Power System Protection E-Book

John Ciufo

• Herausgeber: John Wiley & Sons
• Kategorie: Wissenschaft und neue Technologien
• Serie: IEEE Press Series on Power Engineering
• Sprache: Englisch

Seitenzahl: 826

Veröffentlichungsjahr: 2021

Beschreibung

An all-in-one resource on power system protection fundamentals, practices, and applications

Made up of an assembly of electrical components, power system protections are a critical piece of the electric power system. Despite its central importance to the safe operation of the power grid, the information available on the topic is limited in scope and detail.

In Power System Protection: Fundamentals and Applications, a team of renowned engineers delivers an authoritative and robust overview of power system protection ideal for new and early-career engineers and technologists. The book offers device- and manufacturer-agnostic fundamentals using an accessible balance of theory and practical application. It offers a wealth of examples and easy-to-grasp illustrations to aid the reader in understanding and retaining the information provided within.

In addition to providing a wealth of information on power system protection applications for generation, transmission, and distribution facilities, the book offers readers:

• A thorough introduction to power system protection, including why it's required and foundational definitions
• Comprehensive explorations of basic power system protection components, including instrument transformers, terminations, telecommunications, and more
• Practical discussions of basic types of protection relays and their operation, including overcurrent, differential, and distance relays
• In-depth examinations of breaker failure protection and automatic reclosing, including typical breaker failure tripping zones, logic paths, pedestal breakers, and more

Perfect for system planning engineers, system operators, and power system equipment specifiers, Power System Protection: Fundamentals and Applications will also earn a place in the libraries of design and field engineers and technologists, as well as students and scholars of power-system protection.

