants.
Enclosure type and size, service conditions, loads and their characteristics, outgoing
conductors, characteristics of the electrical distribution system, other protective devices on
the line side and load side of the circuit breaker under consideration, and even frequency of
operation and maintenance should all be taken into account. For this chapter, application
considerations are limited to conditions involving abnormal current and to providing
protection and selective coordination under these conditions.
7.6.1 Protection
The function of system protection may be defined as the detection and prompt isolation of the
affected portion of the system when a short circuit or other abnormality occurs that might
cause damage to, or adversely affect, the operation of any portion of the system or the load
that it supplies.
Treatment of the overall problem of system protection and coordination of electrical power
systems is restricted to the selection, application, and coordination of devices and equipment
whose primary function is the isolation and removal of short circuits from the system. Short
circuits may be phase-to-ground, phase-to-phase, phase-to-phase-to-ground, three-phase, or
three-phase-to-ground. Short circuits may range in magnitude from extremely low-current
faults having high-impedance paths to extremely high-current faults having very low-
impedance paths. However, all short circuits produce abnormal current flow in one or more
phase conductors or in the ground path. Such disturbances should be detected and safely
isolated .
Two types of overcurrent protection are emphasized: phase-overcurrent and ground-fault. At
the present state of the art, phase-overcurrent conditions are detected on the basis of their
magnitudes. Response time is dependent upon the particular overcurrent TCC curve. Ground-
fault currents of a sufficient magnitude may be detected by phase-overcurrent devices.
Currents below the minimum current sensitivity of phase-overcurrent devices, such as arcing
ground faults, are not cleared. A separate means (either internal to the circuit breaker or
externally mounted) should be provided to detect these low-level arcing ground faults. This
means of detection commonly consists of current sensors that monitor each phase and the
grounding conductor separately or one current sensor that monitors all phase conductors. A
single current sensor that monitors the ground-fault current in a transformer or generator

IEEE
neutral grounding conductor may be used. Refer to NEMA PB 2.2-1988 for the application
of ground-fault protective devices for equipment. Circuit breakers have the advantage of
providing a convenient means for opening all phase conductors in response to a signal from
either the phase-overcurrent or ground-fault detection device. They have the additional
advantage of having the current sensors and logic circuitry located internally within the
breaker. This location minimizes the need to make external connections to control
components.
A fundamental rule necessary for system protection is to apply circuit breakers within their
interrupting or short-circuit current ratings. The determination of available short-circuit cur-
rent at the various levels throughout the electrical distribution system is a necessary step to be
completed prior to selecting circuit breakers for system protection. (Chapter 2 discusses
methods of calculating available short-circuit current.) MCCBs are available with various
interrupting ratings in the same physical frame size. Selection by frame size or continuous-
current rating alone is not sufficient; the interrupting rating should also be considered.
Current-limiting fuses, integrally fused circuit breakers, or current-limiting circuit breakers
may be provided to lower the let-through short-circuit current. Curves depicting let-through
current and I2
t are available from manufacturers to assist in the application of these circuit
breakers as shown in Figure 7-9a and Figure 7-9b.
An alternate method is the series connection of MCCBs, that is, two MCCBs electrically in
series sharing fault interruption duties. This protection scheme is viable, provided perfor-
mance is verified by testing. UL presently recognizes series-connected short-circuit ratings
and prescribes test procedures to verify performance. Series ratings are a consequence of cer-
tain tests that are defined by UL standards, and only combinations of devices that have been
appropriately tested should be used in series applications. See Figure 7-10 for an example of
a test setup. Selectivity is not provided at any current level where the breaker trip characteris-
tic curves overlap, that is, both circuit breakers trip. Series-connected ratings should be based
Figure 7-9a—Limited peak let-through current characteristics

IEEE
on tests and are only valid for the speciﬁc circuit breaker types listed in the test reports.
Individual manufacturer’s series-connected ratings may be found in the UL Recognized Com-
ponent Directory. Fuse and breaker coordinated combinations are also tested by UL and are
applicable within their established ratings.
Figure 7-9b—Limited let-through I2
t characteristics
Figure 7-10—Series connection test circuit from UL 489-1996

IEEE
Determination of available fault-current levels, speciﬁcation of circuit breakers and associ-
ated equipment rated for those levels, and inspection to verify that properly rated equipment
has been installed satisfy the basic requirement of providing adequately rated equipment for
system protection.
Selection of appropriate trip unit functions and their settings to provide protection and coor-
dination is the next consideration. Basic rules applicable to phase overcurrent protection are
as follows:
a) Select continuous-current ratings and pickup settings of long-time delay characteris-
tics, where adjustable, that are no higher than necessary without causing nuisance
tripping and that meet applicable code requirements. The amount of time delay pro-
vided by the long-time delay characteristics should be selected to be no higher than
necessary to override transient overcurrents associated with the energizing of load
equipment and to coordinate with downstream protection devices.
b) Take advantage of the adjustable instantaneous trip characteristic on MCCBs and
LVPCBs. Set the instantaneous trip no higher than necessary to avoid nuisance trip-
ping. Be sure that instantaneous trip settings do not exceed the maximum available
short-circuit current at the location of the circuit breaker in the system. This point is
frequently overlooked, particularly in service entrance applications.
c) Provide ground-fault protection in accordance with the NEC, where required.
Ground-fault current settings should be set to minimize hazard to personnel and dam-
age to equipment. Time-delay adjustments of ground-fault protective devices should
be set so that ground faults are cleared by the nearest device on the supply side of the
ground fault.
7.6.2 Selective coordination
When protection is being considered, the performance of a circuit breaker with respect to the
connected conductors and load is a primary concern. To achieve coordination, consideration
is also given to the performance of a circuit breaker with respect to other protective devices
on the supply side or load side of it. The objective in coordinating protective devices is to
make them selective in their operation with respect to each other. In so doing, the effects of
short circuits on a system are reduced to a minimum by disconnecting only the affected part
of the system. Stated another way, only the circuit breaker nearest the short circuit should
open, leaving the rest of the system intact and able to supply power to the unaffected parts.
Chapter 15 covers the general subject of coordination in detail.
Generally, coordination is demonstrated by plotting the TCC curves of the circuit breakers
involved and by making sure that the curves of adjacent circuit breakers do not overlap, as
illustrated in Figure 7-11. Often selective coordination is possible only when circuit breakers
with short-time delay characteristics are used in all circuit positions except the one closest to
the load. This setting arrangement is particularly true when little or no circuit impedance
exists between successive circuit breakers. This condition often exists in a main switchboard
or load center unit substation between the main and feeder circuit breakers. In these cases, for
all levels of possible short-circuit current beyond the load terminals of the feeder circuit
breakers selectivity requires that the main circuit breaker be equipped with a combination of

IEEE
long-time delay and short-time delay trip characteristics. The withstand rating of associated
circuit components and assemblies should not be exceeded. Moving toward the load, on
many feeder circuits sufficient impedance exists in the distribution system to appreciably
lower the available short-circuit current at the next load-side level circuit breaker. If the avail-
able short-circuit current at this circuit breaker is less than the instantaneous trip setting of the
feeder circuit breaker, then selectivity is achieved (see Figure 7-12).
The preceding discussion forms the basis for judging selective coordination between two
circuit breakers in series. If the fault current being interrupted by a circuit breaker flows
through the line-side circuit breaker for a period equal to or greater than its tripping time, the
line-side circuit breaker trips. Under these conditions, the circuit breakers are not selective.
However, if because of impedance between the circuit breakers, the maximum current that
can flow during short-circuit conditions is insufficient to initiate tripping of the line-side
circuit breaker, selectivity exists. An alternate method of achieving selective coordination is
Figure 7-11—Coordinated tripping by overlapping TCC curves

IEEE
by selective interlocking of two or more levels of electronic trip units in a system. In a
selectively interlocked system, the circuit breaker nearest to and toward the supply side of the
fault senses the fault and signals other line-side circuit breakers that it is tripping. That signal
restrains circuit breakers farther to the line-side from reacting until they time out according to
their settings. Because it does not receive such a restraining signal from a load-side circuit
breaker, the circuit breaker nearest the fault continues to trip with minimum delay. This
method signiﬁcantly limits the damaging energy delivered to a fault by permitting the circuit
breaker nearest the fault to react without the short-time delay that is necessary to provide
coordination by the time and pickup level method. The limitation of fault energy is even
greater when the circuit breakers involved are current-limiting. Some circuit breakers with
electronic trip units incorporate an instantaneous override set above their tripping
characteristic for self protection. If fault current through the circuit breaker reaches this level,
the circuit breaker trips with no intentional delay even in selectively interlocked systems.
This feature should be considered in selectivity studies.
7.6.3 Power factor considerations
Normally the short-circuit power factor of a system need not be considered when applying
either LVPCBs or MCCBs. This practice is based on the fact that the test circuit power factors
on which ratings have been established are considered low enough to cover most
applications. Test circuits with lagging power factors no greater than in Table 7-6 are used to
establish interrupting ratings.
Where the power factor or X/R ratio for a speciﬁc system has been determined and is more
inductive than the power factor used to establish the interrupting rating, the multiplying factor
tabulated in Table 7-7 may be applied to the calculated, available short-circuit current. These
Figure 7-12—Coordinated tripping due to impedance in circuit

IEEE
multiplying factors adjust the short-circuit current to a value equal to the maximum transient
offset in the initial half-cycle of short-circuit current ﬂow using the relation in Elements of
Power System Analysis (see Stevenson[B7]), as follows:
where
t is time and is 0 when voltage is applied,
α is the electrical angle after t = 0 at which point the circuit is closed,
θ is the power angle and equals tan–1
(ωL / R),
Z is .
By making the simplifying assumption that the circuit is closed at a time t = 0 when the
instantaneous voltage is zero, the following multiplier is derived:
where
CIRC is the circuit under consideration,
TEST is the circuit used to test the circuit breaker.
Table 7-6—Test circuit power factors
Available short-circuit
current
(A, rms symmetrical)
Lagging power factor (%)
MCCBa
LVPCB
Unfusedb Fusedb
10 000 or less 50 15 20
10 001–20 000 30 15 20
over 20 000 20 15 20
aUL 489-1991.
bANSI C37.50-1989.
i t
( )
Vmax
Z
-----------
- ωt α θ
–
+
( ) ε
Rt
–
L
--------
-
– α θ
–
( )
sin
sin
=
R
2
ωL
( )
2
+
( )
MULT
1 ε
πR
–
X
---------
-
+
 
 
 
CIRC
1 ε
πR
–
X
---------
-
+
 
 
 
TEST
---------------------------------------
-
=

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Table 7-7—Short-circuit current multiplying factor for circuit breakers
Power
factor
(%)
X/R ratio
MCCB interrupting rating (rms
symmetrical A)
LVPCB
10 000 or less
10 001 to
20 000
over 20 000 Unfused Fused
Short circuit current multiplying factor
4 24.98 1.62 1.37 1.23 1.16 1.23
5 19.97 1.59 1.35 1.22 1.14 1.22
6 16.64 1.57 1.33 1.20 1.12 1.20
7 14.25 1.55 1.31 1.18 1.11 1.19
8 12.46 1.53 1.29 1.16 1.10 1.18
9 11.07 1.51 1.28 1.15 1.09 1.15
10 9.95 1.49 1.26 1.13 1.07 1.14
11 9.04 1.47 1.24 1.12 1.05 1.12
12 8.27 1.45 1.23 1.10 1.04 1.11
13 7.63 1.43 1.21 1.09 1.02 1.10
14 7.07 1.41 1.20 1.08 1.01 1.08
15 6.59 1.39 1.18 1.06 1.00 1.06
16 6.17 1.38 1.17 1.05 1.00 1.05
17 5.8 1.36 1.15 1.04 1.00 1.04
18 5.49 1.35 1.14 1.02 1.00 1.03
19 5.17 1.33 1.13 1.01 1.00 1.02
20 4.9 1.31 1.11 1.00 1.00 1.00
21 4.86 1.31 1.11 1.00 1.00 1.00
22 4.43 1.28 1.09 1.00 1.00 1.00
23 4.23 1.27 1.08 1.00 1.00 1.00
24 4.05 1.26 1.06 1.00 1.00 1.00
25 3.87 1.24 1.05 1.00 1.00 1.00
26 3.71 1.23 1.04 1.00 1.00 1.00
27 3.57 1.22 1.03 1.00 1.00 1.00
28 3.43 1.20 1.02 1.00 1.00 1.00
29 3.3 1.19 1.01 1.00 1.00 1.00
30 3.18 1.18 1.00 1.00 1.00 1.00
35 2.68 1.13 1.00 1.00 1.00 1.00
40 2.29 1.08 1.00 1.00 1.00 1.00
45 1.98 1.04 1.00 1.00 1.00 1.00
50 1.73 1.00 1.00 1.00 1.00 1.00

IEEE
These multiplying factors are based on calculated values for peak currents rather than on lab-
oratory tests. Individual manufacturers may have additional information.
For example, consider a 225 A MCCB with an interrupting rating of 35 000 A to be applied
on a circuit with a short-circuit availability of 24 000 A and a power factor of 10%. Select the
multiplying factor of 1.13 and multiply the 24 000 A short circuit by it to arrive at the new
short circuit of 27 100 A. In this case, the MCCB is suitable for the 27 100 A short circuit
because of its 35 000 A rating.
7.6.4 Voltage considerations
The most common industrial and commercial utilization voltage by far is the solidly
grounded 480Y/277 V system. Yet, a number of 600 V and 480 V delta systems are in service
of both ungrounded and corner-grounded conﬁgurations. Further, a growing number of
industrial systems are using resistance-grounded 480Y/277 V systems.
Special attention should be given to resistance-grounded wye systems and delta systems with
respect to ground faults and single-pole interrupting performance. Consider the single fault to
ground in View (a) of Figure 7-13 and the double fault to ground in View (b) of Figure 7-13
in delta systems. In each case, the voltage across the interrupting pole is just below line-to-
line voltage. The magnitude of the fault depends on the prospective current and the value of
the impedances to ground at the respective faults.
Then, consider the resistance-grounded wye system in View (c) of Figure 7-13. With a single
fault to ground, the fault current is severely limited by the resistance grounding connection.
With two faults to ground, voltage across the interrupting pole is at some value between
Figure 7-13—Systems requiring special consideration for single-pole faults

IEEE
phase voltage and line voltage. Again, the magnitude of the fault depends on the prospective
current and the value of the impedances to ground at the respective faults.
For the systems shown in Figure 7-13, straight-rated (or delta-rated) circuit breakers should
be used. Referring to Table 7-8 and testing standards, it is known that each circuit breaker
pole is tested at phase voltage at full prospective current as part of the three-phase test. Also,
each pole is tested individually at line voltage with test currents indicated in Table 7-8. When
system conditions are beyond these test values, use of MCCBs tested speciﬁcally for corner-
grounded delta systems and use of LVPCBs are options.
Table 7-8—Single-pole short-circuit test values for MCCBsa
Frame rating
Individual pole short-circuit test values
Two-pole circuit breaker Three-pole circuit breaker
(A, rms sym) Voltage (A, rms sym) Voltage
100 A maximum
250 V maximum
5 000 L–L 4 330 L–L
100 A maximum
251–600 V Delta
10 000 L–L 8 660 L–L
101–800 A
Delta voltage
10 000 L–L 8 660 L–L
800 A maximum
480Y/277 V or
600Y/347 V
10 000 L–N 10 000 L–N
801–1200 A
Delta voltage
14 000 L–L 12 120 L–L
801–1200 A
480Y/277 V or
600Y/347 V
14 000 L–N 14 000 L–N
1201–2000 A
Delta voltage
14 000 L–L 14 000 L–L
2001–2500 A
Delta voltage
20 000 L–L 20 000 L–L
2501–3000 A
Delta voltage
25 000 L–L 25 000 L–L
3001–4000 A
Delta voltage
30 000 L–L 30 000 L–L
4001–5000 A
Delta voltage
40 000 L–L 40 000 L–L
5001–6000 A
Delta voltage
50 000 L–L 50 000 L–L
aThese test values are the minimum required for certification to UL 489-1991. They are not
marked ratings and are printed here to aid the system designer who may need them for single-
phase short-circuit analysis. Single-pole circuit breakers are tested at values equal to their
interrupting ratings.

IEEE
Table 7-9 is provided as a guide for applying the appropriate voltage rating of the MCCB to
each system.
Individual poles of multipole MCCBs are tested at short-circuit levels indicated in Table 7-9
for all values of multipole interrupting ratings. These tests are in addition to multipole tests in
which the individual poles are required to interrupt under transient conditions that are more
demanding than single-phase tests of the same pole at phase voltage.
7.7 Accessories
Accessories most commonly available are the shunt trip, undervoltage trip, alarm switch, and
auxiliary contacts. Ratings and operating characteristics are specific by manufacturer. Some
accessories are provided for field installation by qualified electricians. Accessories should be
specified by the manufacturer for the specific circuit breaker.
7.8 Conclusions
The following considerations apply to low-voltage circuit breakers for system protection:
a) They combine a switching means with an overcurrent protective device in a compact,
generally self-contained unit.
Table 7-9—MCCB voltage rating by system configuration
System configuration Three-pole MCCB voltage rating
Voltage Grounding 480Y/277 480 600Y/347 600
480Y/277 Solid • • • •
480Y/277 Resistance • a •
480 Ungrounded • •
480 Corner ground • a •
600Y/347 Solid • •
600 Ungrounded •
600 Corner ground •
aCodes and standards allow 480 V rated MCCBs in these applications. Some manufactur-
ers provide MCCBs specially rated for the corner-grounded delta system to satisfy user
preference. These ratings may also be applied to resistance-grounded wye systems.
LVPCBs are also an option.

IEEE
b) No exposure to live parts is involved during operation when installed in an approved
enclosure.
c) They are resettable. Normally after tripping (and removal of the fault or overload that
caused tripping), service may be restored without replacing any part of the assembly.
Inspection of the circuit breaker assembly after fault current interruption is required
to verify suitability to return the circuit breaker and/or other parts of the system to
service. Inspection of the circuit breakers may require replacement of fuses or fuse
assemblies after interruption of high-magnitude fault currents. In LVPCBs, most
designs allow for replacing components, such as contacts or arc chutes, using instruc-
tions from the manufacturer.
d) They provide simultaneous disconnection of all phase conductors.
e) High short-circuit interrupting ratings, the availability of current-limiting circuit
breakers, and series-connected interrupting ratings permit application on systems
with high available fault currents.
f) The advent of highly complex and technologically advanced electronic trip units has
increased circuit breaker versatility and made selective coordination easier.
g) Selection of MCCBs should include consideration of interrupting rating because
more than one interrupting rating may be available in the same frame size.
h) Selective coordination of ground-fault protective devices requires time-delay and
pickup adjustments and may be enhanced by the presence of adjustments that provide
inverse TCCs.
7.9 References
ANSI C37.13-1990 Low Voltage AC Power Circuit Breakers Used in Enclosures.2
ANSI C37.16-2000, American National Standard Preferred Ratings, Related Requirements,
and Application Recommendations for Low-Voltage Power Circuit Breakers and AC Power
Circuit Protectors.
ANSI C37.50-1989, American National Standard for Switchgear—Low-voltage AC Power
Circuit Breakers Used in Enclosures—Test Procedures.
IEEE Std 141-1993, IEEE Recommended Practice for Electric Power Distribution for Indus-
trial Plants (Red Book).

IEEE
IEEE Std C37.100-1992, IEEE Standard Deﬁnitions for Power Switchgear.3
NEMA AB l-1986, Molded-Case Circuit Breakers.4
NEMA AB 3-1991, Molded-Case Circuit Breakers and Their Application.
NEMA PB 2.2-1988, Application Guide for Ground Fault Protective Devices for Equipment.
NFPA 70-1999, National Electrical Code® (NEC®).5
UL Recognized Component Directory (Yellow Book), 2001.6
UL 489-1996, Molded-Case Circuit Breakers, Molded-Case Switches, and Circuit-Breaker
Enclosures, Ninth Edition.
7.10 Bibliography
[B1] ANSI C37.17-1979 (Reaff 1988), American National Standard for Trip Devices for AC
and General-purpose DC Low-Voltage Power Circuit Breakers.
[B2] IEC 947-2, Low-Voltage Switchgear and Controlgear, Part 2: Circuit Breakers.7
[B3] IEEE Std C37.13-1990, IEEE Standard for Low-Voltage AC Power Circuit Breakers
Used in Enclosures.
[B4] NEMA AB 4-1996, Guidelines for Inspection and Preventive Maintenance of Molded
Case Circuit Breakers Used in Commercial and Industrial Applications.
[B5] NEMA FU 1-1986, Standard for Low-Voltage Cartridge Fuses 600 Volts or Less.
[B6] NEMA SG 3-1990, Low-Voltage Power Circuit Breakers.

IEEE
[B7] Stevenson, W. D., Jr., Elements of Power System Analysis. New York: McGraw-Hill,
1982.
[B8] UL 1066-1985, Low-Voltage AC and DC Power Circuit Breakers Used in Enclosures.

Chapter 8
Ground-fault protection
In recent years, interest has been increasing in the use of ground-fault protection in electric
distribution circuits. One reason for this intensified interest is that ground-fault protection is
required by the National Electrical Code® (NEC®) (NFPA 70-1999)1 on certain service-
entrance equipment (see Article 230-95), feeders (see Article 215-10), and remote structures
(see Article 240-13) and recommended in NEMA PB 2.2-1999. Further evidence of this
interest can be found in the number of feature articles dealing with this subject in today’s
electrical indoor distribution, construction, and consulting engineering press. These articles
and the unusual interest in ground-fault protection are a reaction to a disturbing number of
electric failures. One editor reports the cost of arcing faults as follows: “One five-year
estimate places the figure between $1 billion and $3 billion annually for equipment loss,
production downtime, and personal liability” (see O’Connor [B35]). Manufacturers of
ground-fault protection devices have improved the devices and increased the range of devices
available so that designers can now confidently apply the devices to isolate damage and avoid
unnecessary outages. This chapter explores the need for better ground-fault protection,
pinpoints the areas where that need exists, and discusses the solutions that are being applied
today.
Distribution circuits that are solidly grounded or grounded through low impedance require
fast clearing of ground faults. This need for speed is especially true in low-voltage grounded
wye circuits that are connected to busways or long runs of metallic conduit. The problem
involves sensitivity in detecting low ground-fault currents as well as coordination between
main and feeder circuit protective devices.
The concern for ground-fault protection is based on four factors:
— The majority of electric faults involve ground. Even faults that are initiated phase to
phase spread quickly to any adjacent metallic housing, conduit, or tray that provides a
return path to the system grounding point. Ungrounded systems are also subject to
ground faults and require careful attention to ground detection and ground-fault
protection.
— The ground-fault protective sensitivity can be relatively independent of continuous-
load current values and, therefore, have lower pickup settings than phase protective
devices.
— Because ground-fault currents are not transferred through system power transformers
that are connected delta-wye or delta-delta, the ground-fault protection for each
system voltage level is independent of the protection at other voltage levels. This
configuration permits much faster relaying than can be afforded by phase-protective
devices that require coordination using pickup values and time delays that extend

IEEE
from the load to the source generators and often result in considerable time delay at
some points in the system.
— Arcing ground faults that are not promptly detected and cleared can be destructive.
Much of the present emphasis on ground-fault protection centers on low-voltage circuits,
600 V or less. Low-voltage circuit protective devices have usually involved fused switches or
circuit breakers with integrally mounted series tripping devices. These protective elements
are termed overload or fault overcurrent devices because they carry the current in each phase
and clear the circuit only when the current reaches a magnitude greater than full-load current.
To match insulation damage curves of conductors and to accommodate motor and trans-
former inrush currents, phase-overcurrent devices are designed with inverse characteristics
that are slow at overcurrent values up to about ﬁve times rating. For example, a 1600 A
low-voltage circuit breaker with conventional phase protection clears a 3200 A fault in about
100 s, although it can be adjusted in a range of roughly 30 s to 200 s at this fault value. A
1600 A fuse may require 10 min or more to clear the same 3200 A fault. These low values of
fault currents are associated predominantly with faults to ground and generally have received
little attention in the design of low-voltage systems until the occurrence of a number of seri-
ous electric failures in recent years. Arcing fault phenomena surfaced in the late 1940s and
early 1950s with the advent of 480Y/277 V systems. In contrast, on grounded systems of
2400 V and above, applying some form of ground-fault protection has long been standard
practice.
This chapter is primarily directed to ground-fault protection of major portions of circuits and
equipment. The discussions relate to various forms of ground-fault protection to prevent
excessive damage to electrical equipment with current sensitivity in the order of amperes to
hundreds of amperes.
Although its purpose is to disconnect faulty parts of an electric system, to preserve service
continuity in other parts, and to limit ejection of gases and molten metal or to localize faults,
ground-fault protection does not satisfy rigid requirements regarding employee ﬂash hazard
protection, shock hazards, or touch potentials that are designed for protection of people and
necessitate milliampere sensitivity and may only be feasible for small loads.
The action initiated by ground-fault sensing devices should vary depending on the
installation. In some cases, such as services to dwellings, immediately disconnecting the
faulted circuit may be necessary to prevent loss of life or property. However, the opening of
some circuits in critical applications may in itself endanger life or property. Therefore, each
particular application should be studied carefully before selecting the action to be initiated by
the ground-fault protective devices.
8.2 Types of systems relative to ground-fault protection
A comprehensive discussion of grounded and ungrounded systems is given in Chapter 1 of
IEEE Std 142-1991. When considering the choice of grounding, determining the types of
ground-fault protection available and their effect on system performance, operation, and
safety are important.

IEEE
GROUND-FAULT PROTECTION Std 242-2001
An ungrounded system has no intentional connection to ground except through potential-
indicating or potential-measuring devices or through surge protective devices. While a system
is called ungrounded, it is actually coupled to ground through the distributed capacitance of
its phase windings and conductors.
A grounded system is intentionally grounded by connecting its neutral or one conductor to
ground, either solidly or through a current-limiting impedance. Various degrees of grounding
are used ranging from solid to high impedance, usually resistance.
Figure 8-1 shows ungrounded and grounded systems and their voltage relationships. The
terms solidly grounded and direct grounded have the same meaning, that is, no intentional
impedance is inserted in the neutral-to-ground connection.
8.2.1 Classiﬁcation of system grounding
The types of system grounding normally used in industrial and commercial power systems
are
— Solid grounding
— Low-resistance grounding
— High-resistance grounding
— Ungrounded
a) Ungrounded system, showing system capacitance to ground
b) Grounded wye-connected system
c) Grounded delta-connected system
Figure 8-1—Voltages to ground under steady-state conditions

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Each type of grounding has advantages and disadvantages, and no one method is generally
accepted. Factors that influence the choice include
a) Voltage level of power system
b) Transient overvoltage possibilities
c) Type of equipment on the system
d) Required continuity of service
e) Caliber and training of operating and maintenance personnel
f) Methods used on existing systems
g) Availability of convenient grounding point
h) The NEC
i) Cost of equipment, including protective devices and maintenance
j) Safety, including fire and shock hazard
k) Tolerable fault damage levels
l) Effect of voltage dips during faults
m) Availability of high enough single-pole interrupting ratings on protective devices (see
NEMA PB 2.2-1999)
Many factors are involved in selecting grounding methods for the different voltage levels
found in power distribution systems. IEEE Std 142-1991 discusses many of these factors in
detail, while the following discussion mentions only the reasons that relate to ground-fault
protection.
8.2.2 Solid grounding
Most industrial and commercial power systems are supplied from electric utility systems that
are solidly grounded (see Figure 8-2). If the user must immediately convert to lower voltage,
the power transformers typically have a delta-connected primary and a wye-connected sec-
ondary that can again be connected solidly to ground. This configuration results in a system
that can be conveniently protected against overvoltages and ground faults. The system has
flexibility because the neutral can be carried with the phase conductors, and this feature per-
mits connecting loads from phase to phase and from phase to neutral.
a) Systems above 600 V. Ground relaying of medium-voltage and high-voltage systems
that are solidly grounded has been successfully accomplished for many years using
residually connected ground relays or zero-sequence sensing. The circuit breakers
normally have current transformers (CTs) to provide the signal for the phase-
overcurrent relays, and the ground-overcurrent relay is connected in the wye point
(i.e., residual) to provide increased sensitivity for ground faults. Ground-fault magni-
tudes usually are comparable to phase-fault magnitudes and are, therefore, easily
detected by relays or fuses unless they occur in equipment windings near the neutral
point.
b) Systems 600 V and below. All 208 V systems are solidly grounded so that loads can
be connected from line to neutral to provide 120 V service. Similarly, all 480 V sys-
tems that are to serve 277 V lighting should also be solidly grounded. As a result of
this requirement, 480 V systems in most commercial buildings and many industrial
plants are solidly grounded. Even where 277 V lighting is not used, 480 V systems in

IEEE
many industrial plants are solidly grounded to limit overvoltages and to facilitate
clearing ground faults.
While higher voltage systems normally use relays with sensitive ground-fault elements,
low-voltage systems usually use circuit breakers with integrally mounted trip devices in the
phases or fusible switches with relays and shunt trips. Because solidly grounded low-voltage
systems can experience relatively low ground-fault currents, sensitive ground-fault relays and
trip devices have been developed for use with low-voltage circuit breakers and bolted pres-
sure switches.
One disadvantage of the solidly grounded 480 V system involves the high magnitude of
destructive, arcing ground-fault currents that can occur. However, if these currents are
promptly interrupted, the equipment damage is kept to acceptable levels. While low-voltage
systems can be resistance-grounded, resistance grounding restricts the use of line-to-neutral
loads.
Another characteristic of solidly grounded 480 V systems is that the ground fault may cause
immediate forced outages. If such outages cannot be tolerated, then either the
high-resistance-grounded systems (without ground-fault tripping) or the ungrounded systems
are used to delay the required outage for repairs. On the other hand, immediate removal of a
faulty circuit is usually desirable.
8.2.3 Low-resistance grounding
The low-resistance-grounded system (see Figure 8-3) is similar to the solidly grounded sys-
tem in that transient overvoltages are not a problem. Low-resistance grounding is used on
medium-voltage systems, but not on low-voltage systems. The resistor is selected to limit
ground-fault current magnitudes, but leave the current high enough to be detected by
sensitive relays. The resistor is normally selected to limit ground fault in the range of 200 A
to 500 A and is rated for approximately 10 s. Higher rated resistors are necessary when a
Figure 8-2—Direct or solid grounding (uses ground relays to trip)

IEEE
number of relaying steps exist. Multisource system ground faults as high as 800 A to 1600 A
can be anticipated. The magnitude of the grounding resistance is selected to allow sufficient
current for ground-fault relays to detect and clear the faulted circuit. This type of grounding is
used mainly in 2.4 kV to 13.8 kV systems, which often have motors directly connected.
The value of resistance also relates to the type of relaying and the percentage of motor
windings that can be protected. Ground faults in wye-connected motors have reduced driving
voltage as the neutral of the motor winding is approached; thus, ground-fault current
magnitudes are reduced.
8.2.4 High-resistance grounding
High-resistance grounding (see Figure 8-4a and Figure 8-4b) limits first fault-to-ground cur-
rents to very low values. The fault current magnitude is predictable regardless of the location
of the fault because the grounding resistor inserted in the neutral is large compared to the
impedance of the remainder of the ground-fault path. High-resistance grounding schemes,
especially at medium voltages, connect a distribution transformer between the neutral and
ground, with a resistor on the transformer secondary. The transformer primary is rated for
line-to-line voltage, and a 240 V secondary limits the secondary voltage to a convenient
139 V maximum.
High-resistance grounding helps ensure a ground-fault current of known magnitude, making
it possible to identify the faulted feeder with sensitive ground-fault relays, which are avail-
able with fault sensitivity in the range of small fractions of an ampere. If the resistance is cho-
sen so that the fault current is equal to or slightly larger than the charging current of the
system, transient overvoltages are reduced. Charging current can be calculated or measured
and is usually under 2 A for low-voltage systems and up to 5 A or 10 A for medium-voltage
systems.
Ground-fault currents of this magnitude seldom require immediate tripping. Thus high-resis-
tance grounding can often maintain continuity of service under first ground-fault conditions
Figure 8-3—Low-resistance grounding (uses ground relays to trip)

IEEE
until a favorable time for an outage to clear the fault, provided the cable carrying the fault is
rated 173% of the voltage level. If a second ground fault occurs on another phase before the first
fault is cleared, a phase-to-ground-to-phase fault occurs that is not limited by the neutral
grounding resistor (see Figure 8-4b). The second fault may be an arcing fault, whose magnitude
is limited by the ground-path impedance to a value high enough to cause severe arcing damage,
but too low to activate the overcurrent devices quickly enough to prevent or limit this damage.
For this reason, systems of 13.8 kV and higher generate too much heat to justify a delay in trip-
ping. Two-level relays are available that alarm on first (or low) fault, but trip on second (or
high) fault in time to prevent arcing burndowns. One final consideration for resistance-
grounded systems is the necessity to apply overcurrent devices based on their single-pole
Figure 8-4a—High-resistance grounding (may use ground relays to
alarm on first fault, trip on second fault)
Figure 8-4b—High-resistance grounding with phase-to-ground-to-phase
fault

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short-circuit interrupting rating, which can be equal to, or in some cases less than, their nor-
mal rating (see IEEE Std 141-1993).
8.2.5 Ungrounded systems
Ungrounded low-voltage systems (see Figure 8-5a and Figure 8-5b) employ ground detectors
(e.g., lamps or voltmeters connected from each phase to ground) to indicate a ground fault.
These detectors show the existence of a ground on the system and identify the faulted phase,
but do not locate the ground, which could be anywhere on the entire system. The system
operates with the ground fault acting as the system ground point. The ground-fault current
that ﬂows is the capacitive charging current of the system, generally only a few amperes.
If this ground fault is intermittent or allowed to continue, the system could be subjected to
possible severe overvoltages to ground, which can be as high as six or eight times phase
Figure 8-5a—Ungrounded system (uses bus ground detector to alarm and
has potential for possible overvoltage problem)
Figure 8-5b—Ungrounded system with phase-to-ground-to phase fault

IEEE
voltage. Such overvoltages can puncture insulation and result in additional ground faults.
These overvoltages are caused by repetitive charging of the system capacitance or by
resonance between the system capacitance and the inductances of equipment in the system.
A second ground fault occurring before the first fault is cleared results in a
phase-to-ground-to-phase fault, usually arcing, with current magnitude large enough to do
damage, but sometimes too small to activate the overcurrent devices in time to prevent or
minimize damage.
Ungrounded systems offer no advantage over high-resistance-grounded systems in terms of
continuity of service and have the disadvantages of transient overvoltages, difficulty in locat-
ing the first ground fault, and burndowns from a second ground fault. For these reasons, they
are being used less frequently today than high-resistance-grounded systems, and existing
ungrounded systems are often converted to high-resistance-grounded systems by
resistance-grounding the neutral if it exists or, if the system is fed from a delta source, by cre-
ating a neutral point with a zigzag or other transformer and then resistance-grounding it.
Once the system is high-resistance-grounded, overvoltages are reduced; and modern, highly
sensitive ground-fault protective equipment can identify the faulted feeder on first fault and
open one or both feeders on second fault before an arcing burndown does serious damage.
One final consideration for ungrounded systems is the necessity to apply overcurrent devices
based upon their single-pole short-circuit interrupting rating, which can be equal to, or in
some cases less than, their normal rating (see IEEE Std 141-1993).
8.3 Nature, magnitudes, and damage of ground faults
Ground faults on electric systems can originate in many ways, have a wide range of magni-
tudes, and cause varying amounts of damage. The most serious faults from the standpoint of
rate of eroded material are arcing faults, both phase to phase and phase to ground.
8.3.1 Origin of ground faults
Ground faults originating from insulation breakdown can be classified, roughly, as follows:
a) Reduced insulation (e.g., due to moisture, atmospheric contamination, foreign
objects, insulation deterioration)
b) Physical damage to insulation system (e.g., due to mechanical stresses, insulation
punctures)
c) Excessive transient or steady-state voltage stresses on insulation
Good installation and maintenance practices ensuring adequate connections and the integrity
of the insulation of the equipment have a significant effect in reducing the probability of
ground faults. However, insulation breakdowns to ground can occur at any point in the sys-
tem where phase conductors are in close proximity to a grounded reference. The contact
between the phase conductor and ground is usually not a firm metallic contact, but rather usu-
ally includes an arcing path in air or across an insulating surface, or a combination of both. In

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addition to these arcing ground faults, certain bolted faults occur, usually during installation
or maintenance, when an inadvertent ﬁrm metallic connection is made from phase to ground.
8.3.2 Magnitude of ground-fault currents
Ground-fault current magnitudes can vary greatly. Using the method of symmetrical compo-
nents (see Chapter 2), the single line-to-ground fault current IGF is calculated by the formula:
where
Z1 is the positive-sequence impedance,
Z2 is the negative-sequence impedance,
Z0 is the zero-sequence impedance.
ZG is the combined impedance of the ground return circuit, including the fault arc
impedance, the grounding circuit impedance, and the intentional neutral impedance,
when present.
To illustrate how ground-fault currents can vary greatly in magnitude, consider a solidly
grounded system with a bolted ground fault close to the generator terminals. In this example,
ZG could approach zero; and, assuming Z1 = Z2 = Z0, then,
which is actually the formula for a bolted three-phase fault. In fact, with many generators,
because Z0 is smaller than Z1, it is necessary to add an intentional neutral impedance ZN to
reduce the bolted ground-fault current to the magnitude of the bolted three-phase fault
current.
For a ground fault in a high-resistance-grounded system, the neutral resistance RN is large
compared to Z1, Z2, Z0, and the remainder of ZG. Then, IGF is approximately equal to VL–N
divided by RN.
For example, in a high-resistance-grounded 480 V system with a neutral resistance of 20 Ω,
the ground-fault current is
This approximation is true because the fault arc impedances and the ground-circuit imped-
ances are negligible when compared to 20 Ω.
IGF
3VL N
–
Z1 Z2 Z0 3ZG
+ + +
----------------------------------------------
-
=
IGF
VL N
–
Z1
-------------
-
=
IGF
480 3
⁄
20
-------------------
- 14 A
= =

IEEE
Precise calculation of low-voltage ground-fault current magnitudes in solidly grounded
systems is much more difficult than the previous example. The reason is that the circuit
impedances, including the fault arc impedance, that were negligible in the high-resistance
example play an important part in reducing ground-fault current magnitudes. This applies
even in most cases where a sizable grounding conductor is carried along with phase
conductors.
The primary consideration in applying ground-fault protection is whether a selectively coor-
dinated system can be achieved and, if not, to establish the extent to which lack of selectivity
is acceptable.
The two main setting characteristics that need to be determined for ground-fault relays are
— Minimum operating current
— Speed of operation
Selection of the minimum operating current (or pickup) setting is based primarily on the
characteristics of the circuit being protected. If the circuit serves an individual load (e.g., a
motor, transformer, heater circuit), then the pickup setting can be low, such as 5 A to 10 A. If
the protected circuit feeds multiple loads, each with individual overcurrent protection [e.g., a
panelboard, feeder duct, motor control center (MCC)], the pickup settings are higher. These
higher settings (in the order of 200 A to 1200 A) are selected to allow the branch phase-
overcurrent devices to clear low-magnitude ground faults in their respective circuits, if
coordination is possible. Furthermore, low-level faults in some parts of the system may be
self-extinguishing and, therefore, allow uninterrupted operation of other equipment.
8.3.3 Damage due to arcing faults
The arcing fault causes a large amount of energy to be released in the arcing area. The ionized
products of the arc spread rapidly. Vaporization at both arc terminals occurs, and the erosion
at the electrodes is concentrated when the arc does not travel. While the arc tends to travel
away from the source, this movement does not necessarily occur at low levels of fault current
or at higher levels of current in circuits with insulated conductors. If an arcing fault is allowed
to persist indefinitely, it is a potential fire hazard, causes considerable damage, may result in a
more extended power outage, and subjects nearby employees to burns from arc flash.
Shunt trip fusible switches can be equipped with antisingle-phasing provisions that consist of
installing small actuator fuses in parallel with the line fuses in the switch. When a line fuse
opens, these fuses also open and subsequently close a contact to actuate a signal or
switch-opening circuit to open all three poles of the switch. Figure 8-6 shows this particular
scheme, which can also be used in conjunction with ground-fault protective relaying. Other
equipment utilizes voltage relays in place of the actuator fuses to trip interrupter switches.
These antisingle-phasing devices are often specified to clear a ground fault that may cause
only one fuse to open. If the fault remains and is of such high impedance that it does not open
any fuses in any other phases, the opening of the first fuse causes all three poles of the switch
to open and the fault is cleared.

IEEE
Fused circuit breakers and service protectors, as well as circuit breakers, have antisingle-
phasing devices incorporated in their basic designs.
The basic need for ground-fault protection in low-voltage grounded systems is illustrated in
Figure 8-7a and Figure 8-7b. A 1000 kVA transformer, with a 1600 A main circuit breaker
and typical long-time and short-time characteristics, optionally with a fused switch, is
shown.
A 1500 A ground fault (Point I) on the 480Y/277 V grounded neutral system would not be
detected by the main circuit breaker or fuse. A ground relay set at 0.2 s time delay would
cause the circuit breaker or bolted pressure switch to clear the fault in about 0.33 s. A 4000 A
ground fault (Point II) could persist for about 33 s, even if the circuit breaker’s minimum
long-time band were used. The fuse would require up to 5 min to clear this fault. The ground-
relayed circuit breaker or bolted pressure switch would clear the fault in about 0.25 s. An
8000 A ground fault (Point III) would be cleared within about 0.2 s to 0.4 s by the circuit
breaker short-time device, assuming it is present; otherwise, between 8 s to 20 s would elapse
before the long-time device clears the fault.
Arc energies for these assumed faults are tabulated in Table 8-1. Arc voltages are assumed to
be 100 V. Because the arc voltage tends to have a ﬂat top characteristic (nonlinear arc resis-
tance), the energy of the arc in watts per second can be estimated by obtaining the product of
the current in rms amperes, the arc voltage in volts, and the clearing time in seconds. Approx-
imate calculation of the energy required to erode a certain amount of electrode material
shows that 50 kWs of energy divided equally between conductor and enclosure vaporizes
about 2.05 cm3 of aluminum or 0.82 cm3 of copper. The calculation assumes that most of the
arc energy goes into the electrodes, while the energy lost to the surrounding air is neglected.
Comparisons were made from several arcing fault tests (see Conrad and Dalasta [B10];
Fisher [B14]), and good correlation was obtained between calculated energy from test data
and measured conductor material eroded.
Figure 8-6—Antisingle-phasing provisions for fusible switches

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Figure 8-7a—Time-current plot showing slow protection provided by phase
devices for low-magnitude arcing ground faults

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Figure 8-7b—Assumed tolerable damage levels

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For the assumed 8000 A fault, even though the current values are the calculated result using
all source, circuit, and arc impedances, the actual rms current values passing through the
circuit breaker can be considerably lower. The reason is the spasmodic nature of the fault
caused by
— Arc-elongating blowouts effects
— Physical ﬂexing of cables and some bus structures due to mechanical stresses
— Self-clearing attempts and arc reignition
— Shifting of the arc terminals from point to point on the grounded enclosures (and on
the faulted conductors for noninsulated construction)
All of these effects tend to reduce the rms value of arcing fault currents. Therefore, a ground
fault that would normally produce 8000 A under stabilized conditions might well result in an
effective value of only 4000 A and would have the arc energies associated with Point II in
Table 8-1.
Expressing acceptable damage in terms of kWs, or kW cycle units, with an assumption of
100 V arc drop in 480Y/277 V circuits has been proposed.
Investigations show that damage in standard switchboards at normal arc lengths is propor-
tional to time and 1.5 power of ground-fault current magnitude (see Stanback [B42]). Thus,
the arc voltage magnitude question at varying and unpredictable fault currents may be
excluded and damage prediction simpliﬁed.
Table 8-1—Arc energies for assumed faults of Figure 8-7a
Figure 8-7a
points
Fault
(A, rms)
Main device
Clearing time
(s)
Arc energy
(kWs)
I 1500 Relay
Circuit breaker
Fuse
0.33
∞
∞
50
∞
∞
II 4000 Relay
Circuit breaker
Fuse
0.25
33.00
300.00
100
13 200
120 000
III 8000 Relay
Circuit breaker
Fuse
0.25
0.4
10.00
200
320
8000
IV 20 000 Relay
Circuit breaker
Fuse
0.25
0.20
0.01
500
400
20

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According to the study, speciﬁc damage or burning rate
with
ks is 1.18 × 10–5 cm3/A1.5s for copper,
ks is 2.49 × 10–5
cm3
/A1.5
s for aluminum,
ks is 1.08 × 10–5
cm3
/A1.5
s for steel.
Because selection of conductors is often based on nearly uniform current densities (e.g., 125–
155 A/cm2
), acceptable damage could then be based on conductor or disconnect ratings or on
cross-sectional area.
Thus, if based on
IF
1.5
t = keIR
where
IF is fault current,
IR is disconnect or bus rating,
the acceptable damage VD = kskeIR can be used as a constant for a given system and discon-
nect rating. Acceptable damage could then be held by appropriate selection of current and
time settings for ground-fault protective devices.
For example, if IR = 1000 A and ke = 250 [A0.5
s] (as assumed in NEMA PB 2.2-1999)
acceptable damage,
I1.5
t = 250 × 1000 = .025 × 10+6
[A1.5
s], or
VD = 1.18 × 10–5 × 0.25 × 106 = 2.95 cm3 for copper,
conductors are not exceeded for faults between 800 A and 10 000 A, with relay settings as
shown in Figure 8-7b if clearing time of the circuit breaker or bolted pressure switch does not
exceed 200 ms.
The above computations are based on 277 V single-phase test results and the assumption that
the damage would be proportional to the arcing fault current. Therefore, some discretion
should be used when referencing the example in Figure 8-7b (see Love [B32]).
ks
damaged volume VD
current
1.5
time
×
-------------------------------------------------
- in
3
A
1.5
s
⁄
[ ]
=

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8.3.4 Selection of low-voltage protective device settings
Maximum protection against ground faults can be obtained by applying ground protection on
every feeder circuit from source to load. The minimum operating current for all series devices
may be set at about the same pickup setting, but the time curves are selected so that each cir-
cuit protective device is opened progressively faster, moving from the source to the load. The
load switching device can be opened instantaneously or with brief delay upon occurrence of a
ground fault.
The delay required between devices is determined by the addition of
— The trip-operating time of the overcurrent device
— The clearing time of the overcurrent device
— A margin of safety
The trip-operating time of today’s molded-case circuit breakers (MCCBs), service protectors,
power circuit breakers, or shunt-tripped switches is usually about 3 cycles. Current-limiting
fuses clear in about .004 s when operating in their current-limiting range.
This coordination by time delay is similar to other overcurrent coordination. However,
another method of coordination, called zone selective interlocking (ZSI), is available for
ground-fault protection using solid-state relays and electronic trip devices. Ground faults, for
minimum damage, should be cleared as quickly as possible regardless of their magnitude.
Zone coordination assures instantaneous tripping of all ground-fault relays for faults within
their zone of protection, with upstream devices restrained to a time delay in response to
ground faults outside their zone. This restraining signal requires as few as one pair of wires
from the downstream zone to the upstream relay to carry the interlocking signal. ZSI provides
the fastest tripping, for minimum damage, with full coordination so that only the affected part
of the system is shut down on ground fault. ZSI is discussed further in 8.5.4.1.
Bolted-pressure and high-pressure contact fused switches using the ground-fault protection
schemes can be shunt tripped to open quickly.
From the standpoint of damage alone, speed of clearing is paramount. However, in some
situations, delay is desirable, primarily to obtain coordination between main and feeder
circuits and branch currents. Consider a typical 480Y/277 V application consisting of a
3000 A main, an 800 A feeder, and a 100 A branch circuits. If the branch circuits do not have
ground-fault protection, then the feeder ground-fault protection should be set with a time
delay to allow the branch circuit phase-overcurrent device to clear moderately
high-magnitude ground-fault currents without opening the feeder through its ground-fault
protection. When full coordination is essential, setting the feeder ground-fault pickup above
and to the right of the branch circuit devices is desirable. While infrequent loss of
coordination may be acceptable between feeders and branch circuits, full coordination should
be maintained between main and feeder overcurrent protective devices. Setting main service
ground-fault protection at less than 0.1 s (or 6 cycle) response time is generally not
recommended. Proper settings reduce effects of inrush, startups, and switching currents and
prevent nuisance openings.

IEEE
Another reason for delayed clearing of ground faults on main or large feeder circuits is the
threat of circuit interruption where the power outage itself is of greater consequence than the
incremental difference in fault damage.
In summary, the sensitivity (or minimum operating current setting) of ground-fault protection
in solidly grounded low-voltage systems is determined by the following considerations:
a) When the ground-fault protection is used on devices protecting individual loads, such
as motors, the lowest available settings can be used, providing the devices do not
cause false opening from inrush currents.
b) For the main and feeder circuits, the setting for ground-fault protective devices is
normally in the range of 10% to 100% of the circuit trip rating or fuse rating. If
downstream devices do not have ground-fault protection, then the circuit ground-fault
protection may have to be set higher than the downstream phase-protective device
opening characteristics to ensure full coordination. Many times, the main ground-
fault protection needs to be set at the code maximum of 1200 A in order to selectively
coordinate with the downstream phase- and ground-fault protection.
8.3.5 Sensing, relaying, and trip devices
The signal for ground-fault protective devices may be derived from the residual of phase CTs,
window CTs, or sensors. The CTs or sensors provide isolation between main busses and
relaying equipment and should be located in a speciﬁc path to detect proper ground-fault cur-
rents under all operating conditions.
Sensors are often designed with other than 5 A or 1 A nominal secondary rating and for use
with speciﬁc relays or trip devices as a system. If part of such a system, the relays normally
have dials marked in terms of primary ground-fault current amperes.
Ground-fault relays or trip devices may be either self-powered (i.e., fault current) or exter-
nally powered (i.e., operation or trip power), or incorporate both methods. Outputs may be
contact or solid-state (e.g., thyristors).
AC control power, derived from an auxiliary transformer of proper capacity, is frequently
used in systems of 600 V and below and is sometimes supplemented by capacitor trips. The
primaries of control power transformers should be connected line to line to reduce effects of
voltage dips during ground faults, and the trip device should be capable of operating at 0.866
times rated voltage. The need for overcurrent protection and transfer to an alternate control
power source should be evaluated.
Supplementary or backup ground-fault protection may be accomplished by monitoring the
equipment environment. Such systems detect ionized gases and other fault-current
by-products, such as abnormal light and heat. By early detection of one or more of the
by-products of a ground-fault current and prompt opening of the interrupting device serving
the fault, the magnitude of the damage may be reduced. Supplementary sensing is
particularly desirable when the primary means of ground-fault sensing is set relatively high to
prevent nuisance opening or to satisfy coordination requirements. To maximize the

IEEE
effectiveness of environmental detectors, care should be exercised in the selection, proper
installation within the equipment enclosure, and setting of the detectors (see Neuhoff [B34]).
8.4 Frequently used ground-fault protective schemes
While ground-fault protective schemes may be elaborately developed, depending on the inge-
nuity of the relaying engineer, nearly all schemes in common practice are based on one or
more of the following methods of ground-fault detection:
— Residually connected overcurrent relays
— Core balance sensing of feeder conductors
— Detection of ground-return current in the equipment grounding circuit
— Differential relaying
8.4.1 Residual connection
A residually connected ground relay is widely used to protect medium-voltage systems. The
actual ground current is measured by CTs that are interconnected in such a way that the
ground relay responds to a current proportional to the ground-fault current. This scheme,
using individual relays and CTs, is not often applied to low-voltage systems. However, low-
voltage systems are available with three CTs built into them and connected residually with
the solid-state trip devices to provide ground-fault protection.
The term residual in common usage is normally reserved for three-phase system connections
and seldom applied to single-phase or multiple-signal mixing.
The basic residual scheme is shown in Figure 8-8. Each phase relay is connected in the output
circuit of its respective CT, while a ground relay connected in the common or residual circuit
measures the ground-fault current. In three-phase three-wire systems, no current flows in the
residual leg under normal conditions because the resultant current of the three CTs is zero.
This situation is true for phase-to-phase short circuits also. When a ground-fault occurs, the
short-circuit current, returning through earth, bypasses the phase conductors and their CTs,
and the resultant current flows in the residual leg and operates its relay.
On four-wire circuits, a fourth CT should be connected in the neutral circuit as shown in the
dashed portion of the current. The neutral conductor carries both 60 Hz single-phase load
unbalance current as well as zero-sequence harmonic currents caused by the nonlinear induc-
tance of single-phase loads, such as fluorescent lighting. Without the neutral-conductor CT,
the current in that conductor would appear to the ground relay as ground-fault current, and
the ground relay would have to be desensitized sufficiently to prevent opening under unbal-
anced load conditions.
The selectivity of residually connected relays is determined by the CT ratio and the relay
pickup setting. The CT ratio must be high enough for normal load circuits. Also to be consid-
ered are the unbalanced primary currents in each phase, the sum of which may contain suffi-
cient asymmetrical current to cause a trip during a motor start. For this reason, sensitive

IEEE
ground-fault protection schemes do not use instantaneous trips when a residually connected
circuit is involved. If ground-fault protection with greater sensitivity is needed, the core-bal-
ance method should be considered (see 8.4.2).
8.4.2 Core balance
The core-balance method is based on primary current phasor addition or flux summation. The
remaining zero-sequence component, if any, is then transformed to the secondary. The
core-balance CT or sensor is the basis of several low-voltage ground-fault protective systems.
(The core-balance CT is frequently called a zero-sequence sensor or window CT, but the term
core balance is preferable because it more specifically describes the function of the CT.) The
principle of the core-balance CT circuit is shown in Figure 8-9a. All load-carrying conductors
pass through the same opening in the CT and are surrounded by the same magnetic core.
Core-balance CTs are available in several convenient shapes and sizes, including rectangular
designs for use over bus bars. This method can be more sensitive than the residual method
because the sensor rating is large enough for the possible imbalance, not for the individual
conductor load current.
Under normal conditions [i.e., balanced, unbalanced, or single-phase load currents or short
circuits not involving ground (if all conductors are properly enclosed)], all current flows out
and returns through the CT. The net flux produced in the CT core is zero, and no current flows
in the ground relay. When a ground fault occurs, the ground-fault current returns through the
equipment grounding circuit conductor (and possibly other ground paths) and bypasses the
CT. The flux produced in the CT core is proportional to the ground-fault current, and a pro-
portional current flows from the CT secondary to the relay circuit. Relays connected to
core-balance CTs can be made quite sensitive. However, care is necessary to prevent false
opening from unbalanced inrush currents that may saturate the CT core or through faults not
Figure 8-8—Residually connected ground relay

IEEE
involving ground. If only phase conductors are enclosed and neutral current is not zero, the
transformed current is proportional to the load zero-sequence or neutral current. Systems
with grounded conductors, such as cable shielding, should have the CT surround only the
phase and neutral conductors, if applicable, and not the grounded conductor.
By properly matching the CT and relay, ground-fault detection can be made as sensitive as
the application requires. The speed of the relay limits damage and may be adjustable (for cur-
rent or time, or both) in order to obtain selectivity. Many ground protective systems now have
solid-state relays specially designed to operate with core-balance CTs. The relays in turn
open the circuit protective device. Power circuit breakers, MCCBs with shunt trips, or electri-
cally operated fused switches can be used. The last category includes service protectors,
which use circuit breaker contacts and mechanisms, but depend on current-limiting fuses to
interrupt the high available short-circuit currents. Fused contactors and combination motor
starters may be used where the device-interrupting capability equals or exceeds the available
ground-fault current.
Figure 8-9b shows a typical termination of a medium-voltage shielded cable. After the cable
is pulled up through the core-balance CT, the cable jacket is removed to expose the shielding
tape or braid. Jumpering the shields together, the connection to the ground is made after this
shield lead is brought back through the CT. This precaution would have been necessary only
if the shield had been pulled through the CT.
Between multiple shield ground connections on a single conductor cable, a potential exists
that drives a circulating current, often of such a magnitude as to require derating of the cable
ampacity. When applying the core-balance CT, the effects of this circulating current should
be subtracted from the measuring circuit.
Figure 8-9a—Core-balance CT encircling all phase and neutral conductors

IEEE
8.4.3 Ground return
Ground-return relaying is illustrated in Figure 8-10. The ground-fault current returns through
the CT in the neutral-bus to ground-bus connection. For feeder circuits, an insulating segment
may be introduced in busway or conduit, as shown in Figure 8-10, and a bonding jumper con-
nected across the insulator to carry the ground-fault current. A CT enclosing this jumper then
detects a ground fault. This method is not recommended for feeder circuits due to the likeli-
hood of multiple ground-current return paths and the difﬁculty of maintaining an insulated
joint.
8.4.4 Ground differential
A generic term, ground differential is used for a variety of schemes that utilize phasor or alge-
braic subtraction or addition of signals. The currents may be produced by any of the methods
discussed in 8.4.1 through 8.4.3.
Figure 8-11a, for example, shows a ground differential protection for single-phase
center-tapped loads and is similar to the residual method.
Figure 8-9b—Physical installation of a core-balanced CT for shielded cable
termination

IEEE
One core-balance sensor could detect ground faults in a plurality of loads (see Figure 8-11b).
Ground-differential relaying is effective for main bus protection because it has inherent
selectivity. With the differential scheme (see Figure 8-11c), core-balance CTs are installed on
each of the outgoing feeders and another lower ratio CT is placed in the transformer neutral
Figure 8-10—Ground-return relay scheme
Figure 8-11a—Differential protection center-tapped loads

IEEE
connection to ground. This arrangement can be made sensitive to low ground-fault currents
without false opening for ground faults beyond the feeder CTs. All CTs should be carefully
matched to prevent improper opening for high-magnitude faults occurring outside the
differential zone.
Bus-differential protection protects only the zone between CTs and does not provide backup
protection for feeder faults.
8.4.5 Circuit sensitivity
Factors that affect the sensitivity of ground-fault sensing include the following:
a) Circuit-charging current drawn by surge arrestors, shielded cables, and motor
windings
b) The number of coordination steps between the branch circuit and the supply
Figure 8-11b—Differential protection multiple loads
Figure 8-11c—Ground-differential scheme bus and transformer

IEEE
c) Primary rating and accuracy of the largest CT used to supply residually connected
relays in the coordination
d) How well the CTs used for residually connected relays are matched
e) Burden on the CTs, in particular the burden of the residually connected relay
(Solid-state and some induction disk relays have burdens of 40 VA for a 0.1 A tap.)
f) Maximum through-fault current and its effect upon the CTs, with selected relays for
phase and residual connections
g) Fault contact resistance
h) Location of conductors within core-balance transformers
8.5 Typical applications
The application of ground-fault protection to typical low-voltage power distribution systems
is illustrated by the following ﬁgures:
These one-line diagrams show the locations for the ground-fault sensing devices as well as
the locations for the protective devices. Additional considerations in the application of
ground-fault protection are as follows:
a) A common economy in system design is to use the simple radial system without
transformer secondary main overcurrent protective devices. This design results in a
particular hazard when low-magnitude ground faults develop between the trans-
former secondary and the feeder overcurrent protective device.
b) Even with a secondary main overcurrent protective device, the zone from the trans-
former secondary to the main overcurrent protective device is not protected unless the
System Figure
Protection on mains only 8-12
Protection on mains and feeders 8-13
Protection on mains only, fused system 8-14
Ground-fault coordination 8-15a through 8-15d
Ground-fault system with alternate supply 8-16
Three-wire solid ground, single supply 8-17
Three-wire solid ground, dual supply 8-18
Three-wire solid ground, secondary selective 8-19
Three-wire high-resistance ground 8-20
Three-wire low-resistance ground 8-21
Four-wire solid ground, single supply 8-22
Four-wire solid ground, dual supply 8-23
Four-wire solid ground, secondary selective 8-24

IEEE
ground-fault sensing device detects the fault and trips both the secondary main and
the transformer primary circuit protective device.
c) The use of sensitive ground-fault protection makes the coordination of protective
devices extremely important. The ﬁrst consideration is where to apply the
ground-fault protection.
In considering the application of ground-fault protection, several alternatives exist, and each
application varies in cost. This discussion considers two basic approaches:
— Ground-fault protection on the mains only
— Ground-fault protection on mains and feeders
8.5.1 Ground-fault protection on mains only
An example of ground-fault protection on mains only is shown in Figure 8-12. The 3000 A
main has long-time and short-time trip devices, a 1200 A feeder with long-time and instanta-
neous trip devices, and an MCCB in a branch circuit with thermal and instantaneous trip
devices. The ground-fault protection on the main coordinates with both instantaneous trip
devices if given a time delay of about 0.2 s with a relatively ﬂat characteristic.
The problem of where to set the minimum ground pickup arises. For full coordination with
all feeders, the setting would have to be above 6000 A (above the instantaneous setting of the
largest feeder). Obviously, this setting is too high and violates code requirements. For
excellent protection of circuit ground faults, the pickup setting should be about 200 A. This
setting, however, produces loss of coordination for ground faults at Point A of magnitude
between 200 A and 1000 A and loss of coordination for faults at Point B of magnitude
between 200 A and 6000 A. Thus, while the 200 A setting on the main provides excellent
arcing fault protection, the main circuit breaker can be expected to trip for certain feeder
faults where, before choosing this setting, such faults were handled by the feeder or branch
circuit breakers. In short, a substantial degree of coordination would be lost. In a few
applications, this loss of coordination can be tolerated.
Under the circumstances, the best setting is approximately a 1200 A minimum pickup. With
such a setting, a system would have protection against the most severe arcing faults and
would lose coordination only on ground-faults between 1200 A and 6000 A. The scheme
described in this subclause is fairly common, but it is still clearly a compromise.
8.5.2 Ground-fault protection on mains and feeders
An example of ground-fault protection on mains and feeders is shown by Figure 8-13. In this
situation, ground-fault protection is included on the 3000 A main and also on all feeders
above roughly 400 A to 800 A. This application shows a 200 A minimum pickup with a time
delay of 0.1 s on each feeder in addition to a 400 A minimum pickup and a 0.3 s time delay
on the main. Ground-fault protection on the main only is clearly not recommended, as
destructive faults can develop without detection.

