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IEEE 3004 STANDARDS:

PROTECTION & COORDINATION

IEEE Std 3004.11-2019

Recommended Practice
for Bus and Switchgear
Protection in Industrial and
Commercial Power Systems

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IEEE Std 3004.11-2019

IEEE Recommended Practice

for Bus and Switchgear
Protection in Industrial and
Commercial Power Systems
Developed by the

Industrial and Commercial Power Systems Standards Development Committee

of the
IEEE Industry Applications Society

Approved 5 September 2019

IEEE SA Standards Board

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Abstract: Covered in this recommended practice is the protection of bus and switchgear used in
industrial and commercial power systems. Also provided are fault protection and isolation strategies
for the substation bus and switchgear, including the bus, circuit breakers, fuses, disconnecting
devices, transformers, and the structures on which they are mounted.

Keywords: arc flash, arc flash protection, differential protection, double-ended substation, high
impedance bus differential relay, IEEE 3004.11™, percentage differential relay, tie circuit breaker

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PDF: ISBN 978-1-5044-6124-5 STD23863

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Participants

At the time this IEEE recommended practice was completed, the Power System Protection Working Group
had the following membership:

Rasheek Rifaat, Chair

Donald McCullough II, Vice Chair
Marcelo E. Valdes, 3004.11 Project Chair

Paul Cardinal Richard Hunt Suparat Pavavicharn

Tom Dionise John Kay Daniel Ransom
Neal Dowling Claudio Mardegan Saleh Saleh
Nehad El-Sherif Lorraine Padden Dave Scheuerman
Gary Fox Dev Paul Terrence Smith
Robert Hoerauf Ilia Voloh

The following members of the individual balloting committee voted on this recommended practice. Balloters
may have voted for approval, disapproval, or abstention.

Ali Al Awazi Rostyslaw Fostiak Saumen Kundu

Mohammed Ashraf Ali Gary Fox Mikhail Lagoda
Saleman Alibhay Carl Fredericks James Lagree
Robert Arno Dale Fredrickson Chung-Yiu Lam
Curtis Ashton David Gilmer Ed Larsen
Radoslav Barac Paul Gingrich Wei-Jen Lee
Frank Basciano Mietek Glinkowski Duane Leschert
Michael Basler Jalal Gohari Steven Liggio
Philip Beaumont Lou Grahor William Lockley
Thomas Beckwith Stephen Grier Hugo Marroquin
W. J. (Bill) Bergman Randall Groves Omar Mazzoni
Martin Best Paul Guidry John Mcalhaney Jr.
Frederick Brockhurst Paul Hamer Daleep Mohla
Chris Brooks Thomas Hawkins Charles Morse
Gustavo Brunello Jeffrey Helzer Darryl Moser
Demetrio Bucaneg Jr. Charles Henville Jerry Murphy
William Byrd Chris Heron R. Murphy
Thomas Callsen Lee Herron Alexandre Nassif
Paul Cardinal Erling Hesla Warren Naylor
Kyle Carr Werner Hoelzl Daniel Neeser
Sean Carr Robert Hoerauf Dennis Neitzel
Nancy Chilton Richard Hunt John Nelson
Michael Chirico Christel Hunter Arthur Neubauer
Kurt Clemente William Hurst Michael Newman
Daryld Crow Noriyuki Ikeuchi Joe Nims
Ratan Das Gerald Irvine T. W. Olsen
Glenn Davis Richard Jackson Lorraine Padden
Matthew Davis Laszlo Kadar Sergio Panetta
Davide DeLuca John Kay Antony Parsons
Daniel Doan Chad Kennedy Bansi Patel
Thomas Domitrovich Sheldon Kennedy Shawn Patterson
Gary Donner Yuri Khersonsky Dev Paul
Michael Dood James Kinney Branimir Petosic
Neal Dowling Hermann Koch Iulian Profir
Donald Dunn Boris Kogan Roises Ramos
Marcia Eblen Edwin Kramer Samala Santosh Reddy
Keith Flowers Jim Kulchisky Timothy Robirds
H. Landis Floyd Paneendra Kumar Charles Rogers

6
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Thomas Rozek Michael Simon James Van De Ligt
Ryandi Ryandi Jeremy Smith Benton Vandiver
Daniel Sabin Jerry Smith Gerald Vaughn
Hugo R. S. Reategui Gary Smullin John Vergis
Chester Sandberg Wayne Stec John Wang
Steven Sano Bill Stewart Daniel Ward
Vincent Saporita Gary Stoedter Keith Waters
Todd Sauve Peter Sutherland John Webb
Bartien Sayogo C. Taylor Kenneth White
Thomas Schossig David Tepen Iain Wright
Robert Schuerger Michael Thompson Dean Yager
Robert Seitz Wayne Timm Jian Yu
Nikunj Shah David Tucker Luis Zambrano
Vinod Simha Marcelo E. Valdes Gaetano Zizzo

When the IEEE-SA Standards Board approved this recommended practice on 5 September 2019, it had the
following membership:

Gary Hoffman, Chair

Ted Burse, Vice Chair
Jean-Philippe Faure, Past Chair
Konstantinos Karachalios, Secretary

Masayuki Ariyoshi David J. Law Annette D. Reilly

Stephen D. Dukes Joseph Levy Dorothy Stanley
J. Travis Griffith Howard Li Sha Wei
Guido Hiertz Xiaohui Liu Phil Wennblom
Christel Hunter Kevin Lu Philip Winston
Joseph L. Koepfinger* Daleep Mohla Howard Wolfman
Thomas Koshy Andrew Myles Feng Wu
John D. Kulick Jingyi Zhou

*Member Emeritus

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Introduction

This introduction is not part of IEEE Std 3004.11-2019, IEEE Recommended Practice for Bus and Switchgear Protection
in Industrial and Commercial Power Systems.

IEEE 3000 Series®

This recommended practice was developed by the Industrial and Commercial Power Systems Standards
Development Committee of the IEEE Industry Applications Society as part of a project to repackage IEEE’s
popular series of “color books.” The goal of this project is to speed up the revision process, eliminate duplicate
material, and facilitate use of modern publishing and distribution technologies.

When this project is completed, the technical material included in the 13 “color books” will be included in
a series of new standards. Approximately 60 “dot” standards, organized into the following categories, will
provide in-depth treatment of many of the topics formerly covered in the color books:

— Power Systems Design (3001 series)

— Power Systems Analysis (3002 series)
— Power Systems Grounding and Bonding (3003 series)
— Protection and Coordination (3004 series)
— Emergency, Stand-By Power, and Energy Management Systems (3005 series)
— Power Systems Reliability (3006 series)
— Power Systems Maintenance, Operations, and Safety (3007 series)

In many cases, the material in a “dot” standard comes from a particular chapter of a particular color book. In
other cases, material from several color books has been combined into a new “dot” standard. The material in
this recommended practice replaces Chapter 13 of IEEE Std 242-2001, (IEEE Buff Book™).

IEEE Std 3004.11™

This publication provides a recommended practice for the electrical design of commercial and industrial
facilities. It is likely to be of greatest value to the power-oriented engineer with limited commercial or industrial
plant experience. It can also be an aid to all engineers responsible for the electrical design of commercial and
industrial facilities. However, it is not intended as a replacement for the many excellent engineering texts and
handbooks commonly in use, nor is it detailed enough to be a design manual. It should be considered a guide
and general reference on electrical design for commercial and industrial facilities.

Tables, charts, and other information that have been extracted from codes, standards, and other technical
literature are included in this publication. Their inclusion is for illustrative purposes; where technical accuracy
is important, the latest version of the referenced document should be consulted to assure use of complete, up-
to-date, and accurate information.

8
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Contents

1. Scope�� 11
1.1 General discussion�� 11
1.2 Word usage�� 14

2. Normative references�� 14

3. Definitions�� 15

4. Types of buses and arrangements�� 16

4.1 Construction types�� 16
4.2 Voltage ranges�� 17

5. Zones of protection�� 17
5.1 Double-ended substations with two tie CB in series�� 20

6. The need for fast bus protection�� 25

7. Bus overcurrent protection�� 26

7.1 General discussion�� 26
7.2 Low-voltage (LV) bus ground-fault protection for solidly grounded systems�� 28
7.3 Ground-fault protection on LV ungrounded or impedance grounded buses�� 30
7.4 Medium-voltage (MV) and high-voltage (HV) bus ground-fault protection�� 31

8. Zone-selective interlocking and blocking techniques�� 31

8.1 General discussion�� 31
8.2 Coordination studies and delay settings in ZSI schemes�� 32
8.3 In-zone, unrestrained-protection and restrained backup-protection�� 33
8.4 ZSI schemes and protection algorithms�� 34
8.5 ZSI signal timing and creation of custom blocking schemes�� 35
8.6 Circuit breaker failure schemes as backup bus protection�� 36

9. Differential protection�� 37
9.1 Bus differential basics�� 37
9.2 High-impedance bus-differential relays�� 42
9.3 Low-impedance bus-differential relays�� 44
9.4 Modern differential-protection alternatives�� 46

10. Partial-differential protection�� 48

11. Backup protection�� 49

12. Protecting the secondary terminals and connected bus on a step-down substation transformer�� 50
12.1 General discussion�� 50
12.2 Low-voltage (LV) bus protection using primary-side protective devices�� 50
12.3 Selection of transformer primary fuses for arc-flash protection on the transformer secondary bus�� 51
12.4 Zone-selective interlocking across a substation transformer�� 51

13. Low-voltage bus conductors, switchgear, switchboard, and motor control-center protection�� 53

14. Special considerations for arc-flash hazard reduction�� 54

15. Arc quenching devices (AQDs)�� 55

16. Arc-flash relays�� 56

9
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17. Triggered current limiters (TCLs)�� 57

18. Voltage-surge protection�� 57

19. Conclusions�� 57

Annex A (informative) Bibliography�� 59

10
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IEEE Recommended Practice
for Bus and Switchgear
Protection in Industrial and
Commercial Power Systems

1. Scope
This recommended practice covers the protection of bus and switchgear used in industrial and commercial
power systems. It provides fault protection and isolation strategies for the substation bus and switchgear,
including the bus, circuit breakers, fuses, disconnecting devices, transformers, and the structures on which
they are mounted.

1.1 General discussion

Switchboards and switchgear are the parts of the power system used to direct the flow of power to various
feeders or branches and to isolate apparatus and individual circuits from the power system sources. These
parts include the bus bars, circuit breakers, fuses, disconnection devices, current transformers (CTs), voltage
transformers (VTs), instrumentation, and the structure on or in which these are mounted. The term bus usually
refers to the principal conductive components within an assembly of equipment such as medium-voltage (MV)
metal-enclosed switchgear, MV control, low-voltage (LV) switchgear, power switchboards, panelboards,
motor control centers (MCCs) and bus duct, a.k.a. busway (see IEEE Std 3001.5™ for information concerning
the application of this equipment). Electrically a bus may be defined as any conductor with one or more sources
and two or more connected loads with independent switching and protective devices. From the perspective of
arc-flash hazard analysis, the line-side bus of a main device is often considered as part of the main equipment
bus. To reduce the arc-flash incident energy, protection of line-side conductors must also be considered, even
if they are protected by a device on the primary of a transformer.

Several factors have contributed to increasing interest in the improving protection of buses in industrial and
commercial power distribution systems. These include:

— Increased short-circuit levels;

— Increased use of in-plant generators and distributed generation increasing the requirement for fast fault
clearing, which is needed to maintain generator stability and to allow coordination between generator
protection and load-side feeder protection;
— Increased need for reliability;
— Increased use of bus transfer schemes;

11
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IEEE Std 3004.11-2019
IEEE Recommended Practice for Bus and Switchgear Protection in Industrial and Commercial Power Systems

— Availability of more powerful, microprocessor-based protective relays, and circuit breaker with direct
trip units, allowing the application of improved protection to complicated bus configurations;
— Availability of high relaying accuracy current transformers (CTs), airgap CTs, air-core sensors
(Rogowski coils) and optical current sensors, which have better performance with high fault currents
or have immunity to saturation not easily available with traditional iron core current transformers;
— Increased understanding of, and interest in, mitigating the arc-flash hazard.

To isolate bus faults, all power source circuits connected to the bus must be acted on by one or more of the
following:

— Opened electrically by circuit breakers responding to protective-relay action;

— Direct-acting trip units on LV circuit breakers and available in some MV circuit breakers as well;
— Fuses;
— Active current limitation devices for limiting fault current consisting of conductors that are kinetically
opened to shunt current to a current limiting fuse.

These disconnection devices shut down all loads and associated processes supplied by the bus and might affect
other parts of the power system.

Many existing high-voltage (HV) substations are outdoor air-insulated structures enclosed by a fence where
the limit of approach for a bus is established mainly via clearances. In many industrial and commercial power
systems, power distribution is implemented at LV (1 kV or less) or MV (1001 V to 38 kV). MV equipment
standards define MV class equipment up to a 52 kV utilization category which harmonizes IEEE equipment
standards with the corresponding IEC standards. The type of equipment selected can have a great effect on the
reliability, maintainability, and ease of implementation of a power system as well as the ease of implementing
the required safety practices. For various applications, designers may select enclosures for buses that include,
but are not limited to:

— Panelboards (UL 67 [B35]),

— Switchboards (UL 891 [B38]),
— LV motor control centers (UL 845, [B37]),
— LV power circuit breaker switchgear (UL 1558 / IEEE Std C37.20.1™),
— Metal enclosed switchgear (IEEE Std C37.20.3™), or
— Metal clad switchgear (IEEE Std C37.20.2™).

Among the various selections, the designer will find that the standards define different tests that might indicate
that one type of equipment might be more suitable for a specific application than another as the tradeoffs between
costs, physical size, maintenance needs, operational complexity, location, and reliability are considered.
Equipment might vary with respect to the degree of bus insulation or isolation, compartmentalization, and
other characteristics that impact bus reliability, safety, maintainability, or other factors.

To further reduce the occurrence of faults, the bus and associated equipment should be installed in a location
where these are least subjected to extreme environmental conditions. Equipment standards such as the
IEEE C37 family of standards and UL standards will define “standard conditions” and “special conditions”
(IEEE Std C37.100.1™) for equipment environments. Whenever possible, equipment should be applied at
standard conditions to optimize reliability and maintainability of equipment.

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A preventive-maintenance program is essential to detect deterioration, to make repairs, and to check and test
relays, trip units, control systems, and circuit breaker performance before a fault occurs (see IEEE Std 3007.2™
[B16]). The dielectric properties of insulating materials can deteriorate over time, particularly if the equipment
is subject to greater-than-standard temperatures or transient overvoltage conditions. Moving mechanical parts
can become difficult to move because of a loss of lubricity in lubricants and bonds formed at joints, and
electronic capacitors can lose capacitance over time. Proper maintenance is an integral part of equipment
protection, safety, and optimization of capital investments. Proper implementation of safety practices such
as those described in NFPA 70E, require that maintenance of electrical equipment be properly conducted
following manufacturers’ instructions or generally accepted industry practices.

Modern protective relays, trip units, and control systems can measure, monitor, and calculate parameters
important to implement condition-based maintenance. Modern electronic devices with appropriate
communications capabilities can monitor each other as well as implement system-wide protection functions
to facilitate system-wide maintenance and protection. In addition to proper maintenance, consideration should
be given to including instrumentation and sensing devices or functions useful to diagnose power-system and
equipment problems that might occur over the life of the equipment. Powerful multifunction digital meters,
relays, and trip units are economical now. The ability to implement advanced digital communications within
modern controls and protection devices allows remote control of equipment for greater safety and flexibility.
Remote diagnostic capability allows experts located in remote locations to troubleshoot problems at the
equipment regardless of physical location.

Regardless of the steps taken to avoid bus faults, such faults occasionally occur. High-speed protective
relaying, direct acting protection (integral trip units), or appropriately rated fuses should be used to minimize
fault duration. Rapid clearing times limit damage, minimize arc-flash energy, and mitigate the effects of short
circuits on other parts of the power system. Providing proper bus protection requires a well-designed system.
Each equipment assembly should be provided with a main protective device for each power source, either as
an integral part of the assembly, or in a remote location, protecting the incoming line. In some cases, it might
be advisable to install the main device in a dedicated and separate section to manually isolate the line-side bus
from the source if adequate protection of the line-side bus cannot be obtained to sufficiently reduce arc-flash
incident-energy values. If the main protective device is omitted in an assembly and provided by a remote
line side overcurrent device, the installation may be acceptable if the device provides appropriate protection;
however, the lack of a local disconnect may not be optimal for maintenance purposes. The main circuit breaker
sometimes is omitted at the secondary of a power transformer when the secondary feeder breakers have ratings
that adequately protect the transformer from overloading. This topology might reduce the effectiveness of
secondary bus protection because the transformer reduces the sensitivity of the primary protection for
secondary faults unless specific protection schemes are put in place to properly deal with the situation, like
transformer differential that includes the secondary side bus within its zone of protection.