Leseprobe

Table of Contents

Cover

Series Page

Title Page

Copyright

About the Authors

Preface

Acknowledgements

1 What Is Power System Protection, Why Is It Required and Some Basics?

1.1 What Is Power System Protection?

1.2 Why Is Power System Protections Required?

1.3 Some Basic Protection System Terms and Information

References

2 Basic Power System Protection Components

2.1 General Description

2.2 Power System Protection Components

2.3 Physical Implementation

2.4 Power System Isolation Devices and Control Interfaces

2.5 Redundancy Arrangements

3 AC Signal Sources

3.1 Introduction

3.2 Current Transformers

3.3 Voltage Sources

References

Note

4 Basic Types of Protection Relays and Their Operation

4.1 General

4.2 Fundamental Principles and Characteristics

4.3 Overcurrent

4.4 Differential

4.5 Distance

Reference

5 Protection Information Representation, Nomenclature, and Jargon

5.1 General

5.2 Protection Drawing Types

5.3 Nomenclature and Device Numbers

5.4 Classification of Relays

5.5 Protection Jargon

Reference

6 Per‐Unit System and Fault Calculations

6.1 General

6.2 Per‐Unit

6.3 Fundamental Need for Fault Information

6.4 Symmetrical Components

6.5 Sequence Impedances of Power Apparatus

6.6 Balanced Fault Analysis

6.7 Sequence Networks

6.8 Summary of Unbalance Fault Calculations

6.9 High‐Level Summary of the Fault Calculation Process

6.10 Useful Fault Calculation Formulas/Methods

6.11 Fault Calculation Examples

References

7 Protection Zones

7.1 Protection Zones General

7.2 Zones Defined

7.3 Zone Overlap Around Breakers

7.4 Protection Zoning at Stations

7.5 Protection Zones in General

7.6 Backup Protection

7.7 CT Configuration and Protection Trip Zones

7.8 Where Protections Zones do not Overlap Around Breakers

7.9 Lines Terminating Directly on Buses at a HV Switching Station

8 Transformer Protection

8.1 Introduction

8.2 General Principles

8.3 Differential Protection Power Transformers

8.4 Percent Differential Protection Autotransformers

8.5 Transformer Percent Differential Setting Examples

Reference

9 Bus Protection

9.1 Introduction

9.2 Typical Bus Arrangements

9.3 Bus Protection Requirements

9.4 Methods of Protecting Buses

9.5 Example High Impedance Differential Protection Setting

Reference

10 Breaker Failure Protection and Automatic Reclosing

10.1 Introduction

10.2 Breaker Failure General Background

10.3 Breaker Automatic Reclosing General Background

11 Station Protection

11.1 Introduction

11.2 Types of Stations

11.3 Station and Protection Architecture

11.4 Station Switchgear Type

11.5 Sub‐Transmission Types and Station Grounding

11.6 Master Ground

12 Capacitor Bank Protection

12.1 Capacitor Banks

12.2 Purpose for Shunt Capacitors on Power System Networks

12.3 Capacitor Bank Construction

12.4 Capacitor Bank Protection

12.5 Capacitor Bank Breakers

12.6 Capacitor Bank Sample Settings

Reference

13 Synchronous Generator Protection

13.1 Introduction

13.2 General

13.3 Generator/Unit Transformer Protections

13.4 Current Transformers

13.5 Generator Protection Sample Settings

13.6 Generator Control and Protection Systems Coordination

13.7 General Generator Tripping Requirements

13.8 Breaker Failure Initiation

Reference

14 Transmission Line Protection

14.1 General

14.2 Basic Line Protection Requirements

14.3 Impedance Relays and Why Not Just Overcurrent Relays

14.4 Distance Relay Response to Fault Types

14.5 Apparent Impedance

14.6 Redundancy/Backup

14.7 Tele‐Protection (Also Known as Pilot‐Protection)

14.8 General Implications

14.9 Peripheral Requirements of Distance Protection

14.10 Tele‐Protection (Pilot‐Protection) A Historical Perspective

14.11 Tele‐Protection via Power Line Carrier

14.12 Synchronous Optical Network (SONET)

14.13 Three‐Terminal Lines

14.14 Distributed Generation

14.15 Distance Relay Response to Resistive Faults

14.16 Power System Considerations

14.17 Line Current Differential Protection

14.18 Pilot Wire Protection

14.19 Power System Considerations

14.20 Line Setting Application Example

References

15 Subtransmission/Distribution Feeder Protection

15.1 Subtransmission/Distribution Characteristics

15.2 Definitions/Characteristics

15.3 Distribution Feeder Protection Devices

15.4 Protection Coordination Principles

15.5 Feeder Energization

15.6 Subtransmission Feeder Protection

15.7 Impact of Distributed Generators (DGs) on Distribution Feeder Protection

15.8 Feeder Protection Application Settings Example

References

Index

IEEE Press Series on Power and Energy Systems

End User License Agreement

List of Tables

Chapter 3

Table 3.1 Summary of CT secondary burden by CT connections.

Table 3.2 CT secondary burden by CT connections.

Table 3.3 Fully distributed CT winding and tapped ratios.

Chapter 6

Table 6.1 Base quantities summary.

Table 6.2 Typical line impedances.

Table 6.3 Typical transformer impedances.

Chapter 11

Table 11.1 Calculating the 1.544 Mb/s T1 Rate.

Table 11.2 T1 process.

Chapter 14

Table 14.1 Phase‐to‐phase fault Arc resistance.

Table 14.2 Typical 230 kV line impedances.

Table 14.3 Typical protection operating times.

Chapter 15

Table 15.1 Typical North American distribution voltages.

Table 15.2 Some HV fuse voltages ratings [3].

Table 15.4 Some typical ratings for three‐phase reclosers [7].

Table 15.3 Some typical North American ratings for single‐phase hydraulic co...

Table 15.5 “k” Factors for delayed curve of load‐side reclosure [8].

Table 15.6 Typical transformer short time loading [13].

List of Illustrations

Chapter 1

Figure 1.1 Illustration of a protection system for a transmission line [1]....

Figure 1.2 Environmental risk lightning strike – Dallas Tx.

Figure 1.3 Failed transformer on fire – Thessaloniki Greece.

Figure 1.4 Protection system characteristics leading to overall reliability....

Figure 1.5 Example of a dependable protection.

Figure 1.6 Example of a protection that is not secure.

Figure 1.7 Remote backup.

Figure 1.8 Local backup.

Chapter 2

Figure 2.1 Components and sub‐systems for a redundant transmission line prot...

Figure 2.2 Simplified block diagram of protective relay.

Figure 2.3 A conceptual illustration of a seal‐in circuit.

Figure 2.4 Simple breaker trip circuit from a protection relay.

Figure 2.5 Conceptual illustration of a circuit breaker trip control module....

Figure 2.6 A set of legacy protection panels on several racks for a line pro...

Figure 2.7 Mounting of legacy auxiliary logic.

Figure 2.8 A basic battery system (not all components shown).

Figure 2.9 Digital telecommunication equipment used for line protections.

Figure 2.10 An illustration of relays, panels, terminations, wiring, and iso...

Figure 2.11 Example of redundant CTs.

Figure 2.12 AC voltage inputs.

Figure 2.13 Breaker trip circuits illustration.

Chapter 3

Figure 3.1 Typical series connected CTs.

Figure 3.2 CT equivalent circuit.

Figure 3.3 Simplified CT equivalent circuit.

Figure 3.4 Bar‐type current transformer.

Figure 3.5 Bushing‐type current transformer.

Figure 3.6 Window‐type current transformer.

Figure 3.7 Wound‐type CT.

Figure 3.8 The polarity of current transformers.

Figure 3.9 Bushing CT showing primary current entering the spot.

Figure 3.10 Bushing CT showing primary current leaving the spot.

Figure 3.11 Two CTs with the secondary windings connected in series.

Figure 3.12 Bushing CTs connected differentially with an external fault.

Figure 3.13 Construction of multi‐ratio CTs.

Figure 3.14 Typical multi‐ratio bushing CT.

Figure 3.15 Electrical equivalent model of a CT with fully distributed windi...

Figure 3.16 Auxiliary current transformers and reflected burdens.

Figure 3.17 Typical excitation characteristic for a CT‐rated C800.

Figure 3.18 Electrical equivalent model of a C800 class CT.

Figure 3.19 Low primary fault current.

Figure 3.20 Secondary CT fault current during moderate saturation.

Figure 3.21 High primary fault current.

Figure 3.22 Secondary CT fault current during severe saturation.

Figure 3.23 Comparison of residual flux with a closed core and gapped core....

Figure 3.24 CT excitation characteristic with and without air gaps.

Figure 3.25 CT and relay connections – electromechanical.

Figure 3.26 Typical CT excitation characteristic curve rated C800.

Figure 3.27 CT and relay connections – digital relay.