IEEE
In this example, the main circuit breaker is fully coordinated with each feeder circuit breaker.
Also, both main and feeders have sufﬁciently low settings to provide reasonable arcing fault
protection. Coordination is lost between the feeder and branch devices for ground faults at
Point A between 200 A and 1000 A and for all faults greater than 4000 A. Better protection
can be obtained using zone selective interlocking (ZSI), with less damage occurring because
of instantaneous tripping in the faulted zone.
8.5.3 Ground-fault protection on mains only in fused systems
Figure 8-14 shows a situation similar to the situation of Figure 8-12, involving a fused system
with 1200 A ground pickup. This setting coordinates with the 200 A fuses and branch circuit
lighting circuit breakers. However, coordination of the 1200 A pickup with the 800 A feeder
fuses is sacriﬁced from magnitudes of 1200 A through 8000 A.
Figure 8-12—Ground relays on main circuit only

IEEE
8.5.4 Ground-fault coordination
A variety of means exist for coordinating ground-fault protection.
8.5.4.1 Zone selective interlocking (ZSI)
One approach to ground-fault coordination is ZSI, which not only allows operation at the
minimum desirable time for units in every zone when they are responding to ground faults in
their own zone, but also establishes positive coordination between mains, feeders, and
branches so that the smallest possible segment of the system is opened in the event of a
ground fault.
Figure 8-13—Ground relays on both main and feeder circuits

IEEE
Figure 8-15a shows a typical coordination arrangement. Relay 3 restrains in a time-delay
mode Relay 2, which in turn restrains Relay 1. For example, with a fault of 1500 A at
Location 3, Relay 3 initiates a signal in 0.03 s, the minimum delay, to the branch device to
open the circuit. At the time of the fault, Relay 3 also sends a restraining signal to Relay 2,
Figure 8-14—Fused system using ground-fault relays on main circuit only,
showing coordination with 200 A fuses and lack of coordination with
800 A feeder fuses

IEEE
which in turns sends a restraining signal to Relay 1. As a result, these two relays start timing
the duration of the fault. Relay 2 initiates a signal to the feeder device only if the branch
device fails to open the circuit 0.2 s after the ground fault occurred. Relay 1 initiates a signal
to the main device only if the branch device and feeder device fail to open the circuit 0.5 s
after the ground fault occurred. If a 1500 A ground fault occurs at Location 2, Relay 2
initiates a signal in 0.03 s to the feeder device to open the circuit. At the time of the fault,
Relay 2 also sends a restraining signal to Relay 1. Relay 1 initiates a signal to the main device
only if the feeder device fails to open the circuit 0.5 s after the ground fault occurred. If a
1500 A ground fault occurs at Location 1, Relay 1 initiates a signal in 0.03 s to the main
device to open the circuit. This type of system coordination allows the circuit-interrupting
devices nearest to the ground fault to receive an operation signal instantaneously (i.e., 0.03 s)
and provide time delay in only the backup devices. Clearing time of the circuit-interrupting
device should also be considered in complete system coordination. Where MCCBs and
insulated-case circuit breakers (ICCBs) are utilized, the time-current curves should include
their instantaneous overrides. These overrides operate at higher levels of fault current and
may create zones of nonselective coordination.
This system requires at least a pair of control wires between relays of each successive coordi-
nation step. The control leads add exposure to possible faults on these control leads. This
exposure should be considered when ZSI schemes are applied.
8.5.4.2 Coordinations of ground-fault protection schemes
Another approach to a coordinated ground-fault protection scheme is based upon protection
against low-level arcing faults in which the arc has seriously reduced the fault current.
Backup protection utilizes a standard time-overcurrent relay. This scheme is illustrated by
Curve B1 and Curve B2 in Figure 8-15b and Figure 8-15c, where the low level protection
scope is compared against two common ground-fault protection schemes.
Curve C1 and Curve C2 represent the tripping characteristics of a ﬁxed-delay solid-state
ground-fault relay. Curve A1 and Curve A2 represent a special electromechanical ground-
fault relay. Both types are set with a minimum pickup of 1200 A. Curve B1 and Curve B2
represent the tripping characteristics of a standard electromechanical overcurrent relay with
very inverse tripping characteristics, but set to operate on a minimum pickup of 72 A.
Scheme A and Scheme C relays are not sensitive to low ground-fault currents, do not initiate
nuisance trips, but back up phase-overcurrent protection in the range of 1000 A to 20 000 A.
However, they may not necessarily provide real protection service.
Numerous groups have studied the arcing nature of 480 V ground faults. Often a 90 V to
140 V arc has been measured: such an arc limits the ground-fault current magnitude. Some
articles have equated arcing fault damage to 1800 kW cycle, 2000 kW cycle, or even
10 000 kW cycle energy limits.
The 1800 kW cycle and 10 000 kW cycle curves shown in Figure 8-15b and Figure 8-15c are
based upon a 100 V arc and an arcing current of essentially resistive characteristics.

IEEE
Figure 8-15a—Typical zone selective intelocking (ZSI) system

IEEE
Fault energy =
Fault energy = 60t kW cycles
where
Varc is 100 arc (V),
t is time (s),
IF is ground-fault current.
Figure 8-15b—Minimum ground-fault protection for a nonmotor circuit
Varc IF
× time
×
100 IF
( )
1000
------------------
-

IEEE
If fault energy = 1800 kW cycles = 6 (IF × t) kW cycles, then
Figure 8-15c—Minimum ground-fault protection for a motor circuit
IF t
×
1800
6
-----------
- 300
= =

IEEE
Example
IF = 100 A, t = 3 s
IF = 1000 A, t = 0.3 s
IF = 10 000 A, t = 0.03 s
Plotted on a log-log scale, the locus of the boundary points is a straight line, which makes an
ideal criteria for coordinating with a very inverse or extremely inverse ground-fault relay. The
calculations for the 10 000 kW cycle damage limit were developed on the same basis.
Referring again to Figure 8-15b and Figure 8-15c, it can be seen that Scheme A and
Scheme C permit low (<1000 A) ground-fault currents, whereas Scheme B limits the damage
for arcing ground faults in both the motor and the nonmotor circuit. However, Scheme B
loses coordination below 1000 A unless a ground-fault relay is on the MCC branch circuits
above 30 A and on motor branch circuits above 11 kW, as illustrated in Figure 8-15d.
8.5.5 Ground-fault protection of systems with an alternate power source
Following usual considerations of reliability or redundancy, it may be advantageous to
ground the neutral terminal of an alternate power source, such as a second utility source (or
service) or an engine-generator set, at its location. However, this configuration may create
multiple neutral-to-ground connections, which in turn may cause problems unless appropri-
ate steps are taken.
For example, consider a typical three-phase, four-wire 480 V emergency power system in
which a three-pole transfer switch connects the load to either a normal utility source or an
engine-generator set. Ground-fault protection is provided at the utility incoming service. The
neutral conductors of both the utility incoming service and the engine-generator set are sepa-
rately grounded and interconnected (i.e., continuous neutral).
Because of the multiple neutral-to-ground connections, two problems can develop. First,
when a ground fault occurs anywhere in the system, the fault current has two paths of flow:
one directly to the grounded neutral of the utility incoming service via equipment-grounding
conductors and one to the grounded neutral of the engine-generator set via equipment-
grounding conductors. In both cases, the current would then return to the neutral of the utility
incoming service via the continuous neutral. Current following the latter path is seen as neu-
tral current, and it reduces or eliminates the magnitude of the ground-fault current sensed by
a relay.
Second, when the load is unbalanced, the return neutral current has two paths of flow: one
directly to the service neutral via the neutral conductor and one back to the service neutral via
the equipment-grounding conductors at both the utility incoming service and the engine-
generator set and through the continuous neutral. The current through the latter path would
have the same effect on the ground-fault sensor as a ground-fault current and is carried by
equipment-grounding conductors, which are not provided for this purpose. If the second path
has sufficiently low impedance (i.e., comparable to the impedance of the neutral path), an

IEEE
unbalanced load may cause the ground-fault sensor to trip the breaker even though a ground
fault or short circuit does not occur.
Various solutions include single-point grounding, four-pole transfer switches, overlapping
neutral contacts, and transformer isolation. In all cases, consideration should be given to both
modes of transfer switch operation, to providing adequate area protection and ground-fault
protection, and to conformance to the NEC.
a) Single-point grounding eliminates the problems identiﬁed in this subclause and per-
mits simple relaying methods. The basic scheme is shown in Figure 8-24 and can be
used for multiple services or in utility service-generator source systems with a con-
tinuous neutral.
51
G2
51
G2
51
G1
51
G2
IAC77
84 A
TD 10
1000
100
10
1.0
0.1
.01
TIME
IN
SECONDS
100 1000 10 000
10 000
kW-CY
1800
kW-CY
CURRENT IN AMPERES
DAMAGE
CURVES
IAC53
IAC77
MCC
T O L
RELAY
ARC
FAULT
DAMAGE
CURVES
RANGE
OF
MCCB-IT
PICKUP
30 A
HFB
MCCB-IT
ONLY
ALT TIMES
GFR-1
GFR-2
IAC53
90 A, TO 10
Figure 8-15d—Ground-fault protection for an 11 kW motor load

IEEE
The method can be modified to detect not only phase-to-ground (e.g., enclosure)
faults (i.e., the most commonly occurring), but also phase-to-neutral failures in a sys-
tem. However, consideration should be given to the possibility of power disruption
within the facility and transferring the load to ungrounded emergency power source.
Also, a ground-fault condition when the transfer switch is in the emergency position
may cause nuisance tripping of the normal source breaker.
b) Using four-pole transfer switches throughout the system may allow complete isola-
tion of service and generator neutral conductors. This setup eliminates possible
improper ground-fault sensing and nuisance tripping caused by multiple neu-
tral-to-ground connections. When this configuration is set up, the generator complies
with the NEC definition of a separately derived system. However, momentary open-
ing of the neutral conductor may cause voltage surges. Furthermore, the contacts of
the fourth switch pole interrupt current and are, therefore, subject to arcing and con-
tact erosion. A good maintenance program should reaffirm at intervals the integrity of
the fourth pole as a current-carrying member with sufficiently low impedance.
c) A variation of the method of isolating the normal and emergency source neutrals is
for the automatic transfer switch to include overlapping neutral transfer contacts.
This setup provides the necessary isolation between neutrals and at the same time
minimizes abnormal switching voltages. With overlapping contacts, the only time the
neutrals of the normal and emergency power sources are connected is during transfer
and retransfer. With a conventional double-throw transfer switch, this duration can be
less than the operating time of the ground-fault sensor, which is usually set anywhere
from 6 cycles to 24 cycles (100—
400 ms). As with four-pole transfer switches,
conventional ground-fault sensing can be readily added to the emergency side.
Figure 8-16 shows isolation by overlapping contacts and ground-fault sensing on the
emergency side for actuating an alarm circuit rather than tripping a breaker. If
required, emergency source tripping on ground faults can also be provided.
Figure 8-16—Emergency power systems with ground-fault protection on
normal and ground-fault alarm on emergency

IEEE
d) Where a three-phase, four-wire critical load is relatively small compared to the rest of
the load, an isolating transformer is sometimes used. This setup requires both power
sources connected to the transfer switch to be three-phase and three-wire, and the
delta-wye isolating transformer to be inserted between the transfer switch and the
four-wire load. An unbalance of the critical load would have no effect on the
ground-fault protector at the incoming service. Furthermore, ground-fault currents
would not be transmitted through the delta-wye transformer. Any increase in primary
current due to ground-faults in the secondary is seen simply as an overload by the
primary protective devices. Circuits on the secondary side of the isolating trans-
former have the advantage of reduced available fault current, but may require their
own ground-fault protection if the transformer secondary is grounded. Because the
transfer switch is not located directly ahead of the load, it does not guarantee
emergency power supply in the event of isolating transformer failure.
8.5.6 Placement of ground fault sensors and relays
Figure 8-17 through Figure 8-24 illustrate the placement of ground fault sensors, relays, and
alarms for selective protection of main, tie, feeder, and branch circuits systems with varied
grounding arrangements. For increasingly selective systems, ground fault protective devices
should be added as shown to the tie, feeder, and, ﬁnally, branch circuits.

IEEE
NOTE—Ground relays should have time coordination.
Figure 8-17—Three-wire solidly grounded system with single supply

IEEE
8.6 Special applications
8.6.1 Ground-fault identiﬁcation and location
Ground faults in solidly grounded systems usually require the opening of disconnect devices
to reduce damage. Many relays and trip devices have targets or lamp indicators to identify
faulty circuits. The equipment and conductors should be inspected and repaired, if necessary,
prior to restoration of service.
The conventional method of ground-fault detection used on ungrounded wye or delta
three-wire systems utilizes three potential transformers supplying ground detector lamps,
ground-detecting voltmeters, or ground alarm relays. The presence of potential transformers
connected to ground from each phase may in itself be the cause of dangerous overvoltages
because the detector becomes the grounding mechanism, as well as being a detector.
Figure 8-18—Three-wire solidly grounded system with dual supply

IEEE
To reduce the probability of transient overvoltages, high-resistance grounding is often
applied, as described in detail in IEEE Std 142-1991. The basic reason to use high-resistance
grounding is to eliminate an opening operation when the ﬁrst ground fault occurs. Operation
with a ground fault on the system entails a substantial hazard, and locating the fault as soon
as system operation allows becomes important, especially before a second ground fault devel-
ops on a second phase and creates a line-to-line-to-ground fault.
In applying high-resistance grounding, the resistance of the ground circuit should be of a
magnitude to pass a ground current at least equal to the charging current of the system.
Figure 8-25 shows a typical high-resistance-grounded system with a neutral resistor and a
ground alarm relay. Most similar applications use a distribution transformer with a low-
voltage resistor connected to its 240 V secondary.
Each feeder is equipped with a low-ratio core-balance transformer and ammeter or milliamp
meter, which will indicate the faulted feeder. No automatic opening occurs with this scheme.
In lieu of CTs and ammeters on each feeder, a pulsing ground circuit may be used as shown
in Figure 8-26. The pulsing circuit is manually initiated and serves to reduce the resistance to
Figure 8-19—Three-wire solidly grounded secondary selective system

IEEE
about 50% to 75% of its full value, about once or twice a second. This change causes the
ground-fault current to vary sufﬁciently to be detected by a clamp-on ammeter, which can be
placed in turn around the conductors of each feeder circuit.
If a ground fault is not cleared immediately, a relatively dangerous condition may arise upon
the occurrence of a second fault. A second fault has a high probability of occurring because
— The steady-state voltage on the unfaulted phases has increased
— The initial fault may be intermittent and cause some transient overvoltages in spite of
the resistor grounding
Figure 8-27 shows how feeder ground relays are applied to open on the occurrence of the sec-
ond fault on a different feeder. The feeder ground relays are set to pick up at a value higher
than the maximum initial ground-fault current. For example, on a 4.16 kV system, a 300 W
resistor would limit the ground-fault current to 8 A. The ground alarm relay would be set to
pick up at 5 A or less. The feeder ground relays are set to pick up at a current level higher
than the level for a single line-to-ground fault, perhaps 10 A to 15 A.
Figure 8-20—Three-wire high-resistance-grounded system

IEEE
The use of low-voltage grounding resistors coupled with grounding (or standard distribution)
transformers is preferred by some engineers. Figure 8-28 shows how these transformers are
utilized for three-wire grounded wye systems and for three-wire grounded delta systems.
8.6.2 Spot network applications
Spot networks provide continuity of service against the loss of one or more of several utility
supply feeders. Each feeder supplies one network transformer at each vault. All transformer
secondaries at each vault are paralleled at the network service bus from which the user ser-
vice switchgear is connected.
Figure 8-29 shows one method of providing ground-fault protection for a three-transformer
spot network serving three physically separate service switchboards. Ground protection is
provided on each switchboard feeder, in each switchboard main, and in the vault system
neutral, which trips out all network protectors in the event of a vault fault. However, not all
utilities allow user relays to trip network protectors. In a typical approved installation, the
Figure 8-21—Three-wire low-resistance-grounded system

IEEE
feeder ground relays are set at about 0.1 s, the main relays at about 0.3 s, and the vault relays
at about 0.5 s. The minimum operating current settings for the vault relays are set
substantially higher than the setting on the user switchgear so that the vault relays operate
only for a fault in the vault area. Although not shown in the ﬁgure, each service switchboard
should include a connection from neutral bus to ground bus.
Figure 8-22—Four-wire solidly grounded system with single supply

IEEE
Where providing secondary selective ﬂexibility in the user service switchgear is desired, the
system sometimes takes the form shown in Figure 8-30. The ground sensors (i.e., CTs)
should be carefully applied in the main circuits. If the ground sensors are installed over all
phases and neutral, then a fault on either user bus always causes tripping of both main circuit
breakers. One method of circumventing this problem is to install the main sensors over the
phases only. This setup provides the proper selectivity, except that the ground-relay minimum
operating-current setting should be set at a value above the normal neutral current. This
normal neutral current consists of the single phase-to-neutral load unbalance plus the third
harmonic in the neutral caused by nonincandescent lighting systems. Settings of 1000 A to
2000 A may be required. With this type of system, meeting the present 1200 A maximum
setting of the NEC while still accommodating the secondary selective arrangement is
difﬁcult.
FEEDER FEEDER
GROUND AT THIS
POINT OMITTED
FEEDER
GROUND
BUS NO 2
MAIN
NO 1
MAIN
NO 1
POWER
TRANSFORMER
NO 2
POWER
TRANSFORMER
ALTERNATE
LOCATION
(NOTE)
LARGE
MOTOR NOTE: THE GROUND-FAULT SENSING DEVICE FOR THE
MAIN CIRCUIT BREAKER CAN BE IN EITHER LOCATION
SHOWN. WHEN THE TRANSFORMER IS REMOTE FROM THE
SWITCHGEAR, THE CONNECTION TO THE NEUTRAL IS NOT
ALWAYS AVAILABLE
TRANSFORMER
MOTOR CONTROL
CENTER POWER PANEL
OR BUS DUCT
R
M
R
R R
3-PHASE 4-WIRE BUS
R
Figure 8-23—Four-wire solidly grounded system with dual supply

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FEEDER FEEDER FEEDER
LARGE
MOTOR NOTES
(1) NEUTRAL TO GROUND CONNECTION MUST BE MADE
AS SHOWN. TAP EACH FEEDER NEUTRAL JON PROPER SIDE
OF THIS T POINT.
(2) SPECIAL INTERLOCKS MUST BE ADDED TO BLOCK
MAIN GROUND RELAYS UNTIL THE TIE CIRCUIT BREAKER
OPENS WHEN ONE TRANSFORMER ONLY IS IN SERVICE.
CONSULT MANUFACTURER FOR DETAILS.
TRANSFORMER
MOTOR CONTROL
CENTER POWER PANEL
OR BUS DUCT
R
M
R
R R
3-PHASE
4-WIRE BUS BUS 1 BUS 2
NEUTRAL
BUS
BUS TIE
NORMALLY
OPEN
R
FEEDER
GROUND
BUS
R
NO 1
MAIN
FEEDER
R
R
LOADS SIMILAR
TO BUS 1
NO 2
MAIN
NO 1
POWER
TRANSFORMER
NO 2
POWER
TRANSFORMER
NOTE—Ground relays for feeders, tie, and mains should have time coordination.
Figure 8-24—Four-wire solidly grounded secondary selective system
Figure 8-25—High-resistance-grounded system using core-balance CTs and
fault-indicating ammeters

IEEE
An alternate vault arrangement that has been used is shown in Figure 8-31. In this ﬁgure, the
vault is sectionalized into two halves. One of the advantages of this setup is that a vault fault
does not shut off all electrical service to the user. Ground-fault protection is essentially iden-
tical to the protection shown in Figure 8-30. An alternate ground-fault protection scheme
consisting of continuous and probe heat-sensing systems is described in Stanback [B42].
Figure 8-26—High-resistance-grounded system with pulsing contactor to
locate faulted feeder
Figure 8-27—High-resistance-grounded system that continues operation on
ﬁrst ground fault while ground relays protect against second ground fault

IEEE
a) Wye-connected system
b) Delta-connected system
Figure 8-28—High-resistance grounding using distribution or grounding
transformers

IEEE
Figure 8-29—Ground-fault protection for typical three-transformer
spot network

IEEE
Figure 8-30—Ground-fault protection for spot network when user switchgear
is secondary selective

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Figure 8-31—Ground-fault protection for sectionalized vault bus
spot network

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8.7 References
IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and Commer-
cial Power Systems (IEEE Green Book).
NEMA PB 2.2-1999, Application Guide for Ground-Fault Protective Devices for
Equipment.3
(NEC®
).4
8.8 Bibliography
[B1] ANSI C37.16-2000, American National Standard Preferred Ratings, Related Require-
ments, and Application Recommendations for Low-Voltage Power Circuit Breakers and AC
Power Circuit Protectors.5
[B2] ANSI C37.17-1997, American National Standard for Trip Devices for AC and Gen-
eral-Purpose DC Low-Voltage Power Circuit Breakers.
[B3] Bailey, B. G., “Clearing Low-Voltage Ground Faults with Solid-State Trips,” IEEE
Transactions on Industry and General Applications, vol. IGA-3, pp. 60–65, Jan./Feb. 1967.
[B4] Bailey, B. G., and Heilmann, G. H., “Clear Low-Voltage Ground Faults with Solid-State
Trips,” Power Magazine, pp. 69–71, Mar. 1966.
[B5] Beeman, D. L., ed., Industrial Power Systems Handbook. New York: McGraw-Hill,
1955.
[B6] Bisson, A. J., and Rochau, E. A., “Iron Conduit Impedance Effects in Ground Circuit
Systems,” AIEE Transactions on Applications and Industry, pt. II, vol. 73, pp. 104–107, July
1954.

IEEE
[B7] Brinks, J. W., and Wolﬁnger, J. P., “System Grounding Protection and Detection for
Cement Plants,” IEEE Transactions on Industry Applications, vol. IA-17, no. 6, pp. 587–596,
Nov./Dec. 1981.
[B8] Castenschiold, R., “Ground-Fault Protection of Electrical Systems with Emergency or
Standby Power,” IEEE Transactions on Industry Applications, vol. IA-13, no. 6, pp. 517–523,
Nov./Dec. 1977.
[B9] Chumakov, W. V., “Grounding and Ground-Fault Protection—Part 1, Single-Source
Power Systems,” Conference Record, IEEE IAS Annual Meeting, pp. 417–422, Sept. 1980.
[B10] Conrad, R. R., and Dalasta, D. A., “New Ground Fault Protective System for Electrical
Distribution Circuits,” IEEE Transactions on Industry and General Applications, vol. IGA-3,
pp. 217–227, May/June 1967.
[B11] Dalasta, D., “Ground Fault Protection for Low and Medium Voltage Distribution Cir-
cuits,” Proceedings of the American Power Conference, vol. 32, pp. 885–895, 1970.
[B12] Dunki-Jacobs, J. R., “The Effects of Arcing Ground Faults on Low-Voltage System
Design,” IEEE Transactions on Industry Applications, vol. IA-8, no. 3, pp. 223–230, May/
June 1972.
[B13] Edmunds, W. H., Schweizer, J. H., and Graves, R. C., “Protection Against Ground
Fault Hazards in Industry, Hospital, and Home,” Conference Record, IEEE Industry and Gen-
eral Applications Group Annual Meeting, IEEE 68C27-IGA, pp. 863–874, 1968.
[B14] Fisher, L. E., “Arcing-Fault Relays for Low-Voltage Systems,” IEEE Transactions on
Applications and Industry, vol. 82, pp. 317–321, Nov. 1963.
[B15] Fisher, L. E., “Proper Grounding Can Improve Reliability in Low-Voltage Systems,”
IEEE Transactions on Industry and General Applications, vol. IGA-5, pp. 374–379, July/
Aug. 1969.
[B16] Fisher, L. E., “Resistance of Low-Voltage AC Arcs,” IEEE Transactions on Industry
and General Applications, vol. IGA-6, pp. 607–616, Nov./Dec. 1970.
[B17] Fisher, L. E., and Schwieger, W. L., “Tripping Network Protectors to Protect Service
Entrance Conductors to Industrial and Commercial Buildings,” IEEE Transactions on Indus-
try and General Applications, vol. IGA-5, pp. 536–539, Sept./Oct. 1969.
[B18] Fox, F. K., Grotts, H. J., and Tipton, C. H., “High-Resistance Grounding of 2400 V
Delta Systems with Ground-Fault Alarm and Traceable Signal to Fault,” IEEE Transactions
on Industry and General Applications, vol. IGA-1, pp. 366–372, Sept./Oct. 1965.
[B19] Freund, A., “Ground-Fault Protection: How It Works,” Electrical Construction and
Maintenance, pp. 53–60, June 1973.

IEEE
[B20] Freund, A., “Ground-Fault Protection for Ungrounded Distribution Systems,” Electri-
cal Construction and Maintenance, pp. 80–84, June 1979.
[B21] Gienger, J. A., Davidson, O. C., and Brendel, R. W., “Determination of Ground-Fault
Current on Common AC Grounded Neutral Systems in Standard Steel or Aluminum Con-
duit,” AIEE Transactions on Applications and Industry, pt. II, vol. 79, pp. 84–90, May 1960.
[B22] Gross, E. T. B., “Sensitive Ground Protection for Transmission Lines and Distribution
Feeders,” AIEE Transactions, vol. 60, pp. 968–975, 1941.
[B23] lEEE Std 446-1995 (Reaff 2000), IEEE Recommended Practice for Emergency and
Standby Power Systems for Industrial and Commercial Applications (IEEE Orange Book).
[B24] Kaufmann, R. H., “Application Limitations of Single-Pole Interrupters in Polyphase
Industrial and Commercial Building Power Systems,” IEEE Transactions on Applications
and Industry, vol. 82, pp. 363–368, Nov. 1963.sd
[B25] Kaufmann, R. H., “Some Fundamentals of Equipment-Grounding Circuit Design,”
AIEE Transactions on Applications and Industry, pt. II, vol. 73, pp. 227–232, Nov. 1954.
[B26] Kaufmann, R. H., “Let’s Be More Speciﬁc about Grounding Equipment,” Proceedings
of the American Power Conference, vol. 24, pp. 913–922, 1962.
[B27] Kaufmann, R. H., “Ignition and Spread of Arcing Faults,” Conference Record, IEEE
I&CPS and Electric Space Heating and Air Conditioning Joint Technical Conference, IEEE
69C23-IGA, pp. 70–72, 1969.
[B28] Kaufmann, R. H., and Page, J. C., “Arcing-Fault Protection for Low-Voltage Power
Distribution Systems-Nature of the Problem,” AIEE Transactions on Power Apparatus and
Systems, pt. III, vol. 79, pp. 160–167, June 1960.
[B29] Knobel, L. V. “A 480 V Ground Fault Protection System,” Electrical Construction and
Maintenance, pp. 110–112, Mar. 1970.
[B30] Kreiger, C. H., Lera, A. P., and Crenshaw, R. M., “Ground Fault Protection for
Low-Voltage Systems,” Electrical Construction and Maintenance, pp. 88–92, June 1967.
[B31] Love, D. J., “Designing a Comprehensive Coordinated 480 Volt Ground-Fault
Protection System,” Conference Record, IEEE IAS Annual Meeting, vol. 77CH1246-8-14,
pp. 533–537, 1977.
[B32] Love, D. J., “Discussion of Predicting Damage from 277 V Single Phase Ground Arc-
ing Faults,” IEEE Transactions on Industry Applications, vol. IA-14, no. 1, pp. 93–95, Jan./
Feb. 1978.

IEEE
[B33] Love, D. J., “Ground-Fault Protection Electric Utility Generating Station Medium
Voltage Auxiliary Power Systems,” IEEE Transactions on Power Apparatus and Systems,
vol. PAS-97, no. 2, pp. 583–586, Mar./Apr. 1978.
[B34] Neuhoff, C. J., “Improving Ground-Fault Protection by Monitoring Equipment Envi-
ronment,” Conference Record, IEEE IAS Annual Meeting, pp. 1204–1208, Oct. 1979.
[B35] O’Connor, J. J., “The Threat of Arcing Faults,” Power Magazine, p. 48, July 1969.
[B36] Peach, N., “Protect Low-Voltage Systems from Arcing Fault Damage,” Power Maga-
zine, Apr. 1964.
[B37] Peach, N., “Get Ground Fault Protection Now,” Power Magazine, pp. 84–87, Apr.
1968.
[B38] Quinn, G. C., “New Devices End an Old Electrical Hazard-Ground Faults,” Modern
Manufacturing Magazine, Apr. 1969.
[B39] Read, E. C., “Ground Fault Protection at Buick,” Industrial Power Systems, vol. 2, June
1968.
[B40] Shields, F. J., “The Problem of Arcing Faults in Low-Voltage Power Distribution Sys-
tems,” IEEE Transactions on Industry and General Applications, vol. IGA-3, pp. 15–25, Jan./
Feb. 1967.
[B41] Soares, E. C., “Designing Safety into Electrical Distribution Systems,” Actual Specify-
ing Engineer, p. 38, Aug. 1968.
[B42] Stanback, H. I., “Predicting Damage from 277 V Single Phase to Ground Arcing
Faults,” IEEE Transactions on Industry Applications, vol. IA-13, no. 4, pp. 307–314, July/
Aug. 1977.
[B43] Valvoda, F., “Protecting Against Arcing and Ground Faults,” Actual Specifying Engi-
neer, p. 92, May 1967.
[B44] UL 1053-1999, Ground-Fault Sensing and Relaying Equipment, Sixth Edition.6
[B45] Weddendorf, W. A., “Evidence of Need for Improved Coordination and Protection of
Industrial Power Systems,” IEEE Transactions on Industry and General Applications,
vol. IGA-1, pp. 393–396, Nov./Dec. 1965.

Chapter 9
Conductor protection
This chapter deals with insulated power cable protection as well as with busway protection.
The primary considerations are presented along with some methods of application.
The proper selection and rating or derating of power cables is as much a part of cable protec-
tion as the application of the short-circuit and overcurrent protection devices. The whole
scheme of protection is based on a cable rating that is matched to the environment and operat-
ing conditions. Methods of assigning these ratings are discussed.
Power cables require short-circuit current, overload, and physical protection in order to meet
the requirements of the National Electrical Code®
(NEC®
) (NFPA 70-1999).1
A brief
description of the phenomena of short-circuit current, overload current, and their temperature
rises is presented, followed by a discussion of the time-current characteristics (TCCs) of both
cables and protective devices. In addition, a number of illustrations of cable systems and typ-
ical selection and correlation of protective devices are included.
Because of their rigid construction, busways provide their own mechanical protection. How-
ever, they do require short-circuit current and overload protection. A brief discussion of the
types of faults on the busways is presented, followed by a discussion of various methods of
fault protection.
The general intent of this chapter is to provide a basis for design, to point out the problems
involved, and to provide guidance in the application of cable and busway protection. Each
speciﬁc case and type of cable or busway requires attention. In most cases, the attention is
routine, but the out-of-the-ordinary cable and busway schemes require careful consideration.
9.2 Cable protection
Cables are the mortar that holds together the bricks of equipment in an electric system. If the
cable system is inadequate, unsatisfactory operation inevitably results. Today’s cables are
vastly superior in performance to the cables available just a decade or so ago. But even so,
they are not unlimited in power capability and, therefore, need protection to prevent possible
operation beyond that capability.
Cables are generally classiﬁed as either power or control. Power cables are divided into two
voltage classes: 600 V and below, and above 600 V. Control cables include cables used in the
control of equipment and also for voice communication, metering, and data transmission.

IEEE
The amount of damage caused by the faulting of power cables has been illustrated many
times. As power and voltage levels increase, the potential hazards also increase. High
temperature due to continued overload, nonlinear loads, or uncoordinated fault protection is a
frequent cause of decreased cable life and failure. Power cables, internally heated as a result
of their resistance to the current being carried, can undergo insulation failure if the
temperature buildup becomes excessive. Proper selection and rating ensures that the cable is
large enough for the expected current. Suitable protection ensures that cable temperature
rising above ambient does not become excessive. Such protection normally is provided by
time-current sensitive devices. In addition to insulation breakdown, protection is also
required against unexpected overload and short-circuit current. Overcurrent can occur due to
an increase in the number of connected loads or due to overloading of existing equipment or
due to nonlinear loads causing excessive neutral conductor current.
While the extraordinary temperature of the short-circuit arc produces extensive destruction of
materials at a fault location, cables carrying energy to (and from) a fault may also incur ther-
mal damage over their entire length if the fault current is not interrupted quickly enough.
Depending on conductor size, insulation type, and available fault current, the clearing time of
the protection system should be short enough (i.e., coordinated) to stop the current ﬂow
before damaging temperatures are reached.
Physical conditions can also cause cable damage and failure. Failure due to excessive heat
may be caused by high ambient temperature conditions or ﬁre. Mechanical damage may
result in short circuits or reduced cable life and may be caused by persons, equipment,
animals, insects, or fungi.
Cable protection is required to protect personnel and equipment and to ensure continuous
service. From the standpoint of equipment and process, the type of protection selected is
generally determined by economics and the engineering requirements. Personnel protection
also receives careful engineering attention and special consideration to ensure compliance
with the various codes that may be applicable to a particular installation.
Protection against overload is generally achieved by a device sensitive to current magnitude
and duration. Short-circuit protective devices are sensitive to much greater currents and
shorter times. Protection against environmental conditions takes on many forms.
Cables may also be damaged by sustained overvoltages such as exist during a ground fault on
one phase conductor. Modern cables now bear a rating called percent insulation level (or
% IL). This rating is described as follows:
a) 100% IL—Cables that may not be required to operate longer than 1 min in case of
ground fault.
b) 133% IL—Cables that may not be required to operate longer than 1 h in case of a
ground fault.
c) 173% IL—Cables that may be required to operate longer than 1 h continuously with
one phase conductor grounded (manufacturers should be consulted for suitability).

IEEE
CONDUCTOR PROTECTION Std 242-2001
The cable characteristics are not germane to this treatment, but the timing of the permissible
protective system should be in accordance with the IL rating of the cables involved.
In general, this chapter covers methods of rating cables and the conditions and problems
listed in this clause. It also provides a starting point from which further refinements may be
made and other features added for improved power cable protection.
9.3 Definitions
The following symbols are used in cable protection technology. Some symbols are also used
in other parts of electrical engineering practice, such as fault determination. However,
because only a limited number of symbols are available and the ones shown in this clause are
deeply rooted in cable technology, the duplication is tolerated.
9.3.1 Cable current (A)
I is current flowing in cable,
IO is initial current prior to a current change,
IF is final current after a current change,
IN is normal loading current on base ambient temperature,
IN1 is normal loading current on nonbase ambient temperature,
IE is emergency loading current on base ambient temperature,
IX is current at values other than normal or emergency loading,
ISC is three-phase short-circuit current.
9.3.2 Cable temperature (˚C)
T is temperature, in general,
TO is initial temperature prior to a current change,
Tf is final temperature after a current change,
TN is normal loading temperature,
TE is emergency loading temperature,
TX is temperature at any loading current,
Tt is temperature at time t after a current change,
Ta is base ambient temperature,
Ta1 is nonbase ambient temperature.
9.3.3 Miscellaneous
t is time (units as noted),
CM is conductor size (circular mils)
Fac is skin effect ratio or ac/dc ratio [NEC (1999 edition), Table 9],
K is time constant or geometric factor of cable heat flow,
Kt is correction factor for initial and final short-circuit temperature.

IEEE
9.3.4 Reactances (%)
XT is transformer reactance,
Xd" is subtransient reactance of a rotating machine,
Xd' is transient reactance of a synchronous machine.
9.4 Short-circuit current protection of cables
A cable should be protected from overheating due to excessive short-circuit current flowing
in its conductor. The fault point may be on a section of the protected cable or on any other
part of the electric system. The faulted cable section is, of course, to be replaced after the
fault has been cleared.
During a phase fault, the I2
R losses in the phase conductors elevate first the temperature of
the conductor, followed by the insulation materials, protective jacket, raceway, and surround-
ings. During a ground fault, the I2
R losses in both phase conductor and metallic shield or
sheath elevate the temperature in a similar manner to phase faults.
In most cases, the shield of the cable beyond the fault also carries part of the fault return cur-
rent, which may then return along the shields of other conductors or equipment grounding
paths, from common grounding points.
Because the short-circuit current is interrupted either instantaneously or in a short time by the
protective device, the amount of heat transferred from the metallic conductors outward to the
insulation and other materials is small. Therefore, the heat from I2
R losses is almost entirely
in the conductors; and, for practical purposes, it can be assumed that 100% of the I2
R losses
are consumed to elevate the conductor temperature. During the period that the short-circuit
current is flowing, the conductor temperature should not be permitted to rise to the point
where it may damage the insulating materials. The task of providing cable protection during a
short-circuit condition involves determining the following:
— Maximum available short-circuit currents
— Maximum conductor temperature that will not damage the insulation
— Cable conductor size that affects the I2
R value and its capability to contain the heat
— Longest time that the fault can exist and the fault current can flow
9.4.1 Short-circuit current
9.4.1.1 Phase-fault current and rates of decay
The fundamentals of short-circuit current behavior and the calculation of short-circuit
currents are described in Chapter 2. The magnitude of short-circuit current should be properly
determined. As illustrated in Figure 9-1, the initial peak current is called asymmetrical
current (or current for momentary duty). This current then decays in sequence to the
subtransient current, transient current, and synchronous current or sustained short-circuit
current. The short-circuit current decays exponentially in the subtransient and transient

IEEE
periods. Figure 9-1 shows the approximate rate of decay of the total current. Four typical
systems are illustrated in this ﬁgure to give a general picture of the fault-current behavior. The
decay rate in each system depends on the X/R ratio of the system; higher X/R ratios are found
on medium-voltage systems with local generation.
9.4.1.2 Maximum short-circuit currents
Generally, the subtransient current of a system is used to designate the maximum available
short-circuit current in the cables protected by the instantaneous overcurrent relays and
medium-voltage switchgear circuit breakers. For cables protected by noncurrent-limiting
fuses or noncurrent-limiting low-voltage instantaneous trip circuit breakers, the asymmetrical
current value is used. The effective current for cables protected by current-limiting devices
[e.g., fuses, molded-case circuit breakers (MCCBs), cable limiters] in the current-limiting
range is the root-mean-square (rms) value of the let-through current as determined from the
a) Plant generator system, medium-voltage
b) Utility-power supplied system, medium-voltage, with large synchronous motors
c) Utility-power supplied system, medium-voltage, no synchronous motor
d) Utility or plant generation, low-voltage 240 V or 480 V load centers
Figure 9-1—Typical rate of short-circuit current decay

IEEE
manufacturers’ let-through curves (see Example 1 in 9.4.4.2). For delayed tripping of 0.2 s or
longer, the rms value of the decayed current over the flow period of fault current should be
used.
9.4.1.3 Short-circuit currents based on equipment ratings
For liberal design margins where economic considerations are not critical, the interrupting
current ratings of the noncurrent-limiting circuit breakers or noncurrent-limiting fuses may
be used as the basis for cable selection and protection. This approach, of course, assumes that
the protective devices have been applied within their ratings.
9.4.1.4 Ground-fault currents and rates of decay
The fundamentals of ground short-circuit current behavior are similar to the characteristics of
phase-fault current, but the calculations are different, as described in Chapter 2 and
Chapter 8. For a solidly grounded system, the ground-fault current is in the same order of
magnitude as the phase-fault current. For a low-resistance-grounded system, the magnitude
of the ground-fault current is limited to a sustained value determined by the resistor’s current
rating. The decay of the dc component occurs so rapidly that the asymmetry effect in the cur-
rent wave shape can be ignored. For a high-resistance-grounded or ungrounded system, the
ground-fault current is small, but should be immediately alarmed and quickly cleared to pre-
vent persistent arcing and the occurrence of a more serious fault involving other conductors
or circuits.
Ground-fault currents of over 3 A to 4 A are likely to ignite organic insulation in the arc path
within a few minutes, developing a local fire and subsequent phase-to-phase fault, with exten-
sive damage.
9.4.2 Conductor temperature
9.4.2.1 Temperature rise of phase, neutral, or insulated grounding conductors
On the basis that all heat is absorbed by the conductor metal and no heat is transmitted from
the conductor to the insulation material, the temperature rise is a function of the size of the
metallic conductor, the magnitude of the fault current, and the time of the current flow. These
variables are related by the following empirical equations (see ICEA P-32-382-1999):
for copper
for aluminum
If the initial temperature TO and final temperature Tf are predetermined on the basis of
continuous-current rating and insulation material, respectively, the current I versus time t
relation of current flow can be plotted for each conductor size (CM).
I
CM
--------
-
 
 
2
tFac
( ) 0.0297 log10
T f 234
+
TO 234
+
---------------------
-
=
I
CM
--------
-
 
 
2
tFac
( ) 0.0125 log10
T f 228
+
TO 228
+
---------------------
-
=

IEEE
9.4.2.2 Temperature rise of shield and sheath
On the same basis as for phase conductors, the temperature rise on the shield or sheath due to
ground-fault current can be related to the magnitude of the fault current I, the cross section
CM of the shield and sheath, the spiral cross section and length for the spiral, tape shield, and
the time t of current flow, as shown in Table 9-1 (see ICEA P-45-482-1999).
A comprehensive study has been conducted of the flow of ground-fault currents through
shields, conduits, and ground wires during ground faults in connected equipment (see Hamer
and Wood [B2]). Contrary to intuition, most of the ground-fault return current does not return
through the shields of the cables connected to the phase that includes the equipment ground
fault. (In a fault between a conductor and its own metallic shield, the faulted shield would
carry most of the ground return current, but external ground faults in connected equipment
are the major concern of this subclause.) Tests show that little difference exists in the
magnitudes of the ground-fault return currents through the shields of individual cables
connected to equipment that contains a ground fault. The impedances of cable shields
routinely used in industry are relatively high compared with other ground return paths, such
as ground wires within conduits or the conduit itself. Accordingly, the ground-fault return
current divides among several paths with most of the current diverted away from the shields.
While the scope of this chapter does not include covering the actual division of these
currents, guidelines for protecting shields can be provided. For through ground faults of
under 1000 A and conventional operating times of ground protection relays, Hamer and
Wood have concluded that metallic shields are not being damaged during ground faults. For
ground faults exceeding 1000 A, a ground wire should be included within the conduits to
provide a reliable low-impedance ground return path. This setup is especially applicable for
systems using rigid-steel conduit as the return path. Without ground wires within the conduit,
sparking at the couplings (see Kaufmann [B9]) may occur during faults with the resulting
risks for conduits routed through hazardous (or classified) locations (see the NEC). The use
Table 9-1—Temperature rise of shield and sheath due to ground-fault current
Material
Initial/Final temperatures
65/200 °C 65/150 °C 90/250 °C
Copper
Aluminum
Lead
Steel
I 0.0694
CM
t
--------
-
= I 0.0568
CM
t
--------
-
= I 0.0779
CM
t
--------
-
=
I 0.0453
CM
t
--------
-
= I 0.0371
CM
t
--------
-
= I 0.0509
CM
t
--------
-
=
I 0.0124
CM
t
--------
-
= I 0.0103
CM
t
--------
-
= I 0.0141
CM
t
--------
-
=
I 0.0249
CM
t
--------
-
= I 0.0205
CM
t
--------
-
= I 0.0281
CM
t
--------
-
=

IEEE
of a ground wire also eliminates concern over corroded or loose couplings and bushings.
Chapter 2 of IEEE Std 142-1991 contains information for the sizing of ground wires.
9.4.2.3 Maximum short-circuit temperature ratings
ICEA P-32-382-1999 established a guideline for short-circuit temperatures for various types
of insulation as shown in Table 9-2. The short-circuit temperature ratings are considered the
maximum temperatures and, to protect the cable insulation from damage, should not be
exceeded. General agreement does not exist that the temperatures from ICEA P-32-382-1999
accurately depict conductor temperatures because they are calculated rather than measured.
However, agreement does exist that the temperatures shown in Table 9-2 are higher than
actual and, therefore, conservative for the purposes of this chapter.
9.4.2.4 Temperature-current-time curves
For convenience in determining the cable size, the curves depicting the relationship of tem-
perature-current-time are prepared from the temperature rise formula and are based on the
temperature rise from the continuous to short-circuit temperature limits. Figure 9-2 and
Figure 9-3 show the curves for copper and aluminum conductors from 75 ˚C to 200 ˚C. They
also incorporate the total fault-clearing times of various types of switching equipment. For
competent design, a cable may be selected on the basis of the expected load current, total
short-circuit clearing time, and available short-circuit current. For example, AWG # 2/0 cop-
per cable may be selected for connection to a circuit capable of producing 21 000 A with a
clearing time of 8 cycles, and # 4/0 aluminum cable may be selected for connection to the
same circuit.
Table 9-2—Maximum short-circuit temperatures
Type of insulation
Continuous
temperature rating TO
(˚C)
Short-circuit current
temperature rating Tf
(˚C)
Rubber 75 200
Rubber 90 250
Silicone rubber 125 250
Thermoplastic 60, 75, 90 150
Paper 85 200
Vanishing cloth 85 200

IEEE
9.4.2.5 Initial and final temperatures
For cables rated at initial (or operating) and final (or maximum short-circuit) temperatures
different from 75 ˚C and 200 ˚C, respectively, correction factors for use with Figure 9-2 and
Figure 9-3 may be determined by use of Figure 9-4. With this chart, a correction factor is
obtained by which the actual available fault current is converted to a virtual available fault
current that is then used with Figure 9-2 and Figure 9-3. The actual available fault current is
multiplied by the correction factor Kt to obtain the virtual available fault current.
Using Figure 9-4, the following examples were calculated:
a) Initial temperature = 50 ˚C
Maximum fault temperature = 200 ˚C
*Clearing time of current-limiting fuses and current-limiting MCCBs in current-limiting range is
approximately 0.25 cycles (0.004 s). See Table 9-3a through Table 9-3e.
Figure 9-2—Maximum short-circuit current for insulated copper conductors
(initial temperature 75 ˚C; final temperature 200 ˚C; for other temperatures
use correction factors of Figure 9-4)

IEEE
Kt = 0.899
Actual available fault current = 20 000 A
Virtual available fault current = 0.899 × 20 000 = 17 980 A on Figure 9-2 and
Figure 9-3
b) Initial temperature = 90 ˚C
Maximum fault temperature = 250 ˚C
Kt = 0.925
Actual available fault current = 20 000 A
Virtual available fault current = 0.925 × 20 000 = 18 500 A on Figure 9-2 and
Figure 9-3
*Clearing time of current-limiting fuses and current-limiting molded-case circuit breakers in
current-limiting range is approximately 0.25 cycles (0.004 s). See Table 9-3a through Table 9-3e.
Figure 9-3—Maximum short-circuit current for insulated aluminum
conductors (initial temperature 75 ˚C; ﬁnal temperature 200 ˚C;
for other temperatures use correction factors of Figure 9-4)

IEEE
In both cases, a smaller conductor might be safely used.
9.4.3 Protective devices
9.4.3.1 Total fault-clearing time
Devices to protect cables against short-circuit damage should have high reliability and fast
fault-clearing time. In the protective scheme, primary protection is the ﬁrst line of defense,
and backup protection, the second line of defense. Primary protection normally provides
prompt, but not necessarily instantaneous, fault-clearing time while backup protection is
timed for more delayed fault-clearing time. Whether these two levels of protection are to be
provided for all cables is a decision to be made in initial design stages. Total clearing times
are deﬁned as follows:
a) Relayed circuit breaker. Total fault-clearing time equals overcurrent relay time plus
auxiliary relay time (if used) plus circuit breaker interrupting time.
b) Direct tripping circuit breaker. Total fault-clearing time equals circuit breaker clear-
ing time.
c) Fuses. Total fault-clearing time equals melting time plus arcing time.
Figure 9-4—Correction factors Kt for initial and maximum short-circuit
temperatures

IEEE
9.4.3.2 Protective devices and clearing time
The total clearing time of various types of protective devices depends on the type of relay and
circuit breakers or fuses used. Table 9-3a through Table 9-3e estimate the total clearing times
of various types of protective devices.
Table 9-3a—Estimated clearing times of protective devices:
relayed circuit breakers, 2.4–13.8 kV
Plunger,
instantaneous
Type of relay
induction,
instantaneous
Induction,
inverse time
Relay times (cycles) 0.25–1 0.5–2 6–6000
Circuit breaker interrupting
time (cycles)
3–8 3–8 3–8
Total time (cycles) 3.25–9 3.5–10 9–6000
Table 9-3b—Estimated clearing times of protective devices:
molded-case circuit breakers, 600 kV and below
Frame size
225–600 A 1600–4000 A
Instantaneous (cycles) 2–3 3
Short time (cycles) 10–30 10–30
Long time (s) over 100
Ground fault (cycles) 10–30 10–30
Table 9-3c—Estimated clearing times of protective devices:
power circuit breakers, 600 kV and below
Frame size
100 A 225–1200 A
100–1200 A
(current limiting)
Instantaneous (cycles) 0.5–1 1–1.5 Less than 0.5
Long time (s) over 100

IEEE
For convenience, the total clearing time of various overcurrent devices is shown in the lower
left-hand corner of Figure 9-2 and Figure 9-3. These data can be used together with maxi-
mum short-circuit current for proper selection of cable sizes.
9.4.3.3 TCCs of protective devices
A protective device provides maximum protection if its TCCs are suitably below (i.e., 20% in
time) the TCCs of the cable short-circuit current versus the time curves shown in Figure 9-2
and Figure 9-3. Thus the selection of fuses, overcurrent relays, or circuit breakers is vitally
important to the protection of cables. Figure 9-5, Figure 9-6, and Figure 9-7 illustrate the
characteristics of relays and devices commonly used in feeder circuits. Shown also are the
maximum available short-circuit currents of the system and the maximum short-circuit
current curve of the cable.
9.4.3.4 Backup protection
In some instances, the setting or rating of a given device, rather than just protecting the imme-
diate downstream element, may be selected to protect the second downstream element (e.g.,
cable). This setup would come into play if a protective device failed; in other words, the next
upstream device would operate in adequate time to prevent damage to elements such as cable
on the load side of the failed device. This feature is known as backup protection.
Backup protection is almost never applied to industrial or commercial branch circuits, but is
occasionally applied to feeder and subfeeder protection. The consequences resulting from
failure of a feeder or subfeeder protective device need to be considered in deciding whether
backup protection should be provided. Such protection is frequent in utility system practice,
but not generally used in industrial or commercial systems.
Table 9-3d—Estimated clearing times of protective devices:
medium- and high-voltage fuses
High current 0.25 cycles (for current-limiting fuses operating in their
current-limiting range)
1.0 cycles (for power fuses at maximum current)
Low current 600 s (for E-rated fuses operating at 2 times nominal rating;
other ratings are available with different times at 2 times
nominal rating)
Table 9-3e—Estimated clearing times of protective devices:
low-voltage fuses
High current 0.25 cycles (in current-limiting range)
Low current 1000 s (at 1.35 to 1.5 times nominal rating)

IEEE
9.4.4 Application of short-circuit current protective devices
9.4.4.1 Typical cases of cable protection
Power cables are used for transmission or distribution, or as feeders to utilization equipment.
The following cases are typical in industrial and commercial power systems:
a) A single cable feeder through a pull box or splice joint or with taps should be
protected in the same manner as feeders to panels [see Views (b), (d), (e), and (f) of
Figure 9-8].
a) Power or current-limiting fuses
b) Overcurrent relay
Figure 9-5—Short-circuit and overload protection of 5 kV cables

IEEE
b) A single or multiple cable feeder without a pull box or taps should be protected from
the maximum short-circuit current that can occur at the load terminals.
A multiple cable feeder with or without pull box or splice joint should be protected
from the maximum short-circuit current caused by a fault on one cable. The
short-circuit current in each cable is not equally distributed because the maximum
current on the faulted cable is greater than the total current divided by the number of
a) Long-time and instantaneous equipped circuit breakers
b) Long-time and short-time equipped circuit breakers
Figure 9-6—Short-circuit and overload protection of 600 V cables

IEEE
cables [see View (c) of Figure 9-8]. Problems arise in the protection of parallel cables
unless individual devices are used for each cable.
c) A single or multiple cable feeder through a pull box or splice joint, or with taps,
should be protected from the maximum short-circuit current caused by a fault on the
tapped cables or end section of spliced cable. A cable fault requires the replacement
of only the faulted cable section [see View (d) and View (f) of Figure 9-8].
d) Multiple-feeder circuits should be protected in a similar manner to each individual
circuit [see View (g) of Figure 9-8].
a) Thermal-magnetic circuit breakers
b) Heaters and fuses
Figure 9-7—Short-circuit and overload protection of 600 V cables