When power systems are grounded through a resistance or reactance to limit fault damage, the short-circuit
current available to detect a ground fault is smaller and requires more sensitive protective relaying. A delta-wye
transformer connection reflects a secondary ground fault current through two primary phase windings. The
reduced value of current at the primary makes secondary ground fault currents in solidly grounded secondary
transformers more difficult to detect. When the secondary of the transformer is impedance grounded, a
secondary side ground fault may be indistinguishable from load for relays on the primary side and, hence,
providing secondary side sensitive ground-fault relaying is important to initiate the opening of all sources that
can feed the fault (see IEEE Std 242™-2001 (IEEE Buff Book™), Chapter 8 [B12]).1

When supplementary bus-differential protective relaying, zone-selective-interlocking (ZSI), or any other

method is used to isolate bus faults, it is essential that the method operate only for bus and switchgear faults.
False tripping on external faults is, generally, unacceptable.

1
It should be noted that at the time of the writing of this standard, the IEEE Color Books are in the process of being replaced by the
IEEE 3000 Series of standards. Hence a reference to a Color Book now may be better replaced by a reference to the appropriate
IEEE 3000 Series dot standards by the reader when this standard is read. For a guide to the published IEEE 3000 Series dot standards,
consult the IEEE published standards catalog.

13
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1.2 Word usage

The word shall indicates mandatory requirements strictly to be followed in order to conform to the standard
and from which no deviation is permitted (shall equals is required to).2,3

The word should indicates that among several possibilities one is recommended as particularly suitable,
without mentioning or excluding others; or that a certain course of action is preferred but not necessarily
required (should equals is recommended that).

The word may is used to indicate a course of action permissible within the limits of the standard (may equals
is permitted to).

The word can is used for statements of possibility and capability, whether material, physical, or causal (can
equals is able to).

2. Normative references
The following referenced documents are indispensable for the application of this document (i.e., these must
be understood and used, so each referenced document is cited in text and its relationship to this document is
explained). For dated references, only the edition cited applies. For undated references, the latest edition of the
referenced document (including any amendments or corrigenda) applies.

CSA C22.1, Canadian Electrical Code.4

CSA Z462, Canadian Workplace Electrical Safety Standard.

IEEE Std 3001.5™, IEEE Recommended Practice for the Application of Power Distribution Apparatus in
Industrial and Commercial Power Systems.5

IEEE Std 3004.1™, IEEE Recommended Practice for the Application of Instrument Transformers in Industrial
and Commercial Power Systems.

IEEE Std 3004.5™, IEEE Recommended Practice for the Application of Low-Voltage Circuit Breakers in
Industrial and Commercial Power Systems.

IEEE Std C37.2™, IEEE Standard Electrical Power System Device Function Numbers, Acronyms, and
Contact Designations.6

IEEE Std C37.20.1™, IEEE Standard for Metal-Enclosed Low-Voltage (1000 Vac and below, 3200 Vdc and
below) Power Circuit Breaker Switchgear.

IEEE Std C37.20.2™, IEEE Standard for Metal-Clad Switchgear.

IEEE Std C37.20.3™, IEEE Standard for Metal-Enclosed Interrupter Switchgear.

2
The use of the word must is deprecated and shall not be used when stating mandatory requirements, must is used only to describe
unavoidable situations.
3
The use of will is deprecated and shall not be used when stating mandatory requirements, will is only used in statements of fact.
4
CSA standards may be obtained from the Canadian Standards Association, http://www.csagroup.org/ In this document the CEC is
equivalent to NFPA 70 for Canada and Z462 is equivalent to NFPA 70E for Canada.
5
IEEE publications are available from The Institute of Electrical and Electronics Engineers, 445 Hoes Lane, Piscataway, NJ 08854, USA
(http://standards.ieee.org/).
6
ANSI device numbers are used throughout this document to represent protective relays and control elements used in electrical power
system diagrams. Some of the ones used in this document are: 50-Instantaneous Overcurrent Relay, 51-Time-Overcurrent Relay,
52-Circuit Breaker, 86-Lockout Relay and 87-Differential Relay. Letters that follow the numbers such as B for bus, N for neutral, T for
transformer and G for ground further identify the purpose of the device. IEEE Std C37.2 standardizes this nomenclature.

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Copyright © 2019 IEEE. All rights reserved.

IEEE Std C37.20.7™, IEEE Guide for Testing Metal-Enclosed Switchgear Rated Up to 52 kV for Internal
Arcing Faults.

IEEE Std C37.100.1™, IEEE Standard of Common Requirements for High Voltage Power Switchgear Rated
Above 1000 V.

IEEE Std C37.110™, IEEE Guide for the Application of Current Transformers Used for Protective Relaying
Purposes.

IEEE Std C62.22™, IEEE Guide for the Application of Metal-Oxide Surge Arresters for Alternating-Current
Systems.

IEEE Std 1584™, IEEE Guide for Performing Arc-Flash Hazard Calculations.

NFPA 70, National Electrical Code® (NEC®).7

NFPA 70E, Standard for Electrical Safety in the Workplace.

UL 1053, Ground-Fault Sensing and Relaying Equipment.8

3. Definitions
For the purposes of this document, the following terms and definitions apply. The IEEE Standards Dictionary
Online should be consulted for terms not defined in this clause.9

air core sensors: Also known as Rogowski coils. Specially designed air-core mutual inductor whose output
voltage is proportional to the time-rate-of-change of current of the input (primary) current.

arc-flash incident energy: The amount of thermal energy impressed on a surface, a certain distance from
the source, generated during an electrical arc event. Incident energy is measured in joules or calories per
centimeter squared (J/cm2 or cal/cm2).10

bus: A portion of a switchgear, switchboard or distribution system that electrically interconnects several
circuit breakers or switches and is protected as a separate entity from other network elements. It may also
directly connect other elements such as grounding transformers, or a source transformer and the incoming
compartment of distribution equipment.

current transformers (CTs): A current transformer (CT) transforms line current into current values suitable
for standard protective relays and meters, while isolating these instruments from line voltages. A CT has two
windings, designated as primary and secondary, that are insulated from each other. (See IEEE Std 3004.1-2013.)

high-impedance differential scheme: A differential method of bus protection using CTs paralleled on a high-
impedance load (a voltage or current relay in series with a stabilizing resistor). Throughout this text the symbol
87B inside a circle is used to indicate a differential relay in drawings. (See IEEE Std C37.234-2009.)

high-voltage power distribution system: A power system with nominal voltage at or above 69 kV.

7
NFPA publications are available from Publications Sales, National Fire Protection Association, 1 Batterymarch Park, P.O. Box 9101,
Quincy, MA 02269-9101, USA (http://www.nfpa.org/).
8
UL standards are available from Global Engineering Documents, 15 Inverness Way East, Englewood, Colorado 80112, USA (http://
www.global.ihs.com/).
9
IEEE Standards Dictionary Online is available at: http://dictionary.ieee.org.
10
How to calculate potential arc-flash incident energy is described in IEEE Std 1584™. The hazard this represents and implications for
electrical safety are discussed in NFPA 70E.

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Copyright © 2019 IEEE. All rights reserved.

isolated bus (within equipment): Bus within distribution equipment where each phase conductor is separated
from other phase conductors by insulating barriers.

low-impedance differential scheme: A differential method of bus protection using CTs separately connected
to an electronic device that measures and vector sums the measured currents to determine differential restraint
and operate currents. (See IEEE Std C37.234-2009.)

NOTE—Throughout this text, the symbol 87B inside a circle is used to indicate a differential relay in drawings.

low-voltage power distribution system: A power distribution system with nominal voltage of 1 kV or less.

medium-voltage power distribution system: A power distribution system with nominal voltage between
1001 V and 69 kV, inclusive. Traditionally in North America, medium voltage was limited to 38 kV but
equipment standards have evolved to match IEC practices; hence, MV equipment standards include 52 kV
today.

zone of protection: Divisions of protection that are logical subsections of the protection system used to isolate
faulted section, i.e., generators, transformers, buses, transmission lines, distribution lines or cable circuits, and
motor circuits.

NOTE—In LV and MV systems, zones may be classified as primary or backup, differential or overcurrent. Differential
zones of protection are bounded by the sensing used in the differential protection scheme. Overcurrent zones of protections
are bounded by the overcurrent protection device at the supply side of protected zone.

zone selective interlocking (ZSI): A method used to improve the response of protective devices in the event
of a fault by allowing line-side devices to react faster to faults within their zone while maintaining selectivity
for faults that occur within the zone of the load-side device. ZSI utilizes a signal between a load-side
overcurrent protective device and a line-side protective device to indicate that the load-side device has sensed
and is reacting to an overcurrent condition. The signal is used by a line-side device to alter a corresponding
protective characteristic to a slower response to allow the load-side device to clear the fault without sacrificing
selectivity. (See IEEE Std 1683™-2014.)

4. Types of buses and arrangements

4.1 Construction types
There are two major types of bus: exposed and enclosed. Exposed bus is used almost exclusively in outdoor
substations above 1 kV. Indoor switchboards and switchgear always have enclosed bus. Bus connecting
between equipment is typically also enclosed, except in some utility vaults.

Within equipment bus protection conforms to the equipment definitions of metal-enclosed and metal-clad
type equipment construction. In metal-enclosed equipment, the bus may be exposed when the external panels
are removed. In metal-clad switchgear, the bus is protected within an interior grounded metal compartment.
Metal-clad switchgear construction is defined by IEEE Std C37.20.2. Metal-enclosed is defined by
IEEE Std C37.20.1 for equipment rated 1 kV or less and by IEEE Std C37.20.3 for equipment rated above 1
kV. UL 891 defines bus systems for switchboards rated 1000 V ac and less. Bus may also have insulation of
various types applied which may provide additional electrical protection.

When determining what is appropriate protection for a bus system, it is important to understand the level and
quality of the protection that bus receives. Metal barriers that isolate a bus from one compartment to another
can be expected to provide some level of protection from unintended contact. Insulation can be expected to
improve the dielectric reliability of the system. However, the environment, application, quality, and amount of
maintenance are also concerning, regardless of the bus housing and degree or quality of insulation.

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The equipment bus may have many different arrangements depending on the requirements for continuity of
service for the bus and essential feeders supplied from the bus. Within any one line up of equipment there
could be one or more buses. The most common arrangements are single bus radial systems with or without
main devices and double ended line ups with two sources, a tie, and with mains for each source. Other more
complex arrangements with dual ties in series or more than two sources are also possible. In the interest of
reliability, a system designer may decide to implement a system with multiple sources in multiple enclosures
with tie bus separately housed to connect the equipment where the bus associated with each source is located.
This kind of arrangement lends itself well to dual ties. When a system is divided into multiple individual line
ups of equipment with tie bus in between them, consideration should be given to the protection of the longer tie
bus which may be more exposed than a short length of tie bus within a single piece of equipment with multiple
sources. IEEE Std C37.234-2009 describes various bus schemes and associated protection zones used in MV
and HV systems. The methods of protecting substation buses and switchgear might vary depending on voltage,
arrangement of the buses, economic considerations, and other practical considerations.

4.2 Voltage ranges

North American industrial power system voltages fall into three categories:

— Greater than 52 kV
— Above 1 kV to 52 kV (in the past 38 kV instead of 52 kV was the MV to HV transition value)
— Equal to or less than 1 kV

Industrial and commercial power distribution systems may include buses at 52 kV and less. Modern large
industrial complexes, however, may include distribution, sub-transmission, or transmission substation buses
at a higher voltage level. IEEE Std C37.234 discusses power bus configurations and associated protection
schemes for HV arrangements. Also, other IEEE standards address specific configurations where necessary.
Examples of such configuration for interconnections between an industrial facility and its supply utility are
also given in numerous references (e.g., Beckmann, et al. [B3]).

5. Zones of protection
It is critical to ensure the reliability of the protection systems including:

— Dependability: The system must operate when there is a fault (identify fault location and isolate the
faulted part of the system), and
— Security and selectivity: Only the faulted power system zone is isolated, and the remainder of the
power system continues its normal operations.

Zones may have defined demarcation (e.g., transformer differential protection). Protection may be defined
as primary and back up protection as established by time-current coordination (overcurrent thresholds) or
other protection methods. Zones of protection can be identified by the sensor locations that define the zone
within which a fault might be detected, or by the controlled switching elements that can clear the fault once it
is detected. When multiple sensors are used for the various types of protection, proper location of the sensors
can ensure that blind spots are minimized. When using the same sensor for multiple functions or using sensors
located within the switching devices (such as in LV circuit breakers), it is important to understand that blind
spots might be created and these need to be assessed. If multiple sensors are used and they can be dedicated to
different protective functions and zones, then the systems designer should strive to achieve overlapping zones
of protection that eliminate blind spots. However, excessive overlap can negatively impact system reliability
as well.

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Figure 1 shows a simple radial substation with a single source. In this example, differential protection is
applied using dedicated CTs that are arranged so that the differential-protection zone and overcurrent-
protection overlap, and the entire bus is protected. Figure 2 shows the same substation bus protection, but only
one set of CTs is used. Here, there is no overlap. However, for a simple topology in medium and low voltage,
protection is provided by either scheme. In a system with networked sources, CT location can create short
spots that are outside of the faster protection zone, or that are inside multiple protection zones, and can cause
mal-operation of the protection system. For a more thorough discussion of network applications, see 5.1 of
IEEE Std C37.234-2009.

Figure 1—Simple single-source radial substation

Figure 2—Simple single-source radial substation using one set of CTs

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Figure 3—CT location reference diagram

For the purposes of this standard, protection zones related to a CT are drawn so that the CT is included in
the pertinent zone. A CT circuit may have a fault within the bus that is measured by the CT; in that case, the
measurement will contribute to detection in both differential and overcurrent zones. If the fault is such that the
CT undermeasures, it may contribute to a differential zone but may not be detected by an overcurrent zone.

Figure 4—Double-ended substation, single tie, with dedicated CTs for the two differential
zones

Figure 4 illustrates a typical design for systems with multiple sources and tie circuit breaker(s). Differential
zones should overlap so that no bus sections are left without fast differential protection.

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Copyright © 2019 IEEE. All rights reserved.

5.1 Double-ended substations with two tie CB in series

Some double-ended substations are implemented with two ties connected in series, and working together, for
various reasons. The most common reasons are:

— To isolate a tie bus or connection that is considered to have a realistic probability of failure;
— To help ensure complete isolation of the buses from each other for maintenance activities and safety.

There are multiple ways to implement differential protection in such a scheme. Two or three differential
zones may be created. The tie bus may be included in different ways depending which tie the differential
zone controls and the location of the CTs associated with the ties. Table 1 shows five ways to locate CTs
and implement bus differential protection in two-source dual-tie schemes. Selecting the method that is most
applicable to a situation will depend on:

— The location of the realistic probabilities of failure;

— The available space for CTs;
— The type of differential relay being considered;
— The level of complexity or cost that is acceptable for the application.

In these schemes, faults that occur on the main part of the load buses are well protected with proper selectivity.
However, the system reaction to faults near the tie circuit breakers or in the tie interconnection can vary with
each scheme.

In the first scheme described in Table 1 and shown in Figure 5, two differential zones are implemented. Each
bus differential relay will open both ties which means any fault sensed anywhere in the buses will separate the
sources. This is acceptable when sources are operating in parallel or when the fault is on the distant bus when
only one source is connected. However, if the fault is in the tie bus between the tie CTs (fault 3), then both
sources will be taken off line. A fault within the tie bus not located between the CTs (fault 2 and fault 4) will
cause one source to open and both ties to open, isolating the fault, but unnecessarily disconnecting one of the
main buses. Hence, if it is perceived that fault locations 2, 3, and 4 are where faults could happen, this may not
be a good scheme from a reliability perspective; however, it is a good scheme from a protection perspective.
An interlocking scheme using logic from one or both relays may be implemented to prevent operation of
the main CBs and operate only the tie circuit breakers when both differential zones sense differential faults
simultaneously, which occurs when a fault is in the overlapping zone. This may be considered if a fault in
location 3 is more probable than a fault in location 2 or location 4.

In the second scheme described in Table 1 and shown in Figure 6, two differential zones are implemented.
Each bus differential relay operates one tie circuit breaker. One of the sets of tie-CTs is located within the tie
bus and the other CT set is located within one of the main buses. In this scheme, bus fault locations 3 and 4 are
on the tie interconnection. If a fault happens at location 3, both zones will sense the fault, causing both ties and
both sources to open, fully isolating the fault, but also removing both sources from both load buses. If the fault
is at fault location 4, only one source and one tie will open, isolating the fault location from only one source. If
the other tie is closed and that source is connected, the fault may not be fully isolated. Also, the connected load
will be dropped because of the one main CB opening and isolate the main bus.