Figure 3.28 Magnetic voltage transformer equivalent circuit.

Figure 3.29 Typical CVT diagram with a carrier interface.

Chapter 4

Figure 4.1 Torque production in an induction disc relay.

Figure 4.2 Shaded‐pole structure.

Figure 4.3 Torque control shaded‐pole structure.

Figure 4.4 Inverse time‐overcurrent characteristic.

Figure 4.5 Typical inverse time‐overcurrent relay of the shaded‐pole structu...

Figure 4.6 Various inverse current‐time characteristic types.

Figure 4.7 Operating time at 10x pickup in the example.

Figure 4.8 (a) Basic pickup current. (b) Basic pickup current taps.

Figure 4.9 Close‐up showing pickup taps and time dial.

Figure 4.10 Method of setting inverse time‐current characteristics.

Figure 4.11 Overcurrent protection of a simple radial line.

Figure 4.12 Example of the need for relay coordination.

Figure 4.13 Step‐timed coordination with definite time delays.

Figure 4.14 Time coordination with inverse time‐overcurrent.

Figure 4.15 Transformer damage curve, fuse melt curve, and inverse time‐over...

Figure 4.16 Single line diagram for the coordination example in Figure 4.15....

Figure 4.17 Need for directioning.

Figure 4.18 Current and polarizing voltage are in phase.

Figure 4.19 Current and polarizing voltage are out of phase.

Figure 4.20 Current transformer polarity and connections.

Figure 4.21 Watt‐hour meter structure.

Figure 4.22 Induction cup structure.

Figure 4.23 Watt‐hour meter structure as a directional overcurrent relay.

Figure 4.24 Phasor diagram showing the relationship of voltage and current f...

Figure 4.25 Generalized phasor relationship of voltage and current.

Figure 4.26 Phasor diagram – single phase directional relay with MTA 30° lea...

Figure 4.27 Quadrature connection of a single red phase directional relay.

Figure 4.28 Phasor diagram for three single‐phase directional overcurrent re...

Figure 4.29 Zero‐sequence voltage (3

V

0

) derived for polarization of ground d...

Figure 4.30 Zero‐sequence current derived for polarization of ground directi...

Figure 4.31 Zero‐sequence voltage derived for polarization of ground directi...

Figure 4.32 Simple differential connection using an overcurrent relay.

Figure 4.33 Simple differential connection method of operation – external fa...

Figure 4.34 Simple differential connection method of operation – internal fa...

Figure 4.35 Differential bus protection.

Figure 4.36 Waveform distortion for out‐of‐zone faults.

Figure 4.37 Short‐time inverse characteristic.

Figure 4.38 High impedance differential protection.

Figure 4.39 Percent differential relay.

Figure 4.40 Electromechanical percent differential relay basic construction ...

Figure 4.41 Electrical circuit representation of the percent differential re...

Figure 4.42 Operating characteristic for the percent differential relay (typ...

Figure 4.43 Operating characteristic for the percent differential relay (typ...

Figure 4.44 Fault detection using a simple overcurrent relay.

Figure 4.45 Fault detection using an impedance relay.

Figure 4.46 Simple impedance relay basic construction and operation.

Figure 4.47 Operating characteristic of an impedance relay.

Figure 4.48 Operating characteristic of an impedance relay on an

R

‐

X

diagram...

Figure 4.49 Two fault detecting techniques used for impedance relays.

Figure 4.50 Induction cup structure.

Figure 4.51 Operating characteristic of a Mho relay on an

R

‐

X

diagram.

Figure 4.52 Forward offset MHO characteristic.

Figure 4.53 Reverse offset MHO characteristic.

Figure 4.54 Operating characteristic of a reactance relay.

Figure 4.55 Offset Mho relay.

Figure 4.56 Blinder relay.

Chapter 5

Figure 5.1 (a) An example of a single‐line diagram. (b) An example actual st...

Figure 5.2 Three single‐phase and ground overcurrent relays and wye CTs.

Figure 5.3 Three single‐phase overcurrent relays and delta CTs.

Figure 5.4 An example transformer connection and protection.

Figure 5.5 Simple example DC, EWD, or DC control drawing.

Figure 5.6 Typical electrical arrangement diagrams.

Figure 5.7 Digital relay interfacing with telecommunication equipment.

Figure 5.8 (a) Rear connections of the digital relay. (b) Example relay conn...

Figure 5.9 An example DC, EWD for a digital relay (conceptual).

Figure 5.10 An example of a simple protection logic drawing.

Figure 5.11 Single‐line depicting protection function numbers.

Figure 5.12 Breaker and disconnect pallet switch representation.

Figure 5.13 Illustration of pallet switches used as interlocks.

Figure 5.14 Illustration of pallet switch inputs to a relay or logic control...

Chapter 6

Figure 6.1 Two winding transformer.

Figure 6.2 An example case.

Figure 6.3 Impedance diagram in PU for Figure 6.2.

Figure 6.4 Impedance diagram in Ohm for Figure 6.2.

Figure 6.5 Simple circuit example 1.

Figure 6.6 Simplified block diagram of a protective relay.

Figure 6.7 A balanced three‐phase set.

Figure 6.8 An unbalanced three‐phase set.

Figure 6.9 Unbalanced 3PH set represented by symmetrical components.