IEEE
9.4.4.2 Protection and coordination
The protective device should be selected and coordinated to give the cable sufﬁcient
short-circuit protection. This process can be done easily by plotting the TCC curves of the
protected cable and the protective device on the same log-log graph paper. The TCC curve of
the protective device should always be below and to the left of the maximum short-circuit
current-time curve (see Figure 9-2 and Figure 9-3) of the protected cable. Figure 9-5 through
Figure 9-9 illustrate that a # 4/0 copper insulated cable may be protected by various
protective devices as follows:
a) Single-cable feeder or utilization equipment
b) Single-cable feeder to panel
c) Multiple-cable feeder to panel
d) Single-cable feeder with pull box
e) Single-cable feeder with pull box and splice
f) Single-cable feeder with pull box and tap
g) Multiple-cable feeder with pull box and taps
Figure 9-8—Application of protective devices

IEEE
— A 5 kV # 4/0 feeder is protected by a current-limiting fuse [see View (a) of Figure 9-
5] or a Device 50/51 or Device 49/50 relay [see View (b) of Figure 9-5].
— A 600 V # 4/0 feeder is protected by instantaneous tripping [see View (a) of Figure 9-
6], by short-time tripping [see View (a) of Figure 9-6], or by an instantaneous MCCB
[see View (a) of Figure 9-7].
— A 600 V # 4/0 motor circuit is protected by a 400 A current-limiting fuse [see
View (a) of Figure 9-7].
Special consideration is required whenever equipment-grounding conductors are sized
smaller than the phase conductors because the overcurrent device can be several sizes larger
a) Ambient temperature at 20 ˚C
b) Ambient temperature at 30 ˚C
Figure 9-9—Cable loading and temperature rise

IEEE
than the equipment-grounding conductor, making it more difﬁcult to protect. Examples of
short-circuit protection are given in 9.4.4.2.1 and 9.4.4.2.2.
9.4.4.2.1 Example 1
Figure 9-10 presents a one-line diagram for Example 1.
1) Find rms let-through current of the current-limiting fuse.
Entering the let-through curve of the current-limiting fuse at 30 kA, and using the up,
over, and down method the rms let-through current is found to be 12 kA (see
Figure 9-11). Some manufacturers use symmetrical available short circuit (SCA).
The manufacturer’s instructions should be followed for use of let-through curves.
2) Find the short-circuit capability of the 4/0 copper conductor.
In this example, assume that the initial operating temperature is the 90 ˚C continuous
rating of the cable. The reason for this conservative assumption is that the initial
operating temperature is a function of not only the loading, but also the ambient tem-
perature. Therefore, determining the actual operating temperature is not always easy.
Figure 9-10—One-line diagram for Example 1

IEEE
Entering Figure 9-4 with an initial temperature of 90 ˚C and a maximum short-circuit
temperature of 250 ˚C, Kt is found to be 0.925. (See 9.4.2.5 for additional informa-
tion on the use of Figure 9-4.)
The virtual available fault current should be found for use with Figure 9-2. Virtual
available fault current is deﬁned in 9.4.2.5 as the product of the actual available fault
current and Kt . In this example, the actual available fault current is reduced to 12 kA
because of the current-limiting effect of the 200E current-limiting fuse. Therefore,
virtual available fault current = Kt × 12 kA
= 0.925 × 12 kA
= 11.1 kA
Entering Figure 9-2 with the virtual fault current of 11.1 kA, the 4/0 cable is found to
safely carry 11.1 kA for approximately 100 cycles. Referring to Table 9-3a through
Table 9-3e, a medium-voltage current-limiting fuse operating in the current-limiting
range is found to clear a fault in 0.25 cycles. Therefore, the cable is well protected
from short-circuit damage.
3) Plot cable short-circuit thermal limit curve on a coordination plot.
The short-circuit thermal limit curve for this example is constructed by shifting the
4/0 copper damage curve of Figure 9-2 by a current factor of 1/Kt and plotting points
Figure 9-11—Current-limiting fuse let-through for use with Example 1

IEEE
from the shifted curve of Figure 9-2 on to the protection plot (d) in Figure 9-12. An
example of curve shifting is given in Figure 9-13.
9.4.4.2.2 Example 2
Figure 9-14 presents a one-line diagram for Example 2.
1) Find the equivalent rms value of the fault current flowing over the time required to
clear fault.
From 9.4.1.2, the subtransient current is assumed to flow over the time required for a
medium-voltage circuit breaker and instantaneous relay to clear the fault. From
Figure 9-3 and Table 9-3a through Table 9-3e, the total clearing time of a 5 cycle
circuit breaker and instantaneous relay is taken as 0.12 s. Therefore, 40 kA
subtransient short-circuit current is assumed to flow for 0.12 s.
2) Find the short-circuit capability of the 500 kcmil aluminum conductors.
The initial and final temperatures in Example 2 are the same as in Example 1. There-
fore, Kt = 0.925. (See Example 1 for determination of Kt and the virtual available
fault current.) In order to find the short-circuit capability of the 500 kcmil aluminum
cable, Figure 9-3 should be entered with the virtual available fault current. Therefore,
Figure 9-12—Short-circuit protection plot for Example 1

IEEE
virtual available fault current = Kt × 40 kA
= 0.925 × 40 kA
= 37 kA
Entering Figure 9-3 with 37 kA, a single conductor 500 kcmil aluminum cable is
found to carry 37 kA for about 0.6 s. The fault is cleared in 0.12 s; therefore, the
cable is well protected from short-circuit damage.
NOTE—Under short-circuit conditions, all fault current is assumed to ﬂow through a single
conductor when multiconductor feeders are utilized.
The short-circuit protection plot is shown in Figure 9-15. See Example 1 for the
method of plotting the thermal limit curve on the short-circuit protection plot. The
shifted short-circuit thermal limit curve should be plotted on the coordination plot
between the current limits shown in Figure 9-15.
Figure 9-13—Shifting of thermal limit curve for use with coordination plot of
Example 1

IEEE
9.5 Overload protection of cables
Overload protection cannot be applied until the current-time capability of a cable is deter-
mined. Protective devices can then be selected to coordinate cable rating and load
characteristics.
9.5.1 Normal current-carrying capacity
9.5.1.1 Heat ﬂow and thermal resistance
Heat is generated in conductors by I2
R losses. It must ﬂow outward through the cable
insulation, sheath (if any), the air surrounding the cable, the raceway structure, and the
surrounding earth in accordance with the following thermal principle (see AIEE Committee
Report [B1]; Neher and McGrath [B11]; Shanklin and Buller [B13]; Wiseman[B14]):
Figure 9-14—One-line diagram for Example 2
heat flow
difference between conductor and ambient temperature
thermal resistance from materials
-----------------------------------------------------------------------------------------------------------------------------------
-
=

IEEE
The conductor temperature resulting from heat generated in the conductor varies with the
load. The thermal resistance of the cable insulation may be estimated with a reasonable
degree of accuracy, but the thermal resistance of the raceway structure and surrounding earth
depends on the size of the raceway, the number of ducts, the number of power cables, the
raceway structure material, the coverage of the underground duct, the type of soil, and the
amount of moisture in the soil. These considerations are important in the selection of cables.
9.5.1.2 Ampacity
The ampacity of each cable is calculated on the basis of fundamental thermal laws
incorporating speciﬁc conditions, including type of conductor, ac/dc resistance of the
conductor, thermal resistance and dielectric losses of the insulation, thermal resistance and
inductive ac losses of sheath and jacket, geometry of the cable, thermal resistance of the
surrounding air or earth and duct or conduits, ambient temperature, and load factor. The
ampacities of the cable under the jurisdiction of the NEC are tabulated in its current issue or
amendments. The current-carrying capacity of cables under general operating conditions that
* i" is the equivalent value of the rms fault current over the duration of ﬂow of the fault
current (see 9.4.1.2)
Figure 9-15—Short-circuit protection plot for Example 2

IEEE
may not come under the jurisdiction of the NEC are published by the Insulated Cable
Engineers Association (ICEA). In its publications, the ICEA describes methods of calculation
and tabulates the ampacity for 1 kV, 8 kV, 15 kV, and 25 kV cables (see ICEA S-19-81 or
NEMA WC 3-1993, ICEA-61-402 or NEMA WC 5-1992, ICEA S-65-375 or NEMA
WC 4-1988). The ampacities of specific types of cables are calculated and tabulated by
manufacturers. Their methods of calculation generally conform to ICEA P-54-440 or NEMA
WC 51-1986.
9.5.1.3 Temperature derating factor (TDF)
The ampacity of a cable is based on a set of physical and electrical conditions and a base
ambient temperature defined as the no-load temperature of a cable, duct, or conduit. The base
temperature generally used is 20 ˚C for underground installation, 30 ˚C for exposed conduits
or trays, and 40 ˚C for medium-voltage cables.
TDFs for ambient temperatures and other than base temperatures are based on the maximum
operating temperature of the cable and are proportional to the square root of the ratio of
temperature rise, that is,
9.5.1.4 Grouping derating factor
The no-load temperature of a cable in a group of loaded cables is higher than the base
ambient temperature. To maintain the same maximum operating temperature, the
current-carrying capacity of the cable should be derated by a factor of less than 1. Grouping
derating factors are different for each installation and environment. Generally, they can be
classified as follows:
— For cable in free air with maintained space
— For cable in free air without maintained space
— For cable in exposed conduits
— For cable in underground ducts
TDF
IN
IM
-----
-
current capacity
at base ambient temperature
current capacity
at other ambient temperature
--------------------------------------------------------------------
-
TN Ta
–
TN Ta1
–
--------------------
-
=
temperature rise above
base ambient temperature
temperature rise above
other ambient temperature
--------------------------------------------------------------
-
=
= =

IEEE
NEC Table 318-9 and Table 318-10 list fill limits for low-voltage cables in cable trays. NEC
Article 318-11 covers the ampacity of low-voltage cables in trays. Article 318-12 and
Article 318-13 cover ratings and fills of medium-voltage cables in cable trays.
9.5.1.5 Frequency and harmonic derating factors
Chapter 9 and Chapter 12 of IEEE Std 141-1993 contain information pertaining to the derat-
ing of cables as the result of harmonics and frequency considerations. (Six-pulse harmonic
current distribution is covered in 9.8.2.3, and Figure 12-7 treats 400 Hz and 800 Hz systems.)
9.5.2 Overload capacity
9.5.2.1 Normal loading temperature
Cable manufacturers specify for their products the normal loading temperature, which results
in the most economical and useful life of the cables. Based on the normal rate of
deterioration, the insulation can be expected to have a useful life of about 20 years to
30 years. Normal loading temperature of a cable determines the cable’s current-carrying
capacity under given conditions. In regular service, rated loads or normal loading
temperatures are reached only occasionally because cable sizes are generally selected
conservatively in order to cover the uncertainties of load variations. Table 9-4 shows the
maximum operating temperatures of various types of insulated cables.
9.5.2.2 Cable current and temperature
The temperature of a cable rises as the square of its current. The cable temperature for a given
steady load may be expressed as a function of percent full load by the formula
TX = Ta + (TN – Ta) (IX / IN)2
Figure 9-9 shows this relation for cables rated at normal loading temperatures of 60 °C,
75 °C, 85 °C, and 90 ˚C.
9.5.2.3 Intermediate and long-time zones
Taking into account the intermediate and long-time ranges from 10 s out to infinity, the
definition of temperature versus current versus time is related to the heat dissipation
capability of the installation relative to its heat generation plus the thermal inertias of all
parts. The tolerable temperatures are related to the thermal degradation characteristics of the
insulation. The thermal degradation severity is, however, related inversely to time. Therefore,
a temperature safely reached during a fault could cause severe life reduction if it were
maintained for even a few minutes. Lower temperatures, above the rated continuous
operating temperature, can be tolerated for intermediate times.

IEEE
The ability of a cable to dissipate heat is a factor of its surface area, while its ability to
generate heat is a function of the conductor cross section, for a given current. Thus, the
reduction of ampacity per unit cross-section area as the wire sizes increase tends to increase
the permissive short-time current for these sizes relative to their ampacities. It may be seen in
Figure 9-16 that the extension of the intermediate characteristic, on a constant I2t basis,
protects the smallest wire sizes and overprotects the largest sizes, as shown in Figure 9-16.
Constant I2t protection is readily available and is actually the most common; therefore, a
simpliﬁcation of protection systems is possible.
The continuous current, or ampacity, ratings of cable have been long established and pose no
problems for protection. The greatest unknown in the cable thermal characteristic occurs in
the intermediate time zone, or the transition from short-time to long-time or continuous state.
Table 9-4—Typical normal and emergency loading of insulated cables
Insulation Cable type
Normal
voltage
Normal
loading
(°C)
Emergency
loading
(°C)
Thermoplastic T, TW 600 V 60 85
THW 600 V 75 90
THH 600 V 90 105
Polyethelene 0–15 kV 75 95
>15 kV 75 90
Thermosetting R, RW, RU 600 V 60 85
XHHW 600 V 75 90
RHW, RH-RW 0–2 kV 75 95
Cross-linked
polyethylene
5–15 kV 90 130
Ethylene-propylene 5–15 kV 90 130
Varnished polyester 15 kV 85 105
Varnished cambric 0–5 kV
15 kV
85
77
102
85
Paper lead 15 kV 80 95
Silicone rubber 15 kV 125 150

IEEE
9.5.2.4 Development of intermediate characteristics
Cable, with the thermal inertia of its own and of its surroundings, takes from 1 h to 6 h to
change from initial to ﬁnal temperature as the result of a current change. Consequently, over-
loads substantially greater than its continuous rating may be placed on a cable for this range
of times.
Figure 9-16—Rate of temperature rise due to current increase

IEEE
Additionally, all cables except polyethylene (not cross-linked) withstand, for moderate
periods, temperatures substantially greater than their rated operating temperatures. This is a
change recently developed from work done within ICEA and published by that organization
(see 9.9). For example, EPR and XLP cables have emergency ratings of 130 ˚C, based on
maximum time per overload of 36 h, three such periods per year maximum, and an average of
one such period per year over the life of the cable. Thermoplastic cables degrade in this
marginal range by progressive evaporation of the plasticizer and can operate for several hours
at the next higher grade operating temperature (90 ˚C for 75 ˚C rating, and so forth) with
negligible loss of life. Therefore, emergency operating overloads may reasonably be applied
to cables within the time and temperature ratings. This capability should be the basis of
application of protection of the cables.
The complete relationship for determining intermediate overload rating is as follows:
Percent overload capability =
where
IE is emergency operating current rating,
IN is normal current rating,
IO is operating current prior to emergency,
TE is conductor emergency operating temperature,
TN is conductor normal operating temperature,
TO is ambient temperature,
K is a constant, dependent on cable size and installation type (see Table 9-5),
230 is zero-resistance temperature value (234 for copper, 228 for aluminum),
e is base for natural logarithms.
If the cable has been operated at its rated current prior to the excursion, then IO / IN = 1 so the
relation is simpliﬁed to:
Table 9-5—K factors for equations in 9.5.2.4
Cable size
Air
Underground
duct
Direct
buried
No cond In cond
<#2 0.33 0.67 1.00 1.25
#2–#4/0 1.00 1.50 2.50 3.00
≥250 kcmil 1.50 2.50 4.00 6.00
IE
IN
----
-%
TE TO
–
TN TO
–
-------------------
-
IO
IN
----
-
 
 
2
e
θK
–
( )
–
1 e
θK
–
–
-------------------------------------------------------
-
230 TN
+
230 TE
+
---------------------
-
 
  100
=

IEEE
This equation is the basic formula used in this chapter as representing the maximum safe
capability of the cable.
While many medium-voltage cables are operated at substantially less than full rated capacity,
most low-voltage cables are operated near their rated ampacity. Even for medium-voltage
cable, full loading is occasionally impressed. Regardless of preloading, protection should be
coordinated with cable characteristics, not loading. Therefore, data presented in this sub-
clause are based on 100% preloading, by the preceding equation. Factors are developed for
approximating the characteristic for lower preloadings. For such preloadings, the data pre-
sented in this subclause are even more conservative.
Intermediate zone characteristics of medium-voltage cables and 75 °C and 90 ˚C
thermoplastic cables are tabulated in Table 9-6 with the characteristics of medium-voltage
cable illustrated graphically in Figure 9-17a. These factors all apply to preloading at rated
ampacity at 40 ˚C ambient temperature. For lower ambient temperatures and when cable
ampacities have been increased to take this into account, the intermediate overload current
percent should be reduced by the following factors for each degree decrease in ambient
temperature below 40 ˚C:
For preloading less than 100% of rating, emergency overload percentages can be increased by
the following factors:
NOTE—This may safely be done only for permanent preloadings of these percentages.
Cable Factor
EPR-XLP 0.004
THH 0.002
THW 0.0037
Preloading
75% 80% 90%
All insulation types 1.33 1.25 1.11
IE
IN
----
-%
TE TO
–
TN TO
–
-------------------
- e
θK
–
–
1 e
θK
–
–
------------------------------------
-
230 TN
+
230 TE
+
---------------------
-
 
  100
=

IEEE
Intermediate time-current overload curves such as in Figure 9-17b can also be determined by
use of Table 9-6 and Table 9-7. An example of the use of the tables follows:
Example
Determine the intermediate time-current emergency overload curve for three, single-
conductor, #2 AWG copper, 5 kV EPR cables in conduit in air in an ambient temperature of
40 ˚C.
Figure 9-17a—Emergency overload current percent of continuous rating,
EPR-XLP cable, insulated, 40 ˚C ambient temperature

IEEE
For #2 AWG EPR cables in conduit in air, the K factor is 1.5 (see Table 9-5). NEC Table 310-
73 lists an ampacity of 130 A for #2 AWG, 5 kV copper cables in conduit in air. Incorporation
of these data into Table 9-6 is tabulated below:
9.5.2.5 Direct buried cables
With direct buried cables, the conductor operating temperature needs to be kept at no more
than 65 ˚C to keep the outside surface temperature below 60 ˚C, unless the supply of moisture
in the soil is ample. For higher surface temperature, moisture in the normal soil migrates
away from the cable, raising the soil thermal resistivity and resulting in overtemperature of
the cables. Therefore, for intermediate emergency overload, a maximum conductor tempera-
ture of 80 ˚C has been selected as suitable to preserve this thermal resistivity condition for the
Table 9-6—Emergency overload current IE,
percent of continuous rating at 40 ˚C ambient temperature
Time Values of K
s h 0.5 1 1.5 2.5 4 6
EPR-XLP TN = 90 °C TE = 130 °C
10 0.00278 1136 1602 1963 2533 3200 3916
100 0.0278 374 518 629 807 1018 1244
1000 0.278 160 195 226 277 339 407
10 000 2.78 126 128 132 140 152 168
18 000 5.0 126 127 128 131 137 147
THH TN = 90 °C TE = 105 °C
10 0.00278 725 1020 1248 1610 2033 2487
100 0.0278 250 338 407 518 651 794
1000 0.278 127 146 163 192 229 270
10 000 2.78 111 112 114 118 124 131
18 000 5.0 111 111 112 113 116 121
THW TN = 75 °C TE = 95 °C
10 0.00278 987 1390 1703 2197 2275 3396
100 0.0278 329 452 548 702 884 1080
1000 0.278 148 117 202 245 298 357
10 000 2.78 121 123 125 132 142 154
18 000 5.0 121 121 122 125 130 137

IEEE
Table 9-7—Emergency overload current IK,
percent of continuous rating at 20 ˚C ambient temperature, direct buried,
TN = 65 ˚C,TE = 80 ˚C
Time Values of K
(s) (h) 1.5 3 6
10 0.00278 1313 1853 2616
100 0.0278 427 594 834
1000 0.278 168 213 282
10 000 2.78 115 121 134
18 000 5.0 113 116 123
Figure 9-17b—Ratings of small and large cable in conduit in air,
intermediate and short-time, EPR and XLP

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times involved. Consequently, the tables and curves shown for air and duct use are not appli-
cable. Table 9-7 lists values applicable for direct buried installations. The short-time ratings
for 250 ˚C are still applicable for this service because the times involved do not cause mois-
ture migration.
9.5.2.6 Additional observations
The absolute values of the short-time temperature and the emergency operating loading tem-
perature are not precise. They are values selected and proven to apply to the respective cable
types without undue deterioration. For example, tests by Georgia Power Company [B10] of
fault conditions imposed on medium-voltage cable showed no appreciable degradation even
where the nominal short-time temperature was exceeded by about 50 ˚C. Likewise, the
130 ˚C emergency operating temperature has an applicable time value of 36 h for no undue
deterioration. Deducing that this insulation can tolerate a somewhat higher temperature (e.g.,
150 °C to 175 ˚C) for a time shorter than 36 h is only logical. This condition is undoubtedly
true, but its inclusion in calculations would complicate them unduly.
A compensating factor exists in the intermediate range. An overcurrent of from 10 s to 100 s
range, for example, would not have sufﬁcient time to cause heat to be dissipated by earth that
was in contact with the cable. Times of over 100 s, and certainly 1000 s, would see this region
of the heat dissipation chain contributing to the action. Therefore, attributing the surrounding
medium’s heat dissipation characteristics in the shorter portion of the intermediate zone is
illogical.Yet, a rigorous mathematical consideration would again substantially complicate the
analysis.
Therefore, a trade-off exists: the ability of insulation to withstand higher than nominal
operating temperatures for shorter periods is considered adequate compensation for the lack
of contribution of the surrounding media in absorbing heat during the shorter portion of the
intermediate zone. Without this convention, establishing both varying allowable temperatures
From Table 9-6
Percent of continuous-
current capability for
EPR-XPL at K = 1.5
Time
(s)
Allowable emergency overload
amperes based on 130 A
continuous-current rating
(40 °C ambient temperature)
1963 10 2552
629 100 818
226 1000 294
132 10 000 172
128 18 000 166

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and K factors over the whole range of the intermediate zone would be necessary, and such
calculations would be an undue burden when the present method yields satisfactory results.
Even the 36 h nominal limit for 130 ˚C operation for medium-voltage cable does not mean
that lower operating temperatures cannot be tolerated for longer periods. For example, to
illustrate the nature of the situation, 120 ˚C might be tolerated for 75 h, 110 ˚C for 150 h, and
100 ˚C for 500 h. Setting a continuous protective device to trip at precisely the 80 ˚C ampac-
ity is almost certain to result in nuisance tripping on power surges. Therefore, the device
would be set at, in all likelihood, something like 110% of rated cable ampacity, or an operat-
ing temperature of 100 ˚C. Visual or similar monitoring would be used to keep the continuous
loading of a cable from exceeding its rated ampacity for long periods of time.
9.5.3 Overload protective devices
9.5.3.1 TCCs
The time-current overload characteristics (see Figure 9-17a and Figure 9-17b) of the cables
differ from the short-circuit current characteristic (see Figure 9-2 and Figure 9-3). The over-
loads can be sustained for a much longer time than the short-circuit current, but the principle
of protection is the same. A protective device provides maximum protection if its TCC
closely matches the TCC of the cable overload characteristic. Thermal overcurrent relays
generally offer better protection than overcurrent relays because thermal relays operate on a
long-time basis and their response time is proportional to the temperature of the cable or the
square of its current.
9.5.3.2 Overcurrent relays
Very inverse or extremely inverse relays of the induction disk and solid-state types provide
better protection than moderately inverse relays. However, all induction overcurrent relays
can be set to afford the cables sufﬁcient protection. View (b) of Figure 9-5 shows the cable
protection given by overcurrent relays (Device 51) and by thermal overcurrent relays
(Device 49).
9.5.3.3 Thermal overcurrent relays or bimetallic devices
Thermal overload relays or bimetallic devices more closely resemble the cable’s heating
characteristic, but they are generally not as accurate as an overcurrent relay. View (b) of
Figure 9-5 shows the cable protection given by thermal overcurrent relays (Device 49); and
View (b) of Figure 9-7, protection given by bimetallic heaters.
9.5.3.4 Fuses
Where selected to match the ampacity of the cable, fuses provide excellent protection against
high-magnitude short circuits. Additionally, at 600 V and below, fuses provide protection for
overloads or low-current faults. Figure 9-5 and Figure 9-7 illustrate these applications.
Figure 9-7 illustrates a combination of fast-acting 400 A fuse and motor overload relays. Had

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a 225 A dual-element fuse (selected for the ampacity) been used, the fuse alone would have
provided overload protection.
Detailed treatment of fuses is given in Chapter 5 of this recommended practice, in Chapter 5
of IEEE Std 141-1993, in Chapter 5 of IEEE Std 241-1990, and in IEEE Committee Report
JH 2112-1.
9.5.3.5 Magnetic trip device or static sensor on 480 V switchgear
The magnetic trip devices have a wide range of tripping tolerances. Their long-time charac-
teristics match the cable overload curves for almost three quarters of an hour (see Figure 9-6).
Static trip devices provide better protection than magnetic direct-acting trip devices. How-
ever, for safe cable protection, the long-time pickup should be set below the heating curves of
the cable by sizing the cable with normal loading current slightly greater than the trip device
pickup current.
9.5.3.6 Thermal magnetic trip devices on MCCBs
The characteristics of the thermal magnetic trip devices resemble the characteristics of mag-
netic trip devices. They do not provide adequate thermal protection to cables during the
long-term overloads [see View (a) in Figure 9-7]. The cable should be selected and protected
in the same manner as described in 9.5.3.5.
9.5.4 Application of overload protective devices
9.5.4.1 Feeder circuits to panels
A single- or multiple-cable feeder leading to a panel with or without an intermediate pull box
should be protected from excessive overload by a thermal overcurrent device. If there are
splice joints and a different type of installation, such as from an exposed conduit to an under-
ground duct, the cable segment with the lowest current-carrying capacity should be used as
the basis for protection [see View (e) of Figure 9-8].
A single-cable feeder with taps to individual panels cannot be protected from excessive over-
load by a single protective device at the sending end, unless the cable is oversized. Therefore,
overload protection of the tap cable should be provided at the receiving end. The protection
should be based on the current-carrying capacity of the cable supplying power to the panel
[see View (f) of Figure 9-8]. A multiple-cable feeder with only a common protective device
does not have overload protection for each cable feeder. In this case, overload protection
should be provided at the receiving end [see View (g) of Figure 9-8]. See NEC
Article 240-21.
9.5.4.2 Feeder circuit to transformers
A feeder circuit to one or more transformers should be protected in a similar manner as for
feeder circuits to the panels. However, a protective device selected and sized for transformer
protection also provides protection for the primary cable because the cables sized for a full

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transformer load have higher overload capability than the transformer. [See View (a) of
Figure 9-5 for a comparison of the time-current curves between cable and transformer.]
9.5.4.3 Cable circuit to motors
A cable circuit to one or more motors should be protected in a similar manner as for cable cir-
cuits to panels. Again, a protective device selected and sized for motor overload protection
also provides cable protection because the cable has a higher overload capability than the
motor [see View (b) of Figure 9-7].
9.5.4.4 Protection and coordination
Protective devices should be selected and cables sized for coordinated protection from
short-time overload. The method of coordination is the same as for the short-circuit protec-
tion, that is, the time-current curve of the protective device should be below and to the left of
the cable overload curve (see Figure 9-17a and Figure 9-17b). Figure 9-5 through Figure 9-7
illustrate the protective characteristics of relays and devices commonly used in cable circuits
for overload protection.
9.6 Physical protection of cables
Cables require protection against physical damage as well as from electrical overload and
short-circuit conditions. The physical conditions that should be considered are divided into
three categories: mechanical hazards, adverse ambient conditions (excluding high tempera-
tures), and attack by foreign elements. Cables can also be damaged (and frequently are) by
improper handling during installation.
9.6.1 Mechanical hazards
Electric cables can be damaged mechanically by vehicles, falling objects, misdirected exca-
vation, or failure of adjacent circuits. Mechanical protection should serve the dual function of
protecting cables and limiting the spread of damage in the event of an electrical failure.
Isolation is one of the most effective forms of mechanical protection. Conduit, tray, and duct
systems are more effective if they are physically out of the way of probable accidents. A
highly elevated cable is adequately protected against vehicles and falling objects. Where con-
duits or other enclosures must be run adjacent to roadways, large steel or concrete barriers
provide adequate protection.
9.6.2 Exposed raceways
The most popular form of mechanical cable protection is the use of metallic conduits or race-
ways. In addition to the electrical beneﬁts of the grounded enclosure, the metallic conduit or
raceway protects the cable against most types of mechanical damage. Cable trays are also
common because they are economical and convenient for power and control cable systems.
Cables may have increased protection from mechanical damage through the use of solid

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metal tray covers and metal barriers in the trays between different circuits. Covers incur
derating, however.
9.6.3 Underground systems
Underground ducts or embedded conduits provide similar mechanical protection. Ducts
should be encased in concrete for best results. Where they are subject to heavy traffic or poor
soil conditions, reinforcement of the concrete envelope is desirable. Because excavation near
underground cable runs is always a problem, coloring the concrete around electrical ducts is
advisable. The addition of approximately 1.5 kg of iron oxide per sack of cement provides a
readily identifiable red color, which is meant as a warning to anyone digging into the run. The
color is effective even in mud or similarly colored soil because it is conspicuous as soon as
the concrete is chipped.
9.6.4 Direct buried cables
The direct buried cables should be carefully routed to minimize damage from traffic and dig-
ging and to avoid areas where plant expansion is predicted. Cables should be covered with
some type of special material, such as a brightly colored plastic strip or a wooden or concrete
plank. Warning signs should also be placed above ground at frequent intervals along the cable
route. Additionally, plant drawings accurately locating the buried cable run may also prevent
accidental dig-ins.
9.6.5 Aerial cable systems
Insulated cables on a messenger require special care. These systems are especially
susceptible to installation damage. They should be located away from possible interference
from portable cranes and support systems and protected from vehicle damage. Space or solid
barriers provide reasonable protection for supports, whereas warning signs and nonelectric
cables strung between electric cables and roadways offer protection against cranes and high
vehicles.
9.6.6 Portable cables
Exposed portable cables require extra consideration from a mechanical standpoint. Because
they must remain portable, enclosures are not practical. The proper selection of a portable
cable type provides one of the best methods of protection. It should be selected to match
operating conditions. Moisture resistance, resistance to cutting or abrasion, and type of armor
are all considerations that influence cable life. However, even the best cables require mechan-
ical consideration in service. They should not be subjected to vehicular or steel-tired
hand-pushed traffic. Means should be arranged to allow traffic to pass over or under cables
without contacting the cable. Care should also be taken in moving portable cables to avoid
snags or cuts. They should be located where they are clear of welding and where falling
objects are not a serious hazard. A conspicuous color on the jacket is beneficial in warning
personnel of the location of a portable cable.

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9.6.7 Adverse ambient conditions
In 9.4 and 9.5, protection from overtemperature caused by short-circuit current or overload
conditions has been discussed. Other ambient conditions, however, cannot be protected by
overcurrent devices or by compensation for elevated ambient temperatures.
In any type of cable enclosure, water or dampness should be considered, although under-
ground installations are the most susceptible. Repeated cycles of high and low temperature,
combined with humid air, can fill conduits or enclosures with water produced by “breathing”
and condensation. Stopping the breathing is almost impossible, but suitable drains at low
points will remove water as it collects. Preventing immersion is always desirable, and duct
systems and other raceways should be designed to slope so that the water can be removed.
Many of the available cable insulations are highly resistant to moisture; but where moisture is
expected, extra care should be taken in selecting the insulation appropriate for that
application.
In industrial plants, the moisture problem may be amplified by the presence of various chem-
icals, and the possibility of chemical contamination should be considered for cables run
through any process facility. Chemical seepage into ground water, or direct contact due to
process misoperation, may result in chemicals coming into contact with a cable system. The
enclosure, insulation, and conductor should all be tested to determine the effect of possible
chemical contaminants and selected to be most resistant to such chemicals. Where chemical
contamination is severe, rerouting of the system should be considered. Acids and organic sol-
vents are especially harmful.
Fires, which may result directly from cable failure or from unrelated external conditions, can
cripple almost any cable system. Protecting against damage to one cable caused by the failure
of an adjacent cable is easier than protecting against damage caused by an external fire. The
enclosure of individual power circuits and fireproof coatings or tapes are the most effective
means of limiting this type of damage because it is unusual for a cable with proper electrical
protection to burn through its individual conduit or raceway.
Pullboxes, pits, and manholes used as pulling points or sorting areas are the greatest fire
hazards with respect to fault conditions; and elimination of the common enclosure for several
circuits, where possible, offers the best protection.
The combustion of materials adjacent to a cable system is a difficult condition against which
to protect. The obvious solution is to remove all combustibles from the vicinity of the cables.
As much as possible, this practice should be undertaken. Critical circuits should be separated
to lessen the extent of fire damage, and the use of multiple circuits following different routes
can assure continuous service. Higher temperature-rated cable types might be considered for
increased safe shut-down time.
In all cases the selection of proper enclosures or coverings can minimize fire damage;
however, the method chosen should be based upon the possible hazards involved. For
underground installation, heavier enclosures, higher racks, and overinsulation using materials

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with greater temperature resistance are all considerations; and under severe conditions, the
use of mineral insulation (MI) cables may help.
9.6.8 Attack by foreign elements
In some environments, cable systems may be subject to attack by animals, insects, plants, and
fungi, all of which may possibly cause cable failure. Small, gnawing animals have been
known to chew through cables, and insects and small animals such as lizards and snakes can
cause difﬁculties at terminations where they or their nests may bridge the gap between termi-
nals. The use of more resistant enclosures, armor, or indigestible cable materials are effective
protection.
In tropical atmospheres, fungi may grow on cable and wire systems. The creation of a dry
atmosphere is an effective deterrent, although fungus-resistant coatings and insulations are
protection methods most often applied.
9.7 Code requirements for cable protection
Codes and regulations are established to control the installation and operation of electric
cable systems. Although many different codes and regulations may be applied, depending on
governmental, geographical, or company requirements, the NEC is most often quoted; and
portions of it are mandatory by the Occupational Safety and Health Administration’s (OSHA)
Part 1910.302-1910.309. The engineer is responsible for determining which codes are
applicable to each project. The discussion in this subclause is limited to the NEC, which is
principally concerned with overtemperature (or overcurrent), short-circuit, and mechanical
protection in regard to cable applications.
Overcurrent protection is covered in NEC Article 240 under the provision requiring all con-
ductors to be protected in accordance with their current-carrying capacities. In general, the
current-carrying capacity of cables is determined from the tables contained in Article 310,
which concerns the installation of conductors.
Protection of feeders or conductors rated 600 V or less should be in accordance with their
current-carrying capacities as given in NEC tables, except where the load includes motors. In
such cases, the protective device may be set higher than the continuous capability of the con-
ductor (to permit coordination on faults or starting the largest connected motor while the
other loads are operating at full capacity) because running overload protection is provided by
the collective action of the overload devices in the individual load circuits. Where protective
devices rated 800 A or less are applied that do not have adjustable settings that correspond to
the allowable current-carrying capacity of the conductor, the next higher device rating may be
used. Other exceptions are allowed in NEC Article 240-3, such as capacitor and welder cir-
cuits and transformer secondary conductors.
Feeders rated more than 600 V are required to have short-circuit protection, which may be
provided by a fuse rated at no more than 300% of the conductor ampacity or by a circuit
breaker set to trip at no more than 600% of the conductor ampacity. Although not required by

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the NEC, improved protection of these circuits is possible when running overload protection
is also provided in accordance with the conductor ampacity.
Motor feeders receive particular attention in NEC Article 430. In general, Article 430 governs
the selection of the current-carrying capacity of cables used for motor circuits. After the cable
size is selected in accordance with this article, the actual protection is applied in accordance
with Article 240.
NOTE—NEC Article 430 provides rules for the overcurrent protection of the motors themselves.
Although the discussion in this chapter concerns only cables, motor protective devices may also provide
the required cable protection.
NEC Article 310 ensures that cables are adequate for their service applications by specifying
currents that may be carried by particular conductors with specific insulation classifications
and under specific governing conditions. It also requires the selection of cable materials that
are suitable for application conditions, including moisture, chemicals, and nonstandard tem-
peratures. This article permits the use of multiple cables if means are provided to ensure the
equal division of current, and if essentially identical conditions and materials are used for
each of the parallel paths. Article 310 also covers installation methods designed to ensure the
installation of cables without damage and with adequate working space.
NRC Article 300 specifies wiring methods and protection required for cables subject to phys-
ical damage.
These articles pertain specifically to cable protection, but are not the only provisions of the
NEC that deal with the subject. Any specific cable or cable system comes under the
provisions of one or more sections of the NEC, and responsible parties should ensure that the
protective methods they have selected comply with both the relevant provisions and any
special requirements that they may impose.
9.8 Busway protection
Due to their economies, convenience, and excellent electrical characteristics, 600 V busway
systems have gradually assumed a role of greater importance in today’s industrial and com-
mercial buildings. Because numerous cable runs can be consolidated into a single large bus
duct run, the reliability of duct runs has become a critical factor in building design. Today’s
busways are well designed for their intended use. However, because of the critical nature of
their purpose, they must not only suffer fewer outages, they must also be returned to service
with a minimum of downtime. Thus, while the duct manufacturers can incorporate improved
design concepts, better insulation, and so forth, it behooves the system designer to spend an
extra amount of time on incorporating the best possible protection into the integrated system
so that outages due to factors beyond the designer’s control are minimized in duration. This
concept is important in that it does not suggest that the number of outages can be controlled.
It does, however, suggest that by minimizing the duration and extent of the outage, disruption
of the normal activities can also be minimized. The duration of the outage is to a certain
degree directly proportional to the amount of damage suffered by the busway during the fault,
and this amount of damage is determined by the protective elements in the circuit.

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9.8.1 Types of busways
Several different designs of busways are available, and each offers certain features that are
significant when considered in an integrated building plan. These features can be identified as
follows:
a) Low-impedance busways
1) Feeder
2) Plug-in
3) High-frequency
b) High-impedance busways
1) Service-entrance
2) Current-limiting
c) Simple plug-in busways
9.8.1.1 Low-impedance busways
Low-impedance busway designs (see Figure 9-18) achieve their low-reactance characteristics
by a careful positioning of each bus bar in close proximity to other bars of an opposite
polarity. This close physical spacing (ranging from 1.3 mm to 6.4 mm) demands that each bar
be coated with some form of insulation to maintain satisfactory protection from accidental
bridging. The losses in such designs are low. Low-impedance busways are offered in feeder
construction to transmit substantial blocks of power to a specific location or in plug-in
construction. Plug-in designs feature door-like provisions at approximately 0.6 m increments
along the length of the busway which, when opened, expose the bus bars so that plug-in taps
may be made with minimum effort. Although most low-impedance designs are intended for
use on 60 Hz applications, some designs may be used at higher frequencies. Low-impedance
designs are offered in voltage ratings of 600 V or less and current ratings up to 4000 A or
more. Low-impedance busways may be ventilated or nonventilated and offered in indoor or
outdoor construction, except that plug-in busways are available for indoor use only.
9.8.1.2 High-impedance busways
High-impedance busways (see Figure 9-19) are of two general types: busways with deliberate
impedance introduced to minimize fault current levels and busways that achieve high-imped-
ance characteristics as an incidental by-product of their construction.
In the first type, high reactance is obtained just as low reactance was, by a careful placement
of each bar relative to every other bar. In this case, however, the goal is to maximize the
spacing between pairs of bars of opposite polarity. Because these high-impedance designs
experience high losses and because these losses appear as heat, ventilated construction and
insulated conductors are frequently employed. They are offered in generally the same ratings
as low-impedance designs.
Under the provisions of some standards, a special purpose bus duct design may be built in
total installed lengths of 10 m or less to connect between an incoming service and a
switchboard. This duct generally is constructed with a nonventilated enclosure and bars that

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may or may not be insulated. The bars are physically separated, and this large separation,
introduced for safety, results in high-reactance characteristics. Short-run busways are limited
to 2000 A and 600 V.
9.8.1.3 Simple plug-in busways
Among the ﬁrst busway designs (see Figure 9-20) introduced in the mid-1930s was a simple
construction that supported bare conductors on insulators inside a nonventilated casing with
periodic plug-in access doors. Like the short-run busway, this type of duct offered generous
bar-to-bar spacings, but because it was not used to carry large quantities of current for
lengthy runs, its losses were not objectionable. Short-circuit ratings are usually modest. It is
still widely used today and is available in ratings of 100 A to 1000 A and voltages of 600 V
or less.
a) Sandwich construction for heat dissipation and close proximity of conductors, which reduces
reactance
b) Higher current ratings, which often employ multiple sets of bars
Figure 9-18—Low-impedance busway
b)
a)

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9.8.2 Types of faults
Faults associated with busways are either bolted or arcing.
9.8.2.1 Bolted faults
Due to the prefabricated nature of busways, bolted faults are rare. Bolted fault, in this context,
refers to the inadvertent fastening together of bus bars in a solid fashion resulting in an
unintended connection between phases. Bolted faults can occur during the initial installation
or at a later date when modifications are made to the system. The actual offending connection
might be found in a bus duct cubicle, but it is more often found in pieces of equipment
connected to the busway, such as a switchboard connection or a load served from a bus plug.
Because a bolted connection implies a low-resistance connection, the maximum level of fault
current will flow; therefore, circuit protective elements should be sized in accord with this
maximum fault level. Bolted faults result in a distribution of energy through the entire length
of the bus duct circuit. This energy flow results in an intense magnetic field around each
conductor that opposes or attracts fields around adjacent conductors. The mechanical forces
thus created are high and capable of bending bus bars (see Figure 9-21), tearing duct casings
apart, or shattering insulation. For this reason, the busway should have a short-circuit
withstand rating that is greater than the maximum available fault current. Such ratings are
published by the various busway manufacturers and are based on a duration of three cycles.
Table 9-8 reflects the standard ratings of the National Electrical Manufacturers Association
(NEMA) (see NEMA BU 1-1988 and UL 857-1994).
9.8.2.2 Arcing faults
In contrast to the bolted fault, arcing faults can occur at any time in the life of a system.
Although many individual factors may initiate an arcing fault, they generally involve one or
more of the following: loose connections, foreign objects, insulation failure, voltage spikes,
Figure 9-19—High-impedance busway where wide phase-to-phase spacings
result in increased reactance

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and water entrance. Because of the resistance of the arc and the impedance of the return path,
current values are substantially reduced from the bolted fault level.
The interaction of the magnetic ﬁelds around the conductors and around the arc results in an
unbalanced force that causes the arc to try to move away from the power source. If the path is
unobstructed, the arc accelerates and moves quickly toward the remote end of the run. The
only mark of its passage may be a scarcely noticeable pinhead-size pit every several centime-
ters along the edge of the bus bar. These tiny marks, however, provide a clear trail for the
investigator and often lead back to the origin of the fault. As the arc travels away from the
power source, the length of the circuit becomes greater and the forces causing movement
become smaller. Eventually, the arc reaches some obstruction that causes it to hesitate long
enough to cause serious burning or even hang up until the bus duct is burned open. Busways
employing insulated conductors, of course, do not permit traveling arcs. Arcing, therefore,
remains at the point of initiation or may burn slowly toward the source.
a) Bare bars spaced far apart offer generous electrical clearances and low cost.
b) Efficiency is low, but acceptable, for loads of 1000 A or less.
Figure 9-20—Simple plug-in busway
a)
b)

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Although the magnitude of current present in an arcing fault is usually less than in a bolted
fault, the entire thermal effect is concentrated at the arc location and results in major damage
at that point. Figure 9-22 indicates the damage anticipated in terms of the quantity of
conductor material vaporized by a phase-to-phase arc at 480 V. A 15 000 A arc persisting at
one location for 9 cycles would remove about half of the 6-mm-×-51-mm copper conductor.
This chart is based on a simple plug-in busway design with bars on 57 mm centers. Designs
with bars closer together or designs employing aluminum conductors may be expected to
show much more extensive damage. If the designer intends to minimize the duration of
system outages, concern should be directed toward the arcing fault. Even in an insulated bus,
arcing faults can persist, and the arc can extend from within the insulating tube to the
burned-out spot in the insulation, several centimeters to a similar crater within the adjacent
bus. Simple close spacing of an insulated bus does not guarantee against arcing faults.
9.8.3 Types of protection
Like any other circuit, busways are subject to overloads, bolted faults, and arcing faults. Each
of these is characterized by an entirely different set of parameters and, therefore, requires an
entirely different set of protective concepts. No single protective element suits all require-
ments. An examination of the required protection suggests the need for several protective
devices.
NOTE—The busway on the left was protected by current-limiting fuses while the busway on the
right was protected by a noncurrent-limiting device.
Figure 9-21—Simple plug-in busways subjected to fault currents
above their ratings

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9.8.3.1 Overload protection
Overloads are, of course, the temporary conditions that cause a busway to carry currents
greater than its continuous-current rating. Overloads such as stalled rotor currents or motor-
starting currents generally are not harmful to the busway because each motor served is
usually small in comparison to the capacity of the busway. Overloads are more likely to occur
as a result of adding more or larger pieces of equipment, over a period of years, to an existing
Table 9-8—Busway minimum short-circuit current ratings
Continuous current rating of
busway
(A)
Minimum short-circuit current
ratings
(A)
Plug-in Feeder Symmetrical Asymmetrical
100 10 000 10 000
225 14 000 15 000
400 22 000 25 000
600 22 000 25 000
600 42 000 50 000
800 22 000 25 000
800 42 000 50 000
1000 42 000 50 000
1000 75 000 85 000
1350 42 000 50 000
1350 75 000 85 000
1600 65 000 75 000
1600 100 000 110 000
2000 65 000 75 000
2000 100 000 110 000
2500 65 000 75 000
2500 150 000
3000 85 000 100 000
3000 150 000
4000 200 000
5000 200 000

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busway circuit until its capacity is exceeded. Because busways tend to use large conductors,
they exhibit considerable thermal inertia. For this reason, overloads of a temporary nature
require a substantial time before their effect is noticed. Figure 9-23 displays time versus
temperature rise for three different loading conditions. This particular busway required only
12 min to reach 55 ˚C at 200% current. The same busway took over 1 h to reach 55 ˚C at
125% loading. When operating at 100% loading, it required 25 min to raise the temperature
up to the 55 ˚C limit with a 25% overload. Naturally, this time varies from size to size
depending on the stable temperature produced by 100% loading. Most busway sizes are
designed to operate at close to a 55 ˚C rise at full current. The value of 55 ˚C was selected
because this value is the maximum rise allowed by Underwriters Laboratories (UL) on plated
bus bar joints. It was generally assumed that the busway will operate in a 30 ˚C ambient
temperature; and for this reason, busway manufacturers employed 85 ˚C insulation for many
years (30 ˚C ambient + 55 ˚C = 85 ˚C operating temperature). More recent designs of
busways employ higher temperature insulation, although they are still limited to a 55 ˚C rise
at the hottest spot. This fact suggests that busways operated in a 50 ˚C ambient temperature
could still carry full load (producing a 55 ˚C rise) without exceeding the 105 ˚C total
temperature limit of the newer insulations. Therefore, busways employing 85 ˚C insulation
NOTE—The bars are spaced on 57 mm centers in standard plug-in bus duct.
Figure 9-22—TCC for a power arc to burn
a 6-mm-×-51-mm copper bar halfway

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could easily suffer insulation damage should they be subjected to a high ambient temperature
or a moderate overload, or both. For this reason, any protective device should be sensitive to
overload conditions.
The 105 °C or 130 ˚C insulations are intended to provide increased protection from the
danger of high ambient temperatures or temporary overloads. The designer cannot apply
long-duration overloads even to these newer insulations without eliminating all the extended
life factors that they provide.
9.8.3.2 Arcing-fault protection
Arcing-fault currents in 480 V solidly grounded systems are found to be as low as 38% of the
bolted-fault line-to-ground current calculated for the same circuit. Such faults, because of
their destructive nature, should be removed with no intentional time delay. Unfortunately, the
magnitude of this current may be so low that the time-delay characteristics of the overload
protective device confuses the low-magnitude arcing fault with the moderate overload or
temporary inrush current and allows it to persist for lengthy periods. For example, a 200%
overcurrent on a fuse might require 200 s or more before the fuse functions.
Because the arc resistance and circuit impedance limit the current ﬂowing in an arcing fault,
most busway manufacturers offer an optional ground conductor, located inside the busway
casing, to provide a low-reactance ground path for arcing current. Without this conductor, the
arcing current to ground would be forced to travel on the high-impedance steel enclosure,
including its many painted joints. This would have a tendency to reduce the already low
current to an even lower level and further confuse the low-level protective device.
Figure 9-23—Time-temperature curves of 100%, 125%, and 200% loads on a
600 A rated low-impedance busway
(31-mm-×-57-mm aluminum bar per phase)

IEEE
The best protection against an arcing fault is found to be well insulated bus and the second is
ground-fault protection. Chapter 8 gives a more thorough discussion of this protection.
9.8.3.3 Bolted-fault protection
Bolted-fault currents can approach the maximum calculated available fault levels; therefore,
protective elements should be capable of interrupting these maximum values. Circuit break-
ers and current-limiting fuses are suitable in these cases.
Under certain conditions busways may be applied on circuits capable of delivering fault cur-
rents substantially above the busway’s short-circuit rating. Although electromagnetic forces
increase as the square of the current, the use of fast fuses permits busways to be applied on
circuits having available fault currents higher than the busway short-circuit rating. This is
because the busway rating is based on a duration of 3 cycles while Class J, Class R, Class T,
or Class L current-limiting fuses function in much less time, generally less than 0.5 cycle,
during high-level faults. The property of inertia exhibited by the heavy bus bars causes the
bars to resist movement during the short period of time that such fuses allow current to flow.
Current-limiting fuses limit the magnitude of fault current to their let-through values (see
Figure 9-24).
In general, a busway may be protected by a Class J, Class R, Class T, or Class L fuse against
the mechanical or thermal effects of the maximum energy the fuse allows to flow, providing
the fuse continuous-current rating is equal to the bus-duct continuous-current rating. Most
manufacturers have conducted tests and certify that their designs are satisfactory for use with
fuses at least one rating larger than the busway. These higher fuse ratings are often needed for
coordination with a circuit breaker in series with the fuse. UL lists busways for maximum
short-circuit currents when protected with specific circuit breakers or umbrella fuses.
9.8.3.4 Typical busway protective device
While no single element incorporates all the necessary characteristics, several elements may
be assembled into a single device. A particularly effective device is the fused circuit breaker
or fused switch equipped with ground-fault protection. In such devices, the circuit breaker
elements (or fuses in the case of a fused switch) provide operation in the overload or
low-fault range. In the fused circuit breaker, the coordinated current-limiting fuse functions
during high-level faults. The ground-fault sensor detects the arcing faults that go to ground
and, regardless of their low magnitude, signal the circuit breaker or switch to open.
9.8.4 Busway testing and maintenance
Several well-known tests should be performed before any busway is energized:
— Continuity check
— Insulation resistance test
— High-potential test

IEEE
These tests are conducted with the busway disconnected from the supply source and without
bus plugs attached.
9.8.4.1 Continuity check
By using a low-voltage source and a bell, the system should be checked to be sure that no
accidental solid connection exists between phases or from phase to ground.
9.8.4.2 Insulation resistance test
Application of a 500 V megohmeter test to the system indicates the insulation resistance val-
ues between phases and from phase to ground. While assigning speciﬁc acceptability limits to
meter readings is not practical, any reading of less than 1 MΩ for a 30.5 m run should be
investigated.
Figure 9-24—Typical 60 Hz peak let-through current as a function of
available rms symmetrical current; power factor below 20%

IEEE
9.8.4.3 High-potential test
Application of 1650 V for 600 V equipment between phases for 1 min while measuring the
leakage current should disclose incipient insulation failures.
9.8.4.4 Visual inspection
The importance of this step cannot be overemphasized. Periodic inspections to check for evi-
dence of excessive heat or accumulation of dust or foreign matter should be performed as part
of a normal preventive maintenance program. The frequency of such inspections should be
determined by the nature of the installation, but ideally it might take place after 3 months,
6 months, and 1 year to build a history and provide a basis for scheduling future inspections.
9.9 References
ICEA P-32-382-1999, Short-Circuit Characteristics of Insulated Cable.2
ICEA P-45-482-1999, Short-Circuit Performance of Metallic Shields and Sheaths on
Insulated Cable.
ICEA P-54-440, Ampacities of Cables in Open-Top Cable Trays.
ICEA S-19-81, Rubber-Insulated Wire and Cable for the Transmission and Distribution of
Electrical Energy.
ICEA S-61-402, Thermoplastic-Insulated Wire and Cable for the Transmission and
Distribution of Electrical Energy.
ICEA S-65-375, Varnished-Cloth-Insulated Wire and Cable for the Transmission and
Distribution of Electrical Energy.
NEMA BU 1-1988, Busways.3
NEMA WC 3-1993, Rubber-Insulated Wire and Cable for the Transmission and Distribution
of Electrical Energy.
NEMA WC 4-1988 (Reaff 1993), Varnished-Cloth-Insulated Wire and Cable for the Trans-
mission and Distribution of Electrical Energy.
2ICEA publications are available from ICEA, P.O. Box 20048, Minneapolis, MN 55420, USA
(http://www.icea.org/).

IEEE
NEMA WC 5-1992, Thermoplastic-Insulated Wire and Cable for the Transmission and Dis-
tribution of Electrical Energy.
NEMA WC 51-1986 (Reaff 1991), Ampacities of Cables in Open-Top Cable Trays.
(NEC®
).4
UL 857-1994, Busways and Fittings.5
9.10 Bibliography
[B1] AIEE Committee Report, “The Effect of Loss Factor on Temperature Rise of Pipe Cable
and Buried Cables, Symposium on Temperature Rise of Cables,” AIEE Transactions on
Power Apparatus and Systems, pt. III, vol. 72, pp. 530–535, June 1953.
[B2] Hamer, P. S., and Wood, B. M., “Are Cable Shields Being Damaged During Ground
Faults?” IEEE Transactions on Industry Applications, vol. IA-22, no. 6, pp. 1149–1159,
Nov./Dec. 1986.
[B3] ICEA P-46-426, Power Cable Ampacities for Copper and Aluminum Conductors.
[B4] ICEA S-66-524, Cross-Linked Thermosetting-Polyethylene Insulated Wire and Cable
for the Transmission and Distribution of Electrical Energy.
[B5] IEEE Committee Report, “Protection Fundamentals for Low-Voltage Electrical Distri-
bution Systems in Commercial Buildings,” IEEE JH 2112-1, 1974.6
[B6] IEEE Std 141-1993 (Reaff 1999), IEEE Recommended Practice for Electric Power Dis-
tribution for Industrial Plants (IEEE Red Book).
[B7] IEEE Std 142-1991, IEEE Recommended Practice for Grounding of Industrial and
Commercial Power Systems (IEEE Green Book).
[B8] IEEE Std 241-1990 (Reaff 1997), IEEE Recommended Practice for Electric Power Sys-
tems in Commercial Buildings (IEEE Gray Book).
[B9] Kaufmann, R. H., “Some Fundamentals of Equipment-Grounding Circuit Design,” pre-
sented at the AIEE Summer and Paciﬁc General Meeting, Los Angeles, CA, June 21-25,
1954.
USA(http://global.ihs.com/).

IEEE
[B10] Lee, R. H., “Rating Structure of Wire and Cable for Short and Intermediate Times,”
IEEE I&CPS Conference Record, 1977.
[B11] Neher, J. H., and McGrath, M. H., “The Calculation of the Temperature Rise and Load
Capability of Cable Systems,” AIEE Transactions on Power Apparatus and Systems, pt. III,
vol. 76, pp. 752–772, Oct. 1957.
[B12] NEMA WC 7-1993, Cross-Linked Thermosetting-Polyethylene Insulated Wire and
Cable for the Transmission and Distribution of Electrical Energy.
[B13] Shanklin, G. B., and Buller, F. H., “Cyclical Loading of Buried Cable and Pipe Cable,”
AIEE Transactions on Power Apparatus and Systems, pt. III, vol. 72, pp. 535–541, June 1953.
[B14] Wiseman, R. J., “An Empirical Method for Determining Transient Temperatures of
Buried Cable Systems,” AIEE Transactions on Power Apparatus and Systems, pt. III, vol. 72,
pp. 545–562, June 1953.

Chapter 10
Motor protection
This chapter applies specifically to three-phase integral horsepower motors. Many factors
should be considered in choosing motor protection: motor importance, motor rating (from
one to several thousand horsepower), thermal limit of rotor or stator, environment, power
system source and its neutral grounding method, type of motor controller, etc. Protection for
each specific motor installation should meet the requirements of the application. Power
quality of the plant distribution system should be given appropriate attention, especially with
regard to voltage sags and surges, harmonics, service interruptions, and operation of
distribution line reclosers. Items in 10.2 and 10.3 should be considered as checklists when
deciding upon protection for a given motor installation. After the types of protection have
been selected, manufacturers’ bulletins should be studied to ensure proper application of the
specific protection chosen.
10.1.1 Low-voltage systems
Low-voltage systems are nominally 1000 V or less. Table 3-11 of the IEEE Std 141-19931
lists the standard motor nameplate ratings along with the preferred horsepower limits for the
several standard motor voltages. At present, a maximum of 575 V and 750 kW exists for
motor nameplate ratings.
10.1.2 Medium-voltage systems
Medium-voltage systems range from 1000 V and up to 69 kV. Industrial and commercial
power systems operate with distribution voltages of 2.4 kV, 4.16 kV, 6.9 kV, and 13.8 kV and
above. The selection of the motor voltages is described in Chapter 3 of IEEE Std 141-1993.
10.2 Factors to consider in protection of motors
The factors in 10.2.1 through 10.2.10 should be considered when selecting motor protection.
10.2.1 Motor characteristics
Motor characteristics include type, speed, voltage, horsepower rating, service factor, NEMA
design (i.e., A, B, C, D, or E, which are the torque and speed characteristics for low- and
medium-voltage motors as described in NEMA MG 1-1998), application, power factor
rating, type of motor enclosure, bearing lubrication types, arrangement of windings and their
temperature limits, thermal capabilities of rotor and stator during starting, running, and stall
conditions. See Table 10-1.