The third scheme, described in Table 1 and shown in Figure 7, is similar to the second, but the controlled tie
CBs are the more remote from the main CBs. This scheme is an improvement from the second in that a fault in
location 3 or location 4 will be isolated from both sources. However, a fault in location 3 will also isolate both
main load buses, and one in location 4 will clear one load bus.

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In the fourth scheme described in Table 1 and shown in Figure 8, CTs associated with the tie circuit breakers
are located on the main load buses and overlap. The tie interconnection is within both zones so a fault in fault
locations 2, 3, and 4 will cause both ties and both load buses to be isolated from sources. An interlocking
scheme using logic from one or both relays may be implemented that operates only the tie circuit breakers
when both differential zones sense differential faults simultaneously, which occurs when a fault is located in
the overlapping zone. This may be considered if a fault in location 3 is more probable than a fault in location 2
or location 4.

In the fifth scheme described in Table 1 and shown Figure 9, four sets of CTs associated with the tie CB
are used. Tie bus faults are always selectively isolated. However, faults at location 2 and location 4 can still
unnecessarily clear a load bus. If faults at locations 1 and 5 are deemed improbable, it may be advisable to
implement a logic scheme that prevents the main bus protection differential from tripping the main CBs for
a set delay if the tie differential protection is opening the tie CB. That may improve reliability but may delay
protection if a fault occurs at location 1 or 5. Generally when using bus differential, the intent and expectation
is fast bus protection. Delaying the opening of a source CB is not normal practice and should be carefully
considered if contemplated as it significantly limits the benefit associated with bus differential protection.

These examples demonstrate that there is no single perfect implementation of differential protection in sources
with multiple sources and multiple ties in series. What is optimal for a situation will depend on various factors
including perception of the most probable fault locations and the need for reliability. In addition to differential
protection, interlocking logic can further improve a scheme to ensure minimum interruption of power to
served loads.

The main overcurrent protection can be used as a backup to the ties in case the tie circuit breakers fail to isolate
the fault. Modern digital protective relays have capabilities for providing this, and the best way may vary
based on the exact relay used and degree of complexity deemed acceptable. Protective relay manufacturers
should be consulted on the best method suitable for the given situation and specific product recommendations.
These methods should not require delays long enough to allow another CB to open, i.e., more than three to
six cycles. As with any protection solution, the complexity needs to be weighed against the reliability risks
associated with the complexity.

The feeder overcurrent protection might allow a portion of conductors inside the CBs to be protected by the
differential protection instead of the feeder overcurrent protection (as Figure 3 and Figure 4 imply). A fault
internal to the circuit breaker would be a very serious event in the main equipment. Therefore, it may be
acceptable to allow the lack of selectivity created by the differential zone instead of simply allowing the feeder
overcurrent-zone to provide the protection at delays required for selective operation of the system.

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Authorized licensed use limited to: UNIVERSIDADE FEDERAL FLUMINENSE. Downloaded on March 18,2020 at 03:05:52 UTC from IEEE Xplore. Restrictions apply.
Table 1—Dual tie substation with bus differential implementation alternatives
Figure Substation Fault M1 T1 M2 T2 Bus 1 Bus 2 Tie Bus Fault
cleared
5 2 CTs between 1 Open Open Unaffected Open Cleared Unaffected N/A Yes
ties 2 Open Open Unaffected Open Deenergized Unaffected Cleared Yes
3 Open Open Open Open Deenergized Deenergized Cleared Yes
4 Unaffected Open Open Open Unaffected Deenergized Cleared Yes
5 Unaffected Open Open Open Unaffected Cleared N/A Yes
6 2 CTs around 1 Open Open Unaffected Unaffected Cleared Unaffected N/A Yes
1 tie, zone 2 Open Open Open Open Cleared Deenergized N/A Yes
control near tie
3 Open Open Open Open Deenergized Deenergized Cleared Yes
4 Unaffected Unaffected Open Open Unaffected Deenergized Not cleared No
5 Unaffected Unaffected Open Open Unaffected Cleared N/A Yes
7 2 CTs around 1 Open Open Unaffected Unaffected Cleared Unaffected N/A Yes
1 tie, zone 2 Open Open Open Open Cleared Deenergized N/A Yes
control far tie
3 Open Open Open Open Deenergized Deenergized Cleared Yes

22
4 Unaffected Unaffected Open Open Unaffected Deenergized Cleared Yes
5 Unaffected Unaffected Open Open Unaffected Cleared N/A Yes
IEEE Std 3004.11-2019

8 2 CTs outside 1 Open Open Unaffected Unaffected Cleared Unaffected N/A Yes
both ties, with 2 Unaffected Open Unaffected Open Not cleared Deenergized N/A Yes
3rd zone logic
3 Unaffected Open Unaffected Open Unaffected Unaffected Cleared Yes

Copyright © 2019 IEEE. All rights reserved.

or summation
4 Unaffected Open Unaffected Open Deenergized Not cleared N/A Yes
5 Unaffected Unaffected Open Open Unaffected Cleared N/A Yes
9 4 tie CTs 1 Open Open Unaffected Open Cleared Unaffected N/A Yes
external and 2 Open Open Unaffected Open Deenergized Unaffected Cleared Yes
internal to
tie bus 3 Unaffected Open Unaffected Open Unaffected Unaffected Cleared Yes
4 Unaffected Open Open Open Unaffected Deenergized Cleared Yes
5 Unaffected Open Open Open Unaffected Cleared N/A Yes
IEEE Recommended Practice for Bus and Switchgear Protection in Industrial and Commercial Power Systems

Figure 5—Double ended substation with 2 ties and 1 CT set per tie CB with minimum tie
zone overlap

Figure 6——Double ended substation with 2 ties and 1 CT set per CB; 1 tie in each zone

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Copyright © 2019 IEEE. All rights reserved.

Figure 7—Double ended substation with 2 ties and 1 CT set per CB; 1 tie in each zone

Figure 8——A double ended substation with 2 ties and 1 CT set per CB; full tie bus overlap

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Copyright © 2019 IEEE. All rights reserved.

Figure 9—Double ended substation with 2 ties and 2 CT sets per tie CB; full tie bus overlap

6. The need for fast bus protection

As part of the overall industrial and commercial power distribution systems, buses are protected by primary
and back up overcurrent devices. Traditional bus overcurrent protection devices are required to coordinate
with branch and feeder overcurrent devices, resulting in slower bus protection. In many cases, it is important
that bus protection has quick operating characteristics. Such fast bus protection can be important to the entire
power distribution system and positively affect overall system reliability.

Equipment can be damaged by three fault-current-caused effects:

— Large magnetic forces in some systems are severe during the first few fault cycles and can tear the bus
from its attachment points and bend rigid conductors. These effects create additional fault points and
can whip flexible conductors, damaging the conductors and nearby equipment along the path of fault
current from source to fault;
— The I2t heating effect created over time by excessive current can deteriorate insulation and even result
in softening and melting of conductors along the current path;
— Arcing at the point where the fault occurs can be very damaging, causing melting, burning, and
contamination that can damage nearby equipment as well.

In addition, it is not unusual for operating personnel to be near important equipment containing high-energy
buses. Personnel might be engaged in operating circuit breakers, racking circuit breakers in and out. They
might be engaged in other operation or maintenance activity on buses, device control wiring, instrumentation,
and other portions of the distribution, control, and metering system. An arcing fault exposes nearby personnel
to arc-flash related injuries, and fast protection is very important.

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Copyright © 2019 IEEE. All rights reserved.

Fast protection in the case of an in-equipment arcing fault can reduce the incident heat energy released by
the arc. This in turn can also reduce the arc-flash protection boundary around the equipment and reduce the
likelihood of the blast effects that could be created by the arc. In addition to lessening the personnel injury
aspects of arc flash, fast clearing times will also reduce fault damage to the equipment.

The improved safety provided to personnel by fast, sensitive protection can also have significant value in
terms of productivity and reliability, such as reducing:

— The time to recover from a fault event;

— The cost of equipment replacement;
— The cost of providing access to major electrical equipment for replacement;
— Production time lost due to incident investigation;

Therefore, when considering whether to add the cost and complexity of fast bus protection it is important to
consider the following:

— How the equipment will be operated and maintained;

— The consequences of a fault within the equipment;
— The best possible protection that can be afforded to reduce hazards to personnel as well as reducing
damage to equipment wherever it is required or practicable.

Fast-bus transfer schemes should be considered as a part of the protection solution when multiple sources
are available and maintaining power to loads is important for reliability or safety. However, if the bus itself is
faulted, then transfer between multiple sources must be blocked. Such schemes are further discussed in 6.11
of IEEE Std 3004.8.

7. Bus overcurrent protection

7.1 General discussion
Many industrial and commercial power distribution systems are radial, and overcurrent protection is used
for both the incoming power-source circuit and the branch feeders. The incoming power source protection
can also provide bus protection. The incoming power source circuit and bus overcurrent protection is often
required to coordinate with the branch feeder protection resulting in a slower bus protection. Whether the
protection is adequate would depend on the assessed probability of a fault event, the effect of the event on
the system, effect on the mission of the system, estimated time to repair damage, and the risk of injury to
personnel. Considerations for the ability to sustain loads appropriately and desired coordination of protective
devices can degrade the protection that simple overcurrent protection can provide. When simple overcurrent
protection is not capable of obtaining desirable protective and selectivity performance goals, the various
techniques described in this recommended practice should be considered.

To achieve selective coordination, overcurrent relays and trip units may have delay settings and high-current
setting ranges to delay opening the source circuit breakers upon the occurrence of a feeder fault. This is
not uncommon in industrial systems that require selective systems to ensure system reliability. Presently,
systems covered by the NEC’s definition of Emergency (section 700, NEC), Legally Required Standby
Systems (section 701, NEC) or Critical-Operations-Power systems (section 708, NEC) also require selective
performance. For such systems, the NEC requires complete selectivity, called selective coordination in the
NEC, from the branch overcurrent protective device to the emergency power source and for the normal
power source. The NEC mandate requires instantaneous protection, if present, to be selective. The extent
to which protection system selectivity applies depends on the revision of the NEC that has been adopted

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Copyright © 2019 IEEE. All rights reserved.

by the jurisdiction and how these requirements of that revision are interpreted by the jurisdiction. Systems
designed for selective coordination might not provide sensitive, high-speed bus and switchgear protection
unless designs, components, or protective schemes are specifically selected to provide high-speed protection
and selective coordination simultaneously in the fault current range of interest. See Valdes et al. [B41] and
[B43] for further reading.

On MV and HV systems, fuses, overcurrent relays, and arc-flash relays that trip circuit breakers are often
used for 3-phase fault and inter-phase fault protection where fault currents are typically high and overcurrent
protection can be effective. These systems are supplemented with sensitive ground relays when the system is
low-resistance-grounded (MV) and with ground-fault detection in high-impedance grounded systems (LV and
MV). In LV, high-impedance-grounded systems, ground-fault detection systems are required to annunciate the
occurrence of a ground fault when tripping is not immediately initiated. Systems that identify fault location
are desirable to facilitate rapid and safer troubleshooting and to expedite the removal of an accidental ground-
fault. Chapter 4 and Chapter 8 of IEEE Std 242-2001 (IEEE Buff Book™) provide details on relays and
procedures for proper settings. Modern switchgear standards also allow for MV circuit breakers with built-in,
direct-acting trip units that might incorporate GF detection and protection.

On LV systems, most applications use circuit breakers or fuses. Electronic trip units for LV circuit breakers
perform the sensing and timing functions that provide required protection for LV circuits and apparatus.
Modern LV trip units implement protection, metering, communications, and logic capabilities that are
very capable. The selectivity and protection clearing time possible with LV integral trips often exceeds the
capabilities possible with component relays operating those same LV circuit breakers. IEEE Std 3004.5
describes how to select and apply LV circuit breakers. IEEE P3004.3/D1b-2017 covers LV fuse application.

Differential protection of LV buses presents additional challenges to similar protection in MV and HV buses
(see Valdes et al. [B45]). In LV buses, fault currents may be high multiples of load current, while arcing faults
may be significantly lower magnitude than maximum calculated bolted-faults. However, working distances
are shorter, hence incident arc-flash energy per unit time may be high causing every millisecond that protection
is accelerated to be important. For that reason, implementation of differential protection may be desirable, but
traditional methods may be difficult, expensive, or too space consuming to be practical. Techniques such as
combining partial differential with zone-selective-interlocking, using differential protection integral to the
LV protection, or implementing zone-selective interlocking or other manufacturer-specific techniques may be
valuable in providing improved protection in a more practical manner.

The suitability of the protection afforded to LV equipment depends partly on the type of equipment containing
the bus and the standards around which that equipment is designed, manufactured, and tested. When the feeder
circuit breaker clearing time, fed from a bus, exceeds three cycles, the bus in the equipment should have
adequate withstand rating to prevent subsequent internal damage during the time that a through fault might last
(before being cleared by the feeder device in the equipment). LV power-circuit-breaker switchgear (UL 1558,
IEEE Std C37.20.1) is furnished with a 30-cycle rated bus per the requirements of the standard. Protection
should not require 30 cycles to clear a large-magnitude fault. UL 891-listed switchboards normally available
with a 3-cycle withstand rating may be available with optional 30-cycle rated bus based on testing performed
by the manufacturer over and above that required by the UL standard for that equipment. When using protective
relays in LV equipment, extreme care should be taken to ensure that clearing times do not exceed equipment or
circuit breaker withstand capabilities. Integral circuit breaker trips are designed to not allow the circuit breaker
or equipment withstand capabilities to be exceeded; hence, even if protective relays are implemented, the
integral trips should not be removed. Distribution equipment that has branches that always have instantaneous
protection, such as LV MCC, are not required, by applicable standards, to have significant withstand ratings as
any significant through fault will be interrupted by the instantaneous protection in the feeders.

When considering arc-resistant equipment (ANSI/IEEE Std C37.20.7), it is important to ensure that the
protection for all buses and conductors within the equipment protects the buses within the identified arc-
resistant withstand time identified by the manufacturer for the arc-resistant equipment. This might be difficult,
and therefore requires special attention when the line-side conductors of equipment fed by a step-down

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transformer are protected by a device on the line side of the transformer. See Mello et al. [B24], Simpson
[B33], and Valdes et al. [B41] for further reading.

Implementation of fast digital communications networks, such as that defined by the IEC 61850 [B39] set of
standards, in LV and MV protective devices, allows both distributed and central processing of current, voltage,
and device data. Fast digital communication facilitates fast, sophisticated protection that can accommodate
changes in system topology and can identify the fault location within the equipment, optimizing protection as
required by the actual topology in place at the time of the fault. For further reading on use of IEC 61850 in MV
and HV applications, see Apostolov et al. [B1] and [B2], and for an example of an LV application, see Valdes
et al. [B44].

LV bus protection tends to rely on the direct-acting integral trip units provided with circuit breakers tested and
listed as a system that includes the circuit-breaker mechanism and the integral trip unit. The trip unit is not
only designed to provide the proper protection adjustability that might be suitable for a range of connected
loads, it is also designed to protect the circuit breaker from being applied above its withstand capabilities. LV
power circuit breakers (LVPCB) are also UL listed (UL 1066 [B40]) for use with separate protection relaying.
LV, circuit-breaker direct-acting trip units provide most of the protective functions even when self-powered
from fault current. It is not recommended that a LVPCB be used without its integral trip unit even if additional
protective functions are implemented via separate protective relaying such as differential or overcurrent
relays. When operating LVPCB from external relays, such as an arc-flash relay, it is important to consider the
additional operating time that a shunt-trip coil might add versus the usually faster, internal, flux-shifter coil
that the direct-acting trip unit might use. Manufacturers should be consulted to ensure that the operating time
and clearing time of the circuit breaker and all auxiliary devices are included.

To reduce the possibility of destructive arcing faults, phase or ground, on 480Y/277 V and 600/347 V systems,
and to lessen the shock hazard when enclosure rear covers are open, the LV bus can be provided with an
insulating cover. This is generally available as an option on LV power switchgear and might be available
on some switchboard designs, particularly those with individually mounted devices and rear access to cable
terminations. Front-access switchboards have very limited capabilities for insulated bus coverings. It is not
usually available in panelboards.

Insulated and/or isolated bus may be available as an option on MV, metal-enclosed switchgear
(IEEE Std C37.20.3), MV motor control (ANSI/UL 347 [B36]), on LV switchgear (IEEE Std C37.20.1), LV
motor control centers (UL 845, [B37]), and on switchboards (UL 891 [B38]). Insulated bus is mandatory in
metal-clad switchgear (IEEE Std C37.20.2).