Figure 6.10 Positive sequence phasors.

Figure 6.11 Negative sequence phasors.

Figure 6.12 Zero‐sequence phasors.

Figure 6.13 Transformer equivalent circuits.

Figure 6.14 Two winding transformer zero‐sequence equivalent circuit model....

Figure 6.15 Wye Grd–Delta winding transformer zero‐sequence equivalent circu...

Figure 6.16 Three winding transformer zero‐sequence equivalent circuit model...

Figure 6.17 Neutral grounding impedance model.

Figure 6.18 Auto transformer equivalent circuits.

Figure 6.19Figure 6.19 Wyegrd zig‐zag transformer equivalent circuits.

Figure 6.20 Wye–wye–eelta transformer equivalent circuits.

Figure 6.21 Grounding transformer equivalent circuits.

Figure 6.22 Network equivalent at the fault location.

Figure 6.23 A simple system and its sequence network diagrams.

Figure 6.24 Sequence equivalent network blocks.

Figure 6.25 Three‐phase sequence network connections.

Figure 6.26 Line‐ground sequence network connections.

Figure 6.27 Line‐ground fault through fault impedance, sequence network conn...

Figure 6.28 Example one‐line diagram.

Figure 6.29 Positive sequence diagram.

Figure 6.30 Negative sequence diagram.

Figure 6.31 Delta–wye transformer, three‐phase representation.

Figure 6.32 Zero‐sequence diagram.

Figure 6.33 The sequence diagrams.

Figure 6.34 Single‐line diagram of the studied area.

Figure 6.35 Impedance diagram of the studied area.

Figure 6.36 Simple three‐phase balanced fault.

Figure 6.37 L‐G fault example power system.

Figure 6.38 Positive sequence network for the L‐G example.

Figure 6.39 Negative sequence network for the L‐G example.

Figure 6.40 Zero‐sequence network for the L‐G example.

Figure 6.41 Reduction in the positive sequence network for the L‐G example....

Figure 6.42 Reduction in the zero‐sequence network for the L‐G example.

Figure 6.43 Connections of the sequence networks for the L‐G example at Bus ...

Figure 6.44 Bus A and B current distribution for an L‐G at Bus B.

Chapter 7

Figure 7.1 Example zones of protection.

Figure 7.2 Overlapping protection zones.

Figure 7.3 Circuit breaker with bushing CTs.

Figure 7.4 An illustration of breaker bushing CT polarity.

Figure 7.5 Zoning and overlapping zones at a typical HV switching station.

Figure 7.6 Example of current flows for an internal bus fault.

Figure 7.7 Example of current flows for an external bus fault.

Figure 7.8 Example of current flows for an external line fault.

Figure 7.9 Example of current flows for an external line fault showing flows...

Figure 7.10 Load substation protection zones.

Figure 7.11 Current distributions for a transformer fault at a substation.

Figure 7.12 Current distributions for a bus fault at a substation.

Figure 7.13 Current distributions for a feeder phase fault at a substation....

Figure 7.14 Current distributions at a substation for a feeder ground fault....

Figure 7.15 Substation protection zone coordination for a feeder ground faul...

Figure 7.16 Zoning for a transformer with a single secondary winding.

Figure 7.17 Zoning for a transformer with double secondary windings.

Figure 7.18 Zoning for lines terminating into an autotransformer.

Figure 7.19 Zoning for autotransformers connected to buses.

Figure 7.20 Zoning for autotransformer differential and overall bus differen...

Figure 7.21 Generator and unit transformer dedicated protection zones three‐...

Figure 7.22 Generator and unit transformer overall protection zone three‐pha...

Figure 7.23 Example of overlapping line and autotransformer zones.

Figure 7.24 Example of overlapping line and substation transformer zones.

Figure 7.25 Example of remote backup for a failed breaker at Terminal B.

Figure 7.26 Example of local backup for a failed breaker at Terminal B.

Figure 7.27 CTs configured in wye and a balanced load or three‐phase fault....

Figure 7.28 CTs configured in wye and unbalanced load or phase‐ground fault....

Figure 7.29 Derivation of residual current for a white phase‐to‐ground fault...

Figure 7.30 CTs configured in delta.

Figure 7.31 Delta configured CTs and its response to an A‐to‐ground fault.

Figure 7.32 Blind spot on a 500 kV bus diameter.

Figure 7.33 Lines terminating directly onto a bus at an HV switching station...

Figure 7.34 Lines terminating directly onto a Bus at an HV switching station...

Chapter 8

Figure 8.1 33 MVA 115–13.8 kV Power Transformer.

Figure 8.2 Example of a wye–delta configure transformer where the secondary ...

Figure 8.3 Example of a wye–delta configure transformer where the secondary ...

Figure 8.4 Typical 30° phase shift correction using CT connection.

Figure 8.5 Typical 210° phase shift correction using CT connection.

Figure 8.6 CT connections to a transformer differential relay.

Figure 8.7 Wye–closed delta transformer used as a ground source.

Figure 8.8 Zigzag grounding transformer as a ground source.

Figure 8.9 Zero‐sequence current distribution for a delta–wye transformer an...

Figure 8.10 Zero‐sequence current distribution for a delta–wye transformer a...

Figure 8.11 Zero‐sequence current distribution for a wye–delta transformer w...