IEEE
Table 10-1—Typical characteristics and applications of
fixed frequency medium ac polyphase squirrel-cage induction motors
Classification
Locked-
rotortorque
(percent
rated load
torque)
Breakdown
torque
(percent
rated load
torque)
Locked-
rotor
current
(percent
rated load
current)
Slip
Typical
applications
Relative
efficiency
Design B:
normal locked-
rotor torque and
normal locked-
rotor current
70–275a 175–300a 600–700 0.5–5% Fans, blowers,
centrifugal
pumps and
compressors,
motor-generator
sets, etc., where
starting torque
requirements are
relatively low
Medium
or high
Design C: high
locked-rotor
torque and
normal locked-
rotor current
200–250a 190–225a 600–700 1–5% Conveyors,
crushers, stirring
machines,
agitators,
reciprocating
pumps and
compressors,
etc., where
starting under
load is required
Medium
Design D: high
locked-rotor
torque and high
slip
275 275 600–700 5–8% High peak loads
with or without
flywheels such as
punch presses,
shears, elevators,
extractors,
winches, hoists,
oil-well pumping
and wire-
drawing
machines
Medium
Design E:
IEC 34-12
Design N:
locked-rotor
torques and
current
70–190a 160–200a 800–1000 0.5–3% Fans, blowers,
centrifugal
pumps and
compressors,
motor-generator
sets, etc., where
starting torque
requirements are
relatively low
High
NOTE—Design A motor performance characteristics are similar to those for Design B motors except that the
locked-rotor starting current is higher than the values shown in the table.
Reprinted from NEMA MG10-1994 by permission of the National Electrical Manufacturers Association.
aHigher values are for motors having lower horsepower ratings.

IEEE
MOTOR PROTECTION Std 242-2001
10.2.2 Motor-starting conditions
Motor-starting conditions include full voltage or reduced voltage, adjustable speed drive
(ASD), voltage drop and degree of inrush current during starting, repetitive starts, and
frequency and total number of starts. See Figure 10-1 and Padden and Pillai [B10].2
10.2.3 Ambient conditions
Ambient conditions include maximum and minimum temperatures, altitude, adjacent heat
sources, and ventilation arrangement.
10.2.4 Driven equipment
Load characteristics are important in the selection of the motor; otherwise, the driven
equipment may lead to locked rotor, failure to reach normal speed, excessive heating during
acceleration, overloading, and stalling. See Figure 10-2, which illustrates the relationship
between the accelerating current of a motor versus the thermal damage limits of the motor
during accelerating and running conditions. Present practice is to add an electronic reduced-
voltage starter for motors that may have accelerating problems or to add an ASD for motors
that could be operated at a reduced speed for some reasonable period of the duty cycle. The
protection of ASDs is not discussed in this chapter. For a detailed study of reduced-voltage
starting, read Chapter 7 of IEEE Std 241-1990.
2Numbers in brackets correspond to the numbers in the bibliography in 10.7.
Figure 10-1—Typical motor-starting and capability curves
(speciﬁc motor terminal voltage and for cold start)

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10.2.5 Power system quality
Power system quality issues include types of system grounding, exposure to lightning and
switching surges, capacitors and their controls for power factor correction, fault capacity,
exposure to automatic reclosing or transfer, possibilities of single-phase supply (e.g., broken
conductor, open disconnect switch or circuit breaker pole, blown fuse), and other loads that
can cause voltage unbalance. Another factor is harmonics, which may cause motor
overheating and affect the performance of electronic protective devices.
10.2.6 Motor importance
Factors that determine motor importance include motor cost, forced outage costs, amount of
maintenance and operating supervision to be provided, and ease and cost of repair or
replacement. A motor that is important to a plant’s operating continuity or process safety
should include a pre-trip alarm for operator intervention as a ﬁrst step. An example is to
initiate an alarm when a ground fault is detected on high-resistance-grounded neutral low-
voltage systems. This scheme can also be applied to medium-voltage systems below 13.8 kV;
but at the 13.8 kV voltage level, use of a trip, rather than alarm, is preferred.
Figure 10-2—Typical time-current and thermal limit characteristic curves

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10.2.7 Load-side faults for motor controllers
Although most of this subclause concerns low-voltage applications, the principles apply to
medium-voltage applications of motor controllers, as well. Calculation of available fault
current in a circuit is described in Chapter 2. Fuse and circuit breaker protection for
conductors in feeder and branch circuits are described in Chapter 5, Chapter 6, and
Chapter 7.
NOTE—Fuses and circuit breakers are rated for connection to available fault current sources on the
basis of protecting the conductors on the load side of the circuit breaker or fuse.
In a motor controller, the above philosophy does not necessarily extend to protect the motor
controller or its compartment. For proper protection of the motor controller, the fuse or circuit
breaker (or motor circuit protector) that the controller manufacturer has had tested by a
nationally recognized testing laboratory (NRTL) for the rated fault current available at its line
terminals should be used. A motor circuit protector has an instantaneous-only trip element,
similar in construction to a molded-case circuit breaker (MCCB), and is deﬁned in 10.4.1.4.
Such motor controllers for best results should bear an NRTL listing for connection to
available currents higher than the currents found in the power supply of the plant system
under consideration or projected plant expansion fault duty. The NRTL-listed controller may
still be substantially damaged by a load-side fault downstream of the controller. If protection
is necessary to minimize damage to the controller itself, the controller manufacturer should
be consulted, or Type 2 protection should be speciﬁed in accordance with IEC 60947-4-1-
2000.
Controllers connected to available currents above 10 000 A symmetrical should be provided
with fuses or circuit breakers rated to interrupt a fault at least equal to the line terminal fault
current, with provisions to prevent substitution of underrated fuses or circuit breakers. This
subject is covered more thoroughly under protection of low-voltage motors in 10.4.1.
10.2.8 Ground faults
Ground faults often start at a low current level and, if allowed to continue, lead to more
extensive damage. Whether an arcing or bolted fault, the initial damage is to motor windings,
but, if allowed to continue, could cause serious damage to the motor core. The cost to repair
or replace would then be more expensive. This subject is treated in more depth in Chapter 8.
10.2.9 Maintenance capability and schedule
Maintenance capability and schedule are important factors. Selection of complex protection
that cannot or will not be appropriately maintained can lead to inadequate protection.
Likewise, the selection and setting of overload protection do not prevent inadvertent setting
changes due to normal vibration or ambient conditions. Backup protection should be
coordinated to operate if primary protection fails to operate. Maintenance is covered in
Chapter 16.

IEEE
10.2.10 Service factor
The service factor of an ac motor is a multiplier which, when applied to the rated horsepower,
indicates a permissible horsepower loading that may be carried under the conditions speciﬁed
for the service factor (see NEMA MG 1-1998).
10.3 Types of protection
10.3.1 Purpose of motor protection
In a power system, the basic premise is that the delivered power is of acceptable quality to
satisfy the needs of the facility. However, an abnormal condition can exist due to plant
conditions or the external power supply. Depending upon the plant size and location,
conditions such as voltage transients, surges or sags, overfrequency or underfrequency,
harmonics, or discontinuity may develop that require corrective action. For large facilities,
the incoming power is likely monitored, and means have probably been taken to protect the
facility from abnormal conditions. This practice is important, because this chapter focuses
upon only motor protection. For smaller installations or unusual locations, plant protection
may be more integrated with motor protection.
The motor protective devices permit the motor to start and run, but initiate tripping and
removal of the motor circuit from the power system when the motor stalls, does not
accelerate, draws excessive current, overheats, vibrates excessively, or shows other symptoms
of improper motor conditions. Detection is through measurement of voltage, current,
temperature, frequency, harmonics, vibration, and speed, where appropriate. However, for the
majority of small motors (i.e., less than 220 kW), overcurrent is the most prevalent means.
In the discussion of protective devices in this chapter, reference is made to device numbers,
which are described in IEEE Std C37.2-1996. In general, medium-voltage protection resorts
to device numbers because of their convenience in lieu of using repetitive descriptions. The
subject of device numbers is adequately described in Chapter 4.
10.3.2 Abnormal power supply conditions (undervoltage protection)
10.3.2.1 Undervoltage
Although overvoltage conditions should have some consideration, that phenomenon draws
less attention because of protection by surge arresters for momentary conditions and relays
for the less common sustained overvoltage. This subclause concentrates on undervoltage
conditions. Further discussions concerning large motors can be found in 10.5.10.
Undervoltage protection is used as follows:
a) To prevent a motor from automatically restarting when voltage returns following an
interruption, as may happen with single-service arrangements or automatic transfer
operations. This protection can be accomplished either by controls or by an
undervoltage relay (Device 27). Consideration should also be given as to the

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importance of the motor and whether conditions warrant that the motor ride through
voltage sags or drop out at some specific voltage, not to be energized until other
conditions may have been met.
b) To avoid excessive inrush to the total motor load on the power system with a
corresponding voltage sag, following a voltage dip, or when voltage returns
following an interruption.
c) To avoid reaccelerating motors before their fields collapse. Fast asynchronous
reclosing has been damaging and can occur if cooperation is lacking between the
industrial plant and its power supplier. The power supplier should be consulted to
learn whether it follows the practice of adding time delay before reclosing circuit
breakers following an automatic trip. This delay is not a panacea, and some other
form of protection may be required, such as underfrequency relaying (Device 81).
10.3.2.2 Instantaneous or time delay
Undervoltage protection is either instantaneous (i.e., no intentional delay) or time-delay.
Time-delay undervoltage protection should be used with motors important to continuity of
service, providing it is satisfactory in all respects, to avoid unnecessary tripping on voltage
sags that accompany external short circuits. Examples follow of nonlatching starters where
time-delay undervoltage protection is not satisfactory and instantaneous undervoltage should
be used:
NOTE—The limitations in Item a) and Item b) could be overcome by using either a separate ac power
source for control or battery control on the contactor to prevent its instantaneous dropout. In other
words, the time-delay undervoltage feature can be applied directly to the main contactor.
a) Fusible switch or circuit breaker combination motor starters having ac magnetically
held contactors used on systems of low three-phase fault capacity. With the usual
time-delay undervoltage scheme, the contactor could drop out due to the low voltage
accompanying a fault on the load side of the contactor before the supply fuse or
circuit breaker opens to remove the fault. Unless provided with blocking for
automatic restart, the contactor could then reclose into the fault. This problem does
not exist if the available fault capacity is high enough to open the external fuse or
circuit breaker before the contactor interrupts the fault current.
b) Synchronous motors used with starters having ac magnetically held contactors. With
the usual time-delay undervoltage scheme, the contactor could drop out on an
externally caused system voltage dip, then reclose, and reapply the system voltage to
an out-of-phase internal voltage in the motor. The high initial inrush could damage
the motor winding, shaft, or foundation. This problem could also occur for large,
two-pole squirrel-cage induction motors. If asynchronous reclosing represents a risk
to the motor, undervoltage protection alone may not suffice; and an underfrequency
relay may be required. Asynchronous reclosing usually is not a problem with the
150 kW and smaller induction motors with which magnetically held contactor
starters are used because the internal voltages of these motors decay quite rapidly.
c) Motors used on systems having fast automatic transfer or reclosing where the motor
must be tripped to protect it before the transfer or reclosure takes place. See Item b)
regarding asynchronous reclosing needing an underfrequency relay.

IEEE
d) When the total motor load having time-delay undervoltage protection results in
excessive inrush current and voltage drop after an interruption. A problem could
arise of having insufficient system capacity to restart the motors. Options include
designing for a larger power capacity than needed for normal operations or removing
some of the motor loads from automatic restarting. Least important motors should
use instantaneous undervoltage protection. Time-delay undervoltage protection of
selectively chosen delays could be used on the motors whose inrush the system can
handle. Sequencers are available for selecting the order of motor restarts, thus
reducing the need for oversized transformers or lower transformer impedances.
Caution should be observed when placing numerous controls within one device
where common mode failure could negate the benefits.
10.3.2.3 With latching contactor or circuit breaker
Motor switching devices, such as latching contactors or circuit breakers, inherently remain
closed during periods of low or zero ac voltage. The following methods are used to trip open
the devices:
a) Energize shunt trip coil from a battery.
b) Energize shunt trip coil from a separate reliable source of ac. This ac source should
be electrically isolated from the motor ac source in order to enhance reliability.
c) Energize shunt trip coil from a capacitor charged through a rectifier from the ac
system. This method is commonly referred to as capacitor trip.
d) De-energize a solenoid and allow a spring release to trip the contactor or circuit
breaker.
Item a) through Item c) are usually used in conjunction with voltage-sensing relays (see
10.3.2.6). Item d) could have the solenoid operating directly either on the ac system voltage
or from a battery, where a relay would sense loss of ac voltage and de-energize the solenoid.
The solenoid could be either instantaneous or time-delay.
10.3.2.4 With ac magnetically held main contactor
Because the ac magnetically held main contactor (which supplies the motor) drops out on
loss of ac, it provides an instantaneous undervoltage function. If automatic restart is required
because of the process, two common approaches achieve time-delay undervoltage protection:
a) Permit the main contactor to drop out instantaneously, but provide a timing scheme
(which starts timing when ac voltage is low or zero) to reclose the main contactor
when normal ac voltage returns within some preset timing interval. Some of the tim-
ing schemes in use are as follows:
1) Capacitor charged through a rectifier from the ac system. The charge keeps an
instantaneous dropout auxiliary relay energized for an adjustable interval, which
is commonly 2 s or 4 s.
2) Standard timer that times when de-energized (e.g., pneumatic or inverse time-
undervoltage relay).

IEEE
b) Use a two-wire control. This control utilizes a maintained closed start button or oper-
ates from an external contact responsive to some condition such as process pressure,
temperature, or level. The main contactor drops out with loss of ac, but recloses when
ac voltage returns.
Neither arrangement provides perfect undervoltage protection and should not be used if
automatic restarting could endanger personnel or equipment.
10.3.2.5 With dc magnetically held main contactor
With a dc magnetically held main contactor, the contactor remains closed during low or zero
ac voltage. Time-delay undervoltage protection is achieved using voltage-sensing relays (see
10.3.2.6). For this scheme, the dc voltage should be monitored as well.
10.3.2.6 Voltage-sensing relays
A commonly used type of voltage-sensing relay is the single-phase inverse time-undervoltage
relay. Because a blown control fuse could cause tripping, two or three such time-undervoltage
relays are sometimes used, connected to different phases, and wired so that all must operate
before tripping occurs or re-energization can be permitted.
Three-phase undervoltage relays are available. Many operate in response to the area of the
voltage triangle formed by the phasors of the three-phase voltages. Alternatively, a voltage
balance relay (Device 60) could be used for blown fuse protection.
When applying undervoltage protection with time delay, the time-delay setting should be
chosen so that time-delay undervoltage tripping does not occur before all external fault-
detecting relays have had an opportunity to clear faults from the system. This practice
recognizes that the most frequent causes of low voltage are system faults; and when these
faults are cleared, most induction motors can continue normal operation. For inverse time-
undervoltage relays, their trip time versus system short-circuit current should be plotted to
ensure that they trip only after the system overcurrent protective relays. This procedure
should be done for the most critical coordination condition, which exists when the system
short-circuit capacity is minimum. This study should be included with normal systems
studies concerning voltage drop, short circuits, etc. Typical time delay at zero voltage is 2 s to
5 s.
For motors extremely important to continuity of service, such as some auxiliaries in electric
generating plants, the undervoltage relays are used only to alarm. The motors providing ﬁre
pump service should be protected in accordance with NFPA 20-1999.
10.3.3 Phase unbalance protection (Device 46, current) (Device 47, voltage)
10.3.3.1 Purpose
The purpose of phase unbalance protection is to prevent motor overheating damage. Motor
overheating occurs when the phase voltages are unbalanced. A small voltage unbalance

IEEE
produces a large negative-sequence current flow in both synchronous and induction motors.
The per-unit negative-sequence impedance of either motor is approximately equal to the
reciprocal of the rated voltage per-unit locked-rotor current. When, for example, a motor has
a locked-rotor current equal to six times rated current, the motor has a negative-sequence
impedance of approximately 0.167 per unit (16.7%) on the motor rated input kilovoltampere
base. When voltages having a 0.05 per-unit negative-sequence component are applied to the
motor, negative-sequence currents of 0.30 per unit flow in the windings. Thus, a 5% voltage
unbalance produces a stator negative-sequence current equal to 30% of full-load current. This
situation can lead to a 40% to 50% increase in temperature rise.
10.3.3.2 Single phasing
A special form of unbalance is the complete loss of one phase at the same voltage level as the
motor. Under starting conditions, a three-phase motor is unable to start. If the single phasing
occurs during full-load running conditions, the current in the other two phases increases to
approximately 173% of normal full-load current. In each case, adequate protection is
required. For large facilities, a bus phase-balance (negative-sequence) overvoltage relay
(Device 47) could be installed to alarm in a sensitive manner. This alarm would be set in
conjunction with individual large motor (phase-balance) negative-sequence overcurrent
relays (Device 46). For small installations, a single phase-balance (negative-sequence)
overcurrent relay may suffice for a large, important motor; or alternatively one phase-balance
(negative-sequence) bus overvoltage relay could be set to protect several motors, by alarming
and/or tripping.
When a motor is supplied from a delta-wye or wye-delta transformer, single phasing on the
supply voltage (primary) side of the transformer results in currents to the motor in the ratio of
115%, 115%, and 230% of normal. In two phases, the current is only slightly greater than
prior to single phasing, while it is approximately doubled in the third phase. This situation
requires a properly sized overload relay or time-delay fuse in each phase if the motor does not
have suitable phase unbalance protection.
Many motors, especially in the higher horsepower ratings, can be seriously damaged by
negative-sequence current heating, even though the stator currents are low enough to go
undetected by overload (overcurrent) protection. (The standard service factor for large motors
is 1.00.)
Therefore, phase unbalance protection is desirable for all motors where its cost can be
justified relative to the cost and importance of the motor. Phase unbalance protection should
be provided in all applications where single phasing is a strong possibility due to factors such
as the presence of fuses, overhead distribution lines subject to conductor breakage, or
disconnect switches (which may not close properly on all three phases).
A general recommendation is to apply phase unbalance protection to all motors 750 kW and
above. For motors below 750 kW, the specific requirements should be investigated. Phase
unbalance protection should also be considered for certain important motors such as hermetic
refrigeration chiller motors and similar motors having a service factor less than 1.25.

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10.3.3.3 Instantaneous or time delay
Unbalanced voltages accompany unbalanced system faults. Therefore, phase unbalance
protection should include sufficient delay to permit the system overcurrent protection to clear
external faults without unnecessary tripping of the motor or motors.
Delay is also necessary to avoid the possibility of tripping on motor starting inrush.
Therefore, unbalance protection having an inherent delay should be chosen. Another (high-
risk) scheme is to use an auxiliary timer (Device 62). Its selection is important because the
timer probably has a higher failure rate than the protective relay. If a time delay of more than
2 s or 3 s is used, the motor designer should be consulted.
10.3.3.4 Relays
Several types of relays are available to provide phase unbalance protection, including single
phasing. Most of these relays are described in Chapter 4 and in IEEE Std C37.96-2000.
Further information about specific relays should be obtained from the various manufacturers.
Most of the commonly used relays can be classified as follows:
a) Phase current balance (Device 46). Phase current balance relays are induction disk
devices that detect unbalance in the currents in the three phases. As such they have an
inherent time delay. Occasionally, a timer may be required to obtain additional delay.
Because this relay cannot protect for unbalances less than 25%, its selection is
questionable except for complete loss of one phase. Unfortunately, this device shares
the same device number as the negative-sequence overcurrent relay (Device 46) in
Item c).
b) Negative-sequence voltage (Device 47). Because negative-sequence voltage relays
may operate instantaneously on negative-sequence overvoltage, some external time
delay may be necessary.
c) Negative-sequence overcurrent (Device 46). A negative-sequence overcurrent relay is
a time-overcurrent relay with extremely inverse characteristics that operates at very
low levels of negative-sequence current. Settings are available to alarm before trip
and to trip upon a limit of I2
2
t.
10.3.4 Overcurrent protection (Device 51, inverse time) (Device 50,
instantaneous)
Overcurrent sensing is the most frequently used method to monitor and protect the many
power circuits in a facility. If a short circuit occurs, the action must be initiated without delay,
whereas an overload within the service factor rating may not require any action. Under
Chapter 15 guidelines, no delay should occur in the operation of the protection for circuit
components (e.g., motors) upon sensing a fault, with backup protection coordinated by being
delayed in time or overcurrent magnitude, or both.
Motor branch circuit protection is to operate whenever a motor fails to accelerate,
when the motor-running current exceeds normal limits, and when a short circuit is detected.
Time-overcurrent devices are normally used to protect against overloads and failure to

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accelerate, whereas instantaneous devices operate without any intentional delay for short-
circuit protection.
Depending upon the motor rating and voltage, the devices for performing these functions are
of different construction. For medium-voltage or large motors, the protection may be in the
form of three phase-overcurrent protective relays or one multifunction relay (Device 11),
which would include such other protective functions as accelerating characteristics, current
unbalance, differential overcurrent, ground-fault current, and loss of load. Such complex
protection would normally not be provided for unimportant low-voltage motors, although
capable multifunction devices are available for low-voltage motor protection. In addition,
some motors may be supplied directly from low-voltage switchgear and use the protective
characteristics described in IEEE Std C37.17-1997 and shown in Chapter 7. The decision on
whether to use low-voltage switchgear is usually inﬂuenced by the frequency of motor starts
because motor controllers are rated for a considerably greater number of operations.
10.3.5 Multifunction relay (Device 11)
An important development has been the multifunction motor protection relay. Recognized as
a powerful tool, the multifunction relay incorporates many protective functions that would
normally be applied through the use of individual protective relays, but are all incorporated
into one enclosure. For example, the relay incorporates short-circuit and overcurrent
protection in each phase- and ground-fault protection. Depending upon the options selected,
the relay could include protection against stalls, locked rotor, overtemperature alarm or trip,
current unbalance, metering, and communications. No detailed discussion of the relay is
included in this subclause because the possible functions are described under other protective
relays, such as Device 50 and Device 51.
10.4 Low-voltage motor protection
Conventionally, low-voltage motors drive small process equipment and auxiliary equipment.
These motors, usually 220 kW and below, may operate continuously or may be in cyclical
services. These applications use motor contactors in motor control centers (MCCs) or
combination starters.
One-line diagrams of typical low-voltage starters for industrial applications using MCCs or
combination starters are shown in View (a), View (b), View (c), and View (d) of Figure 10-3.
10.4.1 Low-voltage motor overcurrent protection
Overload protection for low-voltage motors is usually provided by thermal overcurrent relays
or electronic overcurrent devices. In some cases, dual-element fuses or a thermal-magnetic
circuit breaker may serve as the primary overload devices, but are normally backup
protection for overload relays. Short-circuit protection for low-voltage motors is usually
provided by fuses, a thermal-magnetic circuit breaker, or an instantaneous trip device (or
motor circuit protection) in combination with an overload relay. Ground-fault protection for
low-voltage motors is usually provided by the short-circuit protection device, but ground-

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fault relays may be installed. (See Bradﬁeld and Heath [B1]; Nailen [B8]; Gregory and
Padden [B4] and [B3]; Smith [B12].)
10.4.1.1 Thermal and electronic overload relays
Thermal overload relays are constructed as either melting alloy or bimetallic. Although
single-phase elements are the most common, they are also furnished in a three-phase
construction block design. The relays are designed to operate within a current range, as
follows:
a) Selection of the heater element should be based upon the relay manufacturer’s tables
relating motor characteristics and ambient temperature conditions and based on the
location of the motor relative to the relay. This method is employed because only
minor adjustments need be made in the relay itself to set a trip value to match the
motor current.
b) After the selection of the heater, the melting alloy unit is considered nontamperable.
c) Older bimetallic types may have limited adjustment of trip setting intended to
compensate for ambient temperature. Newer relays have a wider range of adjustment.
a) Typical starter with fuses
b) Typical starter with a circuit breaker
c) Typical location for power factor correction capacitors
d) Typical location for a control power transformer
Figure 10-3—Typical low-voltage starter one-line diagrams for industrial
applications using MCCs or combination starters

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d) The thermal memory of bimetallic overload relays provides satisfactory protection
for cyclic overloading and closely repeated motor starts.
e) A manual reset feature is available and is normally trip free (i.e., manual override is
not possible).
f) Some relays are available as ambient-temperature-compensated or as
noncompensated. Noncompensated is an advantage when the relay and motor are in
the same ambient because the relay opening time changes with temperature in a
similar manner as the motor overload capability changes with temperature.
g) NEMA ICS 2-2000 has standardized motor overload relays into three classes
denoting time delay to trip on locked-rotor current: Class 10 for fast trip, 10 s at six
times the overload rating; Class 20, for intermediate trip, for 20 s at six times the
overload rating; and Class 30 for long-time trip, 30 s at six times the overload rating.
In most applications, the Class 10 relay is applied for hermetic and other motors with
a service factor of 1.00 or 1.05. The Class 20 relay is commonly used for higher
service factor motors, such as NEMA Design T frame motors. A Class 30 relay is
used in applications where high-inertia loads cause the motor to have a long starting
time, such as conveyor belt motors. Electronic devices, sometimes integral with the
contactor, sense the current in all three phases. They can be adjusted for Class 10,
Class 20, or Class 30.
Overload relays are sized in accordance with the National Electrical Code® (NEC®)
(NFPA 70-1999). Article 430-32, Article 430-33, and Article 430-34 reference the motor
nameplate rating. Power factor correction capacitors installed for individual motors may be
connected as shown in View (c) of Figure 10-3, and no current adjustment need be made to
the overload devices. However, this connection is not the only method of providing individual
power factor correction and has been known to cause contactor failures due to resonance with
other motor capacitors (see Nailen [B8]). When capacitors are installed between the overload
device and the motor, the overload relay provides circuit impedance, which generally
dampens the resonance problem. However, the overload relay current rating should be
adjusted to account for the reduced current ﬂowing to the motor-capacitor combination.
Part 14.43.3 of NEMA MG 1-1998 recommends a bus connection when several motors are
connected to the bus in order to minimize the potential harmonic resonance.
Overload relays and other devices for motor overload protection that are not capable of
opening short circuits shall be protected by fuses or circuit breakers with ratings or settings in
accordance with NEC Article 430-52 or by a motor short-circuit protector in accordance with
NEC Article 430-52.
10.4.1.2 Time-delay (or dual-element) fuses
Time-delay fuses are available from 0.1 A through 600 A. Fuses for short-circuit and ground-
fault protection shall be sized in accordance with NEC Article 430-52 and Table 430-152.
The full-load current values used for that table are in Table 430-148, Table 430-149, and
Table 430-150. The rating of a time-delay fuse shall be permitted to be increased, but in no
case exceed 225% (400% for Class CC fuses) of full-load current. A one-line diagram of a
typical starter with fuses is shown in View (a) of Figure 10-3. Also available are fuses without

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time delay, which can provide short-circuit and ground-fault protection, but may not provide
any backup protection.
10.4.1.3 Inverse-time circuit breakers
These circuit breakers (i.e., molded case) are available from 10 A through 3000 A when
constructed with thermal-magnetic trip elements, and up to 5000 A when constructed with
solid state trip elements. Both types of trip devices are referred to in the NEC as inverse-time
circuit breakers and shall be sized in accordance with NEC Article 430-52 and Table 430-
152. The full-load current values used for that table are in Table 430-148, Table 430-149, and
Table 430-150. The rating of an inverse-time circuit breaker shall be permitted to be
increased, but in no case exceed,
— 400% for full-load currents of 100 A or less,
— 300% for full-load currents greater than 100 A.
A one-line diagram of a typical starter with a circuit breaker is shown in View (b) of
Figure 10-3.
10.4.1.4 Instantaneous trip circuit breakers (or motor circuit protectors)
Instantaneous trip circuit breakers (i.e., molded-case), commonly called motor circuit
protectors, are available from 3 A through 1200 A. The instantaneous setting can typically be
adjusted in ﬁxed steps to between 3 to 13 or 3 to 10 times the continuous-current rating.
Instantaneous trip circuit breakers are tested under UL 489. The trip range of the breaker
should be within +30% or –20% of the set point. On the coordination plot, these devices have
a broad bandwidth corresponding to these tolerances.
These breakers are referenced as instantaneous trip breakers and shall be sized in accordance
with NEC Article 430-52 and Table 430-152. The full-load current values used for that table
are in Table 430-148, Table 430-149, and Table 430-150. Trip settings above 800% for other
than Design E motors and above 1100% for Design E motors shall be permitted where the
need has been demonstrated by engineering evaluation. In such cases, it shall not be
necessary to ﬁrst apply an instantaneous trip circuit breaker at 800% or 1100%. Either an
adjustable instantaneous trip circuit breaker or a motor short-circuit protector shall be used
when it is part of a listed combination controller having coordinated motor overload, short-
circuit, and ground-fault protection in each conductor and if it operates at not more than
1300% of full-load motor current for other than NEMA Design E motors and no more than
1700% of motor full-load current for Design E motors. A one-line diagram of a typical starter
with a circuit breaker is shown in View (b) of Figure 10-3.
Two points should be reviewed by the engineer. First, the overload device is normally the
only line of protection from overloads and high-impedance faults when using instantaneous
trip circuit breakers. A failure of the overload device, the overload wiring, or the contactor
can prevent the circuit from being isolated due to overload or high-impedance fault
conditions. Where backup protection is desired for these abnormal conditions, an inverse-
time circuit breaker or dual-element fuses should be selected.

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Second, the selection of the contactor and conductor sizes depends on the setting of the
instantaneous trip function. NEMA-rated magnetic contactors are tested to break up to
10 times the full-load current values given in NEC Table 430-148, Table 430-149, and
Table 430-150 for the corresponding horsepower rating of the contactor. When an overload
device trips, the contactor is called upon to open the circuit. Therefore, the contactor should
be rated to break the circuit. Under high-impedance fault conditions, the current may be in
the range of 10 to 17 times the motor full-load current. The instantaneous trip breaker may be
set above the 10 times full-load current break test value of the contactor. Refer to Figure 10-4
for the time-current curves of a 480 V, 75 kW motor application with a 175 A instantaneous
trip breaker, a Class 20 overload, and a NEMA size 4 magnetic contactor (i.e., 1350 A break
rating). This ﬁgure illustrates a case where the instantaneous trip is set about 12 times the
full-load current of 124 A (see NEC Table 430-150). The #2/0 AWG XHHW conductor is
rated for 175 A at 75 °C. The contactor is not protected using the setting of about 1500 A. A
lower instantaneous setting would protect the contactor, but some motors may trip the breaker
on starting. Contactors for NEMA Design E motors shall have a horsepower rating not less
than 1.4 times the rating of a motor rated 3 kW through 75 kW, have a rating not less than 1.3
times the rating of the motor rated over 75 kW, or be marked for use with a Design E motor
(see NEC Article 430-83, Exception No. 1).
In a recently published book, the authors reveal that some high-efﬁciency motors draw up to
2.83 times locked-rotor current during starting, and they recommended a 19.2 times full-load
current on the instantaneous breaker setting, approximately 3 times locked-rotor current in
one case (see Prabhakara, et al. [B11]). A typical value used in the industrial applications is
1.76 times locked-rotor current for estimating asymmetrical inrush current. To prevent false
tripping of the instantaneous trip breaker on starting, several options are available:
a) Use an autotransformer or other means for reduced voltage starting to limit the inrush
current.
b) Specify a contactor with a higher break rating and set the instantaneous breaker at a
higher setting within the NEC limits.
c) Use an inverse-time circuit breaker in place of the instantaneous trip breaker so that
the instantaneous setting, if available, can be set above the motor inrush current.
10.4.2 Low-voltage motor ground-fault protection
Many low-voltage motor applications utilize fuses or MCCBs for ground-fault protection.
However, the type of protection selected is dependent upon the type of system grounding.
10.4.2.1 Solidly grounded systems
Fuses and circuit breakers normally provide adequate ground-fault protection for motors on
solidly grounded systems. However, for larger motors applications, such as the 75 kW motor
shown in Figure 10-4, miscoordination occurs. For example, this motor is protected by an
instantaneous only circuit breaker set at 1500 A trip. The main breaker ground trip is set at
1200 A, the maximum allowed by NEC Article 230-95, where a shutdown does not introduce
additional hazards. Miscoordination can occur in the region between the ground trip device
on the main low-voltage power circuit breaker (LVPCB) and the instantaneous trip circuit

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breaker protecting the motor. LVPCBs, speciﬁed with long-time and short-time functions
only (i.e., no instantaneous element), can usually be coordinated selectively.
If selectivity between the individual motor protective device and the main breaker is desired
for ground faults, additional protective devices should be installed for the larger motors or
interlocking ground-fault devices should be installed. For solidly grounded systems, the
protective devices should be wired to open the breaker, not the contactor, unless the
contactors are rated high enough to interrupt the available fault current. Some breakers have
integral solid-state devices that sense ground faults and open the breaker. Contactors may
also have integral solid-state devices that sense ground faults, but these may open the
contactor. Also, zero-sequence current transformers (CTs) and trip units can be installed to
shunt-trip the circuit breakers or switch, provided that the circuit breaker or switch has a
shunt trip, which is not necessarily included on the circuit breaker or switch unless ordered
that way.
NOTE—The contactor is not protected using the 1500 A setting. The motor asymmetrical inrush
current will probably trip the breaker when starting.
Figure 10-4—Time-current curve for a 480 V, 75 kW motor with a size 4
contactor, Class 20 overloads, and an instantaneous trip circuit breaker with
a setting of 12 times full-load current

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10.4.2.2 Low-resistance-grounded systems
Low-resistance-grounded systems are not normally used on low-voltage applications. For
low-resistance-grounded systems (e.g., between 200 A to 400 A), ground-fault currents may
not be high enough to trip the MCCBs or to open fuses in a timely fashion, particularly for
larger motors.
10.4.2.3 High-resistance-grounded systems
For high-resistance-grounded systems, where the fault current is usually 5 A to 10 A range,
no individual motor ground-fault protection is generally provided. Instead, an alarm at the
grounding resistor signals that a ground fault has occurred. A ground pulsed signal is used to
locate the fault. The faulted circuit is then manually cleared. Caution should be used when
selecting conductor insulation materials and ratings for use on high-resistance-grounded
systems, particularly on smaller conductors (e.g., size 10 and below). Zone selective interlock
(ZSI) tripping is another type of ground-fault protection that permits the first ground fault to
be alarmed only, with rapid tripping following a ground fault on a different phase. This trip
rating illustrates the advantage of high-resistance grounding when operation may continue
during the presence of the first ground fault. Removal of the first ground fault is important,
however, in order to prevent escalated damage from a second ground fault on a different
phase. The MCCBs used in high-resistance-grounded systems should be rated for line-to-line
voltage (e.g., 480 V not 480/277 V for a 480 nominal system voltage). (Also the single-pole
interrupting rating should be checked to clear the second fault on a different phase: ground as
well as line-to-ground faults on two separate phases, one on each side of the breaker. See
Gregory [B2].)
10.4.3 Low-voltage motor stator winding overtemperature
The purpose of stator winding overtemperature protection is to detect excessive stator
winding temperature prior to the occurrence of motor damage. In low-voltage motors in
noncritical services, the temperature sensors are normally wired to trip the motor control
circuit and open the contactor.
10.4.3.1 Thermostat winding overtemperature devices
Thermostats are the most common type of stator temperature sensors installed in three-phase
industrial service 460 V motors from 11 kW through 150 kW. Many manufacturers wind the
stators with the devices installed and cut off the leads if a customer does not specify the
protection. Thermostat devices are bimetallic, normally closed devices that operate at one
fixed temperature. They are normally wired in series with the control circuit at 120 V. These
devices are normally sealed from the atmosphere, but are not rated as hermetically sealed for
hazardous NEC Class 1 Division 2 areas.

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10.4.3.2 Thermistor winding overtemperature devices
Thermistors are used to operate relays for either alarm or trip functions, or both. They have
resistance characteristics that are nonlinear with respect to temperature and thus are not used
to indicate temperature. Two types of thermistors exist:
a) Positive temperature coefficient. The resistance of a positive temperature coefficient
thermistor increases with temperature. An open circuit in this thermistor appears as a
high-temperature condition and operates the relay. This arrangement is fail-safe.
b) Negative temperature coefficient. The resistance of a negative temperature coefficient
thermistor decreases as temperature increases. An open circuit in this thermistor
appears as a low-temperature condition and does not cause relay operation.
10.4.3.3 Resistance temperature detector (RTD) winding overtemperature
devices
RTDs are not normally installed in low-voltage motors unless the service is critical. In those
cases, the RTDs are usually connected into a device that provides an alarm-only function. The
most common practice is to install six RTDs, two per phase, of the 120 Ω platinum elements.
More information on RTDs is contained in 10.5.3.1.1.
10.4.4 Low-voltage motor undervoltage protection
Undervoltage protection is used to protect motors from several damaging conditions: low
voltage due to a voltage sag, automatic reclosing or automatic transfer, and power restoration.
In a voltage sag, the motor draws more current than normal and has unusually high heating.
Excessive heating can be a serious problem in hazardous areas where the motor must stay
within its T marking.
When the supply voltage is switched off during automatic reclosing and transfers, the motors
initially continue to rotate and retain an internal voltage. This voltage decays with motor
speed and internal flux. If the system voltage is restored out of phase with a significant motor
internal voltage, high inrush can occur. Such current can damage the motor windings or
produce torques damaging to the shaft, foundation, drive coupling, or gears.
IEEE Std C37.96-2000 discusses considerations for the probability of damage occurring for
various motor and system parameters.
When power is restored after an outage, the starting sequence should be programmed so that
all motors on the system are not starting simultaneously. This step is important for the
generating equipment, as well as for transformers and conductors. Undervoltage devices are
not normally installed on essential loads such as motors for fire pumps.
10.4.4.1 Undervoltage relays
Low-voltage undervoltage relays are typically electronic devices that monitor all three
phases. These devices can be furnished with a time delay to trip, a time delay to restart, or
instantaneous for trip and restart. Usually, the designer sets the device at 85% of line voltage

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with a time delay off and a time delay for restart. Normally, the undervoltage relays are wired
into the motor control circuit to open the contactor.
10.4.4.2 Undervoltage sensors for circuit breakers
Some MCCBs have an undervoltage sensor adapter that trips the circuit breaker on a low-
voltage condition. The circuit breakers are reset manually. Where automatic restart is
necessary, this method should not be used. These sensors may not be as reliable as separate
undervoltage relays, and this factor should be considered when designing the circuit.
10.5 Medium-voltage motor protection
Conventionally, large motors drive the main process equipment and would operate
continuously for the length of the batch process. Because of this infrequent starting, medium-
voltage circuit breakers are often used to apply the power to the motors. Medium-voltage
motor voltage ratings are 2300 V, 4000 V, 4600 V, 6600 V, and 13 200 V per Part 20.12 of
NEMA MG 1-1998. When a motor must be started frequently, it may be necessary (even
economical) to use motor contactors in a combination controller with a current-limiting fuse
or circuit breaker because of the greater life of the contactors. Care should be exercised when
applying fused contactors on solidly grounded neutral systems because the contactor is
incapable of interrupting high fault currents, especially ground faults. As a result, ground-
fault relays and differential relays may not be safely applied. The risks could be minimized
by having the manufacturer perform short-circuit tests on the combination controller to
conﬁrm its safe performance to interrupt the fault on the system to which it is applied. In this
subclause, the text refers to the use of circuit breakers for the main device to both close and
open the motor circuit. The text describing combination controllers for medium-voltage
motors is generally similar to low-voltage combination controllers discussed previously.
In principle, the protection of medium-voltage motors is similar to low-voltage motors, but
the requirements are more demanding. Being closer to the utility source, medium-voltage
motors are more susceptible to voltage sags and surges, reclosing, and higher available fault
levels. Because of the higher bus voltage and load currents, instrument transformers are used
to reduce these currents to lower values, which can be used with protective relays, described
in Chapter 4. The most common instrument transformer secondary ratings are 120 V for
voltage transformers (VTs) and 5 A for CTs, described in Chapter 3. The circuit breakers
[i.e., air, sulfur hexaﬂuoride (SF6), vacuum], instrument transformers, and protective relays
are mounted in switchgear.
10.5.1 Medium-voltage motor overcurrent protection
In Figure 10-6, Figure 10-7, and Figure 10-8, some techniques illustrate different approaches
applied to large motors. The accelerating curve has been shown slightly differently in each
case to demonstrate that no one curve is accepted as a standard, and the motor accelerating
curve should be provided by the motor or equipment supplier before setting the relays. High-
inertia motors often take a much longer time to accelerate and, without proper protection,
could lead to nuisance tripping. In addition, a low-voltage condition can also lead to a longer

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accelerating time, thus necessitating careful selection of the type of overcurrent relays and
their settings. A good practice for these motors is to request motor acceleration curves that
are plotted for the cases of 100% and 80% actual motor starting voltages. Under 10.5.2.1,
some techniques are shown on how to resolve this protection. In some cases, relaying may
not adequately solve the problem, and a turning gear motor has been applied to start the large
inertia motor in at least one case. This latter concept is expensive and is not a
recommendation.
In Figure 10-5, a NEMA Design A or Design B motor curve is shown with protection for
starting and running easily made using a Device 51, a time-overcurrent relay element with
inverse or very inverse characteristics. Within the overcurrent relay is a second element, a
Device 50, which operates without delay to protect against a short circuit. Normally three
overcurrent relays are used, each phase relay supplied from its own CT. Some designers use
only two of the three relays for overcurrent protection, and set Device 51 of the third relay
relatively low (i.e., 110% to 120% of the full-load current) to alarm on an overload condition.
Codes may not permit this practice in some cases, and redundancy is lost during relay testing.
In this latter scheme, the two protective phase relays could be set for extreme overcurrent
conditions at 125% to 140% of the full-load current.
In Figure 10-6, protection for a high-inertia motor allows for the longer accelerating time.
Whereas a conventional motor reaches rated speed within 10 s to 15 s, a high-inertia motor
may take 30 s to 40 s. As a result, little time difference exists between the accelerating current
curve and the motor thermal limits. Several approaches are available, as shown in Figure 10-
6 and Figure 10-7, and an impedance method is shown in Figure 10-8. In Figure 10-6,
Figure 10-5—Conventional overcurrent relay protection of motor

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Device 51 has long-time inverse or very inverse characteristics, set above the accelerating
current. (Definite time delay is another term to describe this element.) Device 50 (HDO) is a
high dropout element that rapidly resets when the starting current drops to a magnitude of
85% to 90% of the set current without delay. For starting, a time delay of less than 1 s occurs
in order to permit the Device 50 (HDO) to be set at 1.15 of locked-rotor current. This delay
prevents false trips due to the asymmetrical starting currents, yet provides short-circuit
protection after the time delay. A second Device 50 is set at approximately two times the
locked-rotor current to protect against short circuits during starting.
Figure 10-7 illustrates a second method for protecting a high-inertia motor. This approach
also uses two Device 50 elements per phase. The conventional Device 50 is set in the normal
way to protect against short circuits. The second Device 50 is used in conjunction with the
Device 51 overcurrent element to block tripping by the Device 51 for overcurrents below the
Device 50 setting. This scheme offers an overload alarm, while allowing the motor to
continue operating unless the actual overcurrent exceeds a high setting. The use of this
scheme is dependent upon the operating philosophy of the facility. Large motors should be
specified with thermistors or RTDs buried in their windings for high-temperature detection,
although temperature changes are generally slower to develop than overcurrent increases.
Actual faults within the windings would be detected faster by the overcurrent differential
relay or a sensitive ground-fault current relay scheme.
Figure 10-8 represents a scheme that relies upon the characteristics of a Device 21 (i.e.,
impedance distance relay) to permit tripping if the high-inertia motor does not accelerate to a
certain speed within a fixed period. Upon energization of the motor circuit, the locked-rotor
current is primarily inductive, as a blocked motor could easily be considered a transformer
with shorted secondary windings. As the motor accelerates, the current decreases from a
Figure 10-6—Protection of high-inertia motor

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subtransient to a transient value, and the power factor and measured impedance increase.
Used in conjunction with the Device 21 is either an overcurrent relay (Device 51) or an
overvoltage relay (Device 59), which operates as a timing device in this case. This scheme
guards against a stalled motor although other schemes exist, such as zero-speed devices used
with timers. Figure 10-9 illustrates how the locked-rotor protection functions below the safe
stall time.
10.5.2 Fault protection
10.5.2.1 Motor overcurrent differential relay (Device 87)
Motor overcurrent differential protection measures the current flow into a load and compares
it to the current measured on the neutral side of the motor. A current difference is detected as
a fault. These schemes can be technically applied to any motor load, but often are applied to
large or critical motors only where damage could be costly or replacement difficult. By
detecting faults at a low level, damage may be confined to windings solely. Three general
recommendations for applying differential overcurrent protection are as follows:
a) With all motors 750 kW and above used on ungrounded systems.
b) With all motors 750 kW and above used on grounded systems where the ground-fault
protection applied is not considered sufficient without differential protection to pro-
tect against phase-to-phase faults.
c) With smaller motors, especially at voltages above 2400 V, although justifying
differential protection for large motors (i.e., 1900 kW and above) is easier.
Figure 10-7—Alternative method of protecting a high-inertia motor

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10.5.2.1.1 Conventional phase differential overcurrent relay
A conventional phase differential overcurrent relay is used to sense low-level phase faults and
to quickly remove the motor circuit before extensive damage develops. This scheme uses six
identical CTs (i.e., one pair for each phase) and three relays (i.e., one per phase). The CTs
should be sized to carry full-load current continuously and to not saturate during an external
or internal fault (see Figure 10-10). The currents from each pair of CTs circulate through the
relay-restraining windings under normal (i.e., no-fault) conditions. For a fault in the motor
windings or in the cable, the CT secondary currents have different magnitudes and/or
polarities, and the differential current from each CT adds to the other and operates the
Device 87 to trip the motor circuit breaker. While sometimes applied to delta-connected
motors, this scheme is usually used with wye-connected motors. (Wye-connected motors are
much more common than delta-connected ones in the larger horsepower ratings.) With the
wye-connected motor, three of the CTs are normally located at the starter (or motor
switchgear) and the other three in the three phases at the motor winding neutral.
10.5.2.1.2 Self-balancing differential using window CTs
Three window (or toroidal) CTs are normally installed at the motor. One CT per phase is used
with the motor line, and neutral leads of one phase are passed through it so that the ﬂux from
the two currents normally cancels each other in the CT. A winding phase-to-phase or phase-
to-ground fault results in an output from the CTs of the associated phases. That current
operates the associated relays (see Figure 10-11).
Figure 10-8—Protection of high-inertia motor using an impedance relay

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Figure 10-9—Schematic of locked-rotor protection of Figure 10-8
Figure 10-10—Conventional phase differential protection using three
percentage differential relays (one shown)

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The CTs and relays would normally be the same as the CTs and relays used for zero-
sequence instantaneous ground overcurrent protection (see 10.5.2.3.2) with the relay set
between 0.25 A and 1.0 A pickup. Therefore, this differential scheme usually has a lower
primary pickup in amperes than the conventional differential scheme because the CT ratio is
usually greater with the conventional scheme. This differential scheme has a slight advantage
over the scheme in Figure 10-10 in detecting ground faults. For motors installed on grounded
systems this difference is signiﬁcant because most faults begin as ground faults. The usual
objective of motor-fault protection is to remove the fault before the stator iron is signiﬁcantly
damaged.
Application problems have occurred with this scheme when the available fault current is very
high and when high-speed balanced-core differential protection signals to trip the motor
starter before the current-limiting fuses clear the fault and thus protect the starter. Because the
starter has such a low fault rating, some engineers have slowed down the operation of the
relay, by delay or different relay type, in order to distinguish between a developing low-level
fault and a direct short.
With the CTs located at the motor, this scheme does not detect a fault in the cables supplying
power to the motor. A fault in these cables would normally be detected by the overcurrent
protection. For large motors, coordinating the supply phase-overcurrent protection with the
motor overcurrent protection is often a problem. The presence of motor differential protection
is sometimes considered to make this coordination less essential. In this regard, the
conventional differential is better than the self-balancing differential because the motor
cables are also included in the differential protection zone. Hence coordination between the
motor differential and supply phase-overcurrent relays is complete.
As with zero-sequence ground-fault overcurrent protection, testing the overall CT and relay
combinations is important during commissioning. Current in a test conductor should be
Figure 10-11—Self-balancing differential protection (one relay shown)

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passed through the window of each CT. Because normally the relays do not carry current, an
open circuit in a CT secondary or wiring to a relay can be discovered by this overall testing.
10.5.2.2 Split winding current unbalance (Device 46)
10.5.2.2.1 Purpose
The purpose of the split winding current unbalance device is to quickly detect low-magnitude
fault conditions. This protection also serves as backup to instantaneous phase-overcurrent and
ground-fault overcurrent protection. This protection is normally only applied to motors
having two (or three) winding paths in parallel per phase (see Figure 10-12).
10.5.2.2.2 Arrangement of CTs and relays
The usual application is with a motor having two winding paths in parallel per phase. The six
line leads (i.e., two per phase) of the motor are brought out, and one CT is connected in each
of the six leads. The primary current rating of the CTs should be chosen to carry full-load
current.
The CTs may be installed at the motor. It may be convenient, however, to use six cables to
connect the motor to its starter (or switchgear), and in this case the CTs can be located in the
starter.
The currents from each pair of CTs, associated with the same phase, are subtracted, and their
difference is fed to a short-time inverse time-overcurrent relay. Three of these relays are
required (i.e., one per phase), and each is set at 1.0 time dial and between 0.5 A and 2.5 A.
Figure 10-12—Split-phase motor overcurrent protection used with
two paths per phase (one relay shown)

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The relay should be set above the maximum current unbalance that can occur between the
two parallel windings for any motor-loading condition.
10.5.2.2.3 Evaluation of split winding current unbalance protection
The following factors should be considered when evaluating split winding current unbalance
protection:
a) Total cost would be somewhat less than conventional phase differential and more
than self-balancing differential.
b) The primary pickup current for this protection would be about half of the primary
pickup current of conventional phase differential because both schemes require the
CT primaries to be rated to carry normal load currents. Self-balancing differential
would usually have a lower primary pickup in amperes.
c) This protection has a slight time delay compared to the phase differential schemes.
d) When the CTs are located in the motor starter, split winding protection has the same
advantage over self-balancing differential as does conventional phase differential,
namely, it detects a fault in the motor cables and may facilitate coordination with the
supply feeder overcurrent relays (see 10.5.2.1.2).
e) The salient feature that this protection provides, and no other motor protection has, is
the ability to sense short-circuited winding turns. The number of turns that must be
short-circuited before detection occurs depends upon the motor winding
arrangement, the relay pickup, and CT ratio. An analysis of the speciﬁc motor
winding would be required to determine the worthiness of this feature. Short-
circuited turns could cause a ground fault, which could be detected by the self-
balancing differential scheme before this split winding protection would sense the
short-circuited turns condition.
f) This protection could be applied to a motor with four winding paths in parallel per
phase by grouping them as two pairs as if only two paths in parallel existed (i.e., six
CTs and three relays are used).
g) A split differential scheme is often effectively used where one CT is in one of the
parallel paths and the other CT sees the total phase current.
10.5.2.2.4 Application of split winding protection
Split winding protection is rarely used, but is feasible to apply to important motors rated
above 3700 kW that have two or four winding paths in parallel per phase.
10.5.2.3 Ground-fault protection
10.5.2.3.1 Purpose
The purpose of ground-fault protection is to protect motors by detecting ground-fault
conditions with no intentional delay and to be certain that the unbalance current represents a
true ground fault (i.e., not due to asymmetry in the primary current or to CT saturation).
Following this detection, the protection may trip the motor circuit or only alarm, depending
upon the voltage and facility operating practice.

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10.5.2.3.2 Instantaneous ground-fault protection
Using a zero-sequence (or window) CT that has been designed for instantaneous ground-fault
protection and tested with a speciﬁc ground-fault relay is recommended (see Figure 10-13).
For medium-voltage applications, the power system should be resistance-grounded, and the
Device 50G should be set to operate for a primary ground-fault current in the range of 10 A
to 30 A. A suitable time delay should be added when the installation has surge protection on
the motors.
10.5.2.3.3 Time-overcurrent ground-fault protection
Many installations have surge protection at the motor terminals, and a surge discharge
through an arrester could cause an instantaneous relay to have a false trip. To avoid this event,
a Device 51G should be applied, in place of the Device 50G in Figure 10-13, and set to trip
within a few seconds of the fault-sensing pickup.
10.5.2.3.4 Installation of cable for ground-fault protection
The following precautions should be observed in applying the relay and zero-sequence CT
and in installing the cables through the CT:
a) If the cable passes through the CT window and terminates in a pothead on the source
side of the CT, the pothead should be mounted on a bracket insulated from ground.
Then the pothead should be grounded by passing a ground conductor through the CT
window and connecting it to the pothead.
b) If metal-covered cable passes through the CT window, the metal covering should be
kept on the source side of the CT, insulated from ground. The terminator for the metal
Figure 10-13—Ground-fault overcurrent protection using window CT

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covering may be grounded by passing a ground conductor through the CT window
and then connecting it to the terminator.
c) Cable shields should be grounded by passing a ground conductor through the CT
window and then connecting it to the shields per Figure 128(b).
d) The overall CT and ground relay scheme should be tested by passing current in a test
conductor through the CT window. Because normally no current exists in the relay,
an open circuit in the CT secondary or wiring to the relay can be discovered by this
overall test.
10.5.2.3.5 Residually connected CTs and ground-fault relay
Applications have been made using the residual connection from three CTs (i.e., one per
phase) to supply the relay. This arrangement is not ideal because high phase currents (e.g.,
due to motor starting inrush or phase faults) may cause unequal saturation of the CTs and
produce a false residual current. As a result, undesired tripping of the ground relay may
occur, and the production or process may be jeopardized. For this reason, a Device 50N is not
recommended in the residual connection. A Device 51N installed in the residual connection
would be more appropriate for these installations.
10.5.2.3.6 Selection of resistor for low-resistance system grounding
The purpose of resistance grounding is to provide current sufﬁcient for protective relays to
operate upon detection of a ground fault, but low enough to limit the magnitude and resulting
damage to the motor. (In mine distribution systems, the objective is to limit equipment-frame-
to-earth voltages for safety reasons.) However, the ground-fault current should not be so
limited that the windings near the neutral end are unprotected. In the past, protection within
5% to 10% of the neutral has often been considered adequate. Selection of the ground resistor
should also consider the number of steps in ground-fault overcurrent protection coordination
and the magnitude of the charging current (from system capacitance) (see Baker [B1]). On
this basis, the ground resistor chosen for the system neutral grounding normally limits the
ground-fault current within the range of 400 A to 2000 A. However, some companies prefer
neutral ground-fault current limited to 200 A to 800 A; this difference emphasizes the need to
coordinate the protection of a system. A 10 s time rating is usually chosen for the resistor.
To avoid excessive transient overvoltages, the resistor should be chosen so that the following
zero-sequence impedance ratio is achieved:
R0 / X0 should be equal to or greater than 2.
A more detailed discussion of the selection of the resistor can be found in Chapter 8.
10.5.3 Monitors
In addition to protection against failures due to electrical causes, advances in instrumentation
and techniques have enabled protective methods that monitor machinery characteristics and,
as a result, can detect trends of equipment failures during the incipient stage. This

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development has manifested into monitors, sensors, and detectors that use inputs not related
directly to measured electrical quantities of voltage and current.
10.5.3.1 Stator winding overtemperature
The purpose of stator winding overtemperature protection is to detect excessive stator
winding temperature prior to the occurrence of motor damage. This protection is often
arranged just to alarm on motors operated with competent supervision. Sometimes two
temperature settings are used, the lower setting for alarm, the higher setting to trip.
10.5.3.1.1 RTDs
Six RTDs should be specified in motors rated 370 kW and above. They are installed in the
winding slots when the motor is being wound. The six are spaced around the circumference
of the motor core to monitor all phases. The most commonly used type is 120 Ω platinum
with three leads. The RTD element resistance increases with temperature, and Wheatstone
bridge devices are used to provide temperature indication or contact operation, or both.
For safety, RTDs should be grounded, and that ground in turn places a ground on the
Wheatstone bridge control. Therefore, the Wheatstone bridge control should not be operated
directly from a switchgear dc battery because these dc control schemes should normally
operate ungrounded in order to achieve maximum reliability. However, loss of ac control
voltage due to a blown fuse could remove protection, unless the null point is near the trip
setting at which time it could cause tripping. An open RTD or its circuit appears as an infinite
resistance and causes a false trip because this corresponds to a very high temperature.
The following arrangements of RTDs are frequently used:
a) Monitor all six leads continuously with alarm points and time-delayed higher trip
points using one monitor or a programmable logic controller.
b) Monitor six leads with alarm points and have a manual trip.
c) Determine which detector normally runs hottest and permanently connect a trip relay
to it. Use one temperature indicator and a selector switch to manually monitor the
other five detectors.
d) Use selector switch and combination indicator and alarm relay. Precaution: An open
circuit in the switch contact will cause a false trip. Bridging contacts are required.
e) Use selector switch and indicator only.
f) Use one, two, or three (i.e., one per phase) alarm relays; and use one, two, or three
(i.e., one per phase) trip relays set at a higher temperature.
10.5.3.1.2 Thermocouples
Thermocouples are used to indicate temperatures for alarm and trip functions, in a similar
manner to RTDs. However, an open circuit in the thermocouple leads does not cause a trip
because the output appears as a low-temperature condition. The output from thermocouples is
compatible with conventional temperature-monitoring and data-logging schemes.