7.2 Low-voltage (LV) bus ground-fault protection for solidly grounded systems
Electronic trip units in circuit breakers are available with integral residually connected phase sensors and may
implement an external neutral sensor, if required. Some circuit breakers and switches (UL 977 [B39]) might
also use external zero-sequence sensing and process the signal within the device to generate a trip. Separate
ground-fault relays using zero sequence sensing are also commonly applied and trip the circuit breaker via
a shunt trip device. The 2017 NEC® (NFPA 70) requires ground-fault protection on solidly grounded, wye-
connected electric services of more than 150 V to ground, and not exceeding 1 kV phase to phase, for the
following devices:

a) Any service disconnecting means rated 1000 A or more (see 230.95);

b) Any feeder-disconnect rated 1000 A or more (see 215.10);
c) Each building or structure main disconnecting means rated 1000 A or more (see 240.13).

The NEC (230.95 for services, 215.10 for feeders, and 210.13 for branch circuit devices) states that GF
protection must be provided in certain applications and that the maximum pickup setting for the ground fault

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function (or sensor) is 1200 A. A GF function with a deliberate time-delay characteristic must trip within 1
s for currents equal to or greater than 3000 A. It also states that this requirement does not apply in certain
applications (such as continuous processes where interruption would be more hazardous than the ground fault
itself). It should be noted that in many situations there is not a given standard that determines practice but the
interpretation of that standard by the local inspector (Authority Having Jurisdiction). UL 1053 also defines
an additional point on the ground-fault curve at 150% of the nominal pickup setting that must not exceed 2
s clearing time. Figure 10 shows an example of an LV ground-fault protection curve and the various NEC-
required limits. NEMA PB2.2 [B27] also provides guidelines for interconnecting LV ground-fault protection
in complex systems as well as recommendations for assessment of acceptable bus damage in the case of a
low-magnitude, single-phase, arcing ground fault. Ground-fault protection in systems with multiple sources
is complex. Different manufacturers employ different schemes to achieve proper protection in complex
systems. Some are more suitable for open-transition systems, others for closed-transition systems. For further
details, see IEEE Std 242-2001 (IEEE Buff Book™)11 Chapter 8 and NEMA PB2.2, as well as manufacturers’
application guidelines.

Where main service-entrance circuit-breakers rated 1000 A or more are required to have ground-fault
protection in solidly grounded systems, achieving selective coordination requires coordination of the ground-
fault device with load-side phase protection (provided by circuit breakers or fuses). Selective coordination
can be achieved using delays, nested pickup thresholds, and careful selection of device response curve where
alternatives exist. Protection can be enhanced using zone-selective interlocking. Bus-differential protection
can also be set sufficiently sensitive to provide ground-fault protection in some cases. However, achieving
selective coordination for ground faults between line-side ground-fault relays and load-side phase protection
might be very difficult because of the limited flexibility in ground-fault device curve shape and pick up settings
that are allowed by the applicable standards. See Figure 10.

11
See footnote 5.

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Figure 10—Required maximum characteristic points for low-voltage, ground-fault

protection

7.3 Ground-fault protection on LV ungrounded or impedance grounded buses

Ungrounded systems are selected to improve system reliability as a first ground fault does not require isolation
of the faulted circuit. Ungrounded systems are rare in modern land-based systems, though common in
shipboard applications. The 2017 NEC requires ground-fault detectors for ungrounded systems in sections
250.36 (2) and 250.187(2). Impedance grounded systems for LV are typically high resistance grounded (HRG)
systems. High resistance grounded systems may also be considered to increase safety as a single unplanned
connection between live conductors and the ground plane does not escalate to an arc flash or fault event. HRG
systems are rarely designed with tripping on the first ground fault (GF). However, they are designed with
varying levels of GF detection systems.

Though the NEC requires only a single level of GF detection and tripping based on the detected GF is not
required, consideration should be given to the implications of meeting only the minimum requirements in
the NEC for GF fault indication on LV HRG systems. Not correcting a first ground creates the possibility
that a high-current phase-to-phase fault will occur between two circuit breakers if a second ground fault on
a different phase of the system happens before the first GF is removed. When two GFs exist simultaneously,
the resulting phase-to-phase fault may result in the loss of multiple circuits. Various systems for detecting
grounded circuits in HRG systems at load-side circuits exist today. These systems can be used to facilitate
trouble shooting of ground faults for more efficient and safer removal. Use of load-side GF detection in LV
HRG systems is recommended. GF detection on an HRG system could be based on voltage or current sensing.
Sensing and indication may be as basic as simply indicating a fault on the system exists to increasing levels
of information detail such as identifying which phase is grounded, which main equipment feeder, or even
which branch circuit overcurrent device is feeding the fault circuit. Detail level detection is advised to improve
maintainability, safety, and reliability. In some cases, LV switchgear or overcurrent devices such as electronic

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overloads may have built-in detection to facilitate such detail location identification and relays systems to
implement such detection is available. To prevent a fault from persisting too long and eventually resulting in
a dangerous multiple phase fault, consideration should be given to alarming that is difficult to go unnoticed.
Consideration should be given to tripping overcurrent devices even if it is days after having first alarmed
a persistent GF. Ground-fault protection in LV systems is discussed further in IEEE Std 142 (IEEE Green
Book™) [B11].

7.4 Medium-voltage (MV) and high-voltage (HV) bus ground-fault protection

In MV and HV solidly grounded systems, ground-fault protection can be implemented using various means:

— When supplied by a user-owned transformer or generator, an inverse-time or definite-time overcurrent

relay connected to a current transformer in the source neutral-to-ground circuit provides good
sensitivity for ground faults (including ground faults within the windings of the transformer secondary
winding or generator stator winding).
— On switchgear where the owner does not have access to the transformer neutral connection, residually
connected ground-fault relays or relays that calculate neutral current from the vector sum of the phase
currents may be used. Ground sensor relays in large systems implemented with iron core sensors (zero-
sequence sensors) may not be practical because the ground sensor windows large enough to allow all
the power cables to pass through may not be available and zero-sequence CTs may pose saturation
problems. Rogowski coils (air core sensors) may be an alternative as they do not pose saturation
concerns. Digital relays can implement GF protection with residual schemes without the need to install
zero-sequence sensors.

The main, or incomer’s, ground-fault relaying should be set to be selective with overcurrent relaying on load-
side feeders, if possible. A feeder ground fault of sufficient magnitude will be sensed as a phase fault by the
feeder overcurrent relay and as a ground fault by the main incomer’s GF relaying. Inverse-time overcurrent
relays, without instantaneous elements, are commonly used. If the feeders have ground-sensor instantaneous
protection, faster time-overcurrent delays are possible.

Because most faults are ground faults, or eventually become ground faults, ground-fault protection greatly
improves bus overcurrent protection. Additional descriptions and guidance on ground-fault protection can be
found in IEEE Std 242 (IEEE Buff Book™) [B12].

8. Zone-selective interlocking and blocking techniques

8.1 General discussion
A common method used in LV protection to improve protection speed is known as zone-selective interlocking
(ZSI). Component relays commonly used in MV systems may also implement blocking schemes that operate
similarly but allow for more customization by users. In the simplest terms, ZSI is the ability of a lower
tier (load-side) protective device that has sensed current that exceeds a set threshold to signal to upper tier
device(s) (line-side), via a restraint signal, that the fault has been detected and will be acted upon by the lower
tier device; thus, the upper tier device(s) can operate in a restrained protective mode to allow the load-side
device to operate (see Figure 11).

These schemes are described in 7.2 of IEEE Std C37.234-2009. The primary advantage of zone-selective
interlocking is its ability to provide faster fault clearing for bus faults without sacrificing system selectivity
with feeder protection fed by the bus. ZSI is an economical alternative to bus differential protection and may
provide a suitable alternative in those situations where CT saturation makes differential schemes impractical.
ZSI might provide less sensitive, or slower protection than differential relays. Also, while differential systems
are inherently selective for through faults, ZSI systems are not. The lowest tier overcurrent device in a ZSI

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scheme must be coordinated with load-side devices not included in the ZSI system. Zone-selective interlocking
is particularly suited for circuit breakers with integral trip units commonly provided with LV circuit breakers.
ZSI is beneficial even in MV circuit breakers with relays and separate CTs. It is less demanding on CT
accuracy relative to differential-protection schemes. The ZSI restraint signal sent from one tier to another is
commonly conveyed over a dedicated control circuit. On systems using protective relays, the signal could also
be conveyed using serial communications, particularly those designed following IEC 61850 standards.

Figure 11—ZSI scheme with two circuit breakers and two protection devices

Modern zone-selective interlocking allows improvements in clearing time, provides interlocking of LV-to-
MV devices across transformers, can be applied with directional relaying, and can provide other advanced
capabilities. Proper implementation of modern interlocking schemes can improve protection speed and
sensitivity for buses located in upper tiers within any distribution topology. In rare cases, selectivity may
be slightly improved using ZSI capabilities.12 For additional reading on advancements in zone-selective-
interlocking, see Valdes et al. [B41] and [B42].

8.2 Coordination studies and delay settings in ZSI schemes

Zone interlocking of LV circuit breakers is widely available for use with short-time and ground-fault functions.
In some situations, circuit breakers might be able to implement instantaneous protection within a ZSI scheme,
at least at the bottom tier, and in some cases at upper tiers as well. The adjustability of short-time and ground-
fault zone interlocking can also vary by manufacturer and product. Most manufacturers allow the user to
adjust the backup protection delay, or “restrain setting” applied on the upper-tier circuit breaker(s). The circuit
breaker with primary clearing responsibility (i.e., the circuit breaker for which the fault is within the primary
zone of protection) will clear the fault in accord with its “unrestrained setting” delay, which might or might
not be adjustable by the user. Typically, adjustable unrestrained settings provide the user greater flexibility
to coordinate selectively the circuit breakers in the lower tiers of a ZSI scheme with overcurrent devices and
loads farther load-side that are not part of the ZSI system. There might be breakers with instantaneous clearing
times that are not necessarily coordinated with the minimum delay available, or there might be a need to
allow expected transient currents (e.g., transformer and motor inrush currents). However, circuit breakers
located above the tier of breakers closest to the load can generally have unrestrained settings at minimum
delays because the zone interlocking with the load-side feeder will coordinate the upper tier breaker with
the load-side breakers not in the ZSI system. In these circumstances, it is possible for bus protection to be

12
Traditionally, ZSI is not considered capable to provide selectivity improvements, only protection improvements.

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faster than the feeder-cable protection. This type of function should be confirmed with the manufacturer of the
protective devices used. In component relays this will require separate inverse functions for blocking logic and
protection and ability to implement the required logic. In LV trips the capability should be discussed with the
manufacturer.

8.3 In-zone, unrestrained-protection and restrained backup-protection

When conducting a coordination study and an arc-flash study it is important to understand the difference
between in-zone unrestrained protection, and restrained backup-protection—it is important to ensure that
the system is properly adjusted for both. Traditionally, coordination studies do not represent the unrestrained
protection provided by ZSI schemes very well. The coordination model typically shows nested restrained time
current curves that represent the backup protection timing and sensitivity provided by devices other than the
bottom tier circuit breakers in the system. For upper tier devices, the protection represented (restrained) is only
active if a lower tier device fails to operate and does not clear its fault current properly. The actual close-in
(in-zone) unrestrained protection provided by the upper-tier circuit breakers, which often is the bus protection,
is not graphically represented in the traditionally modeled coordination-study time-current curves. The
predominant issue is how this modeling affects evaluation of arc-flash energy; however, modern coordination
software might implement capability for dynamic fault scenarios that will shift curves as appropriate based on
modeled fault location.

Not all manufacturers or devices implement delay settings the same way. In LV ZSI implementations within
LV circuit breaker trip units, unrestrained and restrained protection might be selected various ways:

a) User selects “restrained” backup timing and the trip unit automatically sets “unrestrained” protective
timing. This is the most common and simplest configuration in LV trip units.
b) User selects both unrestrained and restrained timing. This configuration is more complex but might
provide greater flexibility. It is important to properly identify which delay is the restrained and which
delay is the unrestrained when adjusting the settings in the trip unit.
c) User selects the same unrestrained protective timing for all tiers and a fixed “delta” time delay to
be added to upper tier devices based on load-side fault location. This configuration might allow for
tighter backup timing but requires some sort of centralized control to identify fault location and logic
that includes system topology considerations. This scheme might be able to adapt backup delays to
topology changes as well. See Valdes et al. [B42] and [B43] for further reading on this ZSI scheme.
d) User sets protection threshold and trip unit has only fixed timing for in-zone protection and a second
fixed timing for out-of-zone backup timing. This scheme is suitable for high fault ranges where
excessive backup timing might be undesirable and in-zone protection is desired to occur as quickly as
possible.
e) User sets two or more alternate setting groups composed of multiple settings and the restraint signal is
used to alternate between them. This method is more common in MV protection but is also available
in LV trip units. It requires multiple user settings but provides very flexible alternate protection that
can be used as backup protection. The signal required to alternate between setting groups is more
appropriately called a logical input than a restraint signal as it can be used to alternate between
protective settings used to back up a lower-tier failed circuit breaker or to reset bus protection as
required for varying system topologies.

When the available short time or ground-fault delay settings permit three or more circuit breakers to be
coordinated, the restrained timing on a trip unit could be selected in a manner where all the upper layers of
trip units are selectively coordinated one to the other in the traditional method where ZSI is not being used.
The case of main-tie-main systems is one where this might occur most often. However, these nested delays
are not strictly necessary. Backup, restrained timing could be set the same for all protective tiers. If the in-
zone protective timing and the backup timing coordinate, and all circuit breakers operate properly, the system

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should be selective under all fault conditions, regardless of whether backup timing is nested in multiple levels
or not. However, if a lower tier device fails to clear properly and all backup timing is set the same for multiple
tiers, then multiple tiers of line-side devices might trip together. This may, or may not, be desirable when one
considers that this only happens if a fault has happened downstream and the circuit breaker that is intended
to operate fails to clear the fault. Tripping multiple devices may be desirable to minimize equipment damage
and ensure reliable fault clearing given evidence of a compromised protective scheme. See Figure 12 for an
illustration of this concept.

Figure 12—Backup settings alternatives in a zone-selective interlocking scheme

8.4 ZSI schemes and protection algorithms

ZSI or blocking schemes are applied to control various protective functions. The most commonly available
schemes in LV trip units apply to short time and ground-fault protection.

It is important to note that the ZSI schemes implemented in trip units or protective relays might allow the
manipulation of multiple protective functions (e.g., short-time, ground-fault, instantaneous) upon receipt of a
blocking signal. Typically, only one signal path is used, and if the receiving unit does not know why the signal
was sent; it will shift whichever functions are ZSI-enabled to their restrained settings. This allows a lower
tier device to have only short-time zone interlocking implemented, but the device on the line side might have
ground-fault and short-time protection shifted if the phase overcurrent of the lower tier device can be adjusted
to coordinate with the line-side ground-fault characteristic. The signal from the lower tier will shift both upper
protective functions once the load-side short time ZSI function picks up, which might occur immediately after
current exceeds the pickup threshold setting. Figure 13 illustrates an example.

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Copyright © 2019 IEEE. All rights reserved.

Figure 13—Time current curves showing feeder CB with only short-time interlocked with a
CB equipped with both short-time and ground-fault protection

Advanced algorithms and circuit breaker protection systems can implement enhanced zone-selective-
interlocking not previously available. Directional zone-selective-interlocking allows interlocking to operate
in systems with multiple sources and ties restraining the proper source side circuit breaker depending on fault
location. Directional capability can also help ensure that a protective device does not issue a restraint signal
because of regenerative fault current supplied by a motor onto a bus fault upstream. Other algorithms allow
separate interlocking of instantaneous and short-time protection or may be capable of automatically shifting
the current pickup thresholds which allows pickup settings to be set to the same current threshold without
regard to maintaining separation between pickups due to tolerance considerations.

8.5 ZSI signal timing and creation of custom blocking schemes

The underlying principle in a ZSI scheme between two or more tiers of protective devices is that when two
devices in series sense the same fault current, the load-side device sends a signal to the line-side device
indicating that it has sensed the fault and is in the process of reacting to it. The line-side device processes
this signal as a restraint upon its protection algorithms and delays them from a faster more protective
operating mode to a slower backup mode that allows enough time for the load-side device to clear the fault.
The operational requirement is that the line-side device receive and process the restraint signal prior to itself
asserting a trip and being committed to operating at its faster protective timing. See Valdes et al., Section V B,
page 1642 [B41].