Figure 8.12 Zero‐sequence current distribution for a wye–delta transformer w...

Figure 8.13 Zero‐sequence current distribution for a wye–delta transformer w...

Figure 8.14 Zero‐sequence current distribution for a wye–delta transformer w...

Figure 8.15 Zero‐sequence current distribution for a wye–delta transformer w...

Figure 8.16 Phase protection of a zigzag grounding transformer.

Figure 8.17 Positive, negative, and zero‐sequence current flow in a differen...

Figure 8.18 Application of ground overcurrent protection for an internal fau...

Figure 8.19 Application of ground overcurrent protection for an external fau...

Figure 8.20 Location of grounding transformer with relay operation.

Figure 8.21 Location of grounding transformer without relay operation.

Figure 8.22 Restricted ground fault protection.

Figure 8.23 Restricted ground fault protection calculation.

Figure 8.24 Typical CT excitation characteristic.

Figure 8.25 Restricted ground fault protection for an internal fault.

Figure 8.26 Restricted ground fault protection for an external fault.

Figure 8.27 Percent differential relay.

Figure 8.28 Percent differential relay basic construction and operation.

Figure 8.29 Electrical circuit representation of the percent differential re...

Figure 8.30 Operating characteristic for the percent differential relay.

Figure 8.31 Maximum system unbalance.

Figure 8.32 Comparison of maximum system unbalance and relay slope.

Figure 8.33 Double slope characteristic.

Figure 8.34 Zoning for a transformer with double secondary windings.

Figure 8.35 Percent differential relay misoperation.

Figure 8.36 Substation configuration requiring overload type protection.

Figure 8.37 Transformer overload protection for double transformer contingen...

Figure 8.38 Flow of zero‐sequence current for an autotransformer internal fa...

Figure 8.39 Flow of zero‐sequence current for an autotransformer external fa...

Figure 8.40 Differential connections for an unloaded tertiary winding.

Figure 8.41 Differential connections for a loaded tertiary winding.

Figure 8.42 Ungrounded system with no phases faulted to ground.

Figure 8.43 Single‐phase ground fault on an ungrounded system.

Figure 8.44 Derivation of 3

V

o

in a delta system with a phase to ground fault...

Figure 8.45 CT excitation characteristic in this example.

Chapter 9

Figure 9.1 Buses at a typical terminal station.

Figure 9.2 Stub‐buses at a typical terminal station.

Figure 9.3 Typical ring bus.

Figure 9.4 LV bus at a typical substation.

Figure 9.5 Simple two‐CT differential bus protection – external fault.

Figure 9.6 Simple two‐CT differential bus protection – internal fault.

Figure 9.7 Differential bus protection.

Figure 9.8 Waveform distortion for out‐of‐zone faults.

Figure 9.9 Short‐time inverse characteristic.

Figure 9.10 Low impedance differential protection.

Figure 9.11 High impedance differential protection.

Figure 9.12 Equivalent differential circuit under transient conditions.

Figure 9.13 Calculation of stabilizing voltage

V

s

.

Figure 9.14 Typical CT excitation characteristic.

Figure 9.15 Three‐phase representation of high impedance differential.

Figure 9.16 Simple two‐node bus protected with percent differential.

Figure 9.17 Trajectory of current with severely saturating CTs.

Figure 9.18 Bus protection zoning at HV terminal stations.

Figure 9.19 Stub‐bus protected by switch onto fault protection.

Figure 9.20 Typical zoning and overlapping zones at a terminal station.

Figure 9.21 Ring bus protection zones.

Figure 9.22 Typical substation LV bus protections.

Figure 9.23 Zero‐sequence current distribution Case #1.

Figure 9.24 Zero‐sequence current distribution Case #2.

Figure 9.25 Zero‐sequence current distribution Case #3.

Figure 9.26 Zero‐sequence current distribution Case #4.

Figure 9.27 Zero‐sequence current distribution Case #5.

Figure 9.28 Zero‐sequence current distribution Case #6.

Figure 9.29 Zero‐sequence current distribution Case #7.

Figure 9.30 Zero‐sequence current distribution Case #8.

Figure 9.31 Zero‐sequence current distribution Case #9.

Figure 9.32 Zero‐sequence current distribution Case #10.

Figure 9.33 Station single‐line diagram showing bus blocking protection.

Figure 9.34 Bus blocking conceptual DC drawing.

Figure 9.35 Bus and feeder protections mounted on metal‐clad switchgear.

Figure 9.36 Calculation of stabilizing voltage

V

s

.

Figure 9.37 Three‐phase representation of high impedance differential.

Figure 9.38 CT excitation characteristic representation C200.

Chapter 10

Figure 10.1 Typical terminal station with no breaker failure.

Figure 10.2 Typical terminal station with breaker failure.

Figure 10.3 Ring bus with a failed breaker.

Figure 10.4 Faulted LV bus at a substation with a failed breaker.

Figure 10.5 Conceptual representation of the three breaker failure logic pat...

Figure 10.6 Breaker failure and need to coordinate with timed Zone 2/Zone 3....

Figure 10.7 Discrete auxiliary relays dedicated to a single “A” protection....

Figure 10.8 Discrete auxiliary relays dedicated to a single “B” protection....

Figure 10.9 Transfer trip from a substation for a bus fault and breaker fail...