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10.5.3.1.3 Thermistors
Thermistors are used to operate relays for alarm or trip functions, or both. They are not used
to provide temperature indication. However, they are often combined with thermocouples,
which provide indication, while the thermistor operates a relatively inexpensive relay. See
10.4.3.2 for further details.
10.5.3.1.4 Thermostats and temperature bulbs
Thermostats and temperature bulbs are used on some motors. For instance, thermostats are
bimetallic elements and are used on random wound motors (460 V class) to detect failure to
start. They are embedded in the end windings and provide a contact opening to trip the motor.
Bulb temperature devices are used to provide measurement and trip contacts for bearing oil
temperature in oil-lubricated bearings. See 10.4.3.1 for further details.
10.5.3.1.5 Application of stator winding temperature protection
Stator winding temperature protection is commonly specified on all motors rated 190 kW and
above. RTDs are commonly specified in all motors rated 370 kW and above. In the following
situations, the application of stator winding temperature protection should be considered:
a) Motors in high ambient temperatures or at high altitudes
b) Motors whose ventilation systems tend to become dirty and lose cooling
effectiveness
c) Motors subject to periodic overloading due to load characteristics of the drive or
process
d) Motors likely to be subjected to continuous overloading (within their service factor
range) in order to increase production
e) Motors for which continuity of service is critical
f) Motors supplied from ASDs
10.5.3.2 Rotor overtemperature
10.5.3.2.1 Synchronous motors
Rotor winding overtemperature protection is available for brush synchronous motors, but is
not normally used. One well-known approach is to use a Kelvin bridge chart recorder with
contacts adjustable to the temperature settings desired. The Kelvin bridge uses field voltage
and field current (from a shunt) as inputs and measures the field resistance in order to
determine the field winding temperature.
10.5.3.2.2 Wound-rotor induction motor-starting resistors
Some form of temperature protection should be applied for wound-rotor induction motor-
starting resistors on motors having severe starting requirements, such as long acceleration
intervals or frequent starting. RTDs and other types of temperature sensors have been used in
proximity to the resistors.

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10.5.3.3 Mechanical and other protection
10.5.3.3.1 Motor bearing and lubricating systems
Various types of temperature sensors are used on sleeve bearings to detect overheating, such
as RTDs, thermocouples, thermistors, thermostats, and temperature bulbs. Excessive bearing
temperature may not be detected soon enough to prevent bearing damage. More serious
mechanical damage to the rotor and stator may be prevented by tripping the motor before
complete bearing failure. Thus, for maximum effectiveness, the following steps are
recommended:
a) Use a fast-responding temperature sensor.
b) Locate the temperature sensor in the bearing metal where it is close to the source of
overheating.
c) Use the temperature sensor for tripping instead of alarm; for some installations, use
both alarm and trip sensors, the former having a lower temperature setting.
d) Provide alarm and trip devices on bearing lubricating systems to monitor
1) Lubricating oil temperature, preferably from each bearing
2) Bearing cooling water temperature, both temperature in and out
3) Bearing lubricating oil flow and cooling water flow
In lieu of the flow-monitoring recommended in Item d) 3), a suitable arrangement of pressure
switches is often used. However, flow monitoring is strongly recommended for important or
high-speed machines.
Temperature sensors generally cannot detect impending failure of ball or roller bearings soon
enough to be effective. Vibration monitors and detectors should be considered (see 10.5.3.4).
Protection to detect currents that may cause bearing damage should be considered for motors
having insulated bearings.
10.5.3.3.2 Ventilation and cooling systems
Alarm and trip devices should be considered, as follows:
a) In motor ventilation systems
1) To detect high differential pressure drop across air filters
2) To detect loss of air flow from external blowers (In lieu of air flow monitoring, a
suitable arrangement of pressure switches is often used; however, flow
monitoring is preferable.)
b) With water-cooled motors, to monitor water temperature, flow, or pressure
c) With inert-gas-cooled motors, to sense pressure and temperature
d) For motors in hazardous areas, to detect gas

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10.5.3.3.3 Liquid detectors
On large machines, liquid detectors are sometimes provided to detect liquid (usually water)
inside the stator frame, e.g., because of a leak in the air cooler of a totally enclosed water- and
air-cooled motor.
10.5.3.3.4 Fire detection and protection
For fire detection and protection, the following items should be considered:
a) Installation of suitable smoke and flame detectors to alert operators to use suitable
portable fire extinguishers.
b) Installation of suitable smoke and flame detectors and an automatic system to apply
carbon dioxide or other suppressant into the motor. Some old, large motors have
internal piping to apply water for fire extinguishing. Possible false release of the
water is a serious disadvantage.
c) Use of synthetic lubricating oil that does not burn, particularly for drives having large
lubricating systems and reservoirs and for systems in hazardous atmospheres.
Lubricating systems of gas compressors or hydrocarbon pumps should be kept
separate from the motor to preclude combustibles and flammables from entering the
motor through the oil system.
10.5.3.3.5 Partial discharge detectors
Partial discharge detectors are embedded in the windings. They show a pattern of frequencies
that are normal for a motor. Abnormal patterns of corona indicate insulation damage. These
detectors are normally installed on large motors (>7500 kW) used for critical service.
10.5.3.4 Vibration monitors and sensors
10.5.3.4.1 Purpose of vibration monitoring
Vibration monitoring has advanced from an important startup function to an effective tool
during operation of the process. It increases safety and reliability and may reduce costs over
the life of the plant. The three components of a vibration monitoring system are transducers,
monitors, and machine diagnostic equipment, although many installations may not have
permanent monitors and diagnostic systems (see Figure 10-14).
10.5.3.4.2 Transducers
Transducers are a critical part of a vibration monitoring system. Accurate machinery
diagnostics depend upon reliable transducer signals. Two orthogonal, or XY, transducers
should be installed at or near each bearing; and a phase reference probe, such as a once-per-
turn event probe, should be installed on each shaft. This configuration provides diagnostic
equipment with the information necessary to accurately indicate the vibratory motion.
Transducers should be of rugged construction to better withstand the motor’s environment. In
general, if rotor-related malfunctions are anticipated (e.g., unbalance, misalignment, rubs),

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vibration transducers that observe the rotor should be preferred. If housing-related
malfunctions are anticipated (e.g., piping strains, structural resonances), transducers mounted
on the machine housing should be preferred.
10.5.3.4.2.1 Proximity transducers
On motors with fluid-film bearings, such as sleeve bearings, noncontacting proximity
transducers (see Figure 10-15) provide the best information and should be preferred. Often
on these motors, much of the rotor motion is not transmitted to the housing. Noncontacting
proximity transducers accurately indicate displacement of the rotor relative to the housing.
They have a broad frequency response, down to dc (i.e., 0 Hz) at the low end. The upper end
frequency response is also high (up to 10 kHz), but useful application at high frequencies is
limited because little measurable displacement occurs at high frequencies. This transducer
can measure slow-roll and the shaft’s average position within the bearing. For motors with
rolling-element bearings, a special transducer can be applied to provide an earlier warning of
bearing malfunctions than velocity transducers or accelerometers provide. Such motors have
a high-gain, low-noise eddy-current proximity transducer that is installed in the bearing
housing to observe the bearing outer race. Such transducers may be difficult to install in
motors with tight clearances. See Figure 10-16 for a vibration limit curve.
10.5.3.4.2.2 Velocity transducers
Velocity transducers may be used on motors with rolling-element bearings where virtually all
of the shaft motion is faithfully transmitted to the bearing housing. Velocity transducers are
seismic devices that measure motion relative to free space, are useful for overall vibration
measurement, and provide good frequency response in the mid-frequency range (i.e., 4.5 Hz
to 1 kHz). This transducer is self-generating; no power source is required. Traditional
velocity transducers are mechanical devices that suffer from a limited life span. Some
Reprinted with permission from Bentley-Nevada.
Figure 10-14—Vibration monitoring system

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modern velocity transducers use a piezoelectric sensing element, do not suffer from this
limitation, and are thus preferred. See Figure 10-17 for a vibration limit curve.
10.5.3.4.2.3 Accelerometers
Accelerometers are generally used on motors with rolling-element bearings where virtually
all of the shaft motion is transmitted to the bearing housing. Accelerometers are useful for
overall vibration measurements and have a broad frequency response. They are particularly
useful for high-frequency measurements. An accelerometer is almost the only viable
transducer at high frequencies (usually above 5 kHz). Motor vibration acceleration increases
with frequency. Therefore, the acceleration unit of measurement is favored. However, at low
frequencies, its usefulness is limited. Accelerometers are sensitive to the method of
attachment and the quality of the mounting surface.
10.5.3.4.2.4 Vibration limits
API Std 541-1995 recommends limits for shaft and bearing vibrations, using noncontact
vibration probes on hydrodynamic bearing motors operating at speeds equal to or greater than
1200 r/min. Examples of these limits are shown in Figure 10-16 and Figure 10-17 from API
Std 541-1995.
10.5.3.4.3 Monitors
10.5.3.4.3.1 Monitors process and display transducer signals
Monitors should detect malfunctions in the transducer system and the transducer power
supply. They should provide two levels of alarm and protect against false alarms. They should
be constructed so that both the unprocessed and processed information is available to online
and portable diagnostic equipment. Monitors designed to work with accelerometers or
velocity transducers should be able to integrate the signal. See Figure 10-18 for sample
monitoring system panels.
Figure 10-15—Typical proximity transducers

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10.5.3.4.3.2 Continuous monitors
Motors that are critical to a process should be instrumented with continuous monitors, in
which each monitor channel is dedicated to a single transducer. These monitors have the
fastest response time and provide the highest level of motor protection.
10.5.3.4.3.3 Periodic monitors
General purpose motors can be instrumented with periodic monitors, in which each monitor
channel is time-shared among many transducers. Consequently, the response time is slower
than the continuous monitor.
Reprinted with permission from Section 3.8 of API 541-1995.
NOTES
1—Vibration displacement at any frequency below running-speed frequency shall not exceed
0.1 mil or 20% of the measured unfiltered vibration displacement, whichever is greater.
2—Vibration displacement at any filtered frequency above running-speed frequency shall not ex-
ceed 0.5 mil peak to peak.
3—Vibration displacement filtered at running-speed frequency shall not exceed 80% of the
unfiltered limit (runout compensated).
Figure 10-16—Shaft vibration limits (relative to bearing housing using
noncontact vibration probes): for all hydrodynamic sleeve-bearing motors;
with the motor securely fastened to a massive foundation

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10.5.3.4.3.4 Portable monitors
These monitors are widely used, primarily when a permanent monitoring system has not been
justiﬁed. They are often used with infrared scanners, which determine whether bearings are
overheating. The results are suitable for trending in condition-based maintenance programs.
Other types of portable monitors include ultrasonic probes as part of their maintenance
programs.
10.5.3.4.4 Diagnostic systems
10.5.3.4.4.1 Purpose of diagnostic systems
A diagnostic system is essential to effective machinery management. Being computerized,
the system processes the data provided by the transducers and monitors into information that
Reprinted with permission from Section 3.8 of API 541-1995.
NOTES
1—For unfiltered vibration limits, use the motor synchronous or maximum rotational speed in
revolutions per minute.
2—For filtered limits, use vibration frequency in hertz.
3—Limits are for sleeve and antifriction bearing motors.
Figure 10-17—Bearing housing vibration limits: for sleeve and antifriction
bearing motors; with the motor securely fastened to a massive foundation

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can be used to make decisions regarding motor operation. A diagnostic system should be
capable of simultaneously processing the data from two orthogonal transducers and a once-
per-turn reference probe. It should display data in several plot formats, including orbit,
timebase, Bode, polar, shaft centerline, trend, spectrum, and full spectrum. It should
minimize operator involvement in motor conﬁguration and data acquisition. It should display
alarms for each monitored channel, trend its data over time, and archive its data to a storage
medium (e.g., computer disk). It should integrate with computer networks and control
systems.
10.5.3.4.4.2 Continuous online diagnostic systems
Motors that are critical to a process should be managed by a continuous online diagnostic
system. Each channel in a continuous online diagnostic system is dedicated to the data from a
single transducer and monitor channel. The diagnostic system processes machinery
information online, and the data are continuously sampled and available to the host computer.
A diagnostic system that processes steady-state information, during normal operation, is a
minimum requirement; and the diagnostic system should be capable of processing data both
during startups and shutdowns. It should be capable of displaying information in real time.
Figure 10-18—Monitoring system panels

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The continuous online diagnostic system is expensive and should be evaluated as any
protection to determine its feasibility.
10.5.3.4.4.3 Periodic online diagnostic systems
General purpose motors can be managed by an online periodic diagnostic system. Each
channel in a periodic system can be shared among many transducers. The data are
periodically sampled and continuously available to the host computer.
10.5.3.4.4.4 Vibration limits
The vibration limits for motor shafts and bearing housings depend mainly on the operating
speed. Typical limits are described in API Std 541-1995 and API Std 546-1997. The limits for
filtered and unfiltered measurements are also described.
10.5.4 Synchronous motor protection
10.5.4.1 Damper winding protection
When a synchronous motor is starting, high currents are induced in its rotor damper winding.
If the motor-accelerating time exceeds specifications, the damper winding may overheat and
be damaged.
Several different electromechanical and electronic protective schemes are available. None of
these schemes directly senses damper winding temperature. Instead, they try to simulate the
temperature by evaluating two or more of the following quantities:
a) Magnitude of induced field current that flows through the field discharge resistor.
This value is a measure of the relative magnitude of induced damper-winding current.
b) Frequency of induced field current that flows through the discharge resistor. This
value is a measure of rotor speed and provides an indicator, therefore, of the increase
in damper-winding thermal capability resulting from the ventilation effect and the
decrease of induced current.
c) Time interval after starting.
10.5.4.2 Field-current failure protection
Field current may drop to zero or a low value when a synchronous motor is operating for
several reasons:
— Tripping of the remote exciter, either motor-generator set or electronic. (Controls for
these should be arranged so that the remote exciter will not drop out on an ac voltage
dip.)
— Burnout of the field contactor coil. (The control should be arranged so that the field
contactor does not drop out on an ac voltage dip.)
— Accidental tripping of the field. (Field-circuit overcurrent protection is usually omit-
ted from field breakers and contactors in order to avoid unnecessary tripping.) The

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field circuit is usually ungrounded and should have ground detection lights or relay
applied to it to detect the first ground fault before a short circuit occurs (see 10.5.7.1).
— High-resistance contact or open circuit between slip ring and brushes due to exces-
sive wear or misalignment.
— Failure of diode bridge on rotating diodes on a brushless exciter (detected by pullout
relays).
Reduced field-current conditions should be detected for the following reasons:
— Overloaded motors pull out of step and stall.
— Lightly loaded motors are not capable of accepting load when required.
— Normally loaded motors, which do not pull out of step, are likely to do so on an ac
voltage sag through which they might otherwise ride.
— The excitation drawn from the power system by large motors may cause a serious
system voltage drop and endanger continuity of service to other motors.
A common approach to field-current failure protection is to use an instantaneous dc
undercurrent relay to monitor field current. This application should be investigated to ensure
that no transient conditions would reduce the field current and cause unnecessary tripping of
this instantaneous relay. A timer could be used to obtain a delay of one or more seconds, or
the relay could be connected to alarm only where competent supervising personnel are
available.
Field-current failure protection is also obtained by the generator loss-of-excitation relay that
operates from the VTs and CTs that monitor motor stator voltages and current. This approach
has been done on some large motors (i.e., 3000 kW and above). This relay may also provide
pullout protection (see 10.5.4.4)
10.5.4.3 Excitation voltage availability
Device 56 is a relay that automatically controls the application of the field excitation to an ac
motor at some point in the trip cycle, probably more related to permissive control function.
This device is a frequency relay, but others apply a simple voltage relay as a permissive start
to ensure that voltage is available from the remote exciter. This approach avoids starting and
then having to trip because excitation was not available. Loss of excitation voltage is not
normally used as a trip; the field-current failure protection is used for this function.
10.5.4.4 Pullout protection (Device 55)
Pulling out of step is usually detected by one of the following relay schemes:
a) A power factor relay (Device 55) responding to motor stator voltage and current VTs
and CTs. See 10.5.4.5 about the need to delay actuation of the pullout relay until the
machine has a chance to pull into synchronism during a calculated period.
b) An instantaneous relay connected in the secondary of a transformer whose primary
carries the dc field. The normal dc field is not transformed. When the motor pulls out
of step, alternating currents are induced in the field circuit and transformed to operate

IEEE
the pullout relay. This relay, while inexpensive, is sometimes subject to false tripping
on ac transients accompanying external system fault conditions and also ac transients
caused by pulsations in reciprocating compressor drive applications. Device 95 has
sometimes been used to designate this relay.
c) The generator loss-of-excitation relay (Device 40).
10.5.4.5 Incomplete starting sequence (Device 48)
Incomplete starting sequence protection is normally a timer that blocks tripping of the field-
current failure protection and the pullout protection during the normal starting interval. The
timer is started by an auxiliary contact on the motor starter, and it times for a preset interval
that has been determined during test starting to be slightly greater than the normal interval
from start to reaching full field current. The timer puts the field-current failure and pullout
protection in service at the end of its timing interval. This timer is often a de-energize-to-time
device so that it is fail-safe with regard to applying the field-current failure and pullout
protection.
10.5.4.6 Operation indicator for protection devices
Many types of the protective devices discussed in 10.5.4.1 through 10.5.4.5 do not have
operation indicators. Separate operation indicators should be used with these protective
devices.
10.5.5 Induction motor protection
For induction motor incomplete starting sequence protection (Device 48), wound-rotor
induction motors and reduced-voltage starting motors should have a timer applied to protect
against failure to reach normal running conditions within the normal starting time. Such a de-
energized-to-time device is started by an auxiliary contact on the motor starter and times for a
preset interval, which has been determined during test starting to be slightly greater than the
normal starting interval. The timer trip contact is blocked by an auxiliary contact of the final
device that operates to complete the starting sequence. This device would be the final
secondary contactor in the case of a wound-rotor motor, or it would be the device that applies
full voltage to the motor stator. Incomplete sequence protection should also be applied to
part-winding and wye-delta motor-starting control and to pony motor and other reduced-
voltage sequential start schemes.
10.5.6 Protection against excessive starting
The following protections against excessive starting are available:
a) A timer, started by an auxiliary contact on the motor starter, with contact arranged to
block a second start until the preset timing interval has elapsed.
b) Stator thermal overcurrent relays (Device 49), which provide some protection, with
the degree of protection depending upon:
1) The normal duration and magnitude of motor inrush
2) The relay-operating time at motor inrush and the cool-down time of the relay

IEEE
3) The thermal damper-winding protection on synchronous motors
4) Rotor overtemperature protection
c) Multifunction motor protection relays that have the capability to be programmed to
limit the number of starts during a specific period. Large motors are often provided
with nameplates giving their permissible frequency of starting.
10.5.7 Rotor winding protection
10.5.7.1 Synchronous motors
The field and field supply should not be intentionally grounded. While the first ground
connection does not cause damage, a second ground connection probably will. Therefore,
detecting the first ground is important. The following methods are used:
a) Connect two lamps in series between field positive and negative with the midpoint
between the lamps connected to ground. A ground condition shows by unequal bril-
liancy of the two lamps.
b) Connect two resistors in series between field positive and negative with the midpoint
between the resistors connected through a suitable instantaneous relay to ground. The
maximum resistance to ground that can be detected depends upon the relay sensitiv-
ity and the resistance in the two resistors. This scheme does not detect a ground fault
at midpoint in the field winding. If a varistor is used instead of one of the resistors,
then the point in the field winding at which a ground fault cannot be detected changes
with the magnitude of the excitation voltage. This approach is used to overcome the
limitation of not being able to detect a field midpoint ground fault.
c) Apply low ac voltage between the field circuit and ground, and monitor the ac flow to
determine when a field-circuit ground fault occurs. Before using one of these
schemes, a determination should be made that a damaging ac current will not flow
through the field capacitance to the rotor iron and then through the bearings to ground
and thus cause damage to the bearings.
If a portion of the field becomes faulted, damaging vibration may result. Vibration monitors
and sensors should be considered.
10.5.7.2 Wound-rotor induction motors
The protection for wound-rotor induction motors is similar to the protection described for
synchronous motors, except the field is three-phase ac instead of a dc field (see Figure 10-
19). Yuen, et al. [B13], describe some operating experience which confirms the effectiveness
of this protection. Wound-rotor motor damage can result due to high-resonant torques from
operation with unbalanced impedances in the external rotor circuit on speed-controlled
motors. Protection to detect this fault is available although it has seldom been used.

IEEE
10.5.8 Lightning and surge protection
10.5.8.1 Types of protection
Surge arresters are often used, one per phase connected between phase and ground, to limit
the voltage to ground impressed upon the motor stator winding due to lightning and
switching surges. The need for this type of protection depends upon the exposure of the
motor and its supply to surges. Medium-voltage cables have capacitance in their shields that
can attenuate a surge. Like many protective applications, the engineer should evaluate
importance and replacement costs, as well. A study is recommended.
The insulation of the stator winding of ac rotating machines has a relatively low impulse
strength. Stator winding insulation systems of ac machines are exposed to stresses due to the
steady-state operating voltages and to steep-front voltage surges of high amplitudes. Both
types of voltages stress the ground insulation. The steep-front surges also stress the turn
insulation. If the rise time of the surge is steep enough (i.e., 0.1 µs to 0.2 µs), most of the
surge can appear across the ﬁrst coil, the line-end coil; and its distribution in the coil can be
nonlinear. This phenomenon can damage the turn insulation even though the magnitude of
the surge is limited to a value that can be safely withstood by the ground wall insulation.
The surge arrester should be selected to limit the magnitude of the surge voltage to a value
less than the motor insulation surge withstand [or basic impulse insulation level (BIL)].
Figure 10-19—Rotor ground protection of wound-rotor motor

IEEE
The steepness of the surge wavefront at the motor terminals is inﬂuenced by two time
constants:
— At the supply end, by the effect of system inductance, grounding resistance, and
motor cable impedance
— At the motor end, by cable impedance and motor capacitance
Surge capacitors are used, also connected between each phase and ground, to decrease the
slope of the wavefront of lightning and switching surge voltages. As the surge voltage
wavefront travels through the motor winding, the surge voltage between adjacent turns and
adjacent coils of the same phase are lower for a wavefront having a decreased slope. (A less
steep wavefront is another way of designating a wavefront having a decreased slope.) The
recommended practice is to install a surge protection package consisting of a three-phase
capacitor and three surge arrestors.
The steep-fronted surges appearing across the motor terminals are caused by lightning
strikes, normal circuit breaker operation, motor starting, aborted starts, bus transfers,
switching windings (or speeds) in two-speed motors, or switching of power factor correcting
capacitors. Turn insulation testing also imposes a high stress on the insulation system.
The crest value and rise time of the surge at the motor depend on the transient event taking
place, on the electrical system design, and on the number and characteristics of all other
devices in the system. These factors include, but are not limited to, the motor, the cables
connecting the motor to the switching device, the conduit and conduit grounding, the type of
switching device, the length of the switchgear bus, and the number of other circuits
connected to the bus.
See IEEE Std C37.96-2000 for additional information on recommendations of the IEEE
Surge Protection Committee.
10.5.8.2 Locations of surge protection
The surge protection should be located as close to the motor terminals (in circuit length) as
feasible, preferably with leads of 1 m or less. The supply circuit should connect directly to
the surge equipment ﬁrst and then go to the motor.
Table 10-2—The equivalent BILs by present standard test for commercially
used motor voltages
Rated voltage
(V)
NEMA BIL
(kV)
IEC BIL
(kV)
2400 9 15
4160 15 22
13 800 51 60

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Specifying that the surge protection be supplied in an oversized terminal box on the motor or
in a terminal box adjacent to the motor is becoming more common. When surge protection is
supplied in a motor terminal box, it must be disconnected before high-voltage dielectric
testing of the motor is begun. This step is a recognized inconvenience of this arrangement. A
separate surge disconnecting device may be required.
If the motors are within 30 m of their starters or the supply bus, locating the surge arresters,
but not capacitors, in the starters or supply bus switchgear is economical (but not as
effective). In the latter case, one set of surge protection can be used for all the motors within
that 30 m of the bus. Alternatively, this approach may be used for the smaller motors, and
individual surge protection installed at each larger motor. Neither of these remote methods is
recommended nor is locating the surge protection at the line side of the motor disconnect
recommended as the disconnect can also be located too distant to be effective.
10.5.8.3 Application of surge protection
The following factors should be considered when applying surge protection:
a) When a medium-voltage motor is rated above 370 kW, surge arresters and capacitors
should be considered.
b) When a 150 kW or larger motor is connected to open overhead lines at the same volt-
age level as the motor, surge arrestors and capacitors should be considered.
c) Even when a transformer is connecting the motors to open overhead lines, surge
protection is still required at times to protect against lightning or switching surges.
Techniques are available to analyze this situation. If doubt exists, surge protection
should be provided. Refer to 10.5.8.2 for surge protection on the supply bus for
motors located remote from the bus. In addition, refer to Chapter 13 and Chapter 14,
which recommend protection for switchgear and incoming lines.
d) Where certain vacuum or SF6 circuit breakers or vacuum contactors are used, surge
protection may be necessary due to the possibility of restrikes, which can result in
voltage spikes.
10.5.9 Protection against overexcitation from shunt capacitance
10.5.9.1 Nature of problem
When the supply voltage is switched off, an induction motor initially continues to rotate and
retain its internal voltage. If a capacitor bank is left connected to the motor or if a long
distribution line having signiﬁcant shunt capacitance is left connected to the motor, the
possibility of overexcitation exists. Overexcitation results when the voltage versus current
curves of the shunt capacitance and the motor no-load excitation characteristic intersect at a
voltage above the rated motor voltage.
The maximum voltage that can occur is the maximum voltage on the motor no-load
excitation characteristic (sometimes called magnetization or saturation characteristic). This
voltage, which decays with motor speed, can be damaging to a motor (see Figure 10-20 as an
example).

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Damaging inrush can occur if automatic reclosing or transfer takes place on a motor that has
a signiﬁcant internal voltage due to overexcitation.
10.5.9.2 Protection
When overexcitation is expected, protection can be applied in several ways, beginning with
the simplest protection of a separate contactor to drop out the capacitors when the motor
power source is lost. The contactor could also be dropped out by instantaneous overvoltage
relays. An alternative is to use a high-speed underfrequency relay, which, however, may not
be fast enough on high-inertia or lightly loaded motors.
The underfrequency relay is not suitable for motors whose frequency may not decrease
following loss of the supply overcurrent protective disconnecting device. With these
applications, a loss-of-power relay could be used. Examples of these applications are
a) Mine hoist with overhauling load characteristic at time of loss of supply overcurrent
device
b) Motor operating as induction generator on shaft with process gas expander
c) Induction motor with forced commutation from an ASD
NOTE–Transient voltage may approach 170%.
Figure 10-20—Excess shunt capacitance from utility line, which is likely to
overexcite a large high-speed motor

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10.5.10 Protection against automatic reclosing or automatic transfer
10.5.10.1 Nature of problem
When the supply voltage is switched off, motors initially continue to rotate and retain an
internal voltage. This voltage decays with motor speed and internal flux. If system voltage is
restored out-of-phase with a significant motor internal voltage, high inrush current can
damage the motor windings or produce torques damaging to the shaft, foundation or drive
coupling, or gears (see 10.3.2).
IEEE Std C37.96-2000 discusses considerations for the probability of damage occurring for
various motor and system parameters. One of the best methods to prevent fast reclosing is to
consult with the power supplier to determine whether they can delay reclosing (e.g., 2 s or
more or whatever becomes a standard practice).
10.5.10.2 Protection
The following protection alternatives should be considered:
a) Delay restoration of system voltage, using a timer (Device 62) for a preset interval
sufficient for adequate decay of the motor internal voltage. This method may not be
as necessary if the power supplier cooperates on the reclosing, but could be an
backup device, provided that the timer’s reliability is acceptable.
b) Delay restoration of system voltage until the internal voltage fed back from the
motors has dropped to a low enough value. This value is commonly considered to be
25% of rated voltage. The frequency also decreases as the voltage decays due to
motor deceleration. The undervoltage relay (Device 27) and its setting should be cho-
sen accordingly to include a full-wave rectifier and a dc coil and to make the relay
dropout independent of frequency. If an ac frequency-sensitive relay is used, it should
be set (based on motor and system tests) to actually drop out at 25% of rated voltage
and at the frequency that will exist when 25% of rated voltage is reached.
c) Use a high-speed underfrequency relay (Device 81) to detect the supply outage and
trip the motors before supply voltage is restored. A limitation exists if the motor
operates at the same voltage level as the supply lines on which faults may occur
followed by an automatic reclosing or transfer operation. The problem is that the
underfrequency relay requires some voltage in order to have operating torque. If no
impedance (e.g., a transformer) exists between the motor and the system fault
location, then the voltage may not be sufficient to permit the underfrequency relay to
operate. Digital frequency relays are not as voltage limited as electromechanical
relays.
d) Use single-phase (Device 27) or three-phase undervoltage relays as follows:
1) One relay with a sufficiently fast time setting can be connected to the same VT
as the underfrequency relay [see Item c)] and sense the fault condition that
results in insufficient voltage to operate the underfrequency relay.
2) One, two, or three relays (i.e., each connected to a different phase) can be used
to detect the supply outage and trip the motors when sufficient time delay exists
before the supply is restored.

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e) Use a loss-of-power relay (Device 37). This underpower relay should be sufficiently
fast and sensitive. A high-speed three-phase relay has been used frequently, but
should be blocked at startup until sufficient load is obtained on the circuit or motor
with which it is applied.
f) Use a reverse-power relay (Device 32). This relay detects a separation between
motors and their source. While this approach is suitable in some circumstances, the
loss-of-power relay application is generally more suitable than the reverse-power
relay application due to the following limitations:
1) During the fault when the source is still connected to the motors, net power flow
continues into the motors for low-level faults. Although not true for three-phase
bolted faults, low-level faults have very low impedance into which reverse
power flows.
2) Tripping by reverse power can usually be relied upon only if a definite load
remains to absorb power from high-inertia motor drives after the source-fault-
detecting relays isolate the source from the motors.
3) Reverse-power relays responsive to reactive power (i.e., vars) instead of real
power (i.e., watts) usually do not provide a suitable means of isolating motors
prior to automatic reclosing or automatic transfer operations.
10.5.11 Protection against excessive shaft torques
A phase-to-phase or three-phase short circuit at or near the synchronous motor terminals
produces high shaft torques that may be damaging to the motor or driven machine. Computer
programs have been developed for calculation of these torques. Refer to IEEE Std C37.96-
2000 for information on this potential problem.
To minimize exposure to damaging torques, a three-phase high-speed undervoltage relay
(Device 27) can be applied to detect severe phase-to-phase or three-phase short-circuit
conditions for which the motors should be tripped. This relay is often the type whose torque
is proportional to the area of the triangle formed by the three voltage phasors. A severe
reduction in phase-to-phase or three-phase voltage causes tripping. An additional tripping
delay of 1 cycle to 8 cycles may be satisfactory from a protection point of view and desirable
to avoid unnecessary shutdowns. This protection can be achieved using a suitable timer.
Selection of protection and settings for this application should be done in consultation with
the suppliers of the motor, driven machine, and protection device.
10.5.12 Protection against excessive shaft torques developed during transfer
of motors between out-of-phase sources
A rapid transfer of large motors from one energized power system to another energized power
system could cause very high motor inrush currents and severe mechanical shock to the
motor. The abnormal inrush currents may be high enough to trip circuit breakers or blow
fuses and could damage motor system components. The mechanical jolt could physically
damage the motor, shaft, and couplings.
These effects can occur in emergency or standby power systems when a motor is de-
energized and then rapidly reconnected to another source of power that is out-of-phase with

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the motor’s regenerated voltage. Motors above 37 kW driving high-inertia loads (e.g.,
centrifugal pumps, fans) may require special consideration.
The problem can be eliminated if the motor circuits can be de-energized long enough to
permit the residual voltage to decay before power is again applied to the motor. This step can
be done in two ways. In one available method, auxiliary contacts or a relay on the automatic
transfer switch can open the motor holding coil circuits, while the transfer is delayed about
3 s. This method is sometimes effective, but requires interwiring between the transfer switch
and the motor starters and depends upon the reliability of a timing device. Another method
utilizes a transfer switch with a timed center-off position. The switch opens, goes to the
neutral or off position, is timed to stay there about 3 s to 10 s, and then completes the transfer.
This approach eliminates any interwiring to the motors. The required time delay should be
carefully set and may vary as the system conditions change. A third position (neutral) creates
the danger that the transfer switch may remain indeﬁnitely in a neutral position in the event of
a control circuit or contactor malfunction.
Another solution is to momentarily parallel the two power sources on transfer, connecting
both sources together and then dropping one out. This approach is completely effective
because power to the motors is never interrupted. However, it can require new equipment. If
one source is utility power, a problem may exist in that some utilities do not permit
paralleling another source with their systems. In obtaining permission for the paralleling
from the utility, a design review may lead to additional protective relaying. An additional
factor is that the combined available fault current may exceed the ratings of the connected
electrical switching equipment.
In-phase transfer is another solution to the problem. An accessory on the transfer switch,
known as an in-phase monitor (Device 25), measures the phase-angle difference between the
two power sources. An on-site generator set would be controlled by an automatic
synchronizer, which recognizes that the two sources continually go in and out of phase. At
the proper window or acceptable phase-angle difference between the sources, the
synchronizer initiates transfer. The design allows for the operating time of the transfer switch
so that the oncoming source is connected to the motors in phase or at a phase difference small
enough to eliminate excessive inrush currents and mechanical shock. No special ﬁeld
adjustments or interwiring to the motors are required. For typical transfer switches with
transfer times of 10 cycles (166 ms) or less and for frequency differences between the sources
of up to 2 Hz, the synchro-check relay provides a safe transfer of motors.
10.5.13 Protection against failure to rotate
10.5.13.1 Failure to rotate
A failure to rotate occurs when the supply is single phased or if the motor or driven machine
is jammed. The following protection is available:
a) Relays may be used to detect single phasing (see 10.3.3.2).
b) The direct means to detect failure to rotate is to use a shaft-speed sensor and timer to
check whether a preset speed has been reached by the end of a short preset interval

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after energizing the motor. This protection is necessary for induction and brushless
synchronous motors that have a permissible locked-rotor time less than normal
acceleration time.
c) For induction and brushless synchronous motors having a permissible locked-rotor
time greater than normal acceleration time, relying upon the inverse-time phase-
overcurrent relays is normal (see 10.3.4 and 10.3.5).
d) For brush synchronous motors having a permissible locked-rotor time less than
normal acceleration time, one method of protection is to use a frequency-sensitive
relay connected to the field discharge resistor and a timer because the frequency of
the induced field current flowing through the discharge resistor is related to the motor
speed. A frequency-sensitive adjustable time-delay voltage relay is also available to
provide this protection.
e) For brush synchronous motors having a permissible locked-rotor time greater than
normal acceleration time, relying upon the damper-winding protection and incom-
plete starting sequence protection is normal.
f) For a large induction motor protection to start, an impedance relay (Device 21) may
be applied (see 10.5.1, Figure 10-8, and Figure 10-9).
10.5.13.2 Reverse rotation
A directional speed switch mounted on the shaft and a timer can be used to detect starting
with reverse rotation. Some motor loads are equipped with a ratchet arrangement to prevent
reverse rotation.
A reversal in the phase rotation can be detected by a reverse-phase voltage relay (Device 47)
[see 10.3.3.4 b)] if the reversal occurs in the system on the supply side of the relay. This relay
cannot detect a reversal that occurs between the motor and the point at which the relay is
connected to the system.
10.6 References
API Std 541-1995, Form-Wound Squirrel Cage Induction Motors—250 Horsepower and
Larger.3
API Std 546-1997, Brushless Synchronous Machines—500 kVA and Larger.
IEC 60947-4-1-2000, Low-Voltage Switchgear and Controlgear, Part 4: Contactors and
Motor Starters, Section One—Electromechanical Contactors and Motor-Starters.4
3API publications are available from the Publications Section, American Petroleum Institute, 1200 L Street NW,
Washington, DC 20005, USA (http://www.api.org/).

IEEE
IEEE Std 241-1990 (Reaff 1997), IEEE Recommended Practice for Electric Power Systems
in Commercial Buildings (IEEE Gray Book).
IEEE Std 1015-1997, IEEE Recommended Practice for Applying Low-Voltage Circuit
Breakers Used in Industrial and Commercial Power Systems (IEEE Blue Book).
IEEE Std C37.2-1996, IEEE Standard Electrical Power System Device Function Numbers.
IEEE Std C37.17-1997, Trip Devices for AC and General Purpose DC Low-Voltage Power
Circuit Breakers.
IEEE Std C37.96-2000, IEEE Guide for AC Motor Protection.
NEMA ICS 2-2000, Industrial Control and Systems Controllers, Contactors and Overload
Relays Rated 600 Volts.6
NEMA MG 1-1998 (Revision 1, 2000), Motors and Generators.
NFPA 20-1999, Standard for the Installation of Centrifugal Fire Pumps.7
(NEC®
).8
10.7 Bibliography
The following publications have material referenced in the text and are recommended for
further study:
[B1] Bradﬁeld, H. L., and Heath, D. W., “Short-Circuit Protection of Energy-Efﬁcient
Motors,” IEEE Industry Applications Magazine, vol. 3, no. 1, pp. 41–44, Jan./Feb. 1997.
7NFPA publications are published by the National Fire Protection Association, Batterymarch Park, Quincy, MA
02269, USA (http://www.nfpa.org/).

IEEE
[B2] Gregory, G. D., “Single-Pole Short-Circuit Interruption of Molded-Case Circuit Break-
ers,” IEEE I&CPS Conference Record, Section 5, Paper 1, pp. 1–8, May 1999.
[B3] Gregory, G. D., and Padden, L. K., “Application Guidelines for Instantaneous Trip Cir-
cuit Breakers in Combination Starters” (a working group report), IEEE Transactions on
Industry Applications, vol. 34, no. 4, pp. 697–704, July/Aug. 1998.
[B4] Gregory, G. D., and Padden, L. K., “Testing and Applying Instantaneous Trip Circuit
Breakers in Combination Motor Starters,” IEEE PCIC Conference Record, pp. 41–49, 1998.
[B5] Love, D. J., “Ground Fault Protection of Electric Utility Generating Station Medium-
Voltage Auxiliary Power System,” IEEE Transactions on Power Apparatus and Systems, vol.
PAS-97, No. 2, March/April 1978, pp. 583–586.
[B6] Love, D. J. and Hashemi, N., “Considerations for Ground Fault Protection, Medium-
Voltage Industrial and Co-Generating Systems,” IEEE Transactions on Industry Applications,
vol. IA-24, July/August 1988, pp. 548–553.
[B7] Nailen, R. L., Managing Motors, 1st
ed. Chicago: Barks Publications, Inc., 1991, pp. 4-
61 and 4-62.
[B8] Nailen, R. L., “Motor Inrush Current: What Does It Really Mean?” Electrical Apparatus
Magazine, pp. 56–60, June 1986.
[B9] NEMA MG 10-1994, Energy Management Guide for Selection and Use of Fixed Fre-
quency Medium AC Squirrel-Cage Polyphase Induction Motors.
[B10] Padden, L. K., and Pillai, P., “Simplifying Motor Coordination Studies,” IEEE Industry
Applications Magazine, vol. 5, no. 2, pp. 38–52, Mar./Apr. 1999.
[B11] Prabhakara, F. S., Smith Jr., R.L., and Stratford, R. P., Industrial and Commercial
Power Systems Handbook, 1st
ed. Mcgraw-Hill, 1995, pp. 8–46.
[B12] Smith III, A. J., “Short Circuit Ratings, Labels and Fault Withstandability of Molded-
Case and Insulated-Case Circuit Breakers and Combination Motor Starters,” IEEE PCIC
Conference Record, pp. 9–18, 1991.
[B13] Yuen, M. H., Rittenhouse J. D., and Fox F. K., “Large Wound-Rotor Motor with Liquid
Rheostat for Reﬁnery Compressor Drive,” IEEE Transactions on Industry and General Appli-
cations, vol. IGA-1, pp.140–149, Mar./Apr. 1965.

Chapter 11
Transformer protection
Increased use of electric power in industrial plants has led to the use of larger and more
expensive primary and secondary substation transformers. This chapter is directed towards
the proper protection of these transformers.
Primary substation transformers normally range in size between 1000 kVA and 12 000 kVA,
with a secondary voltage between 2400 V and 13 800 V. Secondary substation transformers
normally range in size between 300 kVA and 2500 kVA, with secondary voltages of 208 V,
240 V, or 480 V. Larger and smaller transformers may also be protected by the devices dis-
cussed in this chapter.
11.2 Need for protection
Transformer failure may result in loss of service. However, prompt fault clearing, in addition
to minimizing the damage and cost of repairs, usually minimizes system disturbance, the
magnitude of the service outage, and the duration of the outage. Prompt fault clearing usually
prevents catastrophic damage. Proper protection is, therefore, important for transformers of
all sizes, even though they are among the simplest and most reliable components in the
plant’s electrical system.
Previous studies (see Table 11-1) have indicated that all transformers had a failure rate of 62
per 10 000 transformer years; that transformers rated 300 kVA to 10 000 kVA had a failure
rate of 59 per 10 000 transformer years; and that transformers rated greater than 10 000 kVA
had a failure rate 153 per 10 000 transformer years. These statistics might be taken incor-
rectly to imply that little or no transformer protection is required.
The need for transformer protection is strongly indicated when the average forced hours of
downtime per transformer year is considered. The large value of 356 h average out-of-service
time per transformer failure challenges the system engineer to properly protect the trans-
former and minimize any damage that could occur.
The failure of a transformer can be caused by any of a number of internal or external
conditions that make the unit incapable of performing its proper function electrically or
mechanically. Transformer failures may be grouped by initiating cause as follows:
a) Winding breakdown, the most frequent cause of transformer failure. Reasons for this
type of failure include insulation deterioration or defects in manufacturing, overheat-
ing, mechanical stress, vibration, and voltage surges.
b) Terminal boards and no-load tap changers. Failures are attributed to improper
assembly, damage during transportation, excessive vibration, or inadequate design.

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c) Bushing failures. Causes include vandalism, contamination, aging, cracking, and
animals.
d) Load-tap-changer failures. Causes include mechanism malfunction, contact prob-
lems, insulating liquid contamination, vibration, improper assembly, and excessive
stresses within the unit. Load-tap-changing units are normally applied on utility sys-
tems rather than on industrial systems.
e) Miscellaneous failures. Causes include core insulation breakdown, bushing current
transformer (CT) failure, liquid leakage due to poor welds or tank damage, shipping
damage, and foreign materials left within the tank.
Failure of other equipment within the transformer protective device’s zone of protection
could cause the loss of the transformer to the system. This type of failure includes any equip-
ment (e.g., cables, bus ducts, switches, instrument transformers, surge arresters, neutral
grounding devices) between the next upstream protective device and the next downstream
device.
11.3 Objectives in transformer protection
Protection is achieved by the proper combination of system design, physical layout, and pro-
tective devices as required to
a) Economically meet the requirements of the application,
b) Protect the electrical system from the effects of transformer failure,
c) Protect the transformer from disturbances occurring on the electrical system to which
it is connected,
Table 11-1—Reliability of power transformers (1979 survey)
Equipment subclass
Failure rate
(failures for
unit-year)
Average repair
time
(hours per failure)
Average
replacement time
(hours per failure)
All liquid filled 0.0062 356.1 85.1
Liquid filled
300–10 000 kVA
0.0059 297.4 79.3
Liquid filled
>10 000 kVA
0.0153 1178.5a 192.0a
Dry
300–10 000 kVA
a a a
Source: IEEE Std 493-1997 (The Gold Book)
aSmall sample size; less than eight failures.

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TRANSFORMER PROTECTION Std 242-2001
d) Protect the transformer as much as possible from incipient malfunction within the
transformer itself, and
e) Protect the transformer from physical conditions in the environment that may affect
reliable performance.
11.4 Types of transformers
Under the broad category of transformers, two types are widely used in industrial and
commercial power systems: liquid and dry. Liquid transformers are constructed to have the
essential element, the core and coils of the transformer, contained in the liquid-filled
enclosure. This liquid serves both as an insulating medium and as a heat-transfer medium.
The dry transformers are constructed to have the core and coils surrounded by an atmosphere,
which may be the surrounding air, free to circulate from the outside to the inside of the
transformer enclosure. The dry coils may be conventional (with exposed, insulated
conductors) or encapsulated (with the coils completely vacuum-cast in an epoxy resin).
An alternative to the free circulation of outside air through the dry transformer is the sealed
enclosure in which a gas or vapor is contained. In either case, this surrounding medium acts
both as a heat-transfer medium and as an insulating medium. It is important, with both liquid
and dry transformers, that the quality and function of the surrounding media be monitored to
avoid damage to the core and coil structures. Systems to preserve or protect the medium
within the transformer enclosure are presented briefly in 11.5.
11.5 Preservation systems
11.5.1 Dry preservation systems
Dry preservation systems are used to ensure an adequate supply of clean ventilating air at an
acceptable ambient temperature. Contamination of the insulating ducts within the trans-
former can lead to reduced insulation strength and severe overheating. The protection method
most commonly used in commercial applications consists of a temperature-indicating device
with probes installed in the transformer winding ducts and contacts to signal dangerously
high temperature by visual and audible alarm. Figure 11-1 illustrates this feature.
The following types of dry systems are commonly used:
— Open ventilated
— Filtered ventilated
— Totally enclosed, nonventilated
— Sealed air- or gas-filled

IEEE
11.5.2 Liquid preservation systems
Liquid preservation systems are used to preserve the amount of liquid and to prevent its con-
tamination by the surrounding atmosphere that may introduce moisture and oxygen leading
to reduced insulation strength and to sludge formation in cooling ducts.
The importance of maintaining the purity of insulating oil becomes increasingly critical at
higher voltages because of increased electrical stress on the insulating oil.
The sealed tank system is now used almost to the total exclusion of other types in industrial
and commercial applications. The following types of systems are commonly used:
— Sealed tank
— Positive-pressure inert gas
— Gas-oil seal
— Conservator tank
Liquid preservation systems have historically been called oil-cooled systems, even though the
medium was askarel or a substitute for askarel.
11.5.2.1 Sealed tank
The sealed-tank design is most commonly used and is standard on most substation
transformers. As the name implies, the transformer tank is sealed to isolate it from the outside
atmosphere.
Figure 11-1—Tamper-proof, fan-cooled, dry ventilated, outdoor transformer
with microprocessor temperature-control system

IEEE
A gas space equal to about one-tenth of the liquid volume is maintained above the liquid to
allow for thermal expansion. This space may be purged of air and ﬁlled with nitrogen.
A pressure-vacuum gauge and bleeder device may be furnished on the tank to allow the inter-
nal pressure or vacuum to be monitored and any excessive static pressure buildup to be
relieved to avoid damage to the enclosure and operation of the pressure-relief device. This
system is the simplest and most maintenance-free of all of the preservation systems.
11.5.2.2 Positive-pressure inert gas
The positive-pressure inert gas design shown in Figure 11-2 is similar to the sealed-tank
design with the addition of a gas (usually nitrogen) pressurizing the assembly. This assembly
provides a slight positive pressure in the gas supply line to prevent air from entering the trans-
former during operating mode or temperature changes. Transformers with primary windings
rated 69 kV and above and rated 7500 kVA and above typically are equipped with this device.
11.5.2.3 Gas-oil seal
The gas-oil seal design incorporates a captive gas space that isolates a second auxiliary oil
tank from the main transformer oil, as shown in Figure 11-3. The auxiliary oil tank is open to
the atmosphere and provides room for thermal expansion of the main transformer oil volume.
The main tank oil expands or contracts due to changes in its temperature causing the level of
the oil in the auxiliary tank to rise or lower as the captive volume of gas is forced out of or
allowed to reenter the main tank. The pressure of the auxiliary tank oil on the contained gas
maintains a positive pressure in the gas space, preventing atmospheric vapors from entering
the main tank.
Figure 11-2—Positive-pressure inert-gas assembly, often used on sealed-
tank transformers rated 7500 kVA and above and 69 kV and above primary
voltage

IEEE
11.5.2.4 Conservator tank
The conservator tank design shown in Figure 11-4 does not have a gas space above the oil in
the main tank. It includes a second oil tank above the main tank cover with a gas space
adequate to absorb the thermal expansion of the main tank oil volume. The second tank is
connected to the main tank by an oil-filled tube or pipe.
A large diameter stand pipe extends at an angle from the cover and is closed above the liquid
level by a frangible diaphragm that ruptures for rapid gas evolution and thereby releases pres-
sure to prevent damage to the enclosure.
Because the conservator construction allows gradual liquid contamination, it has become
obsolete in the United States.
11.6 Protective devices for liquid preservation systems
11.6.1 Liquid-level gauge
The liquid-level gauge, shown in Figure 11-5 and Figure 11-6, is used to measure the level of
insulating liquid within the tank with respect to a predetermined level, usually indicated at
25 °C. An excessively low level could indicate the loss of insulating liquid. Such a loss could
lead to internal flashovers and overheating if not corrected. Periodic observation is normally
performed to check that the liquid level is within acceptable limits. Alarm contacts for low
liquid level are normally available as a standard option. Alarm contacts should be specified
for unattended stations to save transformers from loss-of-insulation failure. The alarm contact
is set to close before an unsafe condition actually occurs. The alarm contacts should be
connected through a communication link to an attended station.
Figure 11-3—Gas-oil seal system of oil preservation

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11.6.2 Pressure-vacuum gauge
The pressure-vacuum gauge in Figure 11-7 indicates the difference between the transformer’s
internal gas pressure and atmospheric pressure. It is used on transformers with sealed-tank oil
preservation systems. Both the pressure-vacuum gauge and the sealed-tank oil preservation
system are standard on most small and medium power transformers.
Figure 11-4—Conservator tank oil-preservation system
Figure 11-5—Liquid-level indicator depicting level of liquid with respect to a
predetermined level, usually 25 °C

IEEE
The pressure in the gas space is normally related to the thermal expansion of the insulating
liquid and varies with load and ambient temperature changes. Large positive or negative
pressures could indicate an abnormal condition, such as a gas leak, particularly if the
transformer has been observed to remain within normal pressure limits for some time or if the
pressure-vacuum gauge has remained at the zero mark for a long period. The pressure-
vacuum gauge equipped with limit alarms may be used to detect excessive vacuum or
positive pressure that could cause tank rupture or deformation. The need for pressure-limit
alarms is less urgent when the transformer is equipped with a pressure relief device.
Figure 11-6—Liquid-level-indicating needle, driven by a magnetic coupling to
the ﬂoat mechanism
Figure 11-7—Pressure vacuum gauge (which indicates internal gas pressure
relative to atmospheric pressure) with bleeder valve (which allows pressure
to be equalized manually)

IEEE
11.6.3 Pressure-vacuum bleeder valve
A transformer is designed to operate over a range of 100°, generally from –30 °C to +70 °C.
Should the temperature exceed these limits, the pressure-vacuum bleeder valve automatically
adjusts to prevent any gauge pressure or vacuum in excess of 35 kPa. This valve also prevents
operation of the pressure-relief device in response to slowly increasing pressure caused by
severe overload heating or extreme ambient temperatures. Also incorporated in the pressure-
vacuum bleeder valve is a hose burr and a manually operated valve to allow purging or check-
ing for leaks by attaching the transformer to an external source of gas pressure. The pressure-
vacuum bleeder valve is usually mounted with the pressure-vacuum gauge as shown in
Figure 11-7.
11.6.4 Pressure-relief device
A pressure-relief device is a standard accessory on all liquid-insulated substation transform-
ers, except on small oil-insulated secondary substation units, where it may be optional. This
device, shown in Figure 11-8, can relieve both minor and serious internal pressures. When the
internal pressure exceeds the tripping pressure (e.g., 70 kPa, ±7 kPa gauge), the device snaps
open allowing the excess gas or ﬂuid to be released. Upon operation, a pin (standard), alarm
contact (optional), or semaphore signal (optional) is actuated to indicate operation. The
device normally resets automatically, is self-sealing, and requires little or no maintenance or
adjustment.
This pressure-relief device is mounted on top of the transformer cover and usually has a
visual indicator. The indicator should be reset manually in order to indicate subsequent oper-
ation. When equipped with an alarm contact in conjunction with a self-sealing relay, this
device can provide remote warning. Any operation of the pressure-relief device that was not
preceded by high-temperature loading is indicative of possible trouble in the windings.
Figure 11-8—Pressure-relief device, which limits internal pressure to prevent
tank rupture under internal fault conditions

IEEE
The major function of the pressure-relief device is to prevent rupture or damage to the trans-
former tank due to excessive pressure in the tank. Excessive pressure is developed due to
high-peak loading, long-time overloads, or internal arc-producing faults.
11.6.5 Mechanical detection of faults
Two methods of detecting transformer faults exist other than by electric measurements:
a) Accumulation of gases due to slow decomposition of the transformer insulation or
oil. These relays can also detect heating due to high-resistance joints or due to high
eddy currents between laminations.
b) Increases in tank oil or gas pressures caused by internal transformer faults.
Relays that use these methods are valuable supplements to differential or other forms of
relaying, particularly for grounding transformers and transformers with complicated circuits
that are not well suited to differential relaying, such as certain regulating and phase-shifting
transformers. These relays may be more sensitive for certain internal faults than relays that
are dependent upon electrical quantities. Therefore, gas accumulator and oil and gas pressure
relays can be valuable in minimizing transformer damage due to internal faults.
11.6.5.1 Gas-accumulator relay
A gas-accumulator relay, commonly known as the Buchholz relay, is applicable only to trans-
formers equipped with conservator tanks and with no gas space inside the transformer tank.
The relay is placed in the pipe from the main tank to the conservator tank and is designed to
trap any gas that may rise through the oil. It operates for small faults by accumulating the gas
over time or for large faults that force the oil through the relay at a high velocity. This device
is able to detect a small volume of gas and accordingly can detect arcs of low energy. The
accumulator portion of the relay is frequently used for alarming only. It may detect gas that is
not the result of a fault, but rather evolved by the gassing of the oil during a sudden reduction
of pressure. This relay may detect heating due to high-resistance joints or high eddy currents
between laminations.
11.6.5.2 Gas-detector relay
The gas-detector relay shown in Figure 11-9 is a special device used to detect and indicate an
accumulation of gas from a transformer with a conservator tank, either conventional or
sealed. The relay often detects gas evolution from minor arcing before extensive damage
occurs to the windings or core. This relay may detect heating due to high-resistance joints or
high eddy current between laminations. These incipient winding faults and hot spots in the
core normally generate small amounts of gas that are channeled to the top of the special
domed cover. From there the bubbles enter the accumulation chamber of the relay through a
pipe.
Essentially, the gas detector relay is a magnetic liquid-level gage with a float operating in an
oil-filled chamber. The relay is mounted on the transformer cover with a pipe connection
from the highest point of the cover to the float chamber. A second pipe connection from the

IEEE
float chamber is carried to an eye level location on the tank wall. This connection is used for
removing gas samples for analysis. The relay is equipped with a dial graduated in cubic cen-
timeters and a snap action switch set to function to give an alarm when a specific amount of
gas has been collected. Gas accumulation is indicated on the gauge in cubic centimeters. An
accumulation of gas of 100 cm3 to 200 cm3, for example, lowers a float and operates an alarm
switch to indicate that an investigation is necessary. This gas can then be withdrawn for anal-
ysis and recording.
The rate of gas accumulation is a clue to the magnitude of the fault. If the chamber continues
to fill quickly, with resultant operation of the relay, potential danger may justify removing the
transformer from service.
11.6.5.3 Static pressure relay
The static pressure relay can be used on all types of oil-immersed transformers. They are
mounted on the tank wall under oil and respond to the static or total pressure. These relays for
the most part have been superseded by the sudden pressure relay, but many are in service on
older transformers. However, due to their susceptibility to operate for temperature changes or
external faults, the majority of the static pressure relays that are in service are connected for
alarm only.
11.6.5.4 Sudden pressure relays
Sudden pressure relays are normally used to initiate isolation of the transformer from the
electrical system and to limit damage to the unit when the transformer internal pressure
abruptly rises. The abrupt pressure rise is due to the vaporization of the insulating liquid by
Figure 11-9—Gas-detector relay, which accumulates gases from top air
space of transformer (used only on conservator tank units)

IEEE
an internal fault, such as internal shorted turns, ground faults, or winding-to-winding faults.
The bubble of gas formed in the insulating liquid creates a pressure wave that promptly acti-
vates the relay.
Because operation of this pressure-sensitive device is closely associated with actual faults in
the windings, it is risky to re-energize a transformer that has been removed from service by
the rapid pressure rise relay. The transformer should be taken out of service for thorough
visual and diagnostic checks to determine the extent of damage.
One type of relay, the sudden oil-pressure relay shown in Figure 11-10, uses the insulating
liquid to transmit the pressure wave to the relay bellows. Inside the bellows, a special oil
transmits the pressure wave to a piston that actuates a set of switch contacts. This type of
relay is mounted on the transformer tank below oil level. (See 11.6.5.4.1.)
Another type of relay, the sudden gas-pressure relay shown in Figure 11-11, uses the inert gas
above the insulating liquid to transmit the pressure wave to the relay bellows. Expansion of
the bellows actuates a set of switch contacts. This type of relay is mounted on the transformer
tank above oil level. (See 11.6.5.4.2.)
Both types of relays have a pressure-equalizing opening to prevent operation of the relay on
gradual rises in internal pressure due to changes in loading or ambient conditions.
Both types of sudden pressure relays are also sensitive to the rate of rise in the internal pres-
sure. The time for the relay switch to operate is on the order of 4 cycles for high rates of pres-
sure rise (e.g., 172 kPa/s of oil pressure rise; 34.5 kPa/s of air pressure rise). These relays are
designed to be insensitive to mechanical shock and vibration, through faults, and magnetizing
inrush current.
Figure 11-10—Sudden oil-pressure-rise relay mounted on transformer tank
below normal oil level

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The use of sudden pressure relays increases as the size and value of the transformer increases.
Most transformers 5000 kVA and above are equipped with this type of device. This relay pro-
vides valuable protection at low cost.
11.6.5.4.1 Sudden oil-pressure relay
The sudden oil-pressure relay is applicable to all oil-immersed transformers and is mounted
on the transformer tank wall below the minimum liquid level. Transformer oil ﬁlls the lower
chamber of the relay housing within which a spring backed bellows is located. The bellows is
completely ﬁlled with silicone oil and additional silicone oil in the upper chamber is con-
nected to the oil in the bellows by two small equalizer holes.
A piston rests on the silicone oil in the bellows, but extends up into the upper chamber. It is
separated from a switch by an air gap. Should an internal fault develop, the rapid rise in oil
pressure or pressure pulse is transmitted to the silicone oil by the transformer oil and the
bellows. This increased pressure then acts against the piston, which closes the air gap and
operates the switch.
For small rises in oil pressure due to changes in loading or ambient temperature, for example,
the increased pressure is also transmitted to the silicone oil. However, instead of operating the
piston, this pressure is gradually relieved by oil that escapes from the bellows into the upper
chamber by the equalizer holes. The bellows then contract slightly. The pressure bias on the
relay is thus relieved by this differential feature. Relay sensitivity and response to a fault is
thus independent of transformer-operating pressure.
Figure 11-11—Sudden gas-pressure relay mounted on transformer tank
above normal oil level

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This relay has proven sufficiently free from false operations to be connected for tripping in
most applications. It is important that the relay be mounted in strict accordance with the man-
ufacturers’ specifications. A scheme providing a shunt path around the 63X auxiliary-relay
coil is preferred to prevent its operation due to surges (see Figure 11-12).
11.6.5.4.2 Sudden gas-pressure relay
The sudden gas-pressure relay is applicable to all gas-cushioned oil-immersed transformers
and is mounted in the region of the gas space. It consists of a pressure-actuated switch,
housed in a hermetically sealed case and isolated from the transformer gas space except for a
pressure-equalizing orifice.
The relay operates on the difference between the pressure in the gas space of the transformer
and the pressure inside the relay. An equalizing orifice tends to equalize these two pressures
for slow changes in pressure due to loading and ambient temperature change. However, a
more rapid rise in pressure in the gas space of the transformer due to a fault results in
Figure 11-12—Fault pressure relay schemes (a) Auxiliary relay at control
panel (b) Auxiliary relay at transformer with manual reset
NOTE—See 11.6.5.4.1.
NOTE—See 11.6.5.4.1.