Figure 14 illustrates the timing of a ZSI interlocking signal issued by an LV circuit breaker and the timing
requirements for an instantaneous protection function of an MV instantaneous (device 50) relay. The left
diagram shows an LV circuit breaker short-time and instantaneous curve along with the associated restraint
signal timing issued by the same circuit breaker trip unit. The center panel shows the timing of the various
subsystem functions associated with the instantaneous function of a protective relay able to receive a logical
input and process it to alter its protective functions. The lines in the center panel, from bottom (fastest) to top
(slowest) represent the following:

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— Commit time for the relay, i.e., the time it takes for the relay algorithm or circuitry to make the
irrevocable decision to assert a trip. In this case, the minimum time that decision can take. For
instantaneous elements, the commit time is often inversely proportional to the ratio of fault current to
threshold pickup setting;
— The second line above that represents the additional time the relay allocates to sweeping its logical
inputs and processing associated logic. At the end of this time, the relay will assert its trip if the logic
allows it. This line may be viewed as the “blocking window.” If the blocking signal arrives before this
time, the relay logic can block or alter its operation and not assert a trip even if the fault current had
previously exceeded the commit time;
— The third line represents the output contact from the relay. Output contacts might be solid state or
mechanical. Mechanical contacts usually are a few milliseconds slower than solid state contacts;
— The fourth, top most line represents the clearing time of a 3-cycle MV circuit breaker.

The third panel superimposes the LV circuit-breaker, short-time and instantaneous curve, its associated issued
restraint signal, and the various lines representing the MV instantaneous element and MV circuit breaker.
The LV restraint signal is to the left and below the MV line representing the MV instantaneous trip blocking
window that indicates these two devices might be made selective by using the LV restraint signal to alter
the MV relay operating characteristics. Many modern digital relays offer the ability to block instantaneous
protection. Operational details may vary by manufacturer and device model and should be obtained from
manufacturers’ application literature or by consultation with the manufacturer for a specific relay and trip
unit. This capability is particularly useful for fast protection of the transformer secondary bus between the
transformer secondary terminals and the first LV device.

Figure 14—Interlock signal timing for circuit-breaker trip units and protective relays

8.6 Circuit breaker failure schemes as backup bus protection

Circuit breaker failure (CBF) schemes are usually used only in complex topology schemes that have multiple
sources and buses interconnected. However, CBF schemes operate in a similar manner to ZSI schemes, but
timing is initiated within breaker-failure logic in the CB that should be protecting the faulted zone, starting
upon assertion (t0) of the lower-tier trip command, rather than when fault initiation was determined. Backup
protection is provided by transfer tripping from the lower-tier device to the upper-tier device(s) feeding the
circuit if the logic determines that the primary protective device has not interrupted the fault current as expected.

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CBF schemes provide supplemental backup protection for through faults and are not primary protection to
upper-tier buses. Figure 15 shows a schematic comparison of a CBF scheme versus a ZSI scheme. For further
information on CBF applications, see IEEE Std C37.119 [B20].

Figure 15—Comparison of zone-selective-interlocking logic to a circuit breaker failure logic

scheme

A word of caution is appropriate for CBF schemes. Added complexity in a protection system provides
added opportunity for equipment failures, wiring failures, and testing failures. CBF protection should not
be considered for simple systems in which the only outcome of the circuit breaker failing to trip is that the
line-side circuit breaker or fuse clears the fault. Normal backup protection, potentially enhanced with ZSI,
is usually good enough for radial distribution topologies. CBF schemes are for buses with multiple sources
of power where the failure of a circuit breaker to properly isolate the fault may cause multiple systems to be
impacted. This type of protection is usually only seen in utility applications for major substations, but with
distributed resources becoming much more common, it is becoming more common for complex industrial and
commercial power systems.

9. Differential protection
9.1 Bus differential basics
Bus-differential relaying can provide sensitive, high-speed, selective protection for buses, including
switchgear buses. A bus-differential relay measures all currents entering and exiting the protection zone and
operates if the difference between the current sources and current loads is above the differential protection
threshold. Because of this inherent selectivity, a differential relay does not need to have intentional delays
to coordinate with relays in adjacent zones, and it does not need to coordinate pickup thresholds with other
protection—a benefit especially when large fault currents flow through the differential zone. Bus-differential
protection is used when high-speed fault clearance is required to limit the damaging effect to equipment and
to maintain service to as much load as possible. In addition, it permits complete zone protection coverage and
overlapping with other power-system relaying as indicated in Figure 11, Figure 12, and Figure 13, for a variety
of bus configurations. One of the challenges associated with the applications of bus differential relays, is the
behavior of the current transformers associated with the differential schemes. Current transformers saturate
when subjected to excessive fault currents and to dc components in currents under transient fault conditions
at fault inception (IEEE Std C37.110). Saturation of one or more of those current transformers providing

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inputs to the differential scheme may cause relay mis-operation and compromise the scheme reliability. CT
requirements for differential schemes are discussed in detail in IEEE Std C37.234, IEEE Std 3004.1, and
other literature. It is advisable to review such references as well as the relay supplier requirements prior to the
selection of the connected CTs. CT characteristics are especially important when using high impedance bus
differential relays. Modern low impedance bus differential relays are developed with separate input modules
for each CT input signal, and each input is digitized before current inputs are vectorially summed in the relay.
Some details are discussed in the subsequent clauses and more details can be found in associated literature.

Bus-differential relaying often is applied to complex systems that have multiple sources and perhaps multiple
buses at the same voltage level. Improved arc-flash protection is another reason to implement differential
protection, to provide the fastest and most sensitive protection without sacrificing system reliability.
Traditionally, these goals have been used to justify the extra cost and complexity of high-speed bus-differential
relaying. Advances in modern digital relays, digital communications, and alternate sensing techniques
has lowered the cost and complexity of implementing differential protection in industrial and commercial
applications and make applications in commercial LV systems more feasible.

The basic principle of differential protection is that, under normal conditions, the phasor sum of all measured
currents entering and leaving the bus is zero (Kirchoff’s current law). This is ideally always true under normal
load conditions, otherwise, a fault has occurred within the protected zone.

Figure 16—Single-bus scheme with bus-differential protection and other overlapping

protection zones

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Figure 17—Sectionalized-bus scheme with bus-differential relaying, overlapping tie-circuit-

breaker protection

Figure 18—Double-bus scheme with bus-differential relaying and other overlapping

protection zones

Differential relaying is typically provided to supplement basic overcurrent protection. It is frequently used on
a 15 kV-bus, sometimes on a 5kV-bus, and with increasing frequency, on LV buses. The following factors are
often used to determine whether differential relaying should be provided (see Cable et al. [B5]):

— Degree of exposure to faults. For example, open outdoor buses have a higher degree of exposure; and
metalclad switchgear, properly installed and in a clean environment, might have minimum exposure.
Contaminated environments increase the possibilities of faults, and equipment located in these
environments needs better protection;

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— Magnitude of the fault current causing damage of the bus components and voltage depression impact
to the adjacent electrical equipment as a result of slow fault clearance, such as motor control circuit
drop-out or synchronous motors falling out of synchronism;
— Power-system stability. The capability of a system to return to a stable, steady-state mode of operation
after a system disturbance might require high-speed bus differential relaying. The faster clearing
time obtained with high-speed differential relaying enhances the probability of maintaining stability
through and after a fault;
— Use of sectionalized-bus arrangements that require the use of other, more complex protection methods.
Sectionalized-bus arrangements make differential protection more useful and desirable, particularly
when secondary selective distribution systems are used. The faulted bus can be isolated quickly and
continuity of service maintained to a portion of the load served by any other bus;
— Effects of bus failure on other parts of the power system and associated processes. On a major plant
bus, the cost of differential relaying is usually insignificant when compared with the savings associated
with the reduction in damage to the equipment and the reduced outage time of important plant or
process facilities. This cost can include the cost to repair electrical equipment, clean up production
machinery and processes, as well as the opportunity cost incurred and lost revenue resulting from the
inability to continue plant operations.
— If problems exist in selectively coordinating the system overcurrent-relay settings or the selective
coordination requires excessive delays, differential relaying is effective in obtaining selectivity
and faster protection simultaneously. An example is a system that consists of major bus distribution
lineups at the same voltage level, with one bus feeding another. This configuration generally results in
unacceptably high overcurrent relay pickup and delay settings required to obtain coordination.
— Arc-flash incident energy protection. Delays and nested pickups, often required to provide selectivity
for bus main breakers, can increase arc-flash incident energy. The energy released by an arc flash can
create significant hazard to operating and maintenance personnel. Sensitive bus-differential protection
should reduce the severity of the hazard while enabling selectivity for through-faults at protected
buses. Where improved arc-flash mitigation is desired, bus-differential protection is an alternative to
losing selectivity to overlapping short-time bands and instantaneous protection or slowed protection
required to maintain selectivity.

On a bus fed by a local generator, bus differential relaying is recommended to clear the bus quickly and
minimize impact on the generator system. Simple overcurrent relays might not be sufficiently fast or sensitive
to protect the generator if these are set to be selective with other load-side protection.

The differential protection methods generally used are the following:

— High-impedance differential relaying

— Percentage-restrained differential relaying
— Differentially connected overcurrent (instantaneous or delayed)
— Partial differential (sometimes not considered a differential scheme and called “current summation”)

The differential relay should trip all circuit breakers connected to the bus. Typically, a high-speed, multi-
contact lockout relay (device 86B) is used for this purpose. This auxiliary device should also have normally
closed contacts in the circuit breaker closing circuits to prevent inadvertent manual closing of a circuit breaker
on the fault until after the incident has been investigated further. The lockout relay then must be reset manually
before any circuit breakers can be closed. In some schemes, where optimum protection speed is desired,
controls might be connected such that source circuit breakers are directly tripped by the protection relay and
the lockout relay is used to trip feeders. Modern digital differential relays may have enough contacts to trip all
bus breakers and provide lockout functionality.

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Figure 19 shows a simple, current-based differential scheme that may be created by simply connecting current
sensors in a differential manner from each source and feeder circuit in parallel to a simple overcurrent relay
using the net difference from the sum of all currents as the input to the relay. If the current into the bus through
the source is equal to the current leaving the bus through the three feeders, the net sum is zero and no current
flows through the relay. When a fault occurs on the bus, the source contribution into that bus does not flow
through the feeders and hence is sensed as a differential current by the relay. This simple scheme requires that
the characteristics of the CT be considered. CT ratios should match, however other characteristics may vary.
Reviewing CT characteristics with the relay manufacturer is recommended. Generally, this simple scheme
will require the protection to be set high (50 device) or delayed (51 device) to prevent CT performance from
negatively impacting security.

Figure 19—Simple current-differential scheme using overcurrent relay

The simple differential scheme such as shown in Figure 19 might be susceptible to false operation because of
sensing inaccuracy during large through faults. A load-side fault could cause enough current to flow that the
source and feeders CTs, even if nominally identical, could produce enough difference in secondary current that
the relay could incorrectly assert a fault that is not there. Adding delays or increasing the operational threshold
are ways to minimize the possibility of incorrect operation; however, slowing and desensitizing differential
protection is not usually desirable, and to some degree, defeats the purpose of having differential protection.
This type of implementation might be suitable for small systems with a very limited number of circuits. The
more common types of differential relays employed in industry today are called low-impedance and high-
impedance differential relays. Both types of relay expand the number of circuits that can be accommodated
and implement techniques to allow sensitive thresholds and very fast operation that can perform as well as fast
instantaneous protective elements in single-circuit protective relays. In the past, high-impedance differential
relaying was generally considered superior; however, with improvements in digital relays, low-impedance
differential relaying can perform as well as high-impedance differential relaying in speed and sensitivity while
providing for a more flexible implementation.

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9.2 High-impedance bus-differential relays

9.2.1 General

In classic high-impedance bus-differential relays, CT secondary currents are summed via their secondary
circuit wiring as shown in the upper portion of Figure 20. The net differential current is forced to flow through
a resistance as shown in the lower portion of Figure 20. The scheme is relatively simple and straight forward.
Accordingly, it remains widely used despite the need to address certain practical considerations as discussed
further throughout this subclause.

Figure 20—High-impedance bus-differential scheme (high impedance bus differential relays

sometimes designated as 87Z or 87BZ instead of 87B)

The CTs used with traditional high impedance differential relays must have the same ratio, enough accuracy,
matched characteristics if possible, and proper polarity connection to ensure that the secondary current outputs
from the paralleled CTs have a vector sum of zero in the same way that the primary currents in the bus sum to
zero during normal load conditions. Current differences are forced through the high-impedance input at the
bus differential relay causing a voltage across the relay. In some cases, the relay is in series with a resistor,
and those relays will operate from the current through the relay and resistor. The relay is set to trip based on
the voltage across the relay and can be sensitive to small differential currents. Typical relay settings allow
one CT to saturate without relay misoperation. During external faults, with saturation of some of the CTs,
the voltage does not rise above a certain level defined by the saturated CT impedance and wiring impedance.

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The circuit is required to have overvoltage protection, typically in the form of a metal oxide varistor, to limit
the voltage across the relay-input resistor created during internal faults. This type of relay has been used for
several decades because it is robust, cost effective, secure, and fast. Limitations of high-impedance differential
relays and precautions while applying them can be summarized as:

— Dedicated, well-matching CTs are required. The CTs should have distributed secondary windings that
have little or no secondary leakage reactance. Manufacturers of the relays provide guidance on CT
selection to ensure that the CTs are properly matched to each other and to the relay capability;
— CTs must be sized to have an accuracy class that will produce an operate signal on the relay while
saturated;
— CT secondary circuits must be connected with the correct polarity so secondary currents flow in the
proper direction.

Under normal load conditions, differential current should be zero through the differential impedance. Under
through-fault conditions, although bus currents are still balanced, one or more of the CTs might saturate. A
fully saturated CT produces reduced secondary current and can become a (relatively) low-impedance path
for other current sources in the circuit. Secondary CT wiring is an important consideration in determining the
voltage across a saturated CT. It is usually preferred to run CT secondary leads to minimize wiring impedance
and equalize resistance among the various load circuits. The operating-threshold voltage for the differential
protection must be greater than the voltage that could occur across the parallel path provided by a completely
saturated CT. For a bus fault within the differential zone, a large voltage should be produced across the relay
impedance. The overvoltage protection provided by a metal-oxide varistor clamps the voltage peaks to a level
acceptable for the relay. The relay operational threshold must be set below the clamping voltage created by the
overvoltage protection. Manufacturer’s literature should be consulted to secure relay behavior under system
conditions especially:

— Through faults that saturate one or more of the CTs;

— Internal faults that saturate the CTs;
— Internal faults that could result in a very large differential current and consequently cause large voltages
across the relay sensing impedance;
— Internal faults that are not cleared sufficiently can quickly drive current through the relay impedance
longer than the relay is able to withstand.

See Behrendt et al. for further reading on high-impedance relays [B4].

9.2.2 Through-fault operation

Under severe through-fault conditions, CTs carrying the most fault current might saturate. The relay tripping-
voltage threshold must be set above the voltage that could develop across the relay with a completely saturated
CT. A completely saturated CT produces no current output and becomes simply a (mostly resistive) impedance
in the circuit. The CT wiring and internal resistance are small relative to the internal resistance of the high-
impedance relay path. Therefore, the worst-case voltage across the relay under a large through-fault condition
is the voltage drop across the combination of saturated CT wiring and saturated CT internal resistance. The
voltage selected as a tripping threshold must be greater than the possible voltage that could develop across a
saturated CT and associated wiring.

The relay setting threshold should have enough margin to account for potential variation in the available fault
current and in the impedance used in the calculations. This threshold affects the minimum sensitivity setting
for the relay. To simplify calculations, it is recommended that all CTs be connected to one junction point or
terminal board. CTs should not be connected into subsets and the subsets brought to a common connection
point separately.

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9.2.3 Internal faults

During a high-current internal-bus fault, the relay presents high impedance to the flow of CT secondary
current. This impedance causes a large voltage to be developed across the relay. Even if the CTs on incoming
circuits eventually saturate, a large voltage is developed during the first part of the half cycle prior to CT
saturation. Relays should be set to operate from that voltage during the time prior to CT saturation. This setting
should provide the relay enough information and time to make reliable tripping decisions. Manufacturers
implement various filtering, sampling, and signal processing techniques to improve sensitivity, accuracy,
speed, and reliability for the sensing circuit—even when fault magnitudes might be large and source CTs reach
saturation. The net current flowing through the sensing circuit can be very non-sinusoidal; however, modern
relays can discern a fault within a cycle of fault inception.

The voltage peaks created during a fault can exceed the voltage withstand of the relay and even prove
hazardous, hence the voltage must be clamped to a reasonable level that is greater than the expected pickup
threshold of the relay.