Figure 10.10 S&C Series 2000 115 kV circuit switcher and disconnect.

Figure 10.11 Switchyard with dead tank breakers and bushing CTs.

Figure 10.12 Switchyard with live tank breakers and free‐standing CTs.

Figure 10.13 Location of fault that is a blind spot for conventional protect...

Figure 10.14 Location of fault in the free‐standing CT.

Figure 10.15 Location of fault in the breaker.

Chapter 11

Figure 11.1 Typical terminal station arrangement.

Figure 11.2 Typical double switchyard arrangement with autotransformers.

Figure 11.3 Single load substation tapped to two lines.

Figure 11.4 Protections for a typical breaker and half arrangement.

Figure 11.5 Protections for a typical higher voltage breaker and half arrang...

Figure 11.6 Typical ring bus.

Figure 11.7 Protections for a typical ring bus.

Figure 11.8 Dual‐redundant protections for a load substation.

Figure 11.9 Single protections for a load substation.

Figure 11.10 Two‐step tripping scheme.

Figure 11.11 Measuring zero‐sequence voltage for a line ground fault.

Figure 11.12 Measuring ground current for a line ground fault.

Figure 11.13 Fault isolation via communications example.

Figure 11.14 Illustration of stations tele‐protection schemes.

Figure 11.15 Example of FSK with a key pattern for security.

Figure 11.16 A communications network not using T1.

Figure 11.17 A communications network using T1.

Figure 11.18 Pulse amplitude modulation.

Figure 11.19 Assigning binary values to pulses.

Figure 11.20 Time division multiplexing.

Figure 11.21 Illustration of a T1 frame.

Figure 11.22 Protection devices on arc‐proof metal‐clad cell doors.

Figure 11.23 Backside view of a metal‐clad instrument compartment.

Figure 11.24 Master ground example with an open pole in the bus‐tie breaker....

Figure 11.25 Master ground example with an external bus fault.

Chapter 12

Figure 12.1 PF correction and transmission line voltage drop.

Figure 12.2 Illustration of a capacitor unit.

Figure 12.3 Basic series–parallel capacitor can arrangement.

Figure 12.4 Single‐wye ungrounded capacitor bank.

Figure 12.5 Single‐wye grounded capacitor bank.

Figure 12.6 Double‐wye ungrounded capacitor bank.

Figure 12.7 Fused and unfused capacitor bank with one unit failed (only one ...

Figure 12.8 Externally fused capacitor bank configuration.

Figure 12.9 Internally fused capacitor bank configuration.

Figure 12.10 Fuseless.

Figure 12.11 Unfused banks.

Figure 12.12 HV shunt capacitor protection one‐line.

Figure 12.13 Neutral unbalance relay with neutral unbalance compensation (si...

Figure 12.14 Neutral unbalance relay (double‐wye ungrounded bank).

Figure 12.15 Neutral unbalance relay (single‐wye ungrounded bank).

Figure 12.16 Phase and ground overcurrent capacitor bank protection.

Figure 12.17 Two SF6 breakers in series instead of dedicated breaker failure...

Figure 12.18 Phase and ground overcurrent protection.

Figure 12.19 Standard extremely inverse‐time overcurrent curves.

Chapter 13

Figure 13.1 Generator conceptual illustration.

Figure 13.2 Generator subsystem component conceptual schematic.

Figure 13.3 Percent differential connections.

Figure 13.4 Independent generator and unit transformer differential zones.

Figure 13.5 Combined generator and unit transformer zone.

Figure 13.6 Split‐phase protection.

Figure 13.7 Stator ground fault protection.

Figure 13.8 Setting criteria for loss of excitation protection.

Figure 13.9 Trajectory of apparent impedance upon loss of excitation.

Figure 13.10 Under‐frequency‐UFLS coordination example.

Figure 13.11 Single blinder scheme to detect out‐of‐step.

Figure 13.12 Example of an unstable power swing.

Figure 13.13 Phase backup reach setting.

Figure 13.14 Phase and ground backup system protections.

Figure 13.15 Loss of excitation setting example impedance diagram.

Figure 13.16 Stator ground limiting resistor.

Figure 13.17 Calculation of the maximum stator ground fault coverage.

Figure 13.18 Percentage of stator winding protected for ground faults.

Figure 13.19 Loss of excitation setting example impedance diagram.

Figure 13.20 Settings to detect out‐of‐step.

Figure 13.21 A generator's equivalent single‐phase circuit.

Figure 13.22 (a) Generator voltage phasor diagram. (b) Generator power phaso...

Figure 13.23 A generator's power capability plot.

Figure 13.24 A typical synchronous generator capability curve.

Figure 13.25 Example generator's capability plot.

Figure 13.26 Example case one‐line.

Figure 13.27 Example generator capability curve using actual

overexcitation

...

Figure 13.28 Example volts per hertz coordination.

Figure 13.29 Loss of excitation protection and control exciter limiter coord...

Chapter 14

Figure 14.1 Fault detection using a simple overcurrent relay.

Figure 14.2 Fault detection using an impedance relay.

Figure 14.3 Typical 230 kV terminal station.

Figure 14.4 Terminal station with half the infeeds to a faulted line.

Figure 14.5 Maximized source impedance.

Figure 14.6 Minimized source impedance.