IEEE
operation of the relay. High-energy arcs evolve a large quantity of gas, which operates the
relay in a short time. The operating time is longer for low-energy arcs.
This relay has proven sufficiently free from false operations to be connected for tripping in
most applications. It is important that the relay be mounted in strict accordance with the man-
ufacturer’s specifications.
11.6.5.4.3 Sudden gas/oil-pressure relay
A more recent design of the relays described in 11.6.5.4.1 and 11.6.5.4.2 is the sudden gas/
oil-pressure relay, which utilizes two chambers, two control bellows, and a single sensing
bellows. All three bellows have a common interconnecting silicone-oil passage with an ori-
fice, and an ambient-temperature-compensating assembly is inserted at the entrance to one of
the two control bellows.
An increase in transformer pressure causes a contraction of the sensing bellows, which forces
a portion of the silicone oil from that bellows into the two control bellows and expands them.
An orifice limits the flow of oil into one control bellows to a fixed rate, while there is essen-
tially no restriction to flow into the second control bellows. The two control bellows expand
at a uniform rate for gradual rate of rise in pressure; but during high rates of transformer pres-
sure rise, the orifice causes a slower rate of expansion in one bellows relative to the other. The
dissimilar expansion rate between the two control bellows causes a mechanical linkage to
actuate the snap action switch, which initiates the proper tripping.
11.6.5.5 Dissolved fault-gases detection device
The dissolved fault-gases detection device can be used for continuous monitoring of
hydrogen. The instrument shown in Figure 11-13 is a special device (developed in 1975) used
to detect fault gases dissolved in transformer mineral oil and to continually monitor their
evolution. Thermal and electrical stresses break the insulation materials down, and gases are
generated. These gases dissolve in oil. The materials involved and the severity of the fault
determine the gases produced. The rate of production of these gases is dependent on the
temperature of the fault and is indicative of the magnitude of the fault. These faults are
normally not detected until they develop into larger and more damaging ones.
The transformer incipient fault monitor measures the dissolved fault gases that are
characteristic of the breakdown of the solid and liquid insulation materials. Hydrogen and
other combustible gases diffusing through a permeable membrane are oxidized on a platinum
gas-permeable electrode; oxygen from the ambient air is electrochemically reduced on a
second electrode. The ionic contact between the two electrodes is provided by a gelled high-
concentration sulfuric acid electrolyte. The electric signal generated by this fuel cell is
directly proportional to the total combustible gas concentration and is sent to a conditioning
electric circuit. The resulting output signal is temperature compensated.
This device is easily retrofitted on existing transformers in the field or installed on
transformers at the time of manufacture or repair. The sensor is installed on a valve on the
transformer, and the electronics control is mounted on the transformer or on an adjacent

IEEE
structure. A digital display on the electronics control enclosure indicates the concentration of
fault gases. Alarm levels are programmable and warn personnel when diagnostic or remedial
actions are needed. The device can be connected to a data acquisition system to detect a
deviation from a base and to monitor the rate of change.
This type of device is used on critical transformers; it reduces unplanned outages, provides
for more predictable and reliable maintenance, and creates a safer work environment.
Gas-analysis equipment can be used to test the composition of gases in the transformers. By
analyzing the percentage of unusual or decomposed gases in the transformer, a determination
can be made about whether the transformer has a low-level fault and, if so, what type of fault
had occurred.
11.7 Thermal detection of abnormalities
11.7.1 Causes of transformer overheating
Transformers may overheat due to
— High ambient temperature
— Failure of cooling system
— External fault not cleared promptly
— Overload
— Abnormal system conditions, such as low frequency, high voltage, nonsinusoidal
load current, or phase-voltage unbalance
Figure 11-13—Combustible gas relay, which periodically samples gas in
transformer to detect any minor internal fault before it can develop into a
serious fault

IEEE
11.7.2 Undesirable results of overheating
The consequences of overheating include the following:
— Overheating shortens the life of the transformer insulation in proportion to the dura-
tion of the high temperature and in proportion to the degree of the high temperature.
— Severe overtemperature may result in an immediate insulation failure.
— Severe overtemperature may cause the transformer coolant to heat above its flash
temperature and result in fire.
11.7.3 Liquid temperature indicator (top oil)
The liquid temperature indicator shown in Figure 11-14 measures the temperature of the
insulating liquid at the top of the transformer. Because the hottest liquid is less dense and
rises to the top of the tank, the temperature of the liquid at the top partially reflects the tem-
perature of the transformer windings and is related to the loading of the transformer.
The thermometer reading is related to transformer loading only insofar as that loading affects
the liquid temperature rise above ambient. Transformer liquid has a much longer time con-
stant than the winding itself and responds slowly to changes in loading losses that directly
affect winding temperature. Thus, the thermometer’s temperature warning varies between too
conservative or too pessimistic, depending on the rate and direction of the change in loading.
A high reading could indicate an overload condition.
The liquid temperature indicator is normally furnished as a standard accessory on power
transformers. It is equipped with a temperature-indicating pointer and a drag pointer that
shows the highest temperature reached since it was last reset.
The liquid temperature indicator can be equipped with one to three adjustable contacts that
operate at preset temperatures. The single contact can be used for alarm. When forced air
cooling is employed, the first contact initiates the first stage of fans. The second contact either
initiates a second stage of fans, if furnished, or an alarm. The third contact, if furnished, is
Figure 11-14—Liquid temperature indicator, the most common transformer
temperature-sensing device

IEEE
used for the final alarm or to initiate load reduction on the transformer. The indicated temper-
atures would change for different temperature insulation system designs.
Because the top-oil temperature may be considerably lower than the hot-spot temperature of
the winding, especially shortly after a sudden load increase, the top-oil thermometer is not
suitable for effective protection of the winding against overloads. However, where the policy
toward transformer loss of life permits, tripping on top-oil temperature may be satisfactory.
This approach has the added advantage of directly monitoring the oil temperature to ensure
that it does not reach the flash temperature.
Similar devices are available for responding to air or gas temperatures in dry transformers.
For unattended substations, these devices may be connected to central annunciators.
11.7.4 Thermal relays
Thermal relays, diagrammatically shown in Figure 11-15, are used to give a more direct indi-
cation of winding temperatures of either liquid or dry transformers. A CT is mounted on one
of the three phases of the transformer bushing. It supplies current to the thermometer bulb
heater coil, which contributes the proper heat to closely simulate the transformer hot-spot
temperature.
Monitoring of more than one phase is desirable if a reason exists to expect an unbalance in
the three-phase loading.
The temperature indicator is a bourdon gauge connected through a capillary tube to the ther-
mometer bulb. The fluid in the bulb expands or contracts proportionally to the temperature
changes and is transmitted through the tube to the gauge. Coupled to the shaft of the gauge
indicator are cams that operate individual switches at preset levels of indicated transformer
temperature.
Thermal relays are used more often on transformers rated 10 000 kVA and above than on
smaller transformers. They can be used on all sizes of substation transformers.
Figure 11-15—Thermal (or winding temperature) relay, which uses a heating
element to duplicate effects of current in transformer

IEEE
11.7.5 Hot-spot temperature thermometers
Hot-spot temperature equipment shown in Figure 11-16 is similar to the thermal relay
equipment on a transformer because it indicates the hottest-spot temperature of the
transformer. While the thermal relay works with ﬂuid expansion and a bourdon gauge, the
hot-spot temperature equipment works electrically using a Wheatstone bridge method. In
other words, it measures the resistance of a resistance temperature detector (RTD) that is
responsive to transformer temperature changes and increases with higher temperature.
Because this device can be used with more than one detector coil location, temperatures of
several locations within the transformer can be checked. The location of the hottest spot
within a transformer is predictable from the design parameters. A common practice is to
measure or to simulate this hot-spot temperature and to base control action accordingly. The
desired control action depends on the users’ philosophy, on the amount of transformer life the
user is willing to lose for the sake of maintaining service, and the priorities the user places on
other aspects of the problem. Transformer top-oil temperature may be used, with or without
hot-spot temperature, to establish the desired control action.
A common method of simulating the hot-spot temperature is with a thermal relay responsive
to both top-oil temperature and to the direct heating effect of load current. In these relays, the
thermostatic element is immersed in the transformer top oil. An electric heating element is
supplied with a current proportional to the winding current so that the responsive element
tracks the temperature that the hot spot of the winding attains during operation. If this track-
ing is exact, the relay would operate at the same time that the winding reaches the set
temperature. Because insulation deterioration is also a function of the duration of the high
temperature, additional means are generally used to delay tripping action for some period.
One common method is to design the relay with a time constant longer than the time constant
of the winding. Thus, the relay does not operate until some time after the set temperature has
been attained by the winding. No standards have been established for this measuring tech-
nique, nor is information generally available to make an accurate calculation of the complete
performance of such a relay. These relays can have from one to three contacts that close at
successively higher temperatures. With three contacts, the lowest level is commonly used to
start fans or pumps for forced cooling, and the second level to initiate an alarm. The third step
may be used for an additional alarm or to trip load breakers or to de-energize the transformer.
Figure 11-16—Hot-spot temperature indicator, which utilizes Wheatstone
bridge method to determine transformer temperature

IEEE
Another type of temperature relay is the replica relay. This relay measures the phase current
in the transformer and applies this current to heater units inside the relay. Characteristics of
these heaters approximate the thermal capability of the protected transformer. In the
application of a replica relay, it is desirable to know the time constants of the iron, the
coolant, and the winding. In addition, the relay should be installed in an ambient temperature
approximately the same as the transformer’s ambient temperature and should not be ambient
temperature compensated.
11.7.6 Forced-air cooling
Another means of protecting against overloads is to increase the transformer’s capacity by
auxiliary cooling as shown in Figure 11-17. Forced-air-cooling equipment is used to increase
the capacity of a transformer by 15% to 33% of base rating, depending upon transformer size
and design. Refer to Chapter 8 of IEEE Std 141-1993.1
Dual cooling by a second stage of
forced-air fans or a forced-oil system gives a second increase in capacity applicable to three-
phase transformers rated 12 000 kVA and above.
Forced air cooling can be added later to increase the transformer’s capacity to take care of
increased loads, provided that the transformer was ordered to have provisions for future fan
cooling.
Auxiliary cooling of the insulating liquid helps keep the temperature of the windings and
other components below the design temperature limits. Usually, operation of the cooling
equipment is automatically initiated by the top oil temperature indicator or the thermal relay,
after a predetermined temperature is reached.
Figure 11-17—Forced-air fans, normally controlled automatically from a top
oil temperature or winding temperature relay

IEEE
11.7.7 Fuses or overcurrent relays
Other forms of transformer protection, such as fuses or overcurrent relays, provide some
degree of thermal protection to the transformer. Application of these is discussed in 11.9.1.
11.7.8 Overexcitation protection
Overexcitation may be of concern on direct-connected generator unit transformers. Excessive
excitation current leads directly to overheating of core and unlaminated metal parts of a trans-
former. Such overheating in turn causes damage to adjacent insulation and leads to ultimate
failure. IEEE Std C57.12.00-2000 requires that transformers shall be capable of operating
continuously at 10% above rated secondary voltage at no load without exceeding the limiting
temperature rise. The requirement applies for any tap at rated frequency.
Direct-connected generator transformers are subjected to a wide range of frequency during
the acceleration and deceleration of the turbine. Under these conditions the ratio of the actual
generator terminal voltage to the actual frequency shall not exceed 1.1 times the ratio of
transformer rated voltage to the rated frequency on a sustained basis:
Generator manufacturers now recommend an overexcitation protection system as part of the
generator excitation system. This system may also be used to protect the transformer against
overexcitation. These systems may alarm for an overexcitation condition; and, if the
condition persists, they may decrease the generator excitation or trip the generator and field
breakers, or both. The generator and transformer manufacturers should be asked to provide
their recommendation for overexcitation protection.
Overexcitation relays (i.e., V/Hz) may be used on transformers located either at or remote
from generating stations. They are available with a definite time delay or an inverse-time
overexcitation characteristic and may be connected for trip or alarm.
11.7.9 Nonlinear loads
Nonlinear electrical loads may cause severe overheating even when the transformer is
operating below rated capacity. This overheating may cause failure of both the winding and
the neutral conductor. Electronic equipment such as computers, printers, uninterruptible
power supply (UPS) systems, variable-speed motor drives, and other rectified systems are
nonlinear loads. Arc furnace and rectifier transformers also provide power to nonlinear loads.
For nonlinear loads, the load current is not proportional to the instantaneous voltage. This
situation creates harmonic distortion on the system. Even when the input voltage is
sinusoidal, the nonlinear load makes the input voltage nonsinusoidal. Harmonics are integral
multiples of the fundamental frequency. For a 60 Hz system, the second harmonic is 120 Hz,
the third harmonic is 180 Hz, the fifth is 300 Hz, etc. When incoming ac is rectified to dc, the
load current is switched on for part of a cycle. This switching produces harmonics that extend
generator terminal voltage
actual frequency
--------------------------------------------------------------
- 1.1
transformer rated voltage
transformer rated frequency
------------------------------------------------------------------
-
×
≤

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into the radio frequency range. Nonlinear loads were formerly a small proportion of the total
load and had little effect on system design and equipment, but this is no longer true.
The nonlinear load causes transformer overheating in three ways:
— Hysteresis. Hysteresis causes excessive heating in the steel laminations of the iron
core due to the higher frequency harmonics. These harmonics produce greater
magnetizing losses (or hysteresis) than normal 60 Hz losses because the magnetic
reversals due to harmonics are more rapid than are the fundamental 60 Hz reversals.
— Eddy currents. Heating is produced when the high-frequency harmonic magnetic
fields induce currents to flow through the steel laminations. This event occurs when
the high-frequency harmonic magnetic field cuts through the steel laminations. These
currents (called eddy currents) flow through the resistance of the steel and generate
I2R heating losses. These losses are also greater than normal 60 Hz losses due to the
higher frequencies.
— Skin effect. Heating is also produced in the winding conductors due to skin effect.
Skin effect causes the higher frequency harmonic currents to flow on the outer
portion of the conductor and thus reduce the effective cross-sectional area of the
conductor. This reaction causes an increase in resistance, which results in more
conductor heating than for the same 60 Hz current.
Overheating of neutral conductors from nonlinear loads is due to the following:
— Zero-sequence and odd-order harmonics. Zero-sequence and odd-order harmonics
are additive in the neutral and can be as high as three times the 60 Hz magnitude.
Odd-order harmonics are odd multiples of the fundamental (e.g., third, fifth, seventh,
ninth, eleventh). Zero-sequence harmonics are all the odd multiples of the third har-
monic (e.g., third, ninth, fifteenth).
— Skin effect. Skin effect causes the higher frequency harmonic currents to flow on the
outer portion of the conductor and thus reduce the effective cross-sectional area of
the conductor. This reaction causes an increase in resistance, which results in more
conductor heating than for the same 60 Hz current.
Failures of transformers due to nonlinear loads can be prevented by derating the transformer.
In some cases the neutral conductor may need to be larger (e.g., twice the size of the phase
conductor rating) to prevent its failure. True root-mean-square (rms) meters, relays, and cir-
cuit breaker tripping devices that can sense not needed harmonics should be selected.
Transformers that have a K-factor rating can be used with nonlinear loads within their rating.
The K factor is a numerical value that takes into account both the magnitude and the fre-
quency of the components of a current waveform. It is equivalent to the sum of the squares of
the harmonic current multiplied by the square of the harmonic order of the current. True rms
current meters should be used to determine the per-unit value of each harmonic.

IEEE
K factor = Ih
2h2
where
Ih is the per-unit rated rms load current at harmonic h,
h is the harmonic order.
The K-factor rating indicates the amount of harmonic content the transformer can handle
while remaining within its operating temperature limits.
11.8 Transformer primary protective device
A fault on the electrical system at the point of connection to the transformer can arise from
failure of the transformer (e.g., internal fault) or from an abnormal condition on the circuit
connected to the transformer secondary, such as a short circuit (e.g., through fault). The
predominant means of clearing such faults is a current-interrupting device on the primary
side of the transformer, such as fuses, a circuit breaker, or a circuit switcher. Whatever the
choice, the primary-side protective device should have an interrupting rating adequate for the
maximum short-circuit current that can occur on the primary side of the transformer. If a
circuit switcher is used, it should be relayed so that it is called upon only to clear lower
current internal or secondary faults that are within its interrupting capability. Instantaneous
relays used to protect transformer feeders and high-voltage windings are set greater than the
maximum asymmetrical through-fault current on the transformer secondary. The operating
current of the primary protective device should be less than the short-circuit current of the
transformer as limited by the combination of system and transformer impedance. This
recommendation is true for a fuse or a time-overcurrent relay. The point of operation should
not be so low, however, to cause circuit interruption due to the inrush excitation current of the
transformer or normal current transients in the secondary circuits. Of course, any devices
operating to protect the transformer by detecting abnormal conditions within the transformer
and removing it from the system also operate to protect the system; but these devices are
subordinate to the primary protection of the transformer.
11.9 Protecting the transformer from electrical disturbances
Transformer failures arising from abusive operating conditions are caused by
— Continuous overloading
— Short circuits
— Ground faults
— Transient overvoltages
11.9.1 Overload protection
An overload causes a rise in the temperature of the various transformer components. If the
ﬁnal temperature is above the design temperature limit, deterioration of the insulation system

IEEE
occurs and causes a reduction in the useful life of the transformer. The insulation may be
weakened so that a moderate overvoltage may cause insulation breakdown before expiration
of expected service life. Transformers have certain overload capabilities that vary with ambi-
ent temperature, preloading, and overload duration. These capabilities are defined in
ANSI C57.92-2000 and IEEE Std C57.96-1999. When the temperature rise of a winding is
increased, the insulation deteriorates more rapidly, and the life expectancy of the transformer
is shortened.
Protection against overloads consists of both load limitation and overload detection. Loading
on the transformers may be limited by designing a system where the transformer capacity is
greater than the total connected load when a diversity in load usage is assumed. This method
of providing overload protection is expensive because load growth and changes in operating
procedures would quite often eliminate the extra capacity needed to achieve this protection. A
good engineering practice is to size the transformer at about 125% of the present load to
allow for system growth and change in the diversity of loads. The specification of a lower-
than-ANSI temperature rise also permits an overload capability.
Load limitation by disconnecting part of the load can be done automatically or manually.
Automatic load shedding schemes, because of their cost, are restricted to larger units. How-
ever, manual operation is often preferred because it gives greater flexibility in selecting the
expendable loads.
In some instances, load growth can be accommodated by specifying cooling fans or provid-
ing for future fan cooling.
The major method of load limitation that can be properly applied to a transformer is one that
responds to transformer temperature. By monitoring the temperature of the transformer,
overload conditions can be detected. A number of monitoring devices that mount on the
transformer are available as standard or optional accessories. These devices are normally
used for alarm or to initiate secondary protective device operation. They include the devices
described in 11.9.1.1 and 11.9.1.2.
11.9.1.1 Overcurrent relays
Transformer overload protection may be provided by relays. Chapter 4 describes overcurrent
relay construction characteristics and ranges. These relays are applied in conjunction with
CTs and a circuit breaker or circuit switcher, sized for the maximum continuous and inter-
rupting duty requirements of the application. A typical application is shown in Figure 11-18.
Overcurrent relays are selected to provide a range of settings above the permitted overloads
and instantaneous settings when possible within the transformer through-fault current with-
stand rating. The characteristics should be selected to coordinate with upstream and down-
stream protective devices.
The settings of the overcurrent relays should meet the requirements of applicable standards
and codes and meet the needs of the power system. The requirements in the National
Electrical Code®
(NEC®
) (NFPA 70-1999) represent upper limits that should be met when

IEEE
selecting overcurrent devices. These requirements, however, are not guidelines for the design
of a system providing maximum protection for transformers. For example, setting a
transformer primary or secondary overcurrent protective device at 2.5 times rated current
could allow that transformer to be damaged without the protective device operating.
11.9.1.2 Fuses, circuit breakers, and fused switches
The best protection for the transformer is provided by circuit breakers or fuses on both the
primary side and secondary side of the transformer when they are set or selected to operate at
minimum values. Common practice is for the secondary-side circuit breaker or fuses to pro-
tect the transformer for loading in excess of 125% of maximum rating.
Using a circuit breaker on the primary of each transformer is expensive, especially for small-
capacity and less expensive transformers. An economical compromise is where one circuit
breaker is installed to feed two to six relatively small transformers. Each transformer has its
own secondary circuit breaker and, in most cases, a primary disconnect. Overcurrent protec-
tion should satisfy the requirements prescribed by the NEC.
The major disadvantage of this system is that all of the transformers are de-energized by the
opening of the primary circuit breaker. Moreover, the rating or setting of a primary circuit
breaker selected to accommodate the total loading requirements of all of the transformers
would typically be so large that only a small degree of secondary-fault protection, and almost
no backup protection, would be provided for each individual transformer.
By using fused switches on the primary of each transformer, short-circuit protection can be
provided for the transformer and additional selectivity provided for the system. Using fused
switches and time-delay dual-element fuses for the secondary of each transformer allows
Figure 11-18—Overcurrent relays, frequently used to provide transformer
protection in combination with primary circuit breaker or circuit switcher

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close sizing (typically 125% of secondary full-load current) and gives excellent overload and
short-circuit protection for 600 V or less applications.
11.9.2 Short-circuit current protection
In addition to thermal damage from prolonged overloads, transformers are also adversely
affected by internal or external short-circuit conditions, which can result in internal electro-
magnetic forces, temperature rise, and arc-energy release.
Ground faults occurring in the substation transformer secondary or between the transformer
secondary and main secondary protective device cannot be isolated by the main secondary
protective device, which is located on the load side of the ground fault. These ground faults,
when limited by a neutral grounding resistor, may not be seen by either the transformer pri-
mary fuses or transformer differential relays. They can be isolated only by a primary circuit
breaker or other protective device tripped by either a ground relay in the grounding resistor
circuit or a ground differential relay. A ground differential relay may consist of a simple over-
current relay, connected to a neutral ground CT and the residual circuit of the transformer line
CTs fed through a ratio matching auxiliary CT. Because this scheme is subject to error on
through faults due to unequal CT saturation, a relay with phase restraint coils may be used
instead of a simple overcurrent relay.
Secondary-side short circuits can subject the transformer to short-circuit current magnitudes
limited only by the sum of transformer and supply-system impedance. Hence, transformers
with unusually low impedance may experience extremely high short-circuit currents and
incur mechanical damage. Prolonged flow of a short-circuit current of lesser magnitude can
also inflict thermal damage.
Protection of the transformer for both internal and external faults should be as rapid as
possible to keep damage to a minimum. This protection, however, may be reduced by
selective-coordination system design and operating procedure limitations.
Several sensing devices are available that provide varying degrees of short-circuit protection.
These devices sense two different aspects of a short circuit. The first group of devices senses
the formation of gases consequent to a fault and are used to detect internal faults. The second
group senses the magnitude or the direction of the short-circuit current, or both, directly.
The gas-sensing devices include pressure-relief devices, rapid pressure rise relays, gas-
detector relays, and combustible-gas relays. The current-sensing devices include fuses,
overcurrent relays, differential relays, and network protectors.
11.9.2.1 Gas-sensing devices
Low-magnitude faults in the transformer cause gases to be formed by the decomposition of
insulation exposed to high temperature at the fault. Detection of the presence of these gases
can allow the transformer to be taken out of service before extensive damage occurs. In some
cases, gas may be detected a long time before the unit fails.

IEEE
High-magnitude fault currents are usually first sensed by other detectors, but the gas-sensing
device responds with modest time delay. These devices are described in detail in 11.6.
11.9.2.2 Current-sensing devices
Fuses, overcurrent relays, and differential relays should be selected to provide the maximum
degree of protection to the transformer. These protective devices should operate in response
to a fault before the magnitude and duration of the overcurrent exceed the short-time loading
limits recommended by the transformer manufacturer. In the absence of specific information
applicable to an individual transformer, protective devices should be selected in accordance
with applicable guidelines for the maximum permissible transformer short-time loading lim-
its. Curves illustrating these limits for liquid-immersed transformers are discussed in
11.9.2.2.1. In addition, ratings or settings of the protective devices should be selected in
accordance with pertinent provisions of Chapter 4 of NEC Article 450.
11.9.2.2.1 Transformer through-fault capability
The following discussion is excerpted and paraphrased from Appendix A of ANSI C37.91-
2000. Similar information and through-fault protection curves can be found in
IEEE Std C57.109-1993. The following discussion is based on these two standards.
Overcurrent protective devices such as fuses and relays have well-defined operating charac-
teristics that relate fault-current magnitude to operating time. The characteristic curves for
these devices should be coordinated with comparable curves, applicable to transformers,
which reflect their through-fault withstand capability. Such curves for Category I,
Category II, Category III, and Category IV liquid-immersed transformers (as described in
IEEE Std C57.12.00-2000) are presented in this subclause as through-fault protection curves.
The through-fault protection curve values are based on winding-current relationships for a
three-phase secondary fault and may be used directly for delta-delta- and wye-wye-connected
transformers. For delta-wye-connected transformers, the through-fault protection curve val-
ues should be reduced to 58% of the values shown to provide appropriate protection for a
secondary-side single phase-to-neutral fault.
Damage to transformers from through faults is the result of thermal and mechanical effects.
The latter have gained increased recognition as a major cause of transformer failure.
Although the temperature rise associated with high-magnitude through faults is typically
acceptable, the mechanical effects are intolerable if such faults are permitted to occur with
any regularity. This possibility results from the cumulative nature of some of the mechanical
effects, particularly insulation compression, insulation wear, and friction-induced displace-
ment. The damage that occurs as a result of these cumulative effects is, therefore, a function
of not only the magnitude and duration of through faults, but also the total number of such
faults.
The through-fault protection curves presented in IEEE Std C57.12.00-2000 take into consid-
eration the fact that transformer damage is cumulative, and the number of through faults to
which a transformer can be exposed is inherently different for different applications. For

IEEE
example, transformers with secondary-side conductors enclosed in conduit or isolated in
some other fashion, such as transformers typically found in industrial, commercial, and
institutional power systems, experience an extremely low incidence of through faults. In con-
trast, transformers with overhead secondary-side lines, such as transformers found in utility
distribution substations, have a relatively high incidence of through faults. Also, the use of
reclosers or automatic reclosing circuit breakers may subject the transformer to repeated cur-
rent surges from each fault. Thus, for a given transformer in these two different applications,
a different through-fault protection curve should apply, depending on the type of application.
For applications in which faults occur infrequently, the through-fault protection curve should
reflect primarily thermal damage considerations because cumulative mechanical-damage
effects of through faults would not be a problem. For applications in which faults occur fre-
quently, the through-fault protection curve reflects the fact that the transformer is subjected to
both thermal and cumulative-mechanical damage effects of through faults.
In using the through-fault protection curves to select the time-current characteristics (TCCs)
of protective devices, the protection engineer should take into account not only the inherent
level of through-fault incidence, but also the location of each protective device and its role in
providing transformer protection. For substation transformers with secondary-side overhead
lines, the secondary-side feeder protective equipment is the first line of defense against
through faults; therefore, its TCCs should be selected by reference to the frequent-fault-inci-
dence protection curve. More specifically, the TCCs of feeder protective devices should be
below and to the left of the appropriate frequent-fault-incidence protection curve. Secondary-
side main protective devices (if applicable) and primary-side protective devices typically
operate to protect against through faults in the rare event of a fault between the transformer
and the feeder protective devices, or in the equally rare event that a feeder protective device
fails to operate or operates too slowly due to an incorrect (i.e., higher) rating or setting. The
TCCs of these devices, therefore, should be selected by reference to the infrequent-fault-inci-
dence protection curve. In addition, these TCCs should be selected to achieve the desired
coordination among the various protective devices.
In contrast, transformers with protected secondary conductors (e.g., cable, bus duct, switch-
gear) experience an extremely low incidence of through faults. Hence the feeder protective
devices may be selected by reference to the infrequent-fault-incidence protection curve. The
secondary-side main protective device (if applicable) and the primary-side protective device
should also be selected by reference to the infrequent-fault-incidence protection curve.
Again, these TCCs should also be selected to achieve the desired coordination among the var-
ious protective devices.
For Category I transformers (i.e., 5-500 kVA single-phase, 15-500 kVA three-phase), a single
through-fault protection curve applies (see Figure 11-19). This curve may be used for select-
ing protective device TCCs for all applications, regardless of the anticipated level of fault
incidence.
For Category II transformers (i.e., 501-1667 kVA single-phase, 501-5000 kVA three-phase),
and Category III transformers (i.e., 1668-10 000 kVA single-phase, 500-30 000 kVA three-
phase), two through-fault protection curves apply (see Figure 11-20 and Figure 11-21,
respectively). The left-hand curve in both figures reflects both thermal and mechanical

IEEE
damage considerations and may be used for selecting feeder protective device TCCs for
frequent-fault-incidence applications. The right-hand curve in both figures reflects primarily
thermal damage considerations and may be used for selecting feeder protective device TCCs
for infrequent-fault-incidence applications. These curves may also be used for selecting
secondary-side main protective device (if applicable) and primary-side protective device
TCCs for all applications, regardless of the anticipated level of fault incidence.
For Category IV transformers (i.e., above 10 000 kVA single-phase, above 30 000 kVA three-
phase), a single through-fault protection curve applies (see Figure 11-22). This curve reflects
both thermal and mechanical damage considerations and may be used for selecting protective
device TCCs for all applications, regardless of the anticipated level of fault incidence.
Figure 11-19—Through-fault protection curve for
liquid-immersed Category I transformers
(5–500 kVA single-phase, 15–500 kVA three-phase)

IEEE
The aforementioned delineation of infrequent- versus frequent-fault-incidence applications
for Category II and Category III transformers can be related to the zone or location of the
fault (see Figure 11-23).
Because overload protection is a function of the secondary-side protective device or devices,
the primary-side protective device characteristic curve may cross the through-fault protection
curve at lower current levels. (Refer to appropriate transformer loading guides,
IEEE Std C57.91-1995 and ANSI C57.92-2000.) Efforts should be made to have the primary-
side protective device characteristic curve intersect the through-fault protection curve at as
low a current as possible in order to maximize the degree of backup protection for the sec-
ondary-side devices.
Figure 11-20—Through-fault protection curves for
liquid-immersed Category II transformers
(501–1667 kVA single-phase, 501–5000 kVA three-phase)

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11.9.2.2.2 Fuses
Fuses utilized on the transformer primary are relatively simple and inexpensive one-time
devices that provide short-circuit protection for the transformer. Fuses are normally applied
in combination with interrupter switches capable of interrupting full-load current. By using
fused switches on the primary where possible, short-circuit protection can be provided for the
transformer, and a high degree of system selectivity can also be provided.
Fuse selection considerations include having
— An interrupting capacity equal to or higher than the system fault capacity at the point
of application
— A continuous-current capability above the maximum continuous load under various
operating modes
Figure 11-21—Through-fault protection curves for
liquid-immersed Category III transformers
(1668–10 000 kVA single-phase, 5001–30 000 kVA three-phase)

IEEE
— TCCs that pass, without fuse operation, the magnetizing and load-inrush currents that
occur simultaneously following a momentary interruption, but interrupt before the
transformer withstand point is reached
Fuses so selected can provide protection for secondary faults between the transformer and the
secondary-side overcurrent protective device and provide backup protection for the latter.
The magnitude and duration of magnetizing inrush currents vary between different designs of
transformers. Inrush currents of 8 or 12 times normal full-load current for 0.1 s are commonly
used in coordination studies.
Overload protection can be provided when fuses are used by utilizing a contact on the
transformer temperature indicator to shed nonessential load or trip the transformer
secondary-side overcurrent protective device.
Figure 11-22—Through-fault protection curve for
liquid-immersed Category IV transformers
(above 10 000 kVA single-phase, above 30 000 kVA three-phase)

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When the possibility of backfeed exists, the switch, the fuse access door, and the transformer
secondary main overcurrent protective device should be interlocked to ensure the fuse is de-
energized before being serviced.
Relay-protected systems can provide low-level overcurrent protection. Relay protection sys-
tems and fused interrupter switches can provide protection against single-phase operation
when an appropriate open-phase detector is used to initiate opening of a circuit breaker or
interrupter switch if an open-phase condition should occur.
11.9.2.2.3 Overcurrent relay protection
Overcurrent relays may be used to clear the transformer from the faulted bus or line before
the transformer is damaged. On some small transformers, overcurrent relays may also protect
for internal transformer faults. On larger transformers, overcurrent relays may be used to pro-
vide backup for differential or pressure relays.
Figure 11-23—Infrequent- and frequent-fault-incidence zones for
liquid-immersed Category II and Category III transformers

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11.9.2.2.3.1 Time overcurrent relays
Overcurrent relays applied on the primary side of a transformer provide protection for
transformer faults in the winding, and provide backup protection for the transformer for
secondary-side faults. They provide limited protection for internal transformer faults because
sensitive settings and fast operation are usually not possible. Insensitive settings result
because the pickup value of phase-overcurrent relays must be high enough to take advantage
of the overload capabilities of the transformer and be capable of withstanding energizing
inrush currents. Fast operation is not possible because they must coordinate with load-side
protection. Settings of phase-overcurrent relays on transformers involve a compromise
between the requirements of operation and protection.
These settings may result in extensive damage to the transformer from an internal fault. If
only overcurrent protection is applied to the high-voltage delta side of a delta-wye-grounded
transformer, it can have a problem providing sensitive fault protection for the transformer. For
low-voltage (wye-side) line-to-ground faults, the high-side line current is only 58% of the
low-voltage per-unit fault current. When the wye is grounded through a resistor, the high-side
fault current may be less than the maximum transformer load current.
The time setting should coordinate with relays on downstream equipment. However,
transformers are mechanically and thermally limited in their ability to withstand short-circuit
current for ﬁnite periods. For proper backup protection, the relays should operate before the
transformer is damaged by an external fault. (Refer to the transformer through-fault current
duration limits.)
When overcurrent relays are also applied on the secondary side of the transformer, these
relays are the principal protection for transformer secondary-side faults. However, overcur-
rent relays applied on the secondary side of the transformer do not provide protection for the
transformer winding faults, unless the transformer is backfed.
When setting transformer overcurrent relays, the short-time overload capability of the trans-
former in question should not be violated. (See IEEE Std C57.91-1995 and
ANSI C57.92-2000 for allowable short-time durations, which may be different from the
durations in the through-fault current duration curves.) The manufacturer should be consulted
for the capability of a speciﬁc transformer.
11.9.2.2.3.2 Instantaneous overcurrent relays
Phase instantaneous overcurrent relays provide short-circuit protection to the transformers in
addition to overload protection. When used on the primary side, they usually coordinate with
secondary protective devices. Fast clearing of severe internal faults can be obtained. The
setting of an instantaneous relay is selected on its application with respect to secondary
protective devices and circuit arrangements. Such relays are normally set to pick up at a value
higher than the maximum asymmetrical through-fault current. This value is usually the fault
current through the transformer for a low-side three-phase fault. The setting of instantaneous
devices for short-circuit protection for three-circuit arrangements is described in Mathur
[B21].2
For instantaneous units subject to transient overreach, a pickup setting of 175% of the

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calculated maximum low-side three-phase symmetrical fault current generally provides
sufﬁcient margin to avoid false tripping for a low-side bus fault, while still providing
protection for severe internal faults. (Variations in pickup settings of 125% to 200% are
common.) For instantaneous units with negligible transient overreach, a lesser margin can be
used. The settings in either case shall also be above the transformer inrush current to prevent
nuisance tripping. In some cases, instantaneous trip relays cannot be used because the
necessary settings are greater than the available fault currents. In these cases, a harmonic
restraint instantaneous relay may be considered to provide the desired protection.
11.9.2.2.3.3 Tertiary winding overcurrent relays
The tertiary winding of an autotransformer, or three-winding transformer, is usually of much
smaller kilovoltampere rating than the main windings. Therefore, fuses or overcurrent relays
set to protect the main windings offer almost no protection to such tertiaries. During external
system ground faults, these tertiary windings may carry very heavy currents.
The method selected for protecting the tertiary generally depends on whether the tertiary is
used to carry load. If the tertiary does not carry load, protection can be provided by a single
overcurrent relay connected to a CT on the tertiary winding. This relay senses system
grounds and also phase faults in the tertiary or in its leads.
If the tertiary is used to carry load, partial protection can be provided by a single overcurrent
relay supplied by three CTs, one in each winding of the tertiary and connected in parallel to
the relay. This connection provides zero-sequence protection, but does not protect for
positive- and negative-sequence overload current. The relay operates for system ground
faults, but does not operate for phase faults in the tertiary or its leads. This relay needs to be
set to coordinate with other system relays.
11.9.2.2.4 Differential relays
11.9.2.2.4.1 Phase differential relays
Differential relaying compares the sum of currents entering the protected zone to the sum of
currents leaving the protected zone; these sums should be equal. If more than a certain
amount or percentage of current enters than leaves the protected zone, a fault is indicated in
the protected zone; and the relay operates to isolate the faulted zone.
Transformer differential relays operate on a percentage ratio of input current to through cur-
rent; this percentage is called the slope of the relay. A relay with 25% slope operates when the
difference between the incoming and outgoing currents is greater than 25% of the through
current and higher than the relay minimum pickup.
The fault-detection sensitivity of differential relays is determined by a combination of relay
setting and circuit parameters. For most high-speed transformer differential relays, the relay
pickup is about 30% of the tap setting. Depending on the setting, sensitivity is about 25% to
2Numbers in brackets correspond to the numbers in the bibliography in 11.13.

IEEE
50% of full-load current. For delta-wye-connected transformers that supply low-resistance-
grounded systems, phase differential relays should be supplemented with secondary ground
differential relays (Device 87TG), as shown in Figure 11-24, to provide additional sensitivity
to secondary ground faults. For more details on application of Device 87TG, refer to
Chapter 8 on ground-fault protection.
The protection for a single-phase transformer is shown in Figure 11-25, although most trans-
former differential relay applications would apply to three-phase transformers of 5 MVA and
larger.
In Figure 11-25, two restraining windings and one operating coil are shown. The CT ratios
are selected to produce essentially equal secondary currents so that, under a no-fault condi-
tion, the CT secondary current entering one restraining circuit continues through the other
restraining circuit, with no differential current to pass through the operating circuit. Because
Figure 11-24—Transformer phase and ground differential relay CT and
current coil connections

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of ratio mismatches in CTs and relay tap settings, some current may always exist in the oper-
ating circuit under a no-fault condition.
When a fault is internal to the differential relay zone, definite quantities of current flow into
the operating circuit. The relay then responds to this differential current based on the ratio of
the operating current to the restraining currents. The relay operates to trip when this ratio
exceeds the slope setting and is above the relay minimum sensitivity. (Ratio settings of 15%,
25%, 30%, or 40% are usually available.) The three-phase connection shown in Figure 11-26
illustrates a typical application for protection of a three-phase transformer. The transformer is
connected wye-delta: this configuration is selected generally to provide an ungrounded sec-
ondary connection while permitting the primary wye neutral to be grounded solidly. Other
configurations would be reversed, and the grounded wye would be the secondary connection.
The basic delta-wye or wye-delta connection produces a phase shift between current entering
the primary and current leaving the secondary. For this reason, the CTs on the wye side have
their secondaries connected in delta, and the CTs on the delta side have their secondaries con-
nected in wye.
Several considerations are involved in the application of differential relays:
a) The system should be designed so that the relays can operate a transformer primary
circuit breaker. If a remote circuit breaker is to be operated, a remote trip system
should be used (e.g., a pilot wire, a high-speed grounding switch). Often the utility
controls the remote circuit breaker and may not allow it to be tripped. Operation of a
user-owned local primary circuit breaker presents no problem.
b) CTs associated with each winding typically have different ratios, ratings, and excita-
tion characteristics when subjected to heavy loads and short circuits. Multiratio CTs
Figure 11-25—Percentage differential relays, which provide
increased sensitivity while minimizing false operation as a result of
CT mismatch errors for heavy through faults

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and relay taps may be selected to compensate for ratio differences. A less preferable
but acceptable method is to use auxiliary transformers.
c) Transformer taps can be operated changing the effective turns ratio. By selecting the
ratio and taps for midrange, the maximum unbalance will be equivalent to half the
transformer tap range.
d) CTs of the same make and type are recommended to minimize error current due to
the CT’s different characteristics.
e) Magnetizing inrush current appears as an internal fault to the differential relays. The
relays should be desensitized to the inrush current, but they should be sensitive to
short circuits within the protection zone during the same period. This goal can be
accomplished using relays with harmonic restraint. The magnetizing current inrush
has a large harmonic component, which is not present in short-circuit currents. This
feature permits harmonic-restraint relays to distinguish between faults and inrush.
f) Transformer connections often introduce a phase shift between high- and low-voltage
currents. Proper CT connections compensate for this shift. For a delta-primary, wye-
secondary transformer, CTs are normally wye connected in the primary and delta
connected in the secondary.
g) Heavy currents for faults outside the zone of protection can cause an unbalance
between the CTs. Percentage differential relays shown in Figure 11-25, which oper-
ate when the difference is greater than a deﬁnite percentage of the phase current, are
designed to overcome this problem. Percentage differential relays also help in solving
the tap-changing problem and the CT ratio balance problem. Percentage slopes vary
by manufacturer, but are generally available from 15% to 60%. A slope of 15% is
normally used for standard transformers, 25% for load tap-changing transformers,
and 40% to 60% for special applications. Guidelines are provided in 4.4.15.3 on
Figure 11-26—Typical schematic connections for percentage differential
protection of a wye-delta transformer

IEEE
selecting the slope. Harmonic-restraint percentage differential relays are recom-
mended for transformers rated 5000 kVA and above.
Unlike the differential relays applied to protect high-voltage buses or large motors,
the transformer differential relay application has both harmonics and phase shift to
consider. Although all transformer differential relays do not include harmonic filters,
the use of harmonic filters has been beneficial and faster acting, and they permit more
sensitive pickups.
h) A delta-wye, or wye-delta, transformer with the neutral grounded is a source (i.e.,
generator) of zero-sequence (or ground) fault current. A ground fault on the wye side
of the transformer, external to the differential protective zone, causes zero-sequence
currents to flow in the CTs on the wye side of the transformer without corresponding
current flow in the line CTs on the delta side of the transformer. If these zero-
sequence currents are allowed to flow through the differential relays, they cause
immediate undesired tripping. To prevent such undesired tripping, the CT connec-
tions should cause the zero-sequence currents to flow in a closed-delta CT secondary
connection of low impedance instead of in the differential relay operating coil. This
goal is readily accomplished by connecting the CT secondary in delta on the wye side
of the transformer.
In addition to the phase shift, which is easily corrected, the magnitudes of the secondary
currents rarely match each other when standard CT ratios are employed. To compensate for
this tendency, most percentage differential relays have selectable auto transformer taps at the
input of each restraining winding. By following the relay instructions, the best match can be
made so that the current in the no-fault operating coil is minimized. In some cases where
high-voltage switchyards are involved, the available relay adjustments on electromechanical
relays are inadequate, due to the limited tap range available. Therefore, auxiliary CTs or
autotransformers are needed. This configuration should be attempted only after a thorough
examination of the effects of through faults and secondary burdens upon the primary CTs.
Solid-state relays typically have a wide tap range with incremental selectivity that allows
reduced mismatch to below 2%. This setup eliminates the need for auxiliary or
autotransformers.
Assuming that CT ratio and phase shift problems can be resolved, a transformer secondary
may often be connected to more than one bus. In that event, a separate restraining winding is
required for each such bus. Paralleling CT secondaries in place of multiple restraining
windings can lead to misoperation on through faults if the secondary buses are strong fault-
current sources. If they are only weak sources, then paralleled CT secondaries are acceptable.
Harmonics in the primary circuit can develop during transformer energization, during
overvoltage periods, and during through faults. The harmonics could cause differential relay
misoperation if not recognized. For the most part, zero-sequence harmonics (e.g., third,
ninth) are excluded from the relays by the CT secondary connection.
The second harmonic and some relays with higher harmonics (e.g., fifth, seventh, eleventh,
thirteenth) are filtered to restrain them. The filtered harmonics are applied to the restraining
winding when the magnitude of the second harmonic exceeds 7.5% to 20% of the fundamen-

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tal current. The lower percentage is beneﬁcial during normal no-fault conditions because it
provides larger restraining action, but the lower percentage setting makes the relay less sensi-
tive on an internal fault.
11.9.2.2.4.2 Ground differential relays
Protection of the transformer by percentage differential relays improves the overall effective-
ness in detecting phase-to-phase internal faults. However, line-to-ground faults in a wye
winding may not be detected if the transformer is low-resistance-grounded where ground-
fault current is limited to a low value below the differential relay pickup level. Such ground
faults may evolve into to a destructive phase-to-phase fault. A protection scheme for low-
resistance-grounded system is shown in Figure 11-24. Where the transformer is solidly
grounded, the transformer differential relay operates for ground faults within the differential
protective zone.
Two methods can be easily adapted for protecting the wye winding more effectively.
Figure 11-27 illustrates one approach that employs an overcurrent relay in a differential con-
nection. The zero-sequence currents are shown for an external fault. Properly connected, the
secondary current circulates for this external fault, but would be additive for an internal fault
and cause Device 51G to operate. The method shown in Figure 11-27 is susceptible to
through faults that may saturate the phase CTs and cause Device 51G to operate. For this rea-
son CT selections are more demanding and Device 51G settings are less sensitive than would
originally appear.
NOTE—Zero-sequence current arrows are for an external ground fault for which the relay does not
operate.
Figure 11-27—Complete ground-fault protection for delta-wye transformer,
using residual overcurrent and differentially connected ground relay

IEEE
Utilizing a directional relay shown in Figure 11-28 can overcome problems associated with
CT saturation on through faults. The currents shown are for an external fault, and the second-
ary currents circulate as shown. However, upon an internal fault, the secondary currents are
additive in the operating coil as shown in Figure 11-29. This directional relay has the addi-
tional element that prevents misoperation and, in fact, permits a faster acting relay: a product
relay that can operate in less than a cycle. Comparing this operating time to the seconds taken
by a Device 51G relay makes the choice more definitive.
In any ground-fault differential relay application, selection of CT ratios is important. The
neutral CT ratio is generally smaller than the phase CT. In such cases, the auxiliary CT in the
residual secondary can correct this mismatch. Some users select the auxiliary CT ratio so that
slightly more restraining current flows during an external fault, as shown in Figure 11-30. In
effect, this excess secondary current flows in the opposite direction in the operating winding
and precludes false operation.
NOTE–Zero-sequence current arrows are for an external ground fault for which the relay does not
operate.
Figure 11-28—Directional relay for detection of ground faults in grounded
wye-connected transformer
Figure 11-29—Relay current during transformer internal faults

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11.9.2.3 Network protectors
The network protector is normally flange mounted directly on the network transformer low-
voltage terminals. The network protector contains the following components: low-voltage air
circuit breaker, controls for the air circuit breaker, and network relays. Network protectors
trip for faults occurring on the primary side of the network transformer and/or when a power
reversal occurs with power flowing from the secondary side of the network transformer to the
primary side. The wattvar network master relay has superior operating characteristics over
the standard watt network master relay. If a primary-side line-to-ground fault occurs and a
single primary fuse operates without tripping the feeder breaker, the unfaulted phases may
still supply power to the network. Under these conditions, the net three-phase power flow in
the network protector is not in the reverse direction, and the standard watt master relay does
not operate. The reactive flow (vars) in the network protector is in the reverse direction. The
wattvar master relay properly connected to see this reverse reactive flow operates for this
condition.
11.9.3 Protection against overvoltages
Transient overvoltages produced by lightning, switching surges, switching of power factor
correction capacitors, and other system disturbances can cause transformer failures. High-
voltage disturbances can be generated by certain types of loads and from the incoming line. A
common misconception is that underground services are isolated from these disturbances.
System insulation coordination in the use and location of primary and secondary surge arrest-
ers is important. Normally, liquid-insulated transformers have higher basic impulse insulation
level (BIL) ratings than standard ventilated dry and sealed dry transformers. Solid dielectric
cast coil transformers have BILs equal to liquid-insulated transformers. Ventilated dry trans-
formers and sealed dry transformers can be specified to have BILs equal to the BILs of liquid
transformers.
11.9.3.1 Surge arresters
Ordinarily, if the liquid-insulated transformer is supplied by enclosed conductors from the
secondaries of transformers with adequate primary surge protection, additional protection
Figure 11-30—Relay current during external fault when auxiliary CT ratio is
selected to restrain

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may not be required, depending on the system design. However, if the transformer primary or
secondary is connected to conductors that are exposed to lightning, the installation of surge
arresters is necessary. For best protection, the surge arrester should be mounted as close as
possible to the transformer terminals, preferably within 1 m and on the load side of the
incoming switch. This location ensures that the lead inductance does not affect the impedance
adversely and, therefore, affect the performance of the surge arrester and surge capacitor. If
the surge arrester is built into the transformer, further engineering is required to determine
whether additional surge protection is required on the secondary.
The degree of surge protection obtained is determined by the amount of exposure, the size
and importance of the transformer to the system, and the type and cost of the arresters. In
descending order of cost and degree of protection, the types of arresters are station, interme-
diate, and distribution.
Ventilated dry and sealed dry transformers are normally used indoors, and surge protection is
still necessary. Because all systems have the potential for transmitting and reﬂecting primary
and secondary surges caused by lightning and system disturbances, special low-sparkover
distribution arresters and low-voltage arresters have been developed for the protection of dry
transformers and rotating machinery.
The surge arrester selection (i.e., kV class) should be based on the system voltage and system
conditions (i.e., grounded or ungrounded). The arrester kV class is not determined by the kV
class of the primary winding of the transformer.
11.9.3.2 Surge capacitors
Additional protection in the form of surge capacitors located as closely as possible to the
transformer terminals may also be appropriate for all types of transformers. The installation
should be examined for excess capacitance already existing in the shielded conductors.
Transformer windings can experience a nonuniform distribution of a fast-front surge in the
winding, and this surge can overstress the turn insulation locally in parts of the windings.
Surge capacitors serve a dual function of sloping off fast-rising transients that might impinge
on the transformer winding and of reducing the effective surge impedance presented by the
transformer to an incoming surge. This type of additional protection is appropriate against
voltage transients generated within the system due to circuit conditions such as prestriking,
restriking, high-frequency current interruption, multiple reignitions, voltage escalation, and
current suppression (or chopping) as the result of switching, current-limiting fuse operation,
thyristor-switching, or ferroresonance conditions.
11.9.3.3 Ferroresonance
Ferroresonance is a phenomenon resulting in the development of a higher than normal
voltage in the windings of a transformer. These overvoltages may result in surge arrester
operation, damage to the transformer, and electrical shock hazard. The following conditions
combine to produce ferroresonance:
a) No load on the transformer

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b) An open circuit on one of the primary terminals of the transformer and, at the same
time, an energized terminal. In the case of three-phase transformers, either one or two
of the three primary terminals may be disconnected.
c) The location of the point of disconnection if it is not close to the transformer
d) A voltage potential between the disconnected terminal conductor and ground
The resonant circuit may be traced from the energized terminal through the transformer
primary to one of the disconnected terminals, then through the capacitance of the isolated
terminal conductor insulation to ground, and then back through the supply system to the
energized terminal (see Figure 11-31). Although more common with underground
distribution systems, ferroresonance can occur with overhead lines when the single-phase
open point is far enough from the transformer. The typical scenarios for ferroresonance
involve single-phase remote switching of an unloaded transformer, remote primary fuse
operation on one phase, or failure of all three poles of a three-pole device to properly open
accompanied by disconnection of the secondary load.
Ferroresonance may be minimized or eliminated by having load connected to the secondary
when single-phase switching on the primary; by using gang-operated switches, circuit break-
ers, or circuit switchers on the primary; or by providing that current-interrupting devices are
located next to or on the transformer.
The subject of ferroresonance is complicated, and the literature on this subject should be
reviewed by concerned persons to avoid ferroresonance in transformer operation or system
design.
11.10 Protection from the environment
In addition to electrical protection, protection for the transformer against physical conditions
in the environment that may affect reliable performance is also necessary. Although most of
these conditions are obvious, they are important enough to be listed. Undesirable conditions
include
Figure 11-31—One-line diagram showing current ﬂow that may result in
ferroresonance

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a) Average ambient temperatures above 30 °C when the transformer is loaded at rated
kilovoltampere or more
b) Corrosive agents, abrasive particulate matter, and surface contaminants derived from
the surrounding atmosphere
c) Conditions that can lead to moisture penetration or to condensation on windings and
other internal electrical components
d) Submersion in water or mud
e) Obstruction to proper ventilation of liquid transformer radiators or, in the case of dry
transformers, ventilating openings
f) Exposure to damage from collision by vehicles
g) Excessive vibration
h) Exposure to vandalism
11.11 Conclusion
Protection of today’s larger and more expensive transformers can be achieved by the proper
selection and application of protective devices. Published application guides covering
transformers are readily available, for example, ANSI C37.91-2000. The system design
engineer should rely heavily on sound engineering judgment to achieve an adequate
protection system.
11.12 References
ANSI C37.91-2000, ANSI Guide for Protective Relay Applications to Power Transformers.
ANSI C57.92-2000, ANSI Guide for Loading Mineral-Oil-Immersed Power Transformers
Up to and Including 100 MVA with 55 °C or 65 °C Winding Rise.3
IEEE Std 493-1997, IEEE Recommended Practice for the Design of Reliable Industrial and
Commercial Power Systems (IEEE Gold Book).
IEEE Std C57.12.00-2000, IEEE Standard General Requirements for Liquid-Immersed Dis-
tribution, Power, and Regulating Transformers.
Street, 13th Floor, New York, NY 10036, USA. (http://www.ansi.org)

IEEE
IEEE Std C57.91-1995, IEEE Guide for Loading Mineral-Oil-Immersed Power
Transformers.
IEEE Std C57.96-1999, IEEE Guide for Loading Dry-Type Distribution and Power
Transformers.
IEEE Std C57.109-1993, IEEE Guide for Liquid-Immersed Transformer Through-Fault-
Current Duration.
(NEC®
).5
11.13 Bibliography
[B1] AIEE Committee Report, “Bibliography of Industrial System Coordination and Protec-
tion Literature,” IEEE Transactions on Industry Applications, vol. IA-82, pp. 1–2, Mar. 1963.
[B2] Applied Protective Relaying. Newark, NJ: Westinghouse Electric Corporation, 1976.
[B3] The Art of Protective Relaying. Philadelphia: General Electric Company, Bulletin 1768.
[B4] Beeman, D. L., ed., Industrial Power Systems Handbook. New York: McGraw-Hill,
1955.
Mercel Dekker, Inc., 1998.
[B6] Boyaris, E., and Buyot, W. S., “Experience with Fault Pressure Relaying and Combusti-
ble Gas Detection in Power Transformers,” Proceedings of the American Power Conference,
vol. 33, pp. 1116–1126, Apr. 1971.
[B7] Brubaker, J. F., “Fault Protection and Indication on Substation Transformers,” IEEE
Transactions on Industry Applications, vol. IA-14, May/June 1977.
[B8] Burgin, E. R., “A Comparison of Protective Methods and Devices for Industrial Power
Transformers,” Proceedings of the American Power Conference, vol. 26, pp. 931–938, Apr.
1964.
[B9] Dickinson, W. H., “Report on Reliability of Electric Equipment in Industrial Plants,”
AIEE Transactions on Industry Applications, pt. II, vol. IA-81, pp. 132–151, July 1962.
[B10] Dudor, J. S., and Padden, L. K., “Problems and Solutions for Protective Relay
Applications in Petroleum Facilities—Some Protection Applications for Generators and
Transformers,” IEEE IAS PCIC Conference Record, pp. 131–144, 1995.