9.2.4 Protecting the high-impedance differential relay from excessive current and circuit-
breaker failure

The relay current-withstand and overvoltage protection energy limits might be exceeded in cases where the
circuit breaker that the relay controls does not open quickly enough. Additional protective elements need to
be included for such situations. Common implementations include a parallel metal oxide varistor (MOV), or
shunting the differential current through a parallel, low-impedance circuit made of internal relay contacts or
using an external 86 auxiliary relay connected in parallel with the protection relay’s sensing circuit.

9.2.5 Additional relay functionality

High-impedance differential relays may implement a series overcurrent function (50/51) that provides back-
up protection and continues to operate even after the shunt bypass contact is closed to protect the main sensing
circuit and overvoltage protection.

A high-impedance differential relay cannot implement functions that require measuring any single circuit
current because the current information at the relay always represents the net total current flowing in the zone.

One last concern is that, because the high-impedance relay can be set very sensitively, it is important to
account for normal and acceptable currents that may exist or temporarily occur within the protected zone.
These currents may result from auxiliary control power transformers and even currents shunted to ground by
arresters or surge protective devices.

9.3 Low-impedance bus-differential relays

Modern, digital, low-impedance differential relays have fewer restrictions than older electromechanical
versions in the way these relays are wired and in CT selection. Figure 21 shows a simplified, low-impedance
differential relay connection. Generally, these differential relays share the following characteristics:

— CTs may be shared with other metering and protective functions within the relay;
— CT ratio can be corrected or changed at the relay as required;
— The relay will impose a threshold-restraint function to desensitize the relay in proportion to some
measure of the through current in the differential zone to guard against false tripping from CT sensing
error, see Thompson [B34];
— The relay can adjust for a CT wired with any polarity; however, it is recommended that all CTs be
wired with a consistent secondary current direction to facilitate trouble shooting.

Figure 21—Simplified, low-impedance relay scheme

Modern low-impedance differential relays might implement various algorithms creating a restraint function
and use separate measured currents (or rate of change of current) to improve protection sensitivity, speed, and
prevent false operation. Because the relay receives each CT signal independently, the relay can implement
various additional protective and measurement algorithms with each separate CT signal and any combination
of CT signals. Additional protective functions such as breaker-failure detection, overcurrent protection of
load-side circuits, and other multi-function protection, with sophisticated algorithms may be provided by the
same relay.

A commonly used method to account for measurement error in low-impedance differential relays is the
percent-restraint function. The relay sums the currents (vector sum of phasors) from all CT inputs to detect
the differential-current increase resulting from an internal fault. To account for errors introduced by variations
in CT performance and by CT saturation, the relay also may implement one of various methods based on
the measured current magnitudes to create a restraint current. The differential current from the phasor
summation, referred to as the operate current, is compared with the restraint current. The relay operates when
the operate current exceeds a minimum threshold and a percentage of restraint current. Graphically this is
shown as a slope called the percentage-current-differential characteristic for the differential relay. Figure 22
illustrates this principle. Low-impedance differential relays that implement this characteristic are referred to
as percentage-differential relays. A second, steeper slope is often added to address the increasing inability for
the CTs to accurately replicate higher primary currents and hence ensure that the relay does not misoperate if
a CT is saturated during a high-current fault. This second slope makes the relay stable against misoperations
but can significantly desensitize the protection during a high-current fault. The second slope is also shown in
Figure 22.

Figure 22—Percentage-current-differential characteristic

Modern, digital, low-impedance differential relays implement additional algorithms to detect saturated CTs
and the pending saturation of a CT. These algorithms vary by manufacturer. These algorithms improve the
sensitivity and security of modern, digital, low-impedance differential relays.

The relay must have separate input connections for each CT that is part of the differential scheme. Typically,
that will be three CTs per source or feeder circuit, one for each phase conductor. One technique to connect
more circuits to any one relay is to put CTs for multiple circuits in parallel and use the net sum of these CTs
as an input to the relay. This technique requires that the paralleled CTs be of equal ratio and class, and that the
combined expected secondary current from the paralleled CTs does not exceed the relay input signal ratings.
The manufacturer’s literature should be consulted when this technique is used to determine if this might cause
issues with protection algorithms. When implementing low-impedance differential relaying, consideration
should be given to any additional circuits that might be added in the future to ensure that the relay has sufficient
inputs for planned expansion of the bus system. See Kasztenny [B22] and Thompson [B34] for additional
reading on percentage differential relays and Holback [B9] for a comparison between high-impedance and
percentage differential relays.

9.4 Modern differential-protection alternatives

Using distributed processing of power-system information, the equivalent of low-impedance differential
relaying can be implemented in an alternative manner. Systems might use iron-core sensors or air-core sensors
(a.k.a. Rogowski coils) and digitally process the information locally, with a process bus merging unit assigned
to a circuit breaker cubicle. The accumulated data are sent to a central computer processing unit (CCPU)
using modern digital communication methods. The data from various circuits can be analyzed at the CCPU
as appropriate for the system topology. The information sent from each circuit must include the fundamental
current-phasor data and must be time stamped or otherwise tightly synchronized with each other at the CCPU.
Data provided at the CCPU might include non-linear and non-fundamental current components and voltage
information. Like a traditional low-impedance differential relay, the CCPU has all the data required to protect
separate circuits in addition to providing differential protection. Additionally, it can implement various
methods to ensure fast, accurate, and reliable detection of an in-zone fault. This arrangement can provide
additional protection and control capabilities. Phasor currents can be vector summed at the CCPU to produce
a differential current as in a directly coupled, low-impedance differential relay, and the various phasors can be
compared to identify the direction of current flow, and consequently the location of the fault. When directional
comparisons are made, exact measurement of the fault current is less important, if it is known that it is greater
than the set protection threshold. See Valdes et al. [B42] and [B44] for additional reading on this type of
system.

An additional benefit of using digital communications to provide current data from the circuit-breaker cubicle
to the CCPU is that CT leads are always connected to the local node at the circuit breaker bay. For this local
connection, the CT leads do not extend to a central differential relay location. Thus, CT burden is reduced
and the CT is less likely to saturate, and CT wiring does not have to cross where equipment is separated for
shipping purposes (shipping splits).

Distributed data acquisition combined with centralized data processing provides an economic and flexible
solution. This solution accounts for CT saturation, uses the same sensors for multiple functions such as
metering, control and other protection, and uses integral sensors that are normally provided in LV circuit
breakers and in some MV circuit breakers, as well. These systems make differential protection a reasonable
option in some LV systems where traditional differential protection and its components might otherwise be
considered too costly, too complex, or incapable of fitting into the available space. Distributed systems can
easily account for dynamic changes in system topology and circuit-breaker status and can define a zone of
protection as required in response to different system conditions.

Schemes using communications technology can provide differential protection over large systems where
traditional CT wiring would be impractical. IEC 61850 communication may also be used to implement
directional comparisons. These might be less demanding of communication buses because less information is
communicated from the local data-acquisition node to the central-processing node at which the comparisons
are made. See Apostolov et al. [B2] and [B44] for additional reading on this subject.

A communications-based architecture is shown in Figure 23. Alternative architectures are possible with
different levels of functionality distributed between the local and centralized communicating devices.
Information distributed within the system can include several discrete signals such as circuit-breaker status
and blocking signals as well as analog current and voltage phasor, sampling data.

Figure 23—Differential scheme implemented in system with digitally communicating

devices

Among the drawbacks of this type of scheme is the wide variation that might be found between alternatives
available and the unfamiliarity of users with this type of protection. In a centralized scheme, the provision of
multiple important protection and control functions in one processor raises the concern that there might be a
single point of failure affecting too many important functions. That concern can be alleviated by providing
redundancy in sensitive portions of the system and by designing the system such that, in the event of a single
device or communication failure, sufficient protection and control remains to keep the system safe and
operable.

When implementing protection and control schemes using centralized processors, there are many factors that
need to be considered to ensure that protection is fast and reliable, including being able to accurately predict
protection timing regardless of other demands for available communication bandwidth, processing power, or
available memory. Generally, monitoring functions will be lower priority than control functions, and control
functions will be lower priority than protection functions. Fault events may cause significant increases in
data to flow, and this can cause the system to operate in an unintended way if the design does not properly
account for the potential large flow of time-critical data during fault events. Designing complex control and
monitoring systems is complex and requires skilled personnel. Adding protection functions makes it even
more critical that system designers understand the ramification of all system design decisions and that the
system be robustly tested prior to full implementation.

10. Partial-differential protection

Partial-differential protection, sometimes called summation-overcurrent relaying, is a modification of a full
differential scheme in which one or more of the load circuits are not included in the differential system sum
(see Figure 24). This method is often used as backup protection for other overcurrent protection. There are
several considerations to be thought through when implementing this protection. Using Figure 24 as reference,
if the tie is closed and the left source circuit breaker is open, the right source could be supplying the full load
on both the right and left buses. If both buses are fully loaded to 100% of their capacity, the right bus will be
carrying 200% current even though its connected load is half of that. The partial differential sum will only
measure 100% current because the tie is subtracting from the source. Because of this, it is important that the
source circuit breakers have primary protection adequately sized to the capability of the buses and devices.

Another advantage occurs when partial differential schemes are applied on buses being fed from multiple
parallel sources, which can otherwise be difficult to coordinate. Consider that the feeder overcurrent device
in such a system will see all the current flowing to line-side faults, regardless of how the sources contribute
to this current. The degree to which the sources may share can be difficult to predict and makes traditional
representation on time current curves difficult. The relay in the partial differential scheme sees the same fault
current as the feeder device or the faulted bus, regardless of how sources are sharing that current, making
classic time current curve evaluation straightforward. The relay can disconnect all sources simultaneously
selectively. Furthermore, the partial differential relay can be interlocked with blocking signals from the load-
side overcurrent or ground fault relays allowing for faster protection of the bus without negatively impacting
selectivity.

When a normally closed tie circuit breaker separates loads as shown in Figure 24, this scheme can provide
selectivity between the two sources for bus faults and load-side faults. In a conventional scheme with relays
on each incoming line, a fault on either bus results in a loss of both incoming lines because their settings are
identical. With the partial differential scheme, a fault on one bus causes a summation of currents in one set of
relays and a subtraction of currents in the other set of relays (not shown). This difference in currents allows the
incoming line relays to be selective and only the faulted bus is de-energized.

Partial differential relays should provide sufficient delay to be selective with relays on the load circuits.
Consequently, the sensitivity and speed of partial differential protection is not as good as in full differential
protection. A partial differential scheme may be enhanced by use of blocking signals (ZSI) from load-side
load relays to force the partial differential protection to be restrained if the fault is detected by load protection

relays, or trips fast enough. This requires that the blocking signal arrive at the device providing the partial
differential protection before the partial differential protection commits to asserting a trip.

Figure 24—Partial differential relaying (three-breaker scheme)

11. Backup protection

To cover the situation when the primary protective system fails to operate as planned, some form of backup
relaying and protection should be provided in the power system.

Bus backup protection is inherently provided by the primary relaying or trip units at the remote ends of the
supply lines. This setup is known as remote-backup protection. It might not be adequate because of system
instability and effects on other portions of the power system, and local-backup relaying might be necessary.
The performance of various remote- and local-backup relaying schemes should be analyzed. IEEE Std C37.95-
2014 [B19] gives further information on utility-service supply-line requirements and the backup protection of
utility relaying.

Circuit-breaker failures can cause catastrophic results, such as complete system shutdown. In MV and HV
applications, local circuit-breaker failure or stuck-circuit-breaker relay schemes are available to quickly
trip supply-side circuit breakers that are able to isolate the failed protective device if the circuit breaker on
the faulted circuit fails to operate within a specified time. These schemes were normally applied only on
buses where the extra expense could be economically justified when discrete relays were the norm. Now,
multifunction relays provide these functions without additional cost. In LV systems, backup protection is
provided by upper tier devices employing nested delays or zone-selective-interlocking. It should be noted that
the backup to a failed LV main, fed from a transformer, is provided by the first MV protective device ahead of
the transformer. Unless protection has been implemented to specifically provide fast backup protection, the
protection provided by an MV protector on the line side of a transformer, for a LV fault on the secondary side
of the transformer, might be several orders of magnitude slower than the expected, failed, LV protection. This
situation can lead to significant equipment damage and extremely hazardous levels of arc-flash energy. See the
following clause in this recommended practice for some further discussion on this subject as well as Mello et
al. [B24].

Some low-impedance differential relays incorporate multiple protective functions that can back up the
protection provided by the differential-relay algorithm, as well as provide additional protection for feeder
circuits.

12. Protecting the secondary terminals and connected bus on a step-down

substation transformer
12.1 General discussion
Protection of the terminals and conductors on the secondary of a substation transformer can present unique
challenges:

— The protective device, circuit breaker, switch, and fuses are located on the transformer primary circuit
at a higher voltage than the secondary conductors that require sensitive protection;
— The distance might be significant between the MV protective device and the location where sensing for
protection of the lower-voltage bus is located;
— The lower-voltage equipment might not easily accommodate instrument transformers of sufficient
accuracy and burden capability to provide proper sensitivity and performance;
— The transformer winding configuration might further desensitize any primary-side sensing of
secondary fault current;
— Transformer inrush current requirements require accommodation by any primary sensing and
protection implemented.

It is common to protect secondary substation transformers with dedicated primary fused switches. However,
the fuses often do not provide adequate protection of the secondary bus and can allow very large levels of
incident arc-flash energy and equipment damage in the case of an equipment arcing fault. The fuses can provide
adequate protection for large-magnitude faults on the primary connections of the transformer. The transformer
ratio and relatively small magnitude of an arcing secondary fault can cause the fault to be difficult to detect
with primary-side current sensing. The following subclauses describe some alternatives for protecting this
section of the power-distribution system.

Ground-fault protection on the bus between the transformer secondary terminals and the first LV devices may
be important. The NEC only requires ground-fault protection on service entrance disconnects rated at 1200
A or greater. However, the line side of the service entrance disconnects may also be subject to ground faults
and should be protected for low magnitude arcing ground faults if possible. See Paul et al. [B28] for further
discussion on ground faults between the transformer terminals and the first secondary protective device.

12.2 Low-voltage (LV) bus protection using primary-side protective devices

System designers might not employ secondary main circuit breakers in substations when the quantity of
feeder circuit breakers is allowed by applicable codes. This arrangement can minimize cost, reduce footprint,
and circumvent code required ground-fault protection. In such cases, the LV main-bus protection must
come from the MV protective device on the primary side of the transformer. Usually, MV fuses used for
transformer protection do not usually have characteristics suitable for secondary bus protection from arcing
currents because these arcing currents are typically much smaller than the maximum secondary bolted fault
current. If a system without a secondary main is contemplated, a circuit breaker as a primary device should be
considered. Protection provided by the primary device should, as much as possible, sense and react to faults
on the secondary side of the transformer with the same speed and sensitivity that a properly selected and set
secondary main would provide. Such protection may be difficult to achieve with simple 50/51 protection on
the primary side of the transformer or a fuse due to the required transformer inrush considerations. Overcurrent
protection with secondary side sensing along with zone-selective-interlocking, or additional transformer
differential protection, or bus differential protection encompassing all the LV main bus up to the transformer
terminals will provide improved protection.

Omitting a secondary main from a double-ended substation (in this case, double-ended substation refers to
a substation with two sources and a tie device on the bus that can be used to separate the sources) is not
recommended. A fault on a transformer primary, which is directly connected to the main LV bus by the
transformer, would be fed from both sources. The current from the opposite transformer is limited by the
impedance of the two transformers. It might be small and difficult to detect by the overcurrent protection from
the far transformer, and it might last for a long time causing significant damage and hazard.

12.3 Selection of transformer primary fuses for arc-flash protection on the

transformer secondary bus
Selecting the optimum E-rated fuses (ANSI/IEEE C37.42) for transformer primary protection can reduce arc-
flash incident energy levels at the secondary terminals to less than 40 calories/cm2 in selected circumstances.
Standard fuse application for transformer protection allows selecting fuses that meet codes and applicable
standards, but when selected only per NEC requirements and acceptable selectivity, these might provide less
protection to the transformer or secondary circuits than is desired. A fuse selected in this manner might be
larger than necessary and provide less than optimal secondary arc-flash protection and transformer protection.

A fuse is only current-limiting when the fault current is sufficiently large to drive fuse performance into the
fuse current-limiting range, above the threshold current, or current limiting threshold. If the fuse is selected
with a larger current rating than needed, the threshold current is larger than might be prudent. The goal is to
select a fuse size and type with a threshold current that is less than the least-expected secondary arcing current
when reflected to the primary voltage. However, even if the secondary arcing fault current is less than the MV
fuse current-limiting threshold, applying a fuse with an inverse time characteristic will shorten the duration of
the arc current, resulting in less incident energy and less equipment damage at the secondary bus between the
transformer and the first LV primary device.