Figure 14.7 Two fault detecting techniques used for impedance relays.

Figure 14.8 Direction of currents in a phase‐to‐phase fault.

Figure 14.9 Single line to ground fault.

Figure 14.10 Zero‐sequence compensation with electromechanical relays.

Figure 14.11 Effects of mutual impedance between two parallel lines.

Figure 14.12 Effects of mutual impedance with remote breakers open.

Figure 14.13 Distance relay impedance measurement in a simple system.

Figure 14.14 Effect of infeed from the third terminal on a three‐terminal li...

Figure 14.15 Source impedances and effect on apparent impedance.

Figure 14.16 Example three‐terminal line with one terminal faulted.

Figure 14.17 Paralleled conductors (only one phase shown).

Figure 14.18 Paralleled conductors with a mid‐point tie loop.

Figure 14.19 Effect of a tapped load substation on line protection.

Figure 14.20 Line phase backup protection using distance relays.

Figure 14.21 Line protection Zone 2 reaches into a load‐substation LV side....

Figure 14.22 Fault at the end of a load‐substation long tap.

Figure 14.23 Direct underreaching transfer trip.

Figure 14.24 Zone 1 coverage from the two terminals of line. (a) Zone 1 cove...

Figure 14.25 A permissive overreaching scheme.

Figure 14.26 Zone 2 coverage from the two terminals of line. (a) Zone 2 cove...

Figure 14.27 Zone 2 sees some faults in the next line section.

Figure 14.28 (a) Illustration of the eco concept with remote disconnect open...

Figure 14.29 A directional comparison blocking scheme.

Figure 14.30 Illustration of the DCB scheme. (a) Fault locations on a single...

Figure 14.31 MHO relay operating characteristic.

Figure 14.32 Typical line terminations and directioning of relays.

Figure 14.33 Typical line terminations and a close‐in fault.

Figure 14.34 Line test logic.

Figure 14.35 Operating conditions that cause misoperation of compensator typ...

Figure 14.36 Illustration of the echo concept with remote disconnect open.

Figure 14.37 Line supplied by an autotransformer.

Figure 14.38 Example of high source impedance ratio.

Figure 14.39 Three terminal lines with permissive overreaching.

Figure 14.40 Three terminal lines with directional comparison blocking.

Figure 14.41 Outfeed on a three terminal line.

Figure 14.42 Transmission lines with no tapped generation.

Figure 14.43 Transmission lines with tapped generation.

Figure 14.44 Zone 1 reach seeing into the generator side of a wind farm.

Figure 14.45 Effect of mutual impedance on Zone 2 reaches.

Figure 14.46 Effect of tapped generators on Zone 2 seeing the LV side.

Figure 14.47 Distributed generators tapped directly to the transmission line...

Figure 14.48 Automatic reclosing of terminal breakers.

Figure 14.49 MHO relay characteristic.

Figure 14.50 Added resistive reach with MTA lower than line angle.

Figure 14.51 Reach extension to cover limited fault resistance.

Figure 14.52 10 km 230 kV line.

Figure 14.53 50 km 230 kV line

Figure 14.54 Example of a short line and a close‐in resistive fault.

Figure 14.55 (a) Self polarized and (b) cross or memory polarized MHO elemen...

Figure 14.56 Resistive expansion of a cross‐polarized MHO with increasing SI...

Figure 14.57 Typical loadability issue.

Figure 14.58 Load impedance seen by the relay with varying generator voltage...

Figure 14.59 Closest load point before NERC PRC‐023‐1 Standard.

Figure 14.60 Load encroachment by Schweitzer Engineering Laboratories™.

Figure 14.61 Lens characteristic solid state and digital relays.

Figure 14.62 Traditional electromechanical relay blinder.

Figure 14.63 Out‐of‐zone phase fault with a tapped load substation.

Figure 14.64 Out‐of‐zone ground fault with a tapped load substation.

Figure 14.65 Communication links for a two‐ended scheme.

Figure 14.66 – Communication links for a three‐ended scheme.

Figure 14.67 Example of weak end infeed and current reversal.

Figure 14.68 Typical two‐ended pilot wire scheme.

Figure 14.69 Underreaching Zone 1 logic.

Figure 14.70 Underreaching Zone 1 reaches.

Figure 14.71

R

−

X

plot of Zone 1 distance elements.

Figure 14.72 Clean two‐terminal line.

Figure 14.73 Overreaching Zone 2 logic.

Figure 14.74 Overreaching Zone 2 reaches.

Figure 14.75

R

−

X

plot of Zone 2 distance elements.

Figure 14.76 Long line tap protection with directional comparison blocking....

Figure 14.77 Zone 2 reaches.

Figure 14.78 Overreaching Zone 2 logic.

Figure 14.79

R

−

X

plot of Zone 1 distance elements.

Figure 14.80

R

−

X

plot of Zone 2 distance elements.

Figure 14.81

R

−

X

plot of Zone 2 distance elements.

Figure 14.82

R

−

X

plot of Zone 3 distance elements.

Chapter 15

Figure 15.1 Typical electrical power system.

Figure 15.2 Some typical radial distribution feeders.

Figure 15.3 Typical load transformer station and subtransmission feeder arra...

Figure 15.4 (a) Inverse overcurrent characteristics. (b) Time dials.