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[B11] IEEE Std C57.12.01-1998, IEEE Standard General Requirements for Dry-Type Distri-
bution and Power Transformers Including Those With Solid-Cast and/or Resin-Encapsulated
Windings.
[B12] IEEE Std C57.94-1982 (Reaff 1987), IEEE Recommended Practice for Installation,
Application, Operation, and Maintenance of Dry-Type General Purpose Distribution and
Power Transformers.
[B13] IEEE Std C57.100-1999, IEEE Standard Test Procedures for Thermal Evaluation of
Liquid-Immersed Distribution and Power Transformers.
[B14] IEEE Std C57.104-1991, IEEE Guide for the Interpretation of Gases Generated in Oil-
Immersed Transformers.
[B15] IEEE Std C57.106-1991 (Reaff 1998), IEEE Guide for Acceptance and Maintenance
of Insulating Oil in Equipment.
[B16] IEEE Std C57.110-1998, IEEE Recommended Practice for Establishing Transformer
Capability When Supplying Nonsinusoidal Load Currents.
[B17] IEEE Std C57.111-1989 (Reaff 1995), IEEE Guide for Acceptance of Silicone Insulat-
ing Fluid and its Maintenance in Transformers.
[B18] IEEE Std C57.115, Loading > 100 MVA.
[B19] IEEE Std C57.121-1998, IEEE Guide for Acceptance and Maintenance of Less Flam-
mable Hydrocarbon Fluid in Transformers.
[B21] Mathur, B. K., “A Closer Look at the Application and Setting of Instantaneous
Devices,” Presented at I&CPS Technical Conference, Seattle, WA, Paper #CH1460-5/79/
0000-0107, 1979.
[B22] PES Committee Report, “A Relay Performance Considerations with Low Ratio Cts
and High Fault Currents,” IEEE Transactions on Industry Applications, vol. 31, no. 2,
pp. 392–393, Mar./Apr. 1995.
[B23] St. Pierre, C. R., and Wolney, T. E., “A Standardization of Benchmarks for Protective
Device Time Current Curves,” IEEE Transactions on Industry Applications, vol. 1A-22,
no. 4, pp. 623–632, July/Aug. 1986.
[B24] Zolar, D. A., “A Guide to the Application of Surge Arresters for Transformer Protec-
tion,” IEEE Transactions on Industry Applications, vol. IA-15, Nov./Dec. 1979.

Chapter 12
Generator protection
12.1 Introduction
Industrial and commercial power systems may include generators as a local source of energy.
These generators supply all or part of the total energy required, or they provide emergency
power if the normal source of energy fails. The application of generators can be classiﬁed as
single-isolated generators, multiple-isolated generators, unit-connected generators, cogenera-
tion generators, and induction generators.
Generator protection requires the consideration of many abnormal conditions that are not
present with other system elements. The abnormal conditions that may occur with generators
include
— Overheating
— Stator (due to overload or loss of cooling)
— Rotor (due to overexcitation, loss of cooling)
— Winding faults
— Stator (phase and ground faults)
— Rotor (ground faults and shorted turns)
— Overspeed and underspeed
— Overvoltage
— Loss of excitation
— Motoring
— Unbalanced current operation
— Out of step
— Subsynchronous oscillations
— Inadvertent energization
— Nonsynchronized connection
Where the equipment is unattended, it should be provided with automatic stator and rotor
protection against all harmful conditions. In installations where an attendant is present, use of
alarms on some abnormal conditions may be preferable to removing the generator from ser-
vice. Generator protective schemes vary depending on the objectives to be achieved.
12.2 Classiﬁcation of generator applications
12.2.1 Single-isolated generators
Single-isolated generators are used to supply emergency power or for standby service and are
normally shut down. They are operated for brief periods when the normal source fails or
during maintenance, testing, and inspection. They are connected to the system load through
an automatic transfer switch or through interlocked circuit breakers and are not operated in

IEEE
parallel with other system power sources. They are driven by diesel engines or gas turbines
with ratings from less than 100 kW up to a few megawatts. Generation is usually at utilization
voltage level, typically 480 V or 480Y/277 V, but with larger machines the voltage may be
2.4 kV or 4.16 kV. These generators are designed to start, operate during a power failure, and
to shut down when normal power is restored through automatic controls.
12.2.2 Multiple-isolated generators
A multiple-isolated generator application consists of several units operating in parallel
without connection to any electric utility supply system. Examples of these installations are
total energy systems for commercial and industrial projects, offshore platforms for drilling
and production of energy sources, and other remote sites requiring continuous electric energy.
The size of the individual generators may range from a few hundred kilowatts up to several
megawatts depending on the system demand. The prime movers are typically gas turbines
and oil-, gas-, or diesel-fueled engines. These systems are normally operated manually, but
load-sensing controls and automatic synchronizing relays can be used. The rated voltage of
these generators is usually at the utilization voltage or the highest distribution voltage level,
or both, such as 4.16 kV or 13.8 kV.
Figure 12-1 shows a typical installation where generators are connected directly to a
distribution system. If the system is effectively grounded (X0/X1 ≤ 3, R0/X1 ≤ 1), the generator
neutral (or the neutral of the bus-grounding transformer if the generator neutral is isolated) is
grounded with a neutral inductive reactance. If the system is not effectively grounded, as for
some three-wire distribution systems, the generator neutral or grounding-transformer neutral
is generally grounded through a low-ohmic-value resistor.
12.2.3 Large industrial generators
Large industrial generators are bulk power-producing units that operate in parallel with an
electric utility supply system. All generated power is normally utilized by the industrial user.
These units are used where a demand exists for low-pressure process steam, such as in petro-
chemical installations and in pulp and paper plants. The generator size may range from
10 000 kVA to 50 000 kVA. Operation is continuous at or near rated load, but may vary sea-
sonally. The prime movers are usually steam or gas turbines depending on the process
Figure 12-1—Generators connected directly to a distribution system

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GENERATOR PROTECTION Std 242-2001
requirements, fuel availability, and system economics. Generation is usually at the highest
voltage level, typically 12.47 kV or 13.8 kV, of the industrial plant systems. The majority of
these machines are operated by attendants.
Figure 12-2 illustrates how to connect two or more generators to a system using one step-up
transformer. Two or more generators are bussed at generator voltage and a two-winding
grounded wye-delta unit transformer is used to connect the machines to the system. These
approaches may be used with thermal, hydro, or combustion-turbine generators.
Low-resistance grounding of the generators would be used in order to achieve selective
ground-fault protection for the machines. In some instances, the generators may be high-
resistance-grounded through a distribution transformer in order to minimize destructive
iron-burning damage due to phase-to-ground faults. High-resistance grounding for multiple
machines has the disadvantage that it does not provide sufficient current for selective
relaying. To overcome this problem, a combination of zero-sequence voltage and directional
ground-fault protection would need to be provided.
12.2.3.1 Unit generator-transformer configuration
In a unit generator-transformer configuration, a generator and its transformer (or unit
transformer) are connected as a unit to the system as shown in Figure 12-3. The generator is
usually wye-connected and high-resistance-grounded through a distribution transformer. The
unit transformer is most commonly a grounded wye-delta connection.
The unit auxiliary transformers may be either two-winding or three-winding transformers,
depending upon the size of the generator unit. In most instances, each unit auxiliary trans-
former is connected delta-wye with the neutral of the wye connected to ground through some
impedance.
12.2.3.2 Cogeneration generators
Cogeneration is the simultaneous production of several forms of energy. Usually cogenera-
tion involves the production of electric power and process steam within the plant. The Public
Utilities Regulatory Act of 1978 (PURA) empowered the Federal Energy Regulatory Com-
mission (FERC) to provide rules requiring electric utilities to buy power from or to sell power
Figure 12-2—Generators sharing a transformer

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to cogeneration operators. When the generated power exceeds the plant demand, the excess
power flows out to the electric utility. Historically, power only flowed into the industrial
plant. This power flow in either direction significantly impacts the electrical protection at the
intertie between the utility and the industrial, but has only minor significance for the genera-
tor protection.
12.2.4 Induction generators
An induction generator is physically the same machine as an induction motor. The induction
generator is operated slightly above synchronous speed rather than below as for an induction
motor. It takes its excitation from the power system. Induction generators are subject to
overspeed conditions on load rejection. The three-phase fault contribution from an induction
generator duration is short compared to a synchronous generator. Additional electrical
protection functions may be required in the interconnection (i.e., over and under voltage).
12.3 Short-circuit performance
12.3.1 General considerations
The proper application of several generator protective devices requires the knowledge of the
short-circuit performance of the generator. The magnitude of generator fault current is a func-
tion of the armature and field characteristics, time, and the loading conditions immediately
preceding the fault. The ability of the generator to sustain an output current during a fault is
determined by the characteristics of the excitation system.
12.3.2 Excitation systems
Some excitation systems do not have the ability to sustain the short-circuit current. The mag-
nitude of fault current is determined only by the subtransient and transient reactance, decays
as determined by their respective time constants, and can be essentially zero in 1.0 s to 1.5 s.
An example of a system with these characteristics is the static exciter generator, which
Figure 12-3—Unit generator-transformer configuration

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obtains all of its excitation energy from the generator terminal voltage. The excitation sys-
tems of round (or cylindrical) rotor generators, typically two-pole machines above 10 MVA,
have the capability to support a sustained three-phase fault current corresponding to the cur-
rent limited by transient reactance for a period of several seconds. These machines may have
a brushless excitation system, although some units may be equipped with a static exciter
using slip rings to obtain its excitation energy from both generator potential transformers and
current transformers (CTs).
Salient-pole machines that range in size from a few kilowatts up to the round rotor machine
sizes are typically capable of supporting a fault current at 300% of generator full-load cur-
rent. Such units typically have a brushless exciter where the exciter delivers three-phase ac to
rotating rectifiers that are connected directly to the field. Excitation energy to the exciter field
is supplied to maintain the maximum fault-current magnitude.
Four basic types of excitation systems are used to control the output of ac machines:
— The dc generator-commutator exciter
— The alternator-rectifier exciter with stationary rectifier system
— The alternator-rectifier exciter with rotating rectifier system
— The static excitation system
In terms of response times, excitation systems fall into two categories: rotating and static.
Rotating exciters respond at a slower rate than static exciters. The speed of response of the
excitation system is commonly expressed in terms of the response ratio, which indicates the
speed of response during 0.5 s after a sudden 20% reduction in generator terminal voltage.
Rotating exciters have response ratios in the range of 0.5 to 1.0 per-unit exciter V/s. Static
exciters have response ratios in the range of 2.5 to 3.5 per-unit exciter V/s. The detailed
effects of the excitation system response ratio on the fault current characteristics is well-doc-
umented in the references [B11]. While a detailed description of these systems is beyond the
scope of this chapter, their general characteristics will be briefly described in 12.3.2.1
through 12.3.2.4.
12.3.2.1 System with dc generator-commutator exciter
Figure 12-4 shows a schematic of the primary elements of a system with a dc generator-
commutator exciter.
NOTE—Not shown on this diagram nor in Figure 12-5 through Figure 12-7 are the power supplies
(e.g., pilot exciters, the current, potential intelligence inputs to the excitation control) because
essentially they are functionally the same for all systems.
In a system with a dc generator-commutator exciter, a dc control signal is fed from the excita-
tion control to the stationary field of the dc exciter. The rotating element of the exciter then
supplies a dc through a field breaker to the field winding of the main ac generator. The rotat-
ing armature of the dc exciter is either driven from the same shaft as the rotating main field of
the generator or can be on a separate motor-driven shaft. In either case, a dc commutator is
required on the exciter, and brushes and collector rings are required on the rotating generator

IEEE
field to transmit the main generator field current. This system is used only on smaller or older
machines.
12.3.2.2 System with alternator-rectifier exciter and stationary rectifiers
To eliminate the problems of high-current commutation for medium and large machines, the
dc exciter is replaced by an alternator. The system of Figure 12-5 uses an alternator with a
rotating dc field winding driven from the shaft of the main ac generator. Current for this field
winding is obtained from the excitation controls through brushes and collector rings. The
three-phase ac output of the alternator is rectified through a stationary three-phase diode
bridge, and the dc output is fed to the field winding of the generator through brushes and
collector rings.
12.3.2.3 System with alternator-rectifier exciter and rotating rectifiers
(brushless exciters)
The system of Figure 12-6 again uses an alternator; but, by mounting the dc field winding on
the stator of the exciter and the ac armature winding on the rotor, all brushes and
commutators have been eliminated. In this system, the ac armature of the exciter, the rotating
three-phase diode bridge rectifier, and the main field of the ac generator are all mounted on
the same rotating shaft system. All electrical connections are made along or through the
center of this shaft.
Figure 12-4—System with dc generator-commutator exciter
Figure 12-5—System with alternator-rectifier exciter and stationary exciter

IEEE
12.3.2.4 System with static exciter
The schemes in 12.3.2.1 through 12.3.2.3 utilize the energy directly from the prime-mover
shaft to obtain the required excitation power. Static excitation systems obtain this power from
the electrical output of the generator or the connected system. In Figure 12-7, external power
CTs or power voltage transformers (VTs), or both, feed rectifiers in the regulating system
which, in turn, supply dc to the main field winding of the generator through brushes and
collector rings.
Some systems use only potential transformers as input power, while some use additional CTs
to boost the input during fault conditions when the terminal voltage is reduced. During close-
in faults, excitation systems using only potential transformers as input power may be unable
to sustain fault currents long enough for the protective relaying to operate [B11].
Figure 12-6—System with alternator-rectifier exciter and rotating rectifiers
(brushless exciters)
Figure 12-7—System with static exciter

IEEE
12.3.3 Generator decrement characteristics
The current output of a generator with a fault at or near its terminals consists of two
components, both of which have a time variable rate of decay, depending on machine
constants. The two components are the symmetrical ac current iac and the unidirectional
offset current idc. The ac component decays with time according to the pattern shown in
Figure 12-8. The sudden drop, 1-2, is a function of the subtransient values of machine
internal voltage, reactance, and short-circuit time constant. The more gradual drop toward
steady state, 2-4, is a function of the transient values of machine internal voltage, reactance,
and short-circuit time constant. The dc offset current, 1-3, is a function of the subtransient
reactance and the armature short-circuit time constant. The steady-state component, 4, and
beyond is a function of the generator synchronous reactance and field current. The maximum
symmetrical current that a generator can deliver on a bolted three-phase fault is determined
by the subtransient reactance Xd″. This reactance ranges from a minimum of 9% for a two-
pole round rotor machine to 32% for a low-speed salient-pole hydrogenerator. Thus, the
initial symmetrical fault current (i.e., 1–5 cycles) can be as great as 11 times the generator
full-load current. In the intermediate period (i.e., 5–200 cycles), the transient reactance Xd′
determines the magnitude of the ac component. The synchronous reactance, which may vary
from a value of 120% to 240%, determines the sustained value of the ac component of the
fault current. The sustained fault current, assuming no initial load and no change in the
voltage regulator setting, can be as low as 42% of the generator full-load current. Because the
no-load fixed field current results in the longest relay operating times, the stuck regulator
condition should be considered as the criteria for the relay settings. Regulator response
normally occurs, however, and produces sustained fault currents at much higher levels. The
generator decrement curves can be calculated from the procedure in 12.3.3.1 through
12.3.3.4. The initial loading condition, initial terminal voltage, and the field forcing
capability can all be included in these calculations.
12.3.3.1 Total ac component of armature current
The total ac component of armature current consists of the steady-state value id and two com-
ponents that decay at a rate according to their respective time constants.
a) Subtransient component of the ac armature current, id″:
When machine is at no-load, e″ = et.
iac id″ id′
–
( )ε
t Td″
⁄
–
id′ id
–
( )ε
t Td′
⁄
–
id
+ +
=
id″
e″
Xd″
--------
- pu
=
e″ et X
+ d″ θ
sin pu
=

IEEE
b) Transient component of the ac armature current, id″:
Again, at no-load, e′ = et.
c) Steady-state component id. The steady-state component is the current finally attained
and is a function of the field current:
IF is the actual prefault amperes at the initial loading conditions, either no-load or full-load;
or, when regulator action is taken into consideration, it is the field amperes with maximum
excitation voltage applied.
Figure 12-8—Typical generator decrement curve
id′
e′
Xd′
-------
- pu
=
e′ et X
+ d′ θ
sin pu
=
id
et
Xd
-----
-
 
  IF
IFg
------
-
 
 
=

IEEE
12.3.3.2 DC component of armature current
The dc component of armature current is controlled by the subtransient reactance and the
armature time constant:
12.3.3.3 Total root-mean-square (rms) current
The total rms current is the sum of the two components as follows:
12.3.3.4 Variables
The terms used in the expressions in 12.3.3.1 through 12.3.3.3 are defined as follows and are
normally obtained from the generator manufacturer:
Xd″ is subtransient reactance, saturated value,
Xd′ is transient reactance, saturated value,
Xd is synchronous reactance,
et is machine terminal voltage (per unit),
e″ is machine internal voltage behind Xd″,
e′ is machine internal voltage behind Xd′,
Td″ is subtransient short-circuit time constant (s),
Td′ is transient short-circuit time constant (s),
TA is armature short-circuit time constant (s),
IFg is field current at no-load rated voltage (V),
IF is field current at given load condition,
θ is load power factor angle.
12.3.3.5 Example calculation
The following data were obtained from the generator manufacturer for a round (or
cylindrical) rotor machine. Decrement curves, shown in Figure 12-9, are plotted for
a) Constant excitation at no initial load
b) Field current at 3 per unit of no-load value
c) Total current trace of Item b), which includes the dc component
2id″ε
t T A
⁄
–
itot iac
2
idc
2
+
=

IEEE
The machine characteristics are
12.4 Generator grounding
A common practice is to ground all types of generators through some form of external imped-
ance. The purpose of this grounding is to limit the mechanical stresses and fault damage in
the machine, to limit transient voltages during faults, and to provide a means for detecting
ground faults within the machine. A complete discussion of all grounding and ground protec-
tion methods can be found in IEEE Std C37.101-19931
and IEEE Std C62.92-1989.
kVA = 19 500 xd′′ = 10.7% IFg = 1 pu Td′′ = 0.015 s
PF = 0.8 xd′ = 15.4% IF = 3 pu Td′ = 0.417 s
voltage = 12.47 kV xd = 154% TA = 0.189 s
rated amperes = 903
Figure 12-9—Generator decrement curve for a 19 000 kVA generator

IEEE
The following methods, most commonly used for industrial generator grounding, are dis-
cussed in this chapter:
— High-resistance grounding
— Low-resistance grounding
— Reactance grounding
— Grounding-transformer grounding
Solid grounding of a generator neutral is not generally used because this practice can result in
high mechanical stresses and excessive fault damage in the machine. According to ANSI
C50.13-1989, the maximum stresses that a generator is normally designed to withstand are
associated with the currents of a three-phase fault at the machine terminals. Because of the
relatively low zero-sequence impedance inherent in most synchronous generators, a solid
phase-to-ground fault at the machine terminals produces winding currents that are higher
than currents for a three-phase fault. Therefore, to comply with ANSI C50.13-1989, genera-
tors should be grounded so that the maximum phase-to-ground fault current is limited to a
magnitude equal to, or less than, the three-phase fault current.
Generators are not often operated ungrounded. While this approach greatly limits the phase-
to-ground fault currents and consequently limits damage to the machine, it can produce high
transient overvoltages during faults and also makes it difﬁcult to locate the fault.
12.4.1 High-resistance grounding
In high-resistance grounding, a distribution transformer is connected between the generator
neutral and ground, and a resistor is connected across the secondary. The primary voltage
rating of the distribution transformer is usually equal to or greater than rated generator line-
to-neutral voltage, while the secondary winding rating is 120 V or 240 V. The secondary
resistor is selected so that, for a single phase-to-ground fault at the generator terminals, the
power dissipated in the resistor is equal to or greater than three times the zero-sequence
capacitive kilovoltampere to ground of the generator windings and of all other equipment that
may be connected to the machine terminals. The calculation for sizing the resistor R utilizes
the phase-to-ground capacitance Xco in the generator, bus, cable, transformers, and surge
device. The resistor is sized to be
Because the resistor is in parallel with the distributed capacitance, the total zero-sequence
current is greater than the capacitive charging current. With this resistor rating, the transient
overvoltages during faults are kept to safe values. For a single phase-to-ground fault at the
machine terminals, the primary fault current is limited to a value in the range of about 3 A to
25 A. If possible, the ground-fault current level should be chosen to coordinate with the pri-
mary fuses (when used) of wye-wye-connected VTs with grounded neutrals. Distribution
transformers with internal fuses or circuit breakers should not be used. They could inadvert-
ently be open, and the grounding and protection scheme could be inoperative at the time of
fault.
R
Xco
3
-------
-
≤

IEEE
In some cases, the distribution transformer is omitted, and a high value of resistance is con-
nected directly between the generator neutral and ground. The resistor size is selected to limit
ground-fault current to the range of 5 A to 10 A. While this method of grounding is used in
Europe, the physical size of the resistors, the required resistor insulation level, and the cost
may preclude the use of this method.
High-resistance grounding does not provide sufficient current for selective ground
relaying of several machines connected to a common bus. Consequently, it is generally used
with unit-system installations where a single generator is connected through its individual
primary grounded wye/secondary delta step-up transformer (or transformers) to the system.
In a few cases, this type of grounding has been used when two or more generators are con-
nected to one step-up transformer. However, with such a system, coordinating ground-fault
protection is difficult, and shutting down all machines may be required to isolate a fault.
12.4.2 Low-resistance grounding
In low-resistance grounding, a resistor is connected directly between the generator neutral
and ground. The resistor is selected to provide sufficient current for selective ground relaying
of several machines or feeders, or both. In general, the grounding resistor is selected to limit
the generator’s contribution to a single phase-to-ground fault at the generator’s terminals to a
value in the range of 200 A to 400 A. Resistor cost and size usually preclude the use of resis-
tors to limit the current below 200 A or to permit currents above machine-rated current.
Low-resistance grounding is generally used where two or more generators are bussed at
generator voltage and connected to a system through one step-up transformer or where the
generator is connected directly to a distribution system having a low-impedance-grounding
source on the generator bus. The disadvantage of this method is that these values of ground-
fault current may cause serious generator stator iron damage.
12.4.3 Reactance grounding
Reactance grounding uses an inductive reactance between the generator neutral and ground.
The inductive reactance is selected to produce an X0/X1 ratio at the machine terminals in the
range of 1 to 10. A common practice is to maintain an effectively grounded system by keep-
ing the X0/X1 ratio at 3 or less. This method of grounding produces relatively high levels of
phase-to-ground fault currents ranging from approximately 25% to 100% of the three-phase
fault current.
Reactance grounding is generally used where the generator is connected directly to a solidly
grounded distribution system.
12.4.4 Grounding-transformer grounding
Grounding-transformer grounding involves the use of a grounding transformer connected to
the machine terminals or to the generator bus. The grounding may be provided by a zigzag
transformer, by a grounded wye-delta transformer, or by a grounded wye-broken-delta

IEEE
transformer with a resistor connected across a corner of the broken delta. When a zigzag or a
grounded wye-delta transformer is used, the effective grounding impedance is selected to
provide sufﬁcient current for selective ground relaying.
The grounded wye-broken-delta transformer with a resistance in the corner of the broken
delta is generally a high-resistance-grounded system. The resistance would be selected in the
same manner as for the distribution transformer with secondary resistor. This method limits
the single phase-to-ground fault current to a range of 3 primary A to 25 primary A.
A zigzag or grounded wye-delta transformer may be used as an alternate grounding source
when a generator with neutral reactor grounding is connected directly to a distribution
system. This approach can also be used where several ungrounded wye- or delta-connected
generators are bussed at generator voltage.
A grounded wye-broken-delta transformer with a resistor across the corner of the broken
delta may be used to provide a means for detecting ground faults in ungrounded wye- or
delta-connected generators.
12.5 Protective devices
12.5.1 Generator stator thermal protection
Thermal protection for the generator stator core and windings may be provided for the fol-
lowing contingencies:
— Generator overload
— Failure of cooling systems
— Localized hot spots caused by core lamination insulation failures or by localized or
rapidly developing winding failures
These phenomena are long term and not readily detected by other protective devices. In
attended stations, the generator is rarely tripped on overtemperature. Instead, it is set to alarm
and allows the operator to take the appropriate steps to reduce the generator temperature. In
unattended stations, the generator may be tripped.
Resistance temperature detectors (RTDs) embedded in the generator stator windings are used
to sense the actual winding temperature. Typically, six RTDs, two per phase, are installed and
a selector switch provided to connect the thermal relay to the RTD indicating the highest
operating temperature. Precaution should be taken to ensure that the resistance of the RTD
matches the input resistance of the relay.
12.5.1.1 Generator overload
The continuous-output capability of a generator is expressed in kilovoltamperes available at
the terminal at a speciﬁed frequency, voltage, and power factor. For hydrogen-cooled genera-
tors, the output rating is usually given at the maximum and several lesser hydrogen pressures.

IEEE
For combustion-turbine generators, this capability is given at an inlet air temperature of
15 °C at sea level. In general, generators can operate successfully at rated kilovoltamperes,
frequency, and power factor for a voltage variation of 5% above or below rated voltage.
Under emergency conditions, it is permissible to exceed the continuous output capability for
a short time. In accordance with ANSI C50.13-1989, the armature winding short-time ther-
mal capability is given by the following:
where 100% current is the rated current of the machine at maximum hydrogen pressure.
12.5.1.1.1 Winding-temperature protection
Most generators are supplied with a number of temperature sensors to monitor the stator
windings. These sensors are usually RTDs and thermocouples. As the name implies, the RTD
detects temperature by the change in resistance of the sensor. A thermocouple detects temper-
ature by the change in thermoelectric voltage induced at the thermocouple junction. These
sensors are used to continuously monitor the stator winding. In attended generating stations,
the sensors may be connected to a data acquisition system to record or alarm. In unattended
stations, the sensors may be used with a relay to alarm, to initiate corrective action, or to trip
the unit if preset temperatures limits are exceeded. For generators with conventional (or indi-
rectly cooled) stator windings, RTDs embedded between the top and bottom bars are used to
monitor winding temperatures. For generators with inner-cooled (or directly cooled) stator
windings, the stator bar coolant discharge temperature is used along with the embedded
RTDs to monitor the winding temperature. The generator manufacturer should be consulted
for speciﬁc recommendations on the preferred method of monitoring these sensors and tem-
perature limits to alarm and trip.
12.5.1.1.2 Overload protection
In some instances, generator overload protection can be provided through the use of a torque-
controlled overcurrent relay that is coordinated with the ANSI C50.13-1989 short-time
capability curve. This relay consists of an instantaneous overcurrent unit and a time-
overcurrent unit having an extremely inverse characteristic. The instantaneous unit is set to
pick up at 115% of full-load current and is used to torque control the time-overcurrent unit.
The instantaneous unit dropout should be 95% or higher of pickup setting. The time-
overcurrent unit is set to pick up at 75% to 100% of full-load current, and a time setting is
chosen so that the relay operating time is 7 s at 226% of full-load current. With this approach,
the relay is prevented from tripping for overloads below 115% of full-load current and yet
provides tripping in a prescribed time for overloads above 115% of full-load current. An
overload alarm may be desirable to give the operator an opportunity to reduce load in an
Time (s) 10 30 60 120
Armature current (%) 226 154 130 116

IEEE
orderly manner. This device should not give nuisance alarms for external faults and should
coordinate with the generator overload protection if this protection is provided.
For air-cooled generators that may operate in a wide range of ambient temperatures, it is
necessary to coordinate the ANSI C50.13-1989 thermal capability and the relay setting with
the increased capability of the turbine and the generator at reduced ambient temperature.
Conversely, it may be difficult to protect the generator for its reduced capability when the
ambient temperature is high.
12.5.1.2 Failure of cooling systems
Depending upon rating and design, the generator stator core and windings may be cooled by
air, oil, hydrogen, or water. In directly cooled (or conductor-cooled) generators, the coolant is
in direct contact with the heat-producing conductors of the stator winding. In indirectly
cooled generators, the coolant cools the generator by relying on heat transfer through the
insulation. For any type of generator, a failure of the cooling system can result in rapid
deterioration of the stator core lamination insulation and/or stator winding conductors and
insulation.
In general, the generator manufacturer provides all of the necessary protection for the cooling
system. This protection is in the form of sensors, such as RTDs, thermocouples, and flow and
pressure sensors. These devices are used to monitor the winding temperatures or the coolant
temperature, flow, or pressure. They may be connected to alarm, to automatically reduce load
to safe levels, or to trip.
For a particular machine, the generator manufacturer should be consulted to ascertain the
temperature limits, the protection provided, and the recommended operating procedures for a
loss of coolant.
12.5.1.3 Core hot spots
Localized hot spots in the stator core can be produced by lamination insulation failure caused
by misoperation (e.g., excessive leading power factor operation, overfluxing), by vibration
due to looseness (e.g., wear of insulation, fatigue of laminations), by foreign objects left in
the machine, by damage to the core during installation or maintenance, or by objects that are
normally a part of the machine (e.g., a nut, a wedge), but become detached from their normal
position and move to the core.
The hot spots are the result of high eddy currents, produced from core flux, that find conduct-
ing paths across the insulation between laminations. In some designs, stator laminations are
electrically shorted together on the outer diameter of the core where it attaches to the stator
frame. Any contact between laminations on the inner bore results in a circuit for eddy cur-
rents. The shorting of laminations can cause melting of core steel that can be costly to repair.
The only means for detecting hot spots in air-cooled generators is through the use of RTDs
and/or thermocouples imbedded in strategic locations. Because covering the entire core and

IEEE
windings with these detectors is not possible or practical, this approach can provide only par-
tial detection of hot spots.
12.5.2 Field thermal protection
Thermal protection for the generator field may be divided into two categories:
— Protection for the main field winding circuit
— Protection for the main rotor body, wedges, retaining ring, and amortisseur winding
12.5.2.1 Field winding protection
The field winding can operate continuously at a current equal to or less than the current
required to produce rated kilovoltamperes at rated power factor and voltage. For power fac-
tors less than rated, the generator output should be reduced to keep the field current within
these limits. The capability curves as defined in IEEE Std 67-1990 are determined on this
basis.
Under abnormal conditions, such as short circuits and other system disturbances, it is
permissible to exceed these limits for a short time as specified in ANSI C50.13-1989. In
ANSI C50.13-1989, the field winding short-time thermal capability is given in terms of
permissible field voltage as a function of time as noted below:
Protection schemes can utilize this characteristic to prevent thermal damage to the field
winding circuit.
Because putting temperature sensors directly in the field windings is not practical, only indi-
rect monitoring of the field winding temperature is normally possible. For excitation systems
employing main field collector rings, the average temperature of the field winding can be
approximated by calculating the field resistance using simultaneous field current and voltage
readings. This resistance, in conjunction with the known cold resistance, is a measure of the
operating temperature. This method, described in IEEE Std 67-1990, gives only an indication
of the average temperature throughout the field winding and not the more important hot-spot
temperature. This method is not applicable with brushless excitation systems where the
actual main field current and voltage are not available for measurement.
12.5.2.2 Field overexcitation protection
Overexcitation protection for the field winding is generally provided utilizing the generator
field short-time capability characteristic. Several different schemes are available using relays
or excitation system control elements, or both.
Time (s) 10 30 60 120
Field voltage (%) 208 146 125 112

IEEE
12.5.2.2.1 Fixed time-delay relaying scheme
The fixed time-delay relay scheme is the simplest form of field protection, and it utilizes a
contact-making milliammeter or voltmeter connected either in the main field circuit or in the
field of the ac exciter. This device is set to pick up when the field current exceeds its rated
full-load value. When an overexcitation condition occurs, the device picks up and performs
the following functions:
a) Sounds an alarm.
b) Adjusts field excitation to a preselected value corresponding to rated full-load level
or less.
c) After a fixed time delay, trips the generator regulator or transfers to an alternate
control.
d) If overexcitation is not eliminated after some additional short time interval, trips the
unit.
This scheme protects the field for overexcitation conditions during system disturbances and
for the rare occurrence of a faulty excitation system component. While simple in form, this
scheme has the disadvantage that it overprotects the machine because the fixed time-delay
relay must be set for the maximum possible overexcitation condition that can occur. In other
words, for less severe overexcitation conditions, tripping occurs at shorter times than
required. Therefore, full advantage of the inverse-time thermal capability of the field winding
characteristic cannot be obtained.
12.5.2.2.2 Inverse time-delay relay scheme
The inverse time-delay relay scheme utilizes a voltage relay whose characteristic
approximately matches the inverse-time characteristic of generator field. This relay may be
connected at the terminals of an ac exciter alternator, in the main generator field, or in the
field of the ac exciter. When connected to a field circuit, a transducer is used to convert the dc
signal to an ac quantity. The relay is normally set so that a margin of 5% to 10% exists
between the relay characteristic and the field capability curve.
This relay, in conjunction with one or more timers, performs the same functions as the
scheme in 12.5.2.2.1. For an overexcitation condition, the device performs the following
functions:
a) Sounds an alarm.
b) Adjusts the field excitation to a preselected value corresponding to rated full-load
level or less.
c) After some delay, trips the generator regulator or transfers to an alternate control.
d) If overexcitation is not eliminated, trips the unit.
This scheme provides protection for overexcitation conditions and for possible excitation
system failures.

IEEE
12.5.2.2.3 Voltage regulator system
Modern excitation systems usually incorporate the field protective functions and the regulat-
ing function. These systems may have built-in circuitry that duplicates the fixed-time and/or
the inverse-time relaying function. When an overexcitation condition occurs and field current
exceeds a safe value for a specified period, these protective functions reduce field current to
the full-load value or to some other predetermined level. On some excitation systems, if the
overexcitation condition persists after an attempt to reduce field current is made, the protec-
tive function trips the regulator or transfers to an alternate exciter after a short period. If this
step does not eliminate the problem, the generator may be tripped. In this type of excitation
system, the protective function is separate from the excitation function and, therefore, can
provide protection when failures occur in the regulating systems or when the regulator is not
in the control circuit.
If the protective function is part of the regulating system, the protection would be eliminated
when the regulator is tripped or is out of service. For this type of system, supplementary or
backup relay protection as described in the preceding can be provided.
12.5.2.3 Rotor body
No simple methods exist for direct thermal protection of the rotor. Various indirect methods
are used either to approximate rotor temperatures or to act directly on the quantities that
would lead to excessive rotor temperatures. Protection schemes for the rotor are, therefore,
directed at the potential causes of thermal distress. For example, negative-sequence currents
in the stator, loss of excitation, loss of synchronism, induction motoring, or inadvertent ener-
gization can cause excessive rotor temperatures due to circulating currents in various paths of
the rotor body.
12.5.3 Generator stator fault protection
12.5.3.1 General consideration
Generator faults are always considered to be serious because they can cause severe and costly
damage to insulation, windings, and the core. They can also produce severe mechanical tor-
sional shock to shafts and couplings. Moreover, fault currents in a generator do not cease to
flow when the generator is tripped from the system and the field disconnected. Fault current
can continue to flow for many seconds because of trapped flux within the machine and
thereby increase the amount of fault damage.
As a consequence, for faults in or near the generator that produce high magnitudes of short-
circuit currents, some form of high-speed protection is normally used to trip and shut down
the machine as quickly as possible in order to minimize damage. Where external impedances
are used to limit fault currents to a few amperes, slower forms of protection may be justified.
In certain cases, it may be justified to consider the use of rapid de-excitation methods, which
produce a faster decay of fault currents.

IEEE
12.5.3.2 Phase-fault protection
Some form of high-speed differential relaying is generally used for phase-fault protection of
generator stator windings. Differential relaying detects three-phase faults, phase-to-phase
faults, double phase-to-ground faults, and some single phase-to-ground faults depending
upon how the generator is grounded. Because the fault current is proportional to the voltage
at the point of the fault, the closer to the neutral of the generator winding, the less the voltage
and resultant fault current. Therefore, some forms of differential protection can only detect
faults to within 5% to 10% of the generator neutral. For faults within the 5% to 10% of the
neutral winding end, other forms of protection should be used as discussed in 12.5.3.2.1
through 12.5.3.2.3 and illustrated in Figure 12-16.
Differential relaying does not detect turn-to-turn faults in the same phase because no differ-
ence exists in the current entering and leaving the phase winding. Where applicable, separate
turn fault protection can be provided with the split-phase relaying scheme. After the detection
of these faults, the generator is quickly removed from service to limit the extent of damage.
For a further discussion on the basic principles of differential protection, see Chapter 4 on
protective relays.
Percentage differential relays connected, as shown in Figure 12-10, are normally used for
protection of larger generators. Fixed-percentage differential relays have constant slope
characteristics of 10% to 50%, depending on manufacturer, for all fault-current values.
Variable-percentage differential relays make the scheme more tolerant of CT mismatch and
reduce the relay’s sensitivity to external faults. Induction disk, induction cup, or static relays
are commercially available for use in percentage differential protection schemes. The
operating time of standard speed induction disk relays is a minimum of 6 cycles, and high-
speed induction cup or static relays operate in 1.2 cycles to 1.5 cycles.
Normally, when a percentage differential scheme is used, the CTs should be located so that
they include the generator breaker within the protective zone. This conﬁguration gives
maximum protection to the circuit breaker and bus duct or cable connecting the generator to
the power system.
12.5.3.2.1 Variable slope percentage differential relay
The variable slope percentage differential relay is the most widely used form of differential
relaying for generator protection. In this type of relay, the percentage slope characteristic can
vary from about 5% at low values of through current up to 50% or more at high values of
through current as illustrated in Figure 12-11. This characteristic results in a relay that is
sensitive to internal faults and insensitive to CT error currents during severe external faults.
CTs should have a primary current rating equal to or larger than the generator rated current,
preferably at least 150%; and they should also have closely matched performance
characteristics to prevent false operation on faults outside the differential protection zone. It
is preferable to avoid connecting other relays or devices in these current circuits.

IEEE
Figure 12-10—Generator percentage differential relay (phase scheme) and
ground differential scheme using a directional relay
Figure 12-11—Variable slope differential relay

IEEE
Figure 12-12 illustrates the differential connections for a six-bushing machine having single-
turn coils and one or more circuits per phase. This machine is the most widely used
conﬁguration.
Figure 12-13 shows the typical differential relaying arrangement used for a delta-connected
generator.
12.5.3.2.2 Self-balancing differential scheme
The self-balancing differential scheme has been used for phase and ground faults on small
generators with low-resistance neutral grounding. This scheme is illustrated in Figure 12-14.
As shown, leads from both ends of the phase winding are placed in the opening of a window
CT. Any difference between the currents entering and leaving the winding is detected by an
instantaneous overcurrent relay. Where applicable, this scheme is capable of providing
sensitive phase- and ground-fault protection.
Because these CTs see a difference current that is typically zero under normal system
conditions, they commonly are not rated for load currents. Low-ratio CTs are typically used
in this application for greater sensitivity. These low-ratio CTs usually have a lower ANSI CT
accuracy designation, which results in a greater tendency to saturate than the load-rated CTs.
These CTs may saturate even on low-level faults, and sensitivity may be lost. For this reason,
Figure 12-12—Percentage differential relay connection for six-bushing
wye-connected generator

IEEE
care should be taken when selecting relays for use in this application. Furthermore, when
exposed to high fault levels, the CT core may become saturated to the extent that the CT
cannot produce the necessary secondary current to operate the relay. Because both ends of the
generator windings must be passed through the opening in the CT, this scheme is normally
employed only on generators where the ﬂexibility of the conductors permits this connection.
CTs are usually mounted in the generator terminal box. Thus generator cables are excluded
from the protective zone of the scheme. Because the relays are also insensitive to the
generator-load current, the instantaneous overcurrent relay may be set at pickup levels as
sensitive as 5 primary A to 10 primary A.
Figure 12-13—Percentage differential relay connection for
delta-connected generator
Figure 12-14—Self-balancing protection scheme

IEEE
12.5.3.2.3 Differential backup protection
The type and sophistication of backup protection provided is dependent to some degree upon
the size of the generator and on the method of connecting the generator to the system.
When a generator is connected to the system in the unit generator-transformer conﬁguration,
high-speed phase-fault backup protection can be obtained by extending the protective zone of
the unit transformer differential relay scheme to include the generator, the interconnecting
leads, and the unit auxiliary transformer. This backup is often referred to as the overall
differential scheme and is illustrated in Figure 12-15.
In this arrangement, the CTs in the unit auxiliary transformer circuit should be high-ratio CTs
in order to balance the differential circuit. The required ratio may be obtained with a single-
bushing CT or with a combination of bushing and auxiliary CTs as shown in Figure 12-15.
In some cases, the unit auxiliary transformer may be excluded from the overall differential
scheme as indicated by the alternate connection. This approach may introduce a blind spot in
the protection for the unit auxiliary transformer. For faults near the high side of this trans-
former, the available fault current may be 150 to 200 times the rating of the CTs used in the
differential scheme for the unit auxiliary transformer. This high current level would drive the
Figure 12-15—Overall differential scheme of generator phase-fault backup
protection

IEEE
CTs into saturation and result in little or no current output to the differential relays. This blind
spot is eliminated by connecting the overall differential scheme to the low side of the unit
auxiliary transformer. The overall scheme detects the severe faults, while the unit auxiliary
differential detects the low-level faults.
Where generators are bussed at generator voltage as shown in Figure 12-1 and Figure 12-2,
the overall differential scheme is not applicable. Furthermore, a duplicate differential scheme
is rarely used to provide phase-fault backup protection. In these configurations, a common
practice is to use the unbalanced current protection (or negative-sequence current relay) and
system backup protection to provide backup for all generator phase faults. This protection is
discussed in detail in 12.5.5.9. This backup relaying is generally less sensitive than differen-
tial relaying and has time delay associated with it. Backup protection is provided by distance
relay (Device 21) or by voltage-restrained or -controlled time-overcurrent relay
(Device 51V).
12.5.3.2.4 Tripping
A common practice is to have the primary and backup protection energize separate hand-
reset, multicontact auxiliary relays. These auxiliary relays simultaneously initiate the
following:
a) Trip the main generator breakers.
b) Trip the field and/or exciter breakers.
c) Trip the prime mover.
d) Turn on carbon dioxide internal generator fire protection, if provided.
e) Operate an alarm and/or annunciator.
f) Transfer the station service to the standby source.
12.5.3.3 Ground-fault protection
Protective schemes that are designed to detect three-phase and phase-to-phase stator faults
are not intended to provide protection for phase-to-ground faults in the generator zone. The
degree of ground-fault protection provided by these schemes is directly related to how the
generator is grounded and, therefore, to the magnitude of the available ground-fault current.
The maximum phase-to-ground fault current available at the generator terminals may vary
from three-phase fault-current levels or higher to almost zero. In addition, the magnitude of
stator ground-fault current decreases almost linearly as the fault location moves from the
stator terminals toward the generator neutral due to the generator winding impedance. For a
ground fault near the neutral of a wye-connected generator, the available phase-to-ground
fault current becomes small regardless of the grounding method.
As noted in 12.5.3.2, differential relaying provides no ground-fault protection on high-
impedance-grounded machines where primary fault current levels are limited to 3 A to 25 A.
Differential relaying schemes may detect some stator phase-to-ground faults depending upon
how the generator is grounded. Figure 12-16 illustrates the approximate relationship between
available ground-fault current and the percent of the stator winding protected by a current-

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differential scheme. When the ground-fault current level is limited below generator-rated load
current, a large portion of the generator may be unprotected.
Because the available ground-fault current may be small or limited to low values, a common
practice is to provide separate sensitive ground-fault protection for generators. Depending on
the generator-grounding method, the protection provided may include both primary and
backup relaying or may be used to supplement whatever protection may be provided by dif-
ferential relaying.
Numerous schemes have been developed and used to provide sensitive ground-fault
protection for generators and are discussed in considerable detail in IEEE Std C37.101-1993.
Only the most widely used schemes for the four grounding methods considered in 12.4 are
discussed in 12.5.3.3.1 through 12.5.3.3.4.
Figure 12-16—Percent of stator winding unprotected by differential relay
for phase-to-ground fault

IEEE
12.5.3.3.1 High-resistance grounding
The ground-fault current is limited to such low levels that differential relaying does not detect
phase-to-ground faults. Therefore, for high-resistance-grounded generators, a common prac-
tice is to provide separate primary and backup relaying for ground-fault protection.
12.5.3.3.1.1 Protection
The most widely used protective scheme with the resistance-loaded distribution transformer
method of grounding is a time-delay overvoltage relay (Device 59GN) connected across the
grounding impedance to sense zero-sequence voltage as shown in Figure 12-17.
The relay used for this function is designed to be sensitive to fundamental frequency voltage
and insensitive to third-harmonic and other zero-sequence harmonic voltages that may be
present at the generator neutral.
Because the grounding impedance is large compared to the generator impedance and other
impedances in the circuit, the full phase-to-neutral voltage is impressed across the grounding
device for a phase-to-ground fault at the generator terminals. The voltage on the relay is a
function of the distribution transformer ratio and the location of the fault. The voltage is a
Figure 12-17—Generator ground-fault protection for
high-impedance-grounded generator

IEEE
maximum for a terminal fault and decreases in magnitude as the fault location moves from
the generator terminals toward the neutral.
Typically, the overvoltage relay has a minimum pickup setting of approximately 5 V. With
this setting and with typical distribution transformer ratios, this scheme is capable of detect-
ing faults to within 2% to 5% of the stator neutral.
For personnel safety, the distribution transformer secondary winding is usually grounded at
one point, as shown in Figure 12-17. This point may be at one terminal of the secondary
winding or at a center tap, if available.
The time setting for the voltage relay is selected to provide coordination with other system
protective devices. Speciﬁc areas of concern include the following:
a) When grounded-wye-grounded-wye VTs are connected at the machine terminals, the
voltage relay should be time-coordinated with VT fuses for faults on the transformer
secondary windings. If relay time delay for coordination is not acceptable, the
coordination problem can be alleviated by grounding one of the secondary phase
conductors instead of the secondary neutral. When this technique is used, the
coordination problem still exists for ground faults on the secondary neutral. Thus, its
usefulness is limited to applications where the exposure to ground faults on the
secondary neutral is small.
b) The voltage relay may have to be coordinated with system relaying for system
ground faults. System phase-to-ground faults induce zero-sequence voltages at the
generator due to capacitive coupling between the windings of the unit transformer.
This induced voltage appears on the secondary of the grounding distribution trans-
former and may cause operation of the zero-sequence voltage relay.
In general, a maximum time-delay setting for the induction disk relay has been found to pro-
vide adequate coordination with VT fuses and system ground relaying. Shorter time delays
have been used where the VT secondary neutral is isolated and a secondary phase conductor
grounded and where high-speed ground relaying is used on the high-voltage system.
Several schemes use third-harmonic voltage at the neutral or at the generator terminals to
detect faults near the stator neutral. These schemes supplement the fundamental frequency
zero-sequence voltage relay. These schemes assume that adequate harmonic voltage is
present at the neutral of the machine. Typical values needed are approximately 1% of rated
voltage.
In Figure 12-18, a voltage relay is connected to measure the third-harmonic voltage at the
machine terminals. When a stator phase-to-ground fault occurs, third-harmonic voltage
increases, and the increase causes relay operation.

IEEE
12.5.3.3.1.2 Tripping
In general, both the primary and backup protection are connected to trip and to shut down the
generator and the prime mover. Separate lockout relays may be used to distinguish phase
faults from ground faults and/or to distinguish primary from backup relay operation.
12.5.3.3.2 Low-resistance grounding
As indicated in 12.4.2, the grounding resistor is selected to limit the generator’s contribution
to a single phase-to-ground fault at its terminals to a range of current between 200 A and
400 A. With this range of available fault current, differential relaying provides some ground-
fault protection (see Figure 12-16). However, because the differential relaying does not
provide ground-fault protection for the entire stator phase winding, a common practice is to
provide supplementary sensitive protection for ground faults.
Low-resistance grounding is generally used where two or more generators are used at genera-
tor voltage and connected to a system through one step-up transformer as illustrated in
Figure 12-2 or connected directly to a distribution system as illustrated in Figure 12-1. The
protection discussed above permits selective ground relaying of several generators.
When the generator neutral is grounded through an impedance limiting the maximum
ground-fault current to a value less than the primary rating of the CTs, a differential ground-
fault scheme (Device 87G) should be considered. A differential ground-fault scheme,
however, is capable of detecting faults to within 10% from the generator neutral. A current-
polarized directional ground relay, shown in Figure 12-10, may be used in this application. A
neutral CT, separate from the ground overcurrent relay CT, may be necessary for maximum
Figure 12-18—Third-harmonic overvoltage scheme for generator
ground-fault protection

IEEE
relay sensitivity. The ground differential CT should have a primary current rating of 10% to
50% of the neutral resistor-current rating. To match the phase and neutral CT ratios, an
auxiliary CT should be utilized. Again, a careful review of the auxiliary CT performance
characteristics should be made to prevent misoperation on external faults.
Sensitive ground-fault protection can be provided with a product relay, current-polarized
directional ground relay, or with a simple time-overcurrent relay. These three schemes
provide varying degrees of sensitivity for detecting ground faults covered by the differential
zone.
— The product relay is connected to receive differential current from the phase CTs in
the relay’s operating coil circuit and generator neutral 3Io current in its polarizing cir-
cuit as shown in Figure 12-19. Differential comparison is biased via an auxiliary CT
to assure that positive restraint exists for external faults even though the phase and
neutral CTs have substantially different performance characteristics. This scheme
provides excellent security against misoperation for external faults and provides sen-
sitive detection for internal faults.
— When a directional overcurrent relay is used, the polarizing coil is energized from a
CT in the generator neutral, and the operating coil is in the neutral of the generator
differential relaying scheme, as shown in Figure 12-10. This application provides
sensitivity without a high operating coil burden.
— When a simple overcurrent relay is used, a sensitively set time-overcurrent relay is
connected in the neutral of the differential scheme, as shown in Figure 12-20.
In these approaches, the sensitive ground protection detects only faults covered by the
differential zone and eliminates the need to time-coordinate these relays with other system
Figure 12-19—Generator ground differential protection using
product relay

IEEE
relaying. The effect of the ground relay coil burden in the neutral of the generator differential
relaying should be checked.
In addition to this protection, a common practice is to install a sensitive ground time-
overcurrent relay in the generator neutral. This relay provides backup protection for all
ground relays in the system at the generator-voltage level. It also provides protection against
internal generator ground faults, but this protection is limited by the amount of time delay
that the relay must have to coordinate with other ground relays. On small isolated machines,
this device and Device 51V (when the CTs for it are installed on the neutral side) provide the
only protection for internal generator faults.
The neutral-CT-turns ratio and tap setting of the overcurrent relay should be selected to pro-
vide an operating current of 5 to 10 times its pickup setting for a bolted line-to-ground fault at
the generator line terminals. The pickup setting should be at least equal to and preferably
greater than the pickup setting of downstream ground overcurrent devices for selectivity
between those relays. The pickup setting should also be set above the anticipated level of any
harmonic current flowing in the neutral during normal conditions. Many European generator
designs have a winding configuration that produces a higher magnitude of harmonic currents
than domestic machines, sufficient to preclude the use of machine neutral grounding. In these
cases, the use of a zigzag grounding transformer should be considered to establish the source
grounding point.
12.5.3.3.2.2 Tripping
The tripping mode is the same as for high-resistance grounding (see 12.5.3.3.1.2).
Figure 12-20—Generator ground differential protection using
overcurrent relays

IEEE
12.5.3.3.3 Reactance grounding
Reactance grounding is used where the generator is connected directly to an effectively
grounded distribution system. With reactance grounding, the available ground-fault current
levels range from 25% to 100% of the three-phase fault current. With this high level of fault
current, differential relaying is capable of providing almost complete protection of the stator
phase winding for most ground faults. However, differential relaying may not detect high-
resistance faults or faults near the generator neutral. Therefore, a common practice is to
provide additional sensitive ground protection as backup for generator and system ground
faults.
Backup protection is generally provided by a time-overcurrent relay connected to a CT in the
generator neutral. The pickup of this relay should be set above the normal currents that ﬂow
in the neutral due to the unbalanced system loads and zero-sequence harmonic currents.
Because this overcurrent relay operates for system ground faults, it should be time-
coordinated with system ground relaying.
More sensitive ground-fault protection may be provided with the directional overcurrent
relay or with the simple overcurrent relay connected in the neutral of the differential scheme,
as described in 12.5.3.3.2.1.
12.5.3.3.3.2 Tripping
The tripping mode is the same as for high-resistance grounding (see 12.5.3.2.4).
12.5.3.3.4 Grounding-transformer grounding
As discussed in 12.4.4, grounding may be provided by a zigzag transformer, or a grounded
wye-delta transformer or by a grounded wye-broken delta transformer with a resistor con-
nected across a corner of the broken delta.
When a zigzag or grounded wye-delta transformer is used, the effective grounding impedance
is selected to provide sufﬁcient current for selective ground relaying. The available ground-
fault current is generally on the order of 400 A. These types of grounding transformers are
generally used as an alternate grounding source when a generator with neutral reactance
grounding is connected directly to a distribution system or as a bus grounding source where
several ungrounded wye- or delta-connected generators are bussed at generator voltage. A
typical application is illustrated in Figure 12-21. In this arrangement, the generators are
ungrounded, and the grounding bank is the sole source of ground-fault current for faults in
the generators or on the feeders.