The selection process of a primary fuse should include the following:

— Systems considerations such as maximum load current expected, steady-state and transient current,
available source fault current, expected secondary arcing current;
— Transformer characteristics such as impedance, magnetizing current, applicable damage curves,
output power, kVA; short-circuit voltage; service voltage; operation with or without overload;
— Local code requirements;
— Fuse characteristics for the multiple fuses considered such as:
— Rated currrent, the current that the fuse can withstand without abnormal heating;
— Minimum interrupting current, the minimum current that can melt the fuse. Generally, fuses should
not be applied where the sustained load could range above fuse rating and below minimum melting
current.

By selecting a smaller fuse ampere rating and a more extreme inverse-time characteristic, the incident energies
may be substantially lessened at the secondary LV equipment. If the selection process is followed properly,
the system should not have nuisance fuse openings and still be selectively coordinated. It is important to
follow fuse manufacturers’ guidelines and understand the expected transformer needs when tighter protection
is implemented to not incur nuisance operation of the fuses upon energization of the transformer.

12.4 Zone-selective interlocking across a substation transformer

LV circuit-breaker trip unit systems often provide ZSI capability that allows trip units to be selective
while providing minimally delayed protection. In modern circuit-breaker trip unit systems, zone-selective
interlocking is available for ground-fault protection, short-time protection, and even instantaneous protection.

In component relays typically used in MV systems, a similar capability might go by various names such as
blocking or instantaneous blocking systems. In both the LV and MV implementations, the basic theory is the
same. In a distribution system composed of multiple tiers of devices, the load-side lower tiers send a signal to
line-side upper tiers when sensing a fault above a preset threshold. The upper tier devices receive the signal
and using internal logic, alter their tripping characteristics, typically slowing their response to allow the load-
side device to clear the fault. The zone interlocking can be described as forcing the line-side device to shift to a
backup protection role in the interest of maximizing selectivity.

The ability to extend the interlocking capability between the last primary protective device and the first
secondary device is advantageous because it provides protection of the transformer secondary terminals
and connected conductors without the need to compromise protection or selectivity. Also, there is no need
to include long secondary conductors within a transformer differential scheme. Figure 26 shows multiple
ways to design a scheme that uses LV-to-MV interlocking to protect the transformer primary and transformer
secondary without sacrificing system reliability.

Protection of the transformer primary and secondary might be implemented using two separate relays or two
protective elements within one relay. Sensing for secondary faults might be done using CTs located on the
transformer primary or secondary. Secondary sensing might be easier to set sensitively because the transformer
inrush current does not need to be considered. When the transformer secondary is a solidly grounded wye,
attention must be paid to ground faults that are lesser magnitude and are also reduced to 58% of the ground
current when sensed at the primary side (because of the wye-delta winding).

In 25(a) the zone-interlocking signal is routed from the LV equipment feeders to the LV main, and from the
LV main to the MV relay. To improve the sensitivity of the MV relay protection, the restraint signal could be
taken directly from the LV feeders allowing the LV main and MV transformer feeder to operate for equivalent
faults—it makes no difference to the reliability of the substation.

In 25(b) the secondary LV circuit breaker is not included. In this configuration, the MV primary device is
operated as an LV main. This configuration is not recommended for substations with multiple sources that
could result in transformers energized from the LV side.

In 25(c) one or more relays can be used to implement transformer-differential and overcurrent protection
of load-side conductors simultaneously. This configuration might be easier to implement than a transformer
differential scheme that includes the secondary conductors within the zone of protection. Various
considerations might affect the selection of a scheme that includes the secondary bus in the differential zone of
protection or relies on protection with a 50/51 device. The considerations are the following:

— Length of secondary conductors and distance between sensors in the secondary equipment and the MV
relay;
— Required size of secondary CTs required for differential protection might be difficult to locate within
the LV equipment;
— Desensitizing differential sensing required to account for transformer magnetizing current;
— Access to a fast blocking signal from an LV trip unit or protective relay system;
— Ability and time to process a blocking signal for 50/51 protective elements.

Discussed in 8.4 is the subject of modeling the settings and timing of an LV-side sensing scheme interlocked
with MV-side protection. The figures below depict the implementation of the three different transformer
secondary bus protection schemes discussed in this subclause.

Figure 25—Interlocking secondary-protective devices to primary-protective devices

13. Low-voltage bus conductors, switchgear, switchboard, and motor

control-center protection
LV switchgear listed to UL 1558 and built to IEEE C37.20.1 standards have a short-circuit rating and a
short-time withstand rating. Low-voltage equipment such as switchboards listed to UL 891, motor-control
centers listed to UL 845, and panelboards listed to ANSI/UL67 have short-circuit ratings but do not have a
requirement, per standard, for a short-time withstand rating. Manufacturers might offer a short-time withstand
rating, but this will apply, usually, only to the main horizontal bus. Within IEC standards, a single standard is
used to define the multiple types of LV power distribution equipment, and short-time withstand ratings are
optional for all equipment types.

LV power circuit-breaker switchgear built to the IEEE C37.20.1 standard can only employ LV power circuit
breakers (LVPCB). These circuit breakers can be supplied both with and without series fuses. Switchboards
and motor-control centers can be designed to include LVPCBs, molded case circuit breakers (MCCB), or
fusible load-break switches. Each of these protective devices has different characteristics that should be
considered from the bus protection perspective. Equipment manufacturers generally implement protective
devices that are compatible with the capabilities of the equipment. Implementing external protective relays to
provide protection by operating LVPCB without using the circuit breaker’s integral protection as backup can
cause circuit breakers to operate slower than the equipment can withstand. If relays are required for complex
protection or control applications, the circuit breaker trip should be included to ensure that protection is no
slower than the equipment or circuit breaker can withstand. For protection where fast instantaneous fault
clearing is required, it is likely that the integral trip will be faster than an external protective relay.

Equipment buses protected by current-limiting fuses will, under most circumstances, be well coordinated and
well protected from large-magnitude bolted-fault currents occurring within the equipment or flowing through
the equipment. However, as fuse continuous rating increases, they may provide slow protection for lesser-
magnitude arcing currents, and the protection might not be enough for adequate arc-flash incident energy
mitigation. If arc-flash incident-energy mitigation is expected to be provided by LV fuses, it is important
to verify that expected arcing currents are large enough to cause the fuses to operate at the speed required
to provide the desired level of arc-flash incident energy mitigation desired. Equipment buses protected by

LVPCB13, or large insulated case circuit breakers14 might use nested delays to achieve selectivity. Multiple
levels of circuit breakers coordinated with nested delays might result in main breakers with short-time clearing
times of several hundred milliseconds. Nested delays might also result in main or even feeder circuit breakers
with decreased sensitivity and increased clearing times at the levels required to protect against arcing faults,
resulting in slower clearing times and significant incident energy and equipment damage.

Instantaneous trips in circuit breakers provide faster protection than short-time delays; however, these can
negatively impact selectivity. Methods to coordinate circuit breakers with instantaneous trips have been
developed by various manufacturers. Manufacturers should be consulted to properly optimize the selectivity
that might be possible using any one manufacturer’s device(s). The protection afforded by short delays can
also be improved with the use of zone-selective interlocking schemes between circuit breakers and ground-
fault relays in fusible switches. Bus-differential protection is another protection scheme that might be used to
protect LV buses. Using a combination of these capabilities can provide protection that is sensitive to a wide
range of bus-fault magnitudes while maintaining selectivity for large fault magnitudes. For further reading on
this subject, see NEMA publications on selectivity [B25] and [B26] as well as Valdes et al. [B41].

14. Special considerations for arc-flash hazard reduction

IEEE Std 1584 defines arc-flash hazard as “a dangerous condition associated with the release of energy
caused by an electric arc.” The degree of hazard is affected by the amount of time required by the overcurrent
protective device to clear the arcing current. Protective device settings required to achieve reliable power
distribution system operation might result in overcurrent devices operating at clearing times slower than
these might otherwise be able to provide at the arcing current predicted. One potential technique to reduce
operating times temporarily, when improved protection might be preferred over optimized selectivity, is to
use an alternate settings group. Many digital microprocessor-based relays can provide a second set of settings
(via a setting-group change) that might be easily or remotely enabled for temporary improved protection. LV
circuit breakers can also provide temporary settings that might lower the pickup or enable the instantaneous
trip of a circuit breaker as well as override short delays or reduce instantaneous clearing times. Specific
implementations of this function vary by manufacturer.

Remote operation of circuit breakers or switches and remote racking capability might also be employed to
reduce the exposure of operating personnel to arc-flash hazard and should be considered whenever possible.
Most devices available in the industry have capability for remote operation. Use of digital microprocessor-
based relays in MV systems and digital trips in LV systems, both of which can use powerful communication,
allow implementation of remote control, metering, and diagnostic systems that can significantly reduce the
need for operating personnel to enter the flash protection boundary. Because of the increased safety these
methods provide, these capabilities should be considered whenever possible and practicable.

IEC MV equipment standards (IEC 62271-200 2011) specifically address this same concern by describing
these “supplementary” measures to provide additional personnel protection:

a) Fast fault clearing via light, pressure, heat, or differential current sensing protection;
b) Controllable type fuses made up of a current limiting fuse in parallel with a current path that can be
opened quickly to commutate the current to the parallel current limiting path;
c) Extremely fast elimination of the arc by diverting the current to an arc quenching device that shunts
fault current and collapses voltage to eliminate the arcing fault;
d) Remote operation of equipment;

13
Low-voltage power circuit breakers (LVPCB) are a specific type of LV circuit breaker which complies with IEEE Std C37.13. These
circuit breakers may also be listed devices under UL1066.
14
Insulated case circuit breakers are UL 489 listed circuit breakers that share some characteristics of LVPCB. See IEEE Std 3004.5 for
further information.

e) Pressure relief mechanism;

f) Closed door draw-out.

15. Arc quenching devices (AQDs)

Another way to provide bus protection is to use a shunt energy-diversion device called an arc quenching device
(AQD) within IEC practices and sometimes referred to as a crowbar, shorting switch, or fast earthing switch.
These devices are connected as a load on the main bus or ahead of the main bus. When these are operated, they
close and provide a fault current path that collapses available voltage and quickly extinguishes any arcing
fault on the system. These devices have the advantage of providing very fast operation, they can extinguish
an arcing fault in less than a half cycle including sensing and control timing, depending upon the sensing and
control method used. The most common type is the zero-impedance or solid-conductor crowbar. The solid
conductor devices cause bolted-fault current to flow and hence a near complete collapse of system voltage. The
solid-conductor type devices have been used in Europe with success for several years. The solid-conductor
type crowbar is, generally, a one-time-use device and might be applied as temporary protection to be used
only during hazardous maintenance activity. It is possible that the high current caused by devices that fully
short circuit the connected bus can stress system components, and that risk should be considered. Therefore,
some shunt-energy devices that rely on the limited-impedance of a controlled have been introduced for LV
applications. Due to the arc impedance, these devices do not draw full bolted-fault current, thus stressing
system components less and lessening the risk of system damage during an operation. However, these limited-
impedance devices may have a more restricted range of application. Arc-fault mitigation is similar for both
types of devices. Because arc-quenching devices are connected in parallel to the bus system, tap cables can
connect to existing systems to reduce arc-flash hazard as part of an arc-flash hazard mitigation project.

When considering use of this kind of device, the manufacturer should be consulted and applicability to the
system carefully considered. These devices have excellent arc-flash, incident-energy mitigation, and in
some applications, such as a retrofit in an existing installation, these might provide one of very few practical
alternatives to achieve small levels of incident energy. However, there are risks and limitations that must be
considered in consultation with the respective manufacturers.

Arc quenching devices may be controlled with arc-flash relays (see Clause 16), simple overcurrent detection,
differential relays, and other sensing logic. This logic might be implemented in a continuous protection mode
or as part of a temporary protection scheme used during hazardous maintenance or operation activity. The
latter is sometimes recommended because of the possible impact or cost of nuisance operation. For further
reading concerning shunt energy absorbing devices, see Kay et al. [B23] and Roscoe et al. [B31].

Shorting switches have been used to create a low impedance path for fault current in some MV and HV circuits
to ensure that overcurrent relays protecting the circuit sensed the current as fast as possible. These same
devices, and others like them, are now also used for arc-flash protection as described in this subclause.

Figure 26—Two of several ways to implement a MV AQD for LV protection of a substation

secondary bus

16. Arc-flash relays

Arc-flash relays are protective devices specifically designed to sense an electrical explosion as evidence by
the sensor or sensing method they implement. The most common relay is based on sensing light. Others may
use sound or pressure. Most arc-flash relays can also use a current signal to corroborate the primary light or
pressure signal is not caused by a source other than an arcing current fault within the protected volume. This
type of relay has been in use in IEC practices for MV equipment for over a decade and can provide very fast
protection from arcing faults. Relays may assert a fault via its output contact in 1 or 2 ms. Most will operate in
less than half a cycle. However, if used with current confirmation, the response may be slower. In some cases,
other relays such as standard feeder protection relays (50/51) or other protection relays of various types may
allow implementation of additional light sensors to complement the overcurrent protection they provide.

When implementing a light-based arc-flash relay, it is important to understand that the relay is a volume
protector, not a circuit protector. It can sense that there is light above threshold within the volume the sensors
are applied. But it cannot differentiate one circuit from another if there are multiple circuits within the volume,
nor can they detect a remote arcing fault within a circuit if the fault is within a remote volume.

Light-based relays can also nuisance operate if they perceive light from another source as being light caused
by an accidental arcing event. Current-sensing based confirmation is implemented to protect against this
possibility; however, light could be caused by an electromagnetic air circuit breaker interrupting a remote
fault within the protected volume. Current sensing may not differentiate the light from an interrupting circuit
breaker or from a non-electrical source, from the light generated by an accidental electrical arc. Arc-flash relays
implemented near fuses, sealed vacuum circuit breakers, or gas insulated equipment would not be subjected to
light from the operation of those devices. If using an arc-flash relay around low voltage circuit breakers, it may
be advisable to use the relay only during maintenance or implement another method to minimize the possibility
of a nuisance operation due to an interrupting LV circuit breaker. See Roscoe et al. [B32] for additional reading
on this subject. In articles 240.67 and 240.87 of the NEC (2017), there is a function referred to as an energy

reducing switch (ERMS) that is expected to be used only during maintenance similar to how it is suggested for
an arc-flash relay in applications where a nuisance trip presents an unacceptable risk.

As with all protective relays, it is important to not confuse the relay operating time with fault clearing time.
Fault clearing time must include the controlled circuit breaker operating time as well as any intermediary
relays or other sources of delay.

When considering use of an arc-flash relay, the manufacturer should be consulted for exact application
guidelines as they may vary from manufacturer to manufacturer.

17. Triggered current limiters (TCLs)

A triggered current limiter, sometimes also called a commutating current limiter, is a device that consists of
a main current conducting path with a parallel current limiting fuse. During normal operation current mostly
flows through the main current path. Typically, some type of very fast integral relay and sensing is provided
that, based upon a user set trigger threshold, will open the main conducting path commutating the current to
the current limiting fuse, which then interrupts the current very quickly. Often these devices will require that
components be replaced after a fault operation. The devices are only designed for fault operation and are not
used for normal switching applications. Devices are available for application for the LV and MV range.

In addition to opening very fast, these devices can be used as fault current limiters to protect otherwise
underrated equipment; however, they should not be used for that purpose in new system designs if full rated
equipment is available. In some applications, such as retrofitting existing installations, these devices may
provide one of few practical alternatives to achieve lower levels of incident energy or protect equipment that
is underrated for the available prospective short-circuit current. However, there are limitations that must be
considered in consultation with the respective manufacturers.

18. Voltage-surge protection

Protection against voltage surges should be considered for all switchgear assemblies that have exposed
circuits. Exposed circuits are those outside buildings or those that do not have adequate surge protection
connected to limit voltages to less than the withstand level of the switchgear. A circuit connected to open-line
wires through a power transformer is not considered exposed if adequate protection is provided on the line side
of the transformer. Circuits confined entirely to the interior of a building, such as an industrial plant, are not
considered exposed to lightning surges and might not require lightning surge protection. Contact the utility
serving the premises to determine the possibility of switching surges resulting from capacitor switching.

Coordinate the system voltage rating with the surge arrester voltage rating for surge protection selectivity
when protection is installed on transformer primary. Consult with the manufacturers for application.

For further discussion of voltage surge protection, see Chapter 6 in IEEE Std 141 (IEEE Red Book™), 7.8 of
IEEE Std C37.20.3-2001, IEEE Std C62.22, and IEEE Std C62.92.1.

19. Conclusions
Because of its importance in the electric power system, the bus and switchgear should be designed, located,
and maintained to prevent faults as well as to protect quickly when faults happen. System reliability and
safety is promoted by good protection as well as by good systems design; designing for maintainability, future
expansion when applicable, and by considering prevention through design practices that maximize safety for
maintenance and operating personnel. IEEE standards in the 3007 series of operation, maintenance, and safety
standards [B15], [B16], and [B17] offer guidance on these subjects.

The preferred protection practice for switchgear buses applied at 1 kV or greater is differential protection.
But today, in an arc-flash conscious world, differential protection should be considered for LV buses as well.
In LV systems, arcing currents can be substantially lower than bolted fault currents, hence the sensitivity of
protection is as important as the operating time. Differential protection can get around the need to use ever
increasing thresholds that eventually cause important bus protection to be insufficiently sensitive to provide
desired protection. For additional reading, see Pavavicharn et al. [B29] and Rifaat [B30]. Arc-flash relays
provide an alternative to bus differential protection or a way to compliment bus differential protection. Light-
based sensing technology has been available for several years but is rapidly evolving with new products
frequently being introduced into the market.

Improved zone-selective-interlocking capabilities available in protective relays and integral LV trip units
provide additional ways to improve bus protection over traditional nested threshold and nested static time
delay-based selectivity. Protection of buses, such as the one between a distribution transformer’s terminals and
the first secondary overcurrent protector, is important for arc-flash protection as well as for system reliability.
Today, multiple manufacturers offer systems, devices, and protection schemes specifically targeting buses in
LV substations including the bus between the secondary substation transformer LV terminals and the first LV
overcurrent device in the system. Such protection may not have been considered important enough to warrant
the cost or complexity just a few years ago, but today the importance has grown and the complexity and cost
are lower. For further reading, see Valdes et al. [B41], and Hodgson and Shipp [B8].

Modern digital relays with embedded computers able to handle complex computational tasks and complex
logic are commonly and more cost effectively available from multiple manufacturers. Advances in electronics
and sensing facilitate improvements in the products available. Schemes that in the past required many dedicated
CTs connected to dedicated single function relays can now be implemented with fewer CTs connected to
multifunction protective relays. Additional communications, metering, and diagnostic capabilities provided
by the same relays add to the value provided by the investment and expand the range of benefits the devices
can provide. The industry has also introduced new switching devices that allow relay-controlled protection in
applications that formerly were relegated to simpler and lower cost but more limited protection. How a bus
is configured is also important to its long-term protection. How it is connected to its sources, interconnection
circuit breakers or ties, bus transfer schemes, and other factors will affect safety, ability to maintain system
reliability, and the capability for future growth. How reliable and well protected a bus is will depend on these
factors as well as on the relaying used. Location of the equipment in a good environment and maintenance on
a planned basis helps prevent faults, may prevent nuisance operations by protective devices, and ensures the
devices operate as expected when called upon to do so. If a fault does occur, high-speed, sensitive relaying
limits the damage so that repairs can be made quickly, and service is restored in a short time. Fast clearing of
arcing faults also can save lives by minimizing the electrical explosion and consequent arc-flash hazard.

Modern technology and continuous innovation provide an ever-increasing array of alternatives; it is up to the
system design and protection engineer to fully take advantage of them.

Annex A
(informative)

Bibliography
Bibliographical references are resources that provide additional or helpful material but do not need to be
understood or used to implement this standard. Reference to these resources is made for informational use
only.

[B1] Apostolov, A., “IEC 61850 Based Bus Protection—Principles and Benefits,” IEEE Power and Energy
Society General Meeting, pp. 1-6, 2009, http://dx.doi.org/10.1109/PES.2009.5275403.

[B2] Apostolov, A. and D. Tholomier, “Impact of IEC 61850 on Power System Protection,” IEEE PES Power
Systems Conference and Exposition, 2006. PSCE, 2006.

[B3] Beckmann, J. J., D. Dalasta, E. W. Hendron, and T. D. Higgins, “Service Supply Line Protection,”
IEEE Transactions on Industry and General Applications, vol. IGA5, pp. 657-671, November/
December 1969, http://dx.doi.org/10.1109/TIGA.1969.4181091.

[B4] Behrendt, K., K. Costello, and S. Zocholl, “Considerations for Using High-Impedance or Low-Impedance
Relays for Bus Differential Protection,” 63rd Annual Conference for Protective Relay Engineers (Sponsored
by IEEE Power and Energy Society and Texas A&M University), pp. 1-15, 2010, http://dx.doi.org/10.1109/
CPRE.2010.5469509.

[B5] Cable, B. W., L. J. Powell, and R. L. Smith, “Application Criteria for High-Speed Bus
Differential Protection,” IEEE Transactions on Industry Applications, vol. IA-19, no. 4, July 1983, http://
dx.doi.org/10 .1109/TIA.1983.4504263.

[B6] CSA C22.1, Canadian Electrical Code (CEC).

[B7] Franklin, R. et al., “High-Impedance Differential Applications, With Mismatched CTs,” Proceedings of
the Western Protective Relay Conference, Spokane, WA, October 2017.

[B8] Hodgson, D. L. and D. Shipp, “Arc-Flash Incident Energy Reduction Using Zone Selective
Interlocking,” IEEE Transactions on Industry Applications, vol. 46, no. 3, pp. 1243-1251, 2010, http://
dx.doi.org/10.1109/ TIA.2010.2046284.

[B9] Holbach, J., “Comparison Between High Impedance and Low Impedance Bus Differential Protection,”
IEEE Power Systems Conference 2009, Clemson, SC, USA.

[B10] IEC 61850:2017, SER Series: Communication networks and systems for power utility automation—All
parts.

[B11] IEEE Std 142™ (IEEE Green Book™), IEEE Recommended Practice for Grounding of Industrial and
Commercial Power Systems.

[B12] IEEE Std 242™ (IEEE Buff Book™), IEEE Recommended Practice for Protection and Coordination of
Industrial and Commercial Power Systems.

[B13] IEEE P3004.3™/D1b-2017, IEEE Draft Recommended Practice for the Application of Low-Voltage
Fuses in Industrial and Commercial Power Systems.

[B14] IEEE Std 3004.8™, IEEE Recommended Practice for Motor Protection in Industrial and Commercial
Power Systems.

[B15] IEEE Std 3007.1™, IEEE Recommended Practice for the Operation and Management of Industrial and
Commercial Power Systems.

[B16] IEEE Std 3007.2™ IEEE Recommended Practice for the Maintenance of Industrial and Commercial
Power Systems.

[B17] IEEE Std 3007.3™, IEEE Recommended Practice for Electrical Safety in Industrial and Commercial
Power Systems.

[B18] IEEE Std C37.20.9™, IEEE Standard for Metal-Enclosed Switchgear Rated 1 kV to 52 kV Incorporating
Gas Insulating Systems.

[B19] IEEE Std C37.95™-2014, IEEE Guide for Protective Relaying of Utility-Consumer Interconnections.

[B20] IEEE Std C37.119™, IEEE Guide for Breaker Failure Protection of Power Circuit Breakers.

[B21] IEEE Std C37.234™, IEEE Guide for Protective Relay Applications to Power System Buses.

[B22] Kasztenny, B., G. Brunello, and L. Sevov, “Digital low-impedance bus differential protection with
reduced requirements for CTs,” Transmission and Distribution Conference and Exposition, 2001 IEEE/PES,
http://dx.doi.org/10.1109/TDC.2001.971325.

[B23] Kay, J. A., J. Arvola, and L. Kumpulainen, “Protecting at the Speed of Light,” IEEE
Industry Applications Magazine, vol. 17, no. 3, pp. 12-18, 2011, http://dx.doi.org/10.1109/
MIAS.2010.939635.

[B24] Mello, M., M. Noonan, M. Valdes, and J. Benavides, “Arc-Flash Hazard Reduction at Incoming
Terminals of LV Equipment,” IEEE Petroleum and Chemical Industry Technical Conference, 2014.

[B25] NEMA AB5-2016, Establishing Levels of Selective Coordination for Low Voltage Circuit Breakers.

[B26] NEMA ABP-1-2010, Selective Coordination of Low-Voltage Circuit Breakers.

[B27] NEMA PB2.2, Application Guide for Ground-Fault Protective (GFP) Devices for Equipment.

[B28] Paul, D. and B. Chavdarian, IEEE Industry Applications Magazine, vol. 21, no. 1, pp. 23-32, 2015.
Available at: , http://dx.doi.org/10.1109/MIAS.2014.2345797.

[B29] Pavavicharn, S. and G. Johnson, “A review of high-impedance and low-impedance differential

relaying for bus protection,” IEEE 67th Annual Conference for Protective Relay Engineers, March 31,
2014-April 3, 2014, College Station, TX, pp. 723-737, http://dx.doi.org/10.1109/CPRE.2014.6799038.

[B30] Rifaat, R. M., “Considerations in applying power bus protection schemes to industrial and IPP
Systems,” IEEE Transactions on Industry Applications, vol. 40, no. 6, pp. 1705-1711, November-December
2004, http:// dx.doi.org/10.1109/TIA.2004.836223.

[B31] Roscoe, G., T. Papallo, and M. Valdes, “Arc-flash energy mitigation by fast energy capture,” 56th
Annual Petroleum and Chemical Industry Conference, IEEE Industry Applications Society Record of
Conference Papers, pp. 1-9, 2009.

60
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IEEE Std 3004.11-2019
IEEE Recommended Practice for Bus and Switchgear Protection in Industrial and Commercial Power Systems

[B32] Roscoe, G., M. E. Valdes, and R. Luna, “Methods for arc-flash detection in electrical equipment,” 57th
Annual Petroleum and Chemical Industry Conference (PCIC), IEEE Industry Applications Society Record of
Conference Papers, pp. 1-8, 2010, http://dx.doi.org/10.1109/PCIC.2010.5666877.

[B33] Simpson, R. H., “NEC Design Compliance, System Protection and Arc-Flash Hazard,”
IEEE Transactions on Industry Applications, vol. 49, no. 4, pp. 1928-1936, 2003, http:// dx .doi .org/
10.1109/TIA .2013.2256768.

[B34] Thompson, M. J., “Percentage Restrained Differential, Percentage of What?” Proceedings of the 37th
Annual Western Protective Relay Conference, Spokane, WA, October 2010.

[B35] UL 67, UL Standard for Panelboards.

[B36] UL 347-CSA C22.2 No. 253—NMX-J-564–106-ANCE, Standard for Safety for Medium-Voltage AC
Contactors, Controllers, and Control Centers.

[B37] UL 845, UL Standard for Safety for Motor Control Centers.

[B38] UL 891, UL Standard for Switchboards.

[B39] UL 977, UL Standard for Fused Power-Circuit Devices.

[B40] UL 1066, UL Standard for Low-Voltage AC and DC Power Circuit Breakers Used in Enclosures.

[B41] Valdes, M. E. and J. Dougherty, “Advances in Protective Device Interlocking for Improved
Protection and Selectivity,” IEEE Transactions on Industry Applications, vol. 50, no. 3, pp. 1639-1648,
2014, http://dx .doi.org/10.1109/TIA.2013.2285941.

[B42] Valdes, M., P. Hamer, T. Papallo, R. Narel, and B. Premerlani, “Zone Based Protection for Low-voltage
Systems; Zone Selective Interlocking, Bus Differential and the Single Processor Concept,” IEEE Petroleum
and Chemical Industry Technical Conference, pp. 1-10, 2007, http://dx.doi.org/10.1109/PCICON.2007
.4365789.

[B43] Valdes, M. E., S. Hansen, and P. Sutherland, “Optimized Instantaneous Protection Settings:
Improving Selectivity and Arc-Flash Protection,” IEEE Industry Applications Magazine, vol. 18, no. 3, pp.
66-73, 2012, http://dx.doi.org/10.1109/MIAS.2012.2186008.

[B44] Valdes, M. E., I. Purkayastha, and T. Papallo, “The Single-Processor Concept for Protection and Control
of Circuit Breakers in Low-Voltage Switchgear,” IEEE Transactions on Industry Applications, vol. 40, no.
4, pp. 932-940, 2004, http://dx.doi.org/10.1109/TIA.2004.831270.

[B45] Valdes, M. E. and L. Sevov, “Considerations for Differential Protection in Low Voltage Buses,”
IEEE Industry Applications Magazine, 2017.

[B46] Zocholl, S. E. and D. Costello, “Application Guidelines for Microprocessor-Based, High-Impedance

Bus Differential Relays,” Proceedings of the 62nd Annual Conference for Protective Relay Engineers, College
Station, TX, March 2009, http://dx.doi.org/10.1109/CPRE.2009.4982532.

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Ieee 3004.11

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Ieee 3004.11

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IEEE 3004 STANDARDS:

PROTECTION & COORDINATION

IEEE Std 3004.11-2019

IEEE Recommended Practice

Industrial and Commercial Power Systems Standards Development Committee

Approved 5 September 2019

IEEE SA Standards Board

The Institute of Electrical and Electronics Engineers, Inc.

Copyright © 2019 by The Institute of Electrical and Electronics Engineers, Inc.

PDF: ISBN 978-1-5044-6124-5 STD23863

IEEE prohibits discrimination, harassment, and bullying.

Notice and Disclaimer of Liability Concerning the Use of IEEE Standards

Comments on standards should be submitted to the following address:

Secretary, IEEE SA Standards Board

Laws and regulations

Updating of IEEE Standards documents

Rasheek Rifaat, Chair

Paul Cardinal Richard Hunt Suparat Pavavicharn

Ali Al Awazi Rostyslaw Fostiak Saumen Kundu

Gary Hoffman, Chair

Masayuki Ariyoshi David J. Law Annette D. Reilly

IEEE 3000 Series®

— Power Systems Design (3001 series)

IEEE Std 3004.11™

8. Zone-selective interlocking and blocking techniques�������������������������������������������������������������������������������� 31

14. Special considerations for arc-flash hazard reduction����������������������������������������������������������������������������� 54

1.1 General discussion

— Increased short-circuit levels;

— Opened electrically by circuit breakers responding to protective-relay action;

— Panelboards (UL 67 [B35]),

When supplementary bus-differential protective relaying, zone-selective-interlocking (ZSI), or any other

1.2 Word usage

CSA C22.1, Canadian Electrical Code.4

CSA Z462, Canadian Workplace Electrical Safety Standard.

IEEE Std C37.20.2™, IEEE Standard for Metal-Clad Switchgear.

IEEE Std C37.20.3™, IEEE Standard for Metal-Enclosed Interrupter Switchgear.

NFPA 70, National Electrical Code® (NEC®).7

NFPA 70E, Standard for Electrical Safety in the Workplace.

UL 1053, Ground-Fault Sensing and Relaying Equipment.8

4. Types of buses and arrangements

4.2 Voltage ranges

Figure 1—Simple single-source radial substation

Figure 2—Simple single-source radial substation using one set of CTs

Figure 3—CT location reference diagram

5.1 Double-ended substations with two tie CB in series

— The location of the realistic probabilities of failure;

Copyright © 2019 IEEE. All rights reserved.

6. The need for fast bus protection

Equipment can be damaged by three fault-current-caused effects:

— The time to recover from a fault event;

— How the equipment will be operated and maintained;

7. Bus overcurrent protection

a) Any service disconnecting means rated 1000 A or more (see 230.95);

Figure 10—Required maximum characteristic points for low-voltage, ground-fault

7.3 Ground-fault protection on LV ungrounded or impedance grounded buses

7.4 Medium-voltage (MV) and high-voltage (HV) bus ground-fault protection

— When supplied by a user-owned transformer or generator, an inverse-time or definite-time overcurrent

8. Zone-selective interlocking and blocking techniques

8.2 Coordination studies and delay settings in ZSI schemes

8.3 In-zone, unrestrained-protection and restrained backup-protection

Figure 12—Backup settings alternatives in a zone-selective interlocking scheme

8.4 ZSI schemes and protection algorithms

8.5 ZSI signal timing and creation of custom blocking schemes

8.6 Circuit breaker failure schemes as backup bus protection

Figure 15—Comparison of zone-selective-interlocking logic to a circuit breaker failure logic

Figure 16—Single-bus scheme with bus-differential protection and other overlapping

Figure 17—Sectionalized-bus scheme with bus-differential relaying, overlapping tie-circuit-

Figure 18—Double-bus scheme with bus-differential relaying and other overlapping

The differential protection methods generally used are the following:

— High-impedance differential relaying

Figure 19—Simple current-differential scheme using overcurrent relay

9.2 High-impedance bus-differential relays

Figure 20—High-impedance bus-differential scheme (high impedance bus differential relays

— Through faults that saturate one or more of the CTs;

See Behrendt et al. for further reading on high-impedance relays [B4].

9.2.2 Through-fault operation

8. Zone-selective interlocking and blocking techniques�� 31

14. Special considerations for arc-flash hazard reduction�� 54