IEEE
Each generator and feeder breaker would have primary ground overcurrent relaying. This
protection could be sensitive instantaneous overcurrent relaying. Backup protection would be
provided by a time-overcurrent relay connected to a CT in the neutral of the grounding bank.
The grounded wye-broken-delta transformer with a resistance in the corner of the broken
delta is generally a high-resistance-grounded system that limits the single phase-to-ground
fault current to a range of 3 primary A to 25 primary A. This approach is generally used to
provide a means for detecting ground faults in ungrounded generators prior to synchronizing
the generator to the system or to provide backup for high-impedance-grounded generators. In
the application, the grounding transformer would be connected at the terminals of the
generator and a zero-sequence overvoltage relay of the type described in 12.5.3.3.1.1 would
be connected across the resistance in the broken delta. The relay pickup setting and
coordination would be as discussed in 12.5.3.3.1.1.
12.5.3.3.4.2 Tripping
The tripping mode is the same as for high-resistance grounding (see 12.5.3.2.4).
12.5.4 Generator rotor field protection
This subclause is primarily concerned with the detection of ground faults in the field circuit.
Other protection for the field circuits is covered in 12.5.5.1.
Generator field circuits are normally operated ungrounded. Thus, a single ground fault does
not result in equipment damage or affect the operation of the generator. If, however, a second
ground fault should occur, an unbalance in the magnetic field is established by the rotor. This
Figure 12-21—Ground-fault protection with zigzag grounding bank

IEEE
unbalance may be severe enough to develop destructive vibration within the generator. The
field circuit of a generator is an ungrounded system. As such, a single ground fault does not
generally affect the operation of a generator. However, if a second ground fault occurs, a por-
tion of the field winding is short circuited and produces unbalanced air-gap fluxes in the
machine. These unbalanced fluxes may cause rotor vibration that can quickly damage the
machine; also, unbalanced temperatures caused by unbalanced currents can cause similar
damaging vibrations. The probability of the second ground occurring is greater than the first
because the first ground establishes a ground reference for voltages induced in the field by
stator transients and increases the stress to ground at other points on the field winding.
12.5.4.1 Protection
Several methods are in common use for detecting rotor field ground faults. For excitation sys-
tems using slip rings and brushes, two types of relays are available. Satisfactory operation of
either type of relay requires the generator rotor to be grounded. To accomplish this setup, a
means should be provided to bypass the bearing oil film. This step should be done because
the resistance of the path may be too large for dependable relay operation and because even a
small magnitude of current flowing through the bearing may cause its destruction. Bearing
seals may be used to provide the necessary bypass in some machines, while others may
require an additional brush and slip ring for effective rotor grounding.
In one method, a dc voltage is applied between the negative side of the generator field circuit
and ground through the coil of an overvoltage relay, as illustrated in Figure 12-22. A ground
anywhere in the field causes the relay to operate. A brush or braid is used to ground the rotor
shaft because the bearing oil film may insert enough resistance in the circuit so that the relay
would not operate for a field ground. Some time delay is normally used with this relay in
order to prevent unnecessary operations for momentary or transitory unbalances of the field
circuit with respect to ground. These momentary unbalances may be caused by the operation
of fast-response thyristor excitation systems.
Figure 12-22—Field ground-fault protection using a dc source

IEEE
The second method, illustrated in Figure 12-23, is similar to the method employed to detect a
control battery ground and uses a voltage divider and a sensitive overvoltage relay between
the divider midpoint and ground. As with the battery ground detector, a maximum voltage is
impressed on the relay by a ground on either the positive or the negative battery leads. How-
ever, a null point exists between positive and negative where a ground fault does not produce
a voltage across the relay unless the polarity on the ground detector is reversed from time to
time. The generator field ground relay is designed to overcome the null problem by using a
nonlinear resistor in series with one of the two linear resistors in the voltage divider. The
resistance of the nonlinear resistance varies with the applied voltage. The divider is propor-
tioned so that the field winding null point is at the winding midpoint when the exciter voltage
is at rated voltage. Changes in exciter voltage move the null point from the field winding
center.
On a brushless excitation system, continuous monitoring for field ground faults is not
possible with conventional field ground relays because the generator field connections are
contained in the rotating element.
Figure 12-24 illustrates the addition of a pilot brush or brushes to gain access to the rotating
field parts. Normally, this addition is not made because eliminating the brushes is considered
an advantage of the brushless system. However, detection systems can be used to detect field
grounds if a collector ring is provided on the rotating shaft along with a pilot brush that can
be periodically dropped to monitor the system. The ground check can be done automatically
by a sequencing timer and control or by the operator. The brushes used in this scheme are not
suitable for continuous contact with the collector rings. The field circuit impedance to ground
is one leg of a Wheatstone bridge via the brush. A ground fault shorts out the field winding to
rotor capacitance CR, which unbalances the bridge circuit. If a voltage is read between
ground and the brush, which is connected to one side of the generator field, then a ground
Figure 12-23—Field ground-fault protection using a voltage divider

IEEE
fault exists. For brushless machines, resistance measurements can be used to evaluate the
integrity of the field winding.
Figure 12-25 illustrates a method for continuous monitoring of field grounds on brushless
machines without using pilot brushes. The relay’s transmitter is mounted on the generator
field diode wheel. Its source of power is the ac brushless exciter system. Two leads are con-
nected to the diode bridge circuit of the rotating rectifier to provide this power. Ground
detection is obtained by connecting one lead of the transmitter to the negative bus of the field
rectifier and connecting the ground lead to the rotor shaft. The transmitter detects the resis-
tance change between the field winding and the rotor shaft. The transmitter’s light emitting
diodes (LEDs) emit light under normal conditions. Upon detection of a fault, the LEDs are
turned off. A stationary receiver mounted on the exciter housing receives the light signal
across the air gap. Loss of the LED light to the receiver actuates the ground relay and initiates
a trip or alarm. Time delay of 10 s is provided.
If the generator field ground relay is used only to detect the first field ground and to sound an
alarm, backup protection consisting of vibration-detecting equipment should be provided so
that a second ground does not result in an abnormal amplitude of vibration. The vibration
monitor should be arranged with contacts to trip the main and field breaker. If vibration is
above the amount associated with short-circuit transients for faults external to the unit.
12.5.4.2 Tripping
From a protection viewpoint, the safest practice is to shut down the generator automatically
when the first ground is detected. A ground fault can cause damage to the field. Moreover, a
second ground fault may be imminent because of insulation problems in the field. Many
industrial systems are designed to alarm with the field ground relay and have written
Figure 12-24—Field ground-fault protection using pilot brushes

IEEE
instructions for the operator to unload and shut down the machine in an orderly manner so
that other machines can pick up the load thus avoiding a system disturbance.
12.5.5 Generator abnormal operating conditions
This subclause describes hazards to which a generator may be subjected that may not
necessarily involve a fault in the generator. It discusses the typical means for detecting these
abnormal operating conditions and the tripping practices.
12.5.5.1 Loss of field protection (Device 40)
Loss-of-field protection devices sense when a generator’s excitation system has been lost.
This protection is important when generators are operating in parallel or in parallel with a
utility supply system, although it is not needed on a single-isolated unit. The source of
excitation for a generator can be completely or partially removed through such incidents as
accidental tripping of a field breaker, field open circuit, field short circuit (e.g., flashover of
the slip rings), regulation system failure, or the loss of supply to the excitation system.
Whatever the cause, a loss of excitation can present serious operating conditions for both the
generator and the system.
When a generator loses excitation, it overspeeds and operates as an induction generator. It
continues to supply some power to the system and receives its excitation from the system in
the form of vars. In general, the severest condition for both the generator and the system is
when a generator loses excitation while operating at full load. For this condition, the stator
currents can be in excess of 2 per unit; and, because the generator has lost synchronism, high
levels of slip-frequency currents can be induced in the rotor. These high current levels can
cause dangerous overheating of the stator windings and the rotor within a short time. In addi-
tion, because the loss-of-field condition corresponds to operation at very low excitation,
Figure 12-25—Field ground-fault protection for brushless machines

IEEE
overheating of the end portions of the stator core may result. The system itself is also jeopar-
dized because it is forced to supply the lost kVAR output of the machine in trouble, plus
provide still more kVARs in order to excite the unit as an induction generator. The level of
kVARs drawn from the system can be equal to or greater than the generator kilovoltampere
rating. The danger exists that the system would not have sufficient kVAR capacity for such a
condition. The increased reactive flow across the system can cause voltage reduction and/or
tripping of transmission lines and thereby adversely affect system stability. The increased
reactive flow across the system can cause system voltage reduction and thereby affect the
performance of generators in the same station or elsewhere on the system. The other
machines’ excitation systems would be operated at dangerously high levels that can cause
overheating.
12.5.5.1.1 Steam turbine generators
The machine slip and power output is a function of initial machine loading, machine and sys-
tem impedances, and governor characteristics. High system impedances tend to produce a
high slip and a low power output.
If a generator is operating initially at full load when it loses excitation, it can reach a speed of
2% to 5% above normal. No general statements can be made with regard to the permissible
time a generator can operate without field; however, at speeds other than synchronous, the
time would be short.
12.5.5.1.2 Hydrogenerators
Due to saliency, the normal hydrogenerator may carry 20% to 25% of normal load without
field and not lose synchronism. The actual load-carrying capability is a function of machine
and system characteristics. Also, operation with nearly zero field and at reduced load is often
necessary to accept line-charging current. However, if a loss of field occurs when a hydro-
generator is carrying full load, it behaves and produces the same effects as a steam turbine
generator. High stator and induced field currents may damage the stator winding, the field
windings, and/or the amortisseur windings; and the unit would impose a reactive drain on the
system.
12.5.5.1.3 Protection
At least three types of protective devices can be used to provide loss-of-field protection. Each
type has different relative cost, complexity of application, and degree of offered protection.
The type chosen should be dependent upon the application, considering factors such as gen-
erator cost, relay cost, and importance of the generator output.
12.5.5.1.3.1 Distance relays
The most widely applied method for detecting a generator loss of field is the use of distance
relays to sense the variation of impedance as viewed from the generator terminals. When a
generator loses excitation while operating at various levels of loading, the variation of

IEEE
apparent impedance as viewed at the machine terminals has the characteristics shown on the
R-X diagram in Figure 12-26.
Two types of distance relaying schemes are used for detecting the impedances seen during a
loss of field. One approach uses an offset mho distance relay. Figure 12-26 illustrates the
typical characteristics of such a relay. The generator full-load operating condition is
represented by Point A. When excitation is lost, such as from a shorted field winding, the
apparent impedance of the generator traces a locus of points ending inside the operating
characteristic. The impedance locus terminates to the right of the (–x) ordinate and
approaches impedance values somewhat higher than the average of the direct and quadrature
axes’ subtransient impedances of the generator. The curve from Point B represents a locus of
points of a moderately loaded generator. Curve C represents the locus of a lightly loaded and
underexcited generator. In this case, the impedance locus may oscillate in and out of the relay
characteristic depending upon its setting. For a loss of field at no load, the impedance as
viewed from the machine terminals varies between the direct and quadrature axes’
synchronous reactances (Xd , Xq).
For more sensitive protection, a second impedance element can be added that operates in a
more restricted area of impedance values as represented by the dotted characteristics. The
diameter of its circular characteristics is set equal to 1.0 per unit impedance and with an offset
equal to one-half transient reactance (Xd′). It detects a loss of field from full load down to
about 30% load as represented by Curve A and Curve B. This element is generally permitted
to trip without any added external time delay and thereby provides fast protection for the
more severe conditions in terms of possible machine damage and adverse effects on the sys-
tem. The first element is then equipped with a time-delay relay set for 0.5 s or greater so that
upstream fault-initiated system swings that may momentarily intrude into the operating area
Figure 12-26—Loss-of-field impedance relay characteristics using
offset mho distance relays

IEEE
of the relay, illustrated by Curve D, do not trip the generator. Loss of ﬁeld on lightly loaded
generators, illustrated by Curve C, is still cleared after the preset time delay, but with the
inherent adverse effect on the system. This relay can be provided with slightly differing char-
acteristics, but the ultimate quality of protection is the same.
On small or less important units, only a single relay would be used with the diameter of its
circular characteristics set equal to the synchronous reactance of the machine (Xd) and with
an offset equal to one-half transient reactance (Xd′). Time delay of 0.5 s to 0.6 s would be
used with this unit in order to prevent possible incorrect operations from upstream fault-
initiated system swings that may momentarily intrude into the operating area of the relay,
illustrated by Curve D.
The second distance relaying approach is illustrated in Figure 12-27. This scheme uses a
combination of an impedance unit, a directional unit, and an undervoltage unit applied at the
generator terminals and set to look into the machine. The impedance (Z2) and directional
units are set to coordinate with the generator minimum excitation limiter and its steady-state
stability limit. During abnormally low excitation conditions, such as might occur following a
failure of the minimum excitation limiter, these units operate and sound an alarm to alert the
station operator to correct the condition.
Should a low-voltage condition also exist, indicating a loss-of-ﬁeld condition, the under-
voltage unit would operate and initiate tripping with a time delay of 0.25 s to 1.00 s.
Two relays may also be used in this scheme, with the second (shown as Z1 on Figure 12-27
set with an offset equal to Xd′/2 and with the long reach intercept equal to 1.l times Xd. In this
Figure 12-27—Loss-of-excitation protection using impedance, directional,
and undervoltage units

IEEE
case, the relay with the Z1 setting should trip without any external time delay, and the other
relay should be delayed by approximately 0.75 s to prevent operation on stable swings.
12.5.5.1.3.2 Reactive (or var) relay
A second type of loss-of-field relay utilizes the flow of reactive power into the generator.
This relay operates much the same as the mho relay at much less expense. When the genera-
tor is operated with leading power factor, the power system attempts to provide reactive
power to excite the generator. A relay that measures the reactive (var) flow into the generator
can detect the loss of field and initiate a trip.
The var loss-of-field relay provides a characteristic curve in the power plane (or PQ dia-
gram), similar to the curve of the generator’s capability curve. The characteristic curve of the
var loss-of-field relay may also be provided with a shift from the P axis on the PQ diagram.
This shift allows the operation of the relay to be coordinated closely to the steady-state limit
of the generator, while allowing limited operation in the leading power factor region. If the
steady-state stability limit is exceeded, the generator may pull out of step.
Reverse-power relays may also be used to perform loss-of-field protection by connecting
them to measure var flow instead of real power flow. The principle limitation is that it cannot
always distinguish between the occasions when the generator is operating at a leading power
factor because of system conditions and similar-appearing var flows due to loss of excitation.
12.5.5.1.3.3 DC undercurrent relays
The third protective scheme available involves the application of a dc undercurrent relay that
is connected in series with the field. Its low cost makes it attractive for small generators and
for any generators supplying noncritical loads where the generator has leads brought out
through conventional slip rings. The relay may require the use of a timer in order to ride
through momentary interruptions of current that might occur during short circuits in the
power system. The relay would not indicate the loss of excitation due to faults in the field
winding and may not operate during the presence of induced ac currents in the field winding
during certain operating conditions.
12.5.5.1.4 Tripping
The loss-of-field protection is normally connected to trip the main generator breakers and the
field breaker and to transfer unit auxiliaries. The field breaker is tripped to minimize damage
to the rotor field in case the loss of field is due to a rotor field short circuit or a slip ring flash-
over. With this approach, if the loss of field were due to some condition that could be easily
remedied, a tandem compound generator could be quickly resynchronized to the system.
This approach may not be applicable with once-through boilers or with units that cannot
transfer sufficient auxiliary loads to maintain the boiler and fuel systems. In these cases, the
turbine stop valves would also be tripped.

IEEE
12.5.5.2 Unbalanced current protection
A number of system conditions may cause unbalanced three-phase currents in a generator.
The most common causes are system asymmetries (e.g., untransposed lines), unbalanced
loads, unbalanced system faults, and open circuits that result in an unbalance of the generator
phase voltages. These system conditions produce negative-phase-sequence components of
current that induce a double-frequency current in the surface of the rotor; the retaining rings;
the slot wedges; and, to a smaller degree, the field winding. These rotor currents may cause
high and possibly dangerous temperatures in a short time. Serious damage to the generator
occurs if the unbalanced condition is allowed to persist indefinitely.
The ability of a generator to accommodate unbalanced currents is specified by ANSI C50.13-
1989 in terms of negative-sequence current I2 (see Table 12-1). The negative-sequence
current is expressed as a percentage of rated stator current. ANSI C50.13-1989 specifies the
continuous I2 capability of a generator and the short-time capability of a generator, specified
in terms I2
t. The standard further defines the value of constant K for various types of
generators as listed below as I2
2
t = K where the negative-sequence current is expressed in per
unit of the full-load current and the time is given in seconds.
Table 12-1—Continuous and short-time unbalanced current
capability of generators
Type of generator
Permissible I2
(%)
Salient pole
With connected amortisseur windings 10
With non-connected amortisseur windings 5
Cylindrical rotor
Indirectly cooled 10
Directly cooled (to 960 MVA) 8
Directly cooled (961 MVA to 1200 MVA) 6
Directly cooled (1201 MVA to 1500 MVA) 5
These values also express the negative sequence current capability at reduced
generator kVA capabilities.
Unbalanced fault negative sequence current capability is expressed in per unit of
rated current and time is in seconds.
Type of generator Permissible I2
2t
Salient pole generator 40
Synchronous condenser 30
Cylindrical rotor generators
Indirectly cooled 20
Directly cooled (0-800 MVA) 10
Directly cooled (801-1600 MVA (see ANSI C50.13-1989)
Source: ANSI C50.13-1989

IEEE
A generator shall be capable of withstanding, without injury, the effects of a continuous-
current unbalance corresponding to a negative-sequence current I2 of the values in
Table 12-1, providing the rated kilovoltamperes is not exceeded and the maximum current
does not exceed 105% of rated current in any phase.
A common practice is to provide protection for the generator for external unbalanced
conditions that might damage the machine. This protection consists of a time-overcurrent
relay that is responsive to negative-sequence current. The setting determines the level of
protection offered by the relay and should be set to match the I2
2
t limit of the generator being
protected. Two types of relays are available for this protection: an electromechanical time-
overcurrent relay with an extremely inverse characteristic and a static relay with a time-
overcurrent characteristic that matches the I2
t capability curves for generators.
The electromechanical relay was designed primarily to provide machine protection for
uncleared unbalanced system faults. The negative-sequence current pickup of this unit is
generally 0.6 per unit of rated full-load current and hence may not detect open conductors
and/or severe unbalanced load conditions. Typical characteristics for this relay are shown in
Figure 12-28.
Figure 12-28—Characteristics of electromechanical negative-sequence
overcurrent relay showing generator I2
2
t limits

IEEE
The static relays are generally more sensitive and are capable of detecting and tripping for
negative-sequence currents down to the continuous capability of a generator. Typical charac-
teristics for this type of relay are shown in Figure 12-29.
Some relays can be provided with sensitive alarm units (I2 pickup range of 0.03 per unit to
0.20 per unit), which can be used to forewarn an operator when a machine’s continuous
capability is exceeded. In some types of static relay, a meter can be provided to indicate the I2
level in a machine.
12.5.5.2.2 Tripping
The negative-sequence relay is connected to trip the main generator breakers. This tripping is
preferred if the machine auxiliaries permit operation under this condition because this
approach allows quick resynchronization of the unit after the unbalanced conditions have
been eliminated. If the machine auxiliaries do not permit operation of the machine with such
tripping, then the negative-sequence relay must also trip the machine prime mover and the
ﬁeld and must transfer the auxiliaries.
Figure 12-29—Characteristics of static negative-sequence overcurrent
relay showing generator I2
2
t limits

IEEE
12.5.5.3 Loss-of-synchronism protection
As machine sizes have increased, generation per-unit reactances have increased, and inertia
constants have decreased. The culmination of these factors has resulted in reduced critical
clearing times required to isolate a system fault near a generating plant before the generator
losses synchronism with the power system. In addition to prolonged fault-clearing times,
generator loss of synchronism can also be caused by low system voltage, low machine
excitation, high impedance between the generator and the system, or some line switching
operations. When a generator loses synchronism, the resulting high peak currents and off-
frequency operation cause winding stresses, pulsating torques, and mechanical resonances
that are potentially damaging to the generator and turbine generator shaft. To minimize the
possibility of damage, the generator should be tripped without delay, preferably during the
ﬁrst half slip cycle of a loss-of-synchronism condition.
The protection normally applied in the generator zone (e.g., differential relaying, time-delay
system backup) does not detect loss of synchronism. The loss-of-excitation relay may
provide some degree of protection, but cannot be relied on to detect generator loss of
synchronism under all system conditions. Therefore, if during a loss of synchronism the
electrical center is located in the region from the high-voltage terminals of the generator step-
up transformer down into the generator, separate out-of-step relaying should be provided to
protect the machine. Description of the various relays used for loss of synchronism is beyond
the scope of this recommended practice (see IEEE Std C37.102-1995).
12.5.5.3.2 Tripping
This protection can be connected to trip only the main generator breakers and thereby isolate
the generator with its auxiliaries if the unit has full-load rejection capabilities. In this way,
when system conditions have stabilized, the unit can be readily resynchronized to the system.
If the unit does not have full-load rejection capability, this protection should be converted to
trip and shut down the generator and the prime mover.
12.5.5.4 Overexcitation protection
ANSI C50.13-1989 and IEEE Std 67-1990 state that generators shall operate successfully at
rated kilovoltamperes, frequency, and power factor at any voltage not more than 5% above or
below rated voltage. Deviations in frequency, power factor, and voltages outside these limits
can cause thermal distress unless the generator is speciﬁcally designed for such conditions.
Overexcitation is one such deviation for which monitoring and protection schemes can be
provided.
Overexcitation of a generator or any transformers connected to the generator terminals occurs
when the ratio of the voltage to frequency applied to the terminals of the equipment exceeds
1.05 per unit for a generator (i.e., generator base) and 1.05 per unit at full load or 1.l per unit
at no load at the high-voltage terminals for a transformer (i.e., transformer base). When these
voltage-to-frequency ratios are exceeded, saturation of the magnetic core of the generator or

IEEE
connected transformers can occur. Also, stray flux can be induced in nonlaminated compo-
nents that are not designed to carry flux and can cause excessive interlaminar voltages
between laminations at the ends of the core. The field current in the generator could also be
excessive. This excess can cause severe overheating in the generator or transformer and even-
tual breakdown in insulation.
One of the primary causes of excessive voltage-to-frequency ratios on generators and trans-
formers is operation of the unit under regulator control at reduced frequencies during startup
and shutdown. With the regulator maintaining rated voltage while the unit is at 95% or lower
speed, the voltage-to-frequency ratio at the terminals of the machine is 1.05 per unit or
greater, and damage can occur to the generator and/or connected transformers. Generator
rotor prewarming is an example of operating an unloaded machine at reduced terminal volt-
age and frequency.
Overexcitation can also occur during complete load rejection which leaves transmission lines
connected to a generating station. Under this condition, the voltage-to-frequency ratio may
exceed 1.25 per unit. With the excitation control in service, the overexcitation is generally
reduced to safe limits in a few seconds. With the excitation control out of service, the
overexcitation may be sustained, and damage can occur to the generator and/or transformers.
Failures in the excitation system or loss of signal voltage to the excitation control can also
cause overexcitation.
Industry standards do not at present specify definite short-time capabilities for generators and
transformers. However, manufacturers generally provide overexcitation capability limits for
this equipment. Several methods of preventing an overexcitation condition are discussed in
12.5.5.4.1 through 12.5.5.4.3.
12.5.5.4.1 Voltage-to-frequency limiters in excitation control
The voltage-to-frequency limiter limits the output of the machine to a set maximum voltage-
to-frequency ratio no matter what the speed of the unit. This limiter functions only in the
automatic control mode. To provide protection when the unit is under manual control, the
limiter may have a relay signal output that activates any additional protective circuits to trip
the generator field. The relay circuit is functional whether the excitation control is in or out of
service.
With or without a voltage-to-frequency limiter in the excitation control, a common practice is
to provide separate voltage-to-frequency relaying to protect the station transformers and the
generator, when the excitation control is out of service.
12.5.5.4.2 Voltage-to-frequency relays
Several forms of voltage-to-frequency relays are available and may be provided with the
generating unit. One type uses a fixed-time single voltage-to-frequency relay set at 110%
of normal, which alarms and trips in 6 s. A second type has an inverse characteristic that
can be applied to protect a generator and/or transformer from an excessive level of voltage-

IEEE
to-frequency ratio and time-delay voltage-to-frequency ratio. A minimum operate level of
voltage-to-frequency ratio and time delay can usually be set to provide a close match of
the generator-transformer-combined voltage-to-frequency ratio characteristics. The
manufact-urers’ voltage-to-frequency ratio limitations should be obtained if possible and
used to determine the combined characteristic.
12.5.5.4.3 Exciter relays
A dc relay (Device 53) can be connected across a field shunt to check when the machine field
voltage has reached a given value. During startup, this supplemental off-line protection can
help prevent an overexcitation condition if something is wrong with the potential circuits and
the voltage-to-frequency relays are unable to function. This relay is set to operate when field
current exceeds its rated full-field no-load voltage by a certain value. Operating high speed
with a short time delay, this scheme can be set to alarm, initiate automatic field run back, and/
or trip the generator.
12.5.5.4.4 Tripping
Overexcitation protection is generally connected to trip the main generator breakers and the
field breakers and transfer auxiliaries if necessary.
12.5.5.5 Antimotoring protection
Motoring of a generator occurs when the energy supply to the prime mover is cut off while
the generator is still on line. When this event occurs, the generator acts as a synchronous
motor and drives the prime mover. While this condition is defined as generator motoring, the
primary concern is the protection of the prime mover, which can be damaged during a motor-
ing condition.
12.5.5.5.1 General considerations
Motoring causes many undesirable conditions. A steam turbine could overheat due to the loss
of the cooling effect provided by the steam. A diesel or gas engine could either catch fire or
explode. In a steam turbine, the rotation of the turbine rotor and blades in a steam
environment causes idling or windage losses. Because windage loss is a function of the
diameter of rotor disc and blade length, this loss is usually greatest in the exhaust end of the
turbine. Windage loss is also directly proportional to the density of enclosing steam. Thus,
any situation in which the steam density is high causes dangerous windage losses. For
example, if vacuum is lost on the unit, the density of the exhaust steam increases and causes
the windage losses to be many times greater than normal. Also, when high-density steam is
entrapped between the throttle valve and the interceptor valve in reheat units, the windage
losses in the high-pressure turbine are high.
Windage loss energy is dissipated as heat. The steam flow through a turbine has a two-fold
purpose: to give up energy to cause rotation of the rotor and to carry away the heat of the
turbine parts. Because no steam flows through the turbine during motoring, the heat of the
windage losses is not carried away and the turbine is heated. Even when the unit has been

IEEE
synchronized, but no load has been applied, and enough steam is flowing through the unit to
supply the losses, the ventilating steam flow may not be sufficient to carry away all of the heat
generated by the windage losses. Although the generator is not motoring under this condition,
the problems caused in the turbine are the same, and protection should be provided.
Because the temperature of the turbine parts is controlled by the steam flow, various parts
cool or heat at abnormal, uncontrolled rates during motoring. This irregularity can cause
severe thermal stresses in the turbine parts. Another problem resulting from this temperature
change can be unequal contraction or expansion of the turbine parts. This irregularity could
cause a rub between rotating and stationary parts. Because a rub generates heat, the problem
is made more severe (as with windage losses) by the lack of ventilation steam flow to carry
the heat away.
A maximum permissible time is established for how long a steam turbine can be operated in a
motoring condition, and this time is generally a function of the rated speed of the unit. These
data can readily be obtained from the manufacturer for a particular steam-turbine unit.
Windage loss is not a particular problem in other types of prime movers, but they exhibit
additional motoring difficulties. Gas turbines, for example, may have gear problems when
being driven from the generator end. With hydroturbines, motoring can cause cavitation of
the blades on low water flow. If hydro units are to operate as synchronous condensers, the
unit will be motoring. This fact should be recognized in any motoring protection. With diesel-
engine generating units, explosion and fire from unburned fuel are additional dangers.
Motoring protection should, therefore, be provided for all generating units except units
designed to operate as synchronous condensers, such as hydro units.
12.5.5.5.2 Reverse-power relay
From a system standpoint, the primary indication of motoring is the flow of real power into
the generator acting as a synchronous motor. The reverse-power relay detects the reverse
flow of power (i.e., watts) that would occur should the prime mover lose its input energy. The
magnitude of motoring power varies considerably depending on the type of prime mover, as
shown in Table 12-2.
Table 12-2—Maximum motoring power for prime movers
Steam turbine 3.0%
Water wheel turbine 0.2%
Gas turbine 50.0%
Diesel engine 25.0%

IEEE
The sensitivity and setting of the relay are dependent upon the type of prime mover involved
because the power required to motor is a function of the load and losses of the idling prime
mover.
The reverse-power relay should have sufficient sensitivity so that the motoring power
provides 5 to 10 times the minimum pickup power of the relay.
In gas turbines, for example, the large compressor load represents a substantial power
requirement from the system, up to 50% of the nameplate rating of the unit; therefore, the
sensitivity of the reverse-power relay is not critical. A diesel engine with no cylinders firing
represents a load of up to 25% of rating; therefore, again, no particular sensitivity problem
exists.
With hydroturbines, when the blades are under the tail-race water level, the percent motoring
kilowatts is high. When the blades are above the tail-race level, however, the reverse power is
low, between 0.2% to 2.0% of rated, and a sensitive reverse-power relay may be needed.
Steam turbines operating under full vacuum and zero steam input require about 0.5% to 3.0%
of rating to motor. This condition may be detected by a sensitive reverse-power relay. If the
turbine were operated with its valves only partially closed to, for example, slightly less than
the no-load value, the electrical input from the system could be essentially zero, and the
reverse-power relay could not detect the condition. Because overheating of the turbine could
still occur, some additional means of protection is required, such as the schemes discussed in
12.5.5.5.3 through 12.5.5.5.6.
A directional power relay with either definite- or inverse-time characteristics is frequently
used to introduce sufficient time delay necessary to prevent operation during power swings
caused by system disturbances or when synchronizing the machine to the system. A time
delay of 10 s to 30 s is typical. Either a single-phase or a three-phase relay may be used
although a single-phase relay calibrated in three-phase watts is frequently selected.
12.5.5.5.3 Exhaust hood temperature
Because the prime cause of distress in a motoring steam turbine is the temperature rise due to
the windage losses, temperature-sensing devices can be used for protection. Because windage
loss is generally most severe in the exhaust end of the turbine, a temperature-sensing device
located in the exhaust hood is often used as auxiliary protection. This device, set at
approximately 250 °F, is used to alarm the operator for this motoring condition.
This device should not be used as primary protection because the measured temperatures
vary with the location on the exhaust end of the turbine. Placement of the detector is impor-
tant. Also, the reliability of existing detectors is questionable. Some other form of protection
should, therefore, be used as primary protection.

IEEE
12.5.5.5.4 Valve limit switches
Limit switches on the turbine valves provide indication of when steam flow has been either
completely shut off or reduced to harmfully low levels. By arranging these switches in the
appropriate series-parallel arrangement, protection against loss of steam flow can be
provided.
This method was used for many years as the primary protection for motoring of steam
turbines and is still used for the smaller units. With the increased number of valves and
corresponding limit switches on the larger modern units, the arrangement became complex.
Also, because a number of switches are in series, a failure of any one switch would render the
protection scheme inoperative. For these reasons, most present-day units use the control oil
pressure and turbine steam flow schemes (see 12.5.5.5.5 and 12.5.5.5.6, respectively).
12.5.5.5.5 Control oil pressure
The operation of the valves in a steam turbine is controlled by two oil systems: a turbine-trip
system and a governing oil system. The turbine-trip oil system is used as an emergency shut-
down system; and, when the pressure is reduced on this system, all valves close. The pressure
in the governing oil system positions the governor and intercept valves to control load during
normal operation. Pressure switches in these two systems provide a simple and reliable
method of detecting a motoring condition.
Because loss of pressure in the turbine-trip oil system normally indicates complete closure of
all steam valves, the contact of the pressure switch in this system may be used for instanta-
neous electrical tripping of the unit. For security against possible overspeed, the oil system
trips may be supervised by a reverse-power relay. The pressure switch in the governing oil
system is set at the no-load steam flow position and, after 1 min, trips the turbine-trip oil sys-
tem, which in turn trips the electrical system. The governing oil trip system is, of course,
supervised by an “a” contact on the unit breaker to prevent tripping of the turbine-trip system
before synchronizing.
12.5.5.5.6 Turbine steam flow
Steam flow equal to or greater than synchronous-speed no-load steam flow is an indication
that the unit is not being motored. The steam flow, even at this low percentage of rated steam
flow, can accurately be determined by measuring the pressure drop across the high-pressure
turbine element. Use of a differential pressure switch across this high-pressure element,
instead of the governing oil pressure switch, is the most accurate and reliable method. It func-
tions independently of the type of control system, hydraulic or electrohydraulic, and is the
recommended scheme for large steam turbines. Again, for security against possible over-
speed, this system may be supervised by a reverse-power relay.
12.5.5.5.7 Protection summary
On steam turbine units, the primary motoring protection used is the control oil pressure and
turbine steam flow scheme, with the reverse-power relay used for backup and security and

IEEE
with the exhaust hood temperature used as an alarm. With gas turbines, diesel engines, and
hydroturbines, the reverse-power relay is primary protection.
12.5.5.6 Overvoltage protection
Overvoltage protection is normally provided on machines such as hydrogenerators where
excessive terminal voltages may be produced following load rejection without necessarily
exceeding the voltage-to-frequency ratio limit of the machine. The hydrogenerator overspeed
could exceed 200% of normal. Under this condition on a voltage-to-frequency basis, the
overexcitation may not be excessive, but the sustained voltage magnitude may be above per-
missible limits. In general, this problem does not exist with steam or gas turbines because the
rapid response of the speed governor and voltage regulator systems preclude this possibility.
Protection for generator overvoltage is provided with a frequency-compensated (or
frequency-insensitive) overvoltage relay. The relay has both instantaneous function and time-
delay function with an inverse-time characteristic. The instantaneous function is generally set
to pick up at 130% to 150% of normal voltage while the inverse-time function is set to pick
up at about 110% of normal voltage.
12.5.5.6.2 Tripping
The protection is generally connected to trip the main generator breakers and the ﬁeld
breakers.
12.5.5.7 Abnormal frequency protection
The operation of generators at abnormal frequencies (either overfrequency or
underfrequency) generally results from full or partial load rejection or from overloading of
the generator. Overloading a generator may be caused by a variety of system disturbances
and/or operating conditions. The possibility of damage to steam- or gas-turbine generators
exists when operating at reduced frequency for sufﬁcient time. In general, underfrequency
operation of a turbine generator is more critical than overfrequency operation because the
operator does not have the option of control action. Therefore, it is often recommended that
some form of underfrequency protection be provided for steam- and gas-turbine generators.
Underfrequency and overfrequency protection is often required by the electric utility when
industrial or cogeneration units are operated in parallel with the utility.
12.5.5.7.1 Abnormal frequency capabilities of turbine generators
Both the generator and the turbine are limited in the degree of abnormal frequency operation
that can be tolerated. At reduced frequencies, the output capability of a generator is reduced.
The reduction in output capability coupled with possible overloading of the generator during
a system disturbance may result in thermal damage to the generator if its short-time thermal
capability is exceeded.

IEEE
The turbine is usually considered to be more restrictive than the generator at reduced
frequencies because of possible mechanical resonances in the many stages of turbine blades.
Departure from rated speed brings stimulus frequencies closer to one or more of the natural
frequencies of the various blades and an increase in vibratory stresses. As vibratory stresses
increase, damage is accumulated and may lead to cracking of some parts of the blade
structure, most likely the tie wires or blade covers. Tie wire and blade cover cracks are not
catastrophic failures, but they change the vibration behavior of the blade assembly so that it is
likely to have natural resonance frequencies closer to rated speed. This change may produce
blade fatigue during normal running conditions. Turbine manufacturers provide time limits
for abnormal frequency operation. The effects of abnormal frequency operation are
cumulative.
Underfrequency protection for steam- and gas-turbine generators is provided by the imple-
mentation of automatic load-shedding programs on the power system. These load-shedding
programs should be designed so that, for the maximum possible overload condition, suffi-
cient load is shed to quickly restore system frequency to near normal.
The underfrequency relays and timers are usually connected to trip the generator.
12.5.5.8 Undervoltage protection
The undervoltage relay can be used to serve any one of several protective functions
depending on the voltage tap and time-dial setting. The automatic voltage regulator normally
maintains the voltage within specified limits on multiple-isolated systems; therefore, a
sustained undervoltage could indicate a severe overload condition or the loss of a generator.
The relay may be used to initiate the starting of a standby unit. For single-machine operation,
the relay could be used to remove load from the generator should a regulator failure or other
malfunction cause the unit to be unable to maintain proper voltage. The relay may also be
used to provide a form of single-phase short-circuit protection because close-in or internal
faults would normally depress the voltage sufficiently to cause relay operation. On isolated
systems with multiple generators, the undervoltage relay may be used to provide a backup to
the backup protective devices. In this application, a time delay of 15 s to 20 s is necessary in
order to give all other relays an opportunity to operate.
12.5.5.9 System backup protection
The protective relaying described in 12.5.5.1 through 12.5.5.8 provides protection for all
types of faults in the generator zone and for generator abnormal operating conditions. In
addition to this protection, a common practice is to provide protective relaying that detects
and operates for system faults external to the generator zone that are not cleared due to some
failure of system protective equipment. This protection, generally referred to as system
backup, is designed to detect uncleared phase and ground faults on the system. This function
serves to protect the distribution system components against excessive damage and to prevent
the generator and its auxiliaries from exceeding their thermal limitations.

IEEE
12.5.5.9.1 System phase-fault backup
Two types of relays are commonly used for system phase-fault backup: a distance relay or a
time-overcurrent relay (either voltage-restrained or voltage-controlled). The choice of relay
in any application is usually a function of the type of relaying used on the distribution or
transmission system. In order to simplify coordination, the distance backup relay is used
where distance relaying is used for transmission-line protection, while the overcurrent
backup relay is used where overcurrent relaying is used for line protection. In industrial and
commercial application, where the generator is connected to a bus that serves distribution and
utilization equipment using overcurrent devices, the overcurrent relay (Device 51V) is used.
Where the output of the generator is stepped up to a transmission voltage, an impedance relay
(Device 21) is normally used.
12.5.5.9.1.1 Application of distance backup
One zone of distance relaying with an mho characteristic is commonly used for system
phase-fault backup. The proper currents and potentials must be used so that these relays see
correct impedances for system faults. If required, this phase shift is accomplished by using
auxiliary VTs connected in delta-wye as shown in Figure 12-30. When a generator is con-
nected directly to a system, the connections to the relay are shown in Figure 12-31. In both
cases, for the connections shown, the relay not only provides backup for system faults, but it
also provides some backup protection for phase faults in the generator and generator zone
before and after the generator is synchronized to the system.
12.5.5.9.1.2 Overcurrent backup
In general, a simple time-overcurrent relay cannot be properly set to provide adequate backup
protection. Users and system designers are reluctant to use any relay that operates solely on
overcurrent for fear that it might trip off the generator when the load demand on it is the
greatest. The use of ordinary time-overcurrent relays presents a dilemma in attempting to
determine the proper current and time settings. If the current and time settings are too low, the
relay may trip the generator unnecessarily on normal overloads. If the settings are too high to
allow for the proper coordinating time interval for selectivity with downstream devices, the
relay may not respond at all due to the decaying characteristic of the generator fault current.
Figure 12-30—Application of system backup relays for unit generator-
transformer arrangement

IEEE
Thus ordinary overcurrent relays cannot be used without the likelihood of false operation
occurring. In the successful application of these relays, it is, therefore, necessary to know not
only the fault characteristics of the generator, but also the system emergency conditions that
call for backup relay operation, and the characteristics of the relays available for that purpose.
The pickup setting of this type of relay would normally have to be set from 1.5 to 2 times the
maximum generator rated full-load current in order to prevent unnecessary tripping of the
generator during some emergency overload conditions. With this pickup setting and with
time delays exceeding 0.5 s, the simple time-overcurrent relay may never operate because the
generator-fault current may have decayed below relay pickup. After 0.5 s or more, generator-
fault current is determined by machine synchronous reactance; and the current magnitude
could approach generator rated full-load current, which would be below the relay setting.
The type of overcurrent device generally used for system phase-fault backup protection is
either a voltage-restrained or voltage-controlled time-overcurrent relay. Both types of relays
are designed to provide security under normal and emergency overload conditions and still
provide adequate sensitivity for the detection of faults.
12.5.5.9.1.2.1 Voltage-dependent overcurrent relays
These overcurrent relays are specially constructed to make their operating characteristics a
function of voltage and current. As the magnitude of the voltage applied to the coil decreases
from rated value, the operating characteristic is modiﬁed so that the relay becomes more
sensitive. Two types of overcurrent relays are customarily used: voltage-restrained and
voltage-controlled.
a) The voltage-restrained overcurrent relay consists of a conventional inverse time-
overcurrent function and a restraining voltage function that effectively reduces the
sensitivity setting of the overcurrent function proportionally over a 4:1 range. The
relay is calibrated and rated for a range of tap settings, for example, 0.5 A to 16.0 A,
with 100% of the voltage applied to the restraint coil. As the voltage is reduced, the
current required to operate the relay at a given tap setting drops. This change gives an
inﬁnite series of characteristic curves. The performance at selected values of voltage
is given as follows:
Figure 12-31—Application of system backup relay for generator
connected directly to system

IEEE
b) The voltage-controlled overcurrent relay consists of a conventional inverse time-
overcurrent function and a high-speed voltage function. The voltage function controls
when the overcurrent function senses current. The high-speed voltage function is
adjustable over a range of 40% to 100% of rated voltage depending upon
manufacturer. When the applied voltage is above the pickup setting, its contacts
connected in the circuit of the overcurrent function are open; and no operating output
(i.e., torque) is produced regardless of current magnitude. When the applied voltage
falls below the dropout value, the contacts in the overcurrent function circuit close.
This event enables the relay to produce an operating output and operate as a
conventional overcurrent relay. If the current is above the tap setting, then it operates
in accordance with its inherent time-current characteristics (TCCs). A clear
distinction can thus be made between normal no-fault conditions and abnormal fault
conditions.
12.5.5.9.1.2.2 Settings
Examples of the considerations for selecting the tap and time-dial settings for both the
voltage-restrained and voltage-controlled overcurrent relays show the basic differences
between the two types. Each relay is to be applied on the 19 500 kVA generator whose decre-
ment curves have been calculated and plotted in Figure 12-9. The criteria for selecting the
relay tap setting are as follows:
a) The relay should pick up on synchronous current for 0 V to the relay (i.e., constant
excitation).
b) The relay should not pick up for moderate overloads up to 150% of generator full-
load current with 100% of voltage on the potential coil.
Example for voltage-controlled relay
The tap values of the voltage-controlled relay are based on the current ﬂowing when the volt-
age is below the dropout setting on the voltage function (potential coil). With the voltage
above the pickup setting, the relay is effectively removed from the circuit. Calculate the tap
setting so that it is less than the sustained fault current of 586 A.
Rated voltage
(V)
Percent of pickup,
tap setting
100 100
78 78
48 48
25 25
0 25

IEEE
Select a 2 A tap.
The relay operates because the sustained fault current is 1.22 multiples of relay pickup, as
illustrated in Figure 12-32. This relay should be selected to have a setting range that includes
a 2.0 setting. (Using a relay with a 1.5 A tap could be selected for even greater sensitivity,
that is, 1.63 multiples.)
Example for voltage-restrained relay
Because the current tap values are based on normal operating conditions, that is, 100% of
restraint voltage applied, calculate the tap setting to be equal to or greater than 150% of full-
load current.
I fault
IFLA
Xd
---------
-
903
1.54
---------
- 586 A
= = =
tap value
I fault
CT ratio
-------------------
-
586
1200 5
÷
--------------------
- 2.44 A
= = =
Figure 12-32—Voltage-controlled relay, 19 500 kVA generator,
fault-current decrement curves with backup overcurrent relays
tap value IFL
1.5
CT ratio
-------------------
-
×
903 1.5
×
1200 5
÷
---------------------- 5.6 A
= = =

IEEE
Select a 6 A tap (i.e., 159% of full-load current).
Verify that the relay will operate at 0 V. At 0 V, the relay sensitivity is reduced to 25% so
From the decrement curve in Figure 12-33, it is determined that the relay picks up because
the sustained fault current is 586 A, or 1.63 multiples of pickup. The relay should be selected
to have a range that includes a 6 tap setting.
12.5.5.9.1.2.3 Conclusion
Two observations can be made from the selection process demonstrated in 12.5.5.9.1.2.2.
First, the type of relay selected makes a signiﬁcant difference in the proper choice of tap
range. Second, with the tap set as described, from the inception of the fault, the current in the
relay will always be above its pickup value; thus, the relay contacts will ultimately close.
If applied properly, the overcurrent pickup level in both types of relays is below the
generator-fault current level as determined by synchronous reactance.
Ipickup 6 0.25
1200
5
-----------
-
×
× 360 A
= =
Figure 12-33—Voltage-restrained relay, 19 500 kVA generator,
fault-current decrement curves with backup overcurrent relays

IEEE
To provide system phase-fault backup, three voltage-restrained or voltage-controlled time-
overcurrent relays are connected to receive currents and voltages in the same manner as the
distance relays illustrated in Figure 12-30 and Figure 12-31.
12.5.5.9.2 System ground-fault backup
Ground-fault backup can be provided with a simple time-overcurrent relay having an inverse-
time or very inverse-time characteristic. When the generator is connected in a unit generator-
transformer arrangement, the ground backup relay is connected to a CT in the neutral of the
step-up transformer as shown in Figure 12-30.
When the generator is connected directly to a system, the ground backup relay is connected
to a CT in the generator neutral as shown in Figure 12-31.
12.5.5.9.3 Settings
Ideally, the phase- and ground-fault backup relays are set to detect and operate for uncleared
bus and transmission-line faults outside of the generator zone. Where VT static exciters are
used, the generator-fault current can decay quite rapidly when voltage is low at the generator
terminals due to a fault. As a consequence, the overcurrent phase-fault backup relay with
long time delays may not operate for system faults. Therefore, the performance of these
relays should be checked with the fault-current decrement curve for a particular generator
and VT static excitation system. Both the phase and ground backup relays should be time-
coordinated with the protection on all system elements outside of the generator zone to
ensure proper selectivity; however, this step may not always be possible.
12.5.5.9.4 Tripping
Two tripping modes commonly used with the system backup protection are as follows:
a) The system backup relays are connected to energize a hand-reset lockout relay, which
trips the main generator breakers, the ﬁeld and/or the exciter breakers, and the prime
mover. See the caution in 12.5.5.1.4.
b) The system backup relays are connected in a two-step tripping mode.
1) First-time step: Trip only the main generator breakers. (When tripping in this
mode, dangerous generator overspeed may result.) The generator must be capa-
ble of full load rejection.
2) Second-time step: Energize a hand-reset lockout relay, which initiates machine
shutdown.
12.5.5.10 Generator breaker failure protection
A functional diagram of a typical generator zone breaker failure scheme is shown in
Figure 12-34. Like all such schemes, when the protective relays detect an internal fault or an
abnormal operating condition, they attempt to trip the generator and at the same time initiate
the breaker-failure timer.

IEEE
If a breaker does not clear the fault or abnormal condition in a specified time, the timer trips
the necessary breakers to remove the generator from the system. As shown in Figure 12-34,
to initiate the breaker-failure timer, a protective relay must operate and a current detector or a
breaker “a” switch. The breaker “a” switch must be used in this case because the faults and/or
abnormal operating conditions (e.g., stator or bus ground faults, overvoltage-to-frequency
excitation, excessive negative sequence, excessive underfrequency, reverse power flow) may
not produce sufficient current to operate the current detectors.
Breaker-failure schemes are connected to energize a hand-reset lockout relay, which will trip
the necessary backup breakers.
12.5.5.11 VTs
Two possible areas of concern exist with the VT used in the generator zone:
— Blown fuses (loss of VT signal)
— Ferroresonance
12.5.5.11.1 Blown fuses
A common practice is to use two or more sets of VTs in the generator zone. These VTs, con-
nected grounded-wye-grounded-wye, normally have secondary and possibly primary fuses
and are used to provide potential to a number of protective relays and the voltage regulator. If
one or more of the fuses blow in the VT circuits, the secondary voltages applied to the relays
and voltage regulator are reduced in magnitude and shifted in phase angle. This change in
voltage can cause both the relays (e.g., Device 21, Device 32, Device 40, Device 46,
Device 51V) to misoperate and the regulator to overexcite the generator.
To eliminate the possibility of such misoperations, a common practice is to apply a voltage-
balance relay, which compares the three-phase secondary voltages of two sets of VTs as
shown in Figure 12-35. When the two sets of VTs have output voltage alike, the relay is
Figure 12-34—Functional diagram of a generator zone breaker failure
scheme

IEEE
balanced; and both the right and left contacts are open. If the fuses blow in one set of VTs, the
resulting unbalance causes the relay to operate. When a fuse opens in any phase of one set of
VTs, the unbalance causes its associated contact to close. When a fuse opens in the second set
of VTs, its associated contacts close. The relay is connected to alarm, remove the voltage
regulator from service, and block possible incorrect tripping by protective relays whose
performance may be affected by the change in potential. The voltage-balance relay should be
set as sensitive as possible because corrosion or poor contact of VT stabs could result in a
voltage drop in the circuit significant enough for regulator runaway (i.e., overexcitation), but
too small for detection by the relay.
When two sets of VTs on the generator circuit cannot be justified, the bus potential trans-
formers may be used as the second set so long as dead bus startup of the generator is not
necessary.
12.5.5.11.2 VT ferroresonance
Ferroresonance can occur when grounded VTs are connected to an ungrounded system.
Under this condition, the voltage appearing on one or more VTs could be distorted 60 Hz or
subharmonic voltages, and the VTs could be operating overexcitedly well in the saturated
region. The VT exciting currents would be high; and if permitted to operate in this condition,
the VTs would fail thermally in a relatively short time.
The possibility of VT ferroresonance can be minimized by using line-to-line rated VTs con-
nected line to ground. This setup, however, does not eliminate the problem. To completely
suppress ferroresonance, applying resistance loading across each phase of the secondary
winding is necessary. Resistance loading equal to the rated thermal capability of the VT may
be required to suppress ferroresonance. This resistance loading should be applied to the VT
secondaries when the VT is to be operated on an ungrounded system. This load would be
removed when the generator is connected and the system grounding reestablished.
12.5.5.12 Protection during startup or shutdown
During startup or shutdown of a generator, the unit may be operated at reduced and/or
decreasing frequency with field applied for a period of time. When operating frequency
Figure 12-35—Application of voltage-balance relay

IEEE
decreases below rated, the sensitivity of some of the generator zone protective relays may be
adversely affected. The sensitivity of a few relays may be only slightly reduced while other
relays may not provide adequate protection or become inoperative. Figure 12-36 shows the
effects of frequency on the pickup of electromechanical relays, which may be used in the
generator zone. Some relays lose sensitivity rapidly below 60 Hz. Induction disk current
relays could provide adequate protection down to 20 Hz while plunger relays are not
adversely affected by off-frequency operation. Static relays have various frequency response
characteristics. The speciﬁc effect of off-frequency operation should be checked with the
manufacturer.
Supplementary protection during startup or shutdown of a generator can be provided through
the use of protective relays whose pickup is not affected by frequency, such as instantaneous
overcurrent or plunger voltage relays. In general, this protection would be placed in service
only when the generator is disconnected from the system. A cut-off contact may be required
to remove the relay from service to avoid exceeding the thermal rating of the relay.
Figure 12-36—Relay pickup versus frequency

IEEE
When generators are bused at their terminals, supplemental ground protection could be pro-
vided by using a sensitive instantaneous overcurrent relay in series with the time-overcurrent
relay normally used for protection. These relays are connected to CTs located on the neutral
end of the machine phase winding.
Supplemental phase-fault protection could be provided by placing an instantaneous relay in
the CT phase leads. The current coils of both the phase and ground instantaneous overcurrent
relays need to be short circuited when the machine is connected to the system if both relays
could be picked up continuously.
For a unit generator-transformer arrangement, supplementary ground-fault protection can be
provided by using a plunger voltage relay connected in parallel with the normal ground
overvoltage protection. Relays with a pickup range of below 10 V would be desirable for this
purpose. Supplementary phase-fault protection can be provided by using plunger
instantaneous overcurrent relays placed in series with the operate circuits of the transformer
differential relay. The instantaneous phase overcurrent relay would be set above the
difference current that flows in the differential circuit during normal 60 Hz operation to avoid
damage due to continuous operation in the picked-up position. In general, the difference
current is small, and in most instances setting the instantaneous overcurrent relay at its
minimum pickup setting is possible. The instantaneous overcurrent relay current coil is in the
differential circuit at all times and presents additional burden to the CTs. The ratio error of
the CTs should be checked to ensure proper transformer differential relay operation.
The supplementary protection for both types of generator arrangements is usually deactivated
when the units are connected to the system. This deactivation can be accomplished by open-
ing the trip circuits with a breaker “b” switch, directional or voltage-sensing relay, or an
underfrequency relay.
12.5.5.13 Inadvertent energizing
Inadvertent or accidental energizing of off-line generators has occurred often enough to war-
rant installation of dedicated protection to detect this condition. A number of generators have
been damaged or completely destroyed due to inadvertent energization. Operating errors,
breaker head flashovers, control circuit malfunctions, or a combination of these events have
caused generators to be accidentally energized while off line. This subclause discusses the
problem of inadvertent generator energization, the limitations of conventional generator pro-
tection to detect this condition, and the use of dedicated inadvertent energizing protection
schemes.
When a generator on turning gear is energized from the power system, it accelerates like an
induction motor. The generator terminal voltage and the current are a function of the genera-
tor, transformer, and system impedances. Depending on the system, this current can be as
high as 3 per unit to 5 per unit and as low as 1 per unit to 2 per unit of the machine rating.
While the machine is accelerating, high currents induced into the rotor can cause significant
damage in only a matter of seconds.

IEEE
12.5.5.13.1 Normally available relays
The normal relay complement for generator protection has serious limitations when trying to
detect inadvertent energizing. Speciﬁcally, the following relays cannot be relied on to protect
the generator for all inadvertent energizing conditions:
— Loss-of-excitation relays
— Reverse-power relays
— System backup relays
— Negative-sequence relays
12.5.5.13.2 Dedicated protection schemes
Unlike conventional schemes, which provide protection when the generator is on line, dedi-
cated protection schemes are designed to protect the generator when it is off line. Great care
is required to ensure that dc tripping power and input quantities are not removed when the
generator is off line. Consideration should be given to locating this protection where it is less
likely to be disabled during generator maintenance.
Relays that are voltage dependent are disabled if the standard procedure is to remove VT
fuses when the machine is off line. For reverse-power relays, with the potential applied, a
voltage drop of 50% or more usually renders them inoperative. Relays with intentional time
delay for coordination are too slow to provide any substantial protection for inadvertent
energization.
When assessing whether a relay provides adequate protection, determining its status when
the generator is off line is necessary. Numerous cases have been reported where all of the
generator protection was inoperative when the machine was accidentally energized.
Common schemes used to detect inadvertent energizing are
— Directional overcurrent relays
— Frequency-supervised overcurrent
— Distance relay scheme
— Voltage-supervised overcurrent
— Auxiliary contacts scheme with overcurrent relays
For information on the application of these relays for inadvertent energization protection, see
IEEE Std C37.102-1993.
12.5.5.13.3 Summary recommendations
Inadvertent energization protection was added to alert protection engineers to the real and
devastating consequences of inadvertently energizing a generator. Conventional generator
protection schemes are typically insensitive or so slow to operate that they do not prevent the
generator and prime mover from being damaged. Therefore, it is recommended that some
form of dedicated inadvertent energizing scheme be used as part of an overall generator

IEEE
protection package. This scheme should be isolated so that there is good assurance that it will
not be disabled during plant shutdown or maintenance.
12.5.5.14 Transmission-line reclosing near generating stations
Switching operations involving the opening and closing of circuit breakers at or near a
generating station can produce transient power and current oscillations, which can stress or
damage turbine generators. Of particular concern are the switching operations that produce
torsional oscillations and shaft torques, which may cause major shaft fatigue damage in one
or relatively few incidents of severe switching disturbances. The switching disturbances of
primary concern are
— Steady-state switching of lines
— High-speed reclosing of circuit breakers following transmission-line faults
12.5.5.14.1 Steady-state switching of lines
The switching of lines near a generating station for maintenance can produce a step change in
power, which can result in transient mechanical forces on both the rotating and stationary
components of a turbine generator. This sudden change in power is a function of the
switching angle across an open circuit breaker and the system impedance. If this change in
power exceeds 0.5 per unit, the turbine-generator manufacturer should be consulted in order
to determine whether potential exists for signiﬁcant damage.
12.5.5.14.2 High-speed reclosing following system faults
High-speed reclosing of transmission lines at or near a generating station following a fault
has the potential for causing major shaft fatigue damage to a turbine generator. Of particular
concern is the possibility of an unsuccessful reclosure into a persistent fault, which may
reinforce the torsional oscillations and shaft torques caused by the original disturbance and
thereby cause a signiﬁcant loss in fatigue life of turbine-generator shafts.
In order to minimize the potential detrimental effects of high-speed reclosing of transmission
lines near generating stations, alternative reclosing practices should be investigated as a
means for reducing fatigue duty.
12.5.5.15 Synchronizing
Improper synchronizing of a generator to a system can result in damage to any type of
generating unit. The damage incurred can be slipped couplings, increased shaft vibration, a
change in bearing alignment, loosened stator windings, loosened stator laminations, and
fatigue damage to shafts and other mechanical parts.
In order to avoid damaging a generator during synchronizing, the generator manufacturer
generally provides synchronizing limits in terms of breaker-closing angle and voltage
matching. Typical limits include the following:

IEEE
a) Breaker-closing angle: within 10 electrical degrees. The closing of the circuit
breaker should ideally take place when the generator and the grid are at 0° phase
angle with respect to each other. To achieve this result, the breaker must be closed
enough in advance of the point of phase-angle coincidence to account for the breaker-
closing time. This is mathematically expressed as
where
A is the advance angle (°),
FS is the slip frequency (Hz),
TS is the breaker closing time (s).
b) Voltage matching: 0% to +5%. The voltage difference should be minimized and not
exceed 5%. This limit aids in maintaining system stability by ensuring some var ﬂow
into the system. Additionally, if the generator voltage is excessively lower than the
grid when the breaker is closed, sensitively set reverse-power relays may trip.
c) Frequency difference: less than 0.067 Hz. The frequency difference should be
minimized to the practical control and response limitations of the given prime mover.
A large frequency difference causes rapid load pickup or excessive motoring of the
machine. This effect manifests itself both as power swings on the system and as
mechanical torques on the machine. Additionally, if the machine is motored,
sensitively set reverse-power relays may trip.
Slip frequency limits applied for certain machine types are based on the ruggedness of the
turbine generator under consideration and the controllability of the turbine generator.
The synchronizing approaches used to minimize the possibility of damaging a generator
include
— Automatic synchronizing
— Semiautomatic synchronizing
— Manual synchronizing
12.5.5.15.1 Automatic synchronizing

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