Figure 15.5 Operating time for inverse overcurrent relays.

Figure 15.6 Operating characteristic of a Mho relay on an

R

‐

X

diagram.

Figure 15.7 An example of a stepped distance scheme for Terminal A.

Figure 15.8 An example of a communication‐based scheme.

Figure 15.9 (a) S&C SMD‐20 14.4 kV overhead – pole top fuse.(b) SM‐4 pow...

Figure 15.10 (a) Current‐limiting fuse illustration of operation. (b) S&C cu...

Figure 15.11 A fuse's minimum melting and total clearing time–current curves...

Figure 15.12 Primary fuse currents for secondary faults on Delta/Y‐Grd. tran...

Figure 15.13 An example 1‐PH recloser – S&C – TripSaver

®

II cutout‐moun...

Figure 15.14 Typical recloser operational curves.

Figure 15.15 Basic distribution coordination principles.

Figure 15.16 Fuse to fuse coordination.

Figure 15.17 A typical DS fuse to recloser overcurrent protection scheme.

Figure 15.18 Legacy fuse‐recloser coordination.

Figure 15.19 Fuse‐recloser coordination.

Figure 15.20 Fuse adjusted recloser coordination.

Figure 15.21 IEEE C37.91 Category ll Transformer Damage Curves [11].

Figure 15.22 Transformer short time damage curves.

Figure 15.23 An example of dynamic TCC curve [12].

Figure 15.24 (a) Feeder protection and automatic reclose scheme overview. (b...

Figure 15.25 Distance relay (21) operating characteristic.

Figure 15.26 A feeder‐connected DG.

Figure 15.27 DG islanding.

Figure 15.28 Internal feeder fault.

Figure 15.29 (a) Apparent effects due to the connected DG. (b) Apparent effe...

Figure 15.30 External feeder zone faults.

Figure 15.31 DG sends a DGEO signal once it is disconnected.

Guide

Cover

Table of Contents

Series Page

Title Page

Copyright

About the Authors

Preface

Acknowledgements

Begin Reading

Index

IEEE Press Series on Power and Energy Systems

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Power System Protection

Fundamentals and Applications

John CiufoCiufo and Cooperberg Consulting (CCCI)MississaugaGreater Toronto AreaOntarioCanada

Aaron CooperbergCiufo and Cooperberg Consulting (CCCI)MississaugaGreater Toronto AreaOntarioCanada

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Names: Ciufo, John, 1953‐ author. | Cooperberg, Aaron, 1952‐ author.Title: Power system protection : fundamentals and applications / John Ciufo, Ciufo and Cooperberg Consulting (CCCI), Aaron Cooperberg, Ciufo and Cooperberg Consulting (CCCI).Description: First edition. | Hoboken, New Jersey : John Wiley & Sons, Inc., [2022] | Series: IEEE press series on power and energy systems | Includes bibliographical references and index.Identifiers: LCCN 2021048461 (print) | LCCN 2021048462 (ebook) | ISBN 9781119847366 (cloth) | ISBN 9781119847373 (adobe pdf) | ISBN 9781119847380 (epub)Subjects: LCSH: Electric power systems–Protection.Classification: LCC TK1010 .C58 2022 (print) | LCC TK1010 (ebook) | DDC 621.31–dc23/eng/20211122LC record available at https://lccn.loc.gov/2021048461LC ebook record available at https://lccn.loc.gov/2021048462

Cover Design: WileyCover Image: © Patrick Jennings/Shutterstock

About the Authors

John Ciufo, P. Eng.

Is a professional Electrical Engineer with over forty years of electric utility experience with a focus on protection and control (P&C) engineering. He has worked for Hydro One Inc., formerly Ontario Hydro from 1976 to 2010. Over the years, he has held many different positions in the P&C power system discipline. His experience includes engineering, power system reliability compliance, smart grid, asset management, development of strategies, policies, developing functional and design standards, cybersecurity, and digital stations. He completed his career with Hydro One as a Senior Manager – Protection & Control Strategies and Standards in Asset Management. In 2011, he became a principal owner of Ciufo & Cooperberg Consulting Inc. a consulting company that specializes in power system protection.

John has an extensive background in protection and control systems in the electric industry. He is a registered Professional Engineer in the Province of Ontario and was a member of the Northeast Power Coordinating Council (NPCC), Task Force on System Protection for 10 years, and a Vice‐Chair from January 2008 to January 2010. Was a member of the North American Electric Regulatory Corporation (NERC), System Protection and Control Subcommittee since May 2004, and was the Chair between the periods June 2008 to September 2010. He was on several NERC drafting teams developing protection and control‐related standards and has co‐authored several industry papers.

During his career at Ontario Hydro/Hydro One, he was instrumental in developing protection engineering application standards; protection philosophies and processes; transitioned the company from electromechanical designs to microprocessor‐based designs that resulted in significant cost savings; developed protection and control health indices and asset management processes; developed reliability compliance programs and processes; developed the company's cybersecurity compliance program, introduced and piloted digital station designs, transitioned the company from microwave to Digital Synchronous Optical Network (SONET) teleprotection systems, established, developed, and conducted internal company protection training, among other achievements.

John continues to be active in the industry and provides engineering services to many North American electric utilities. He is a Technical Advisor for the Centre for Energy Advancement Technological Innovations (CEATI) for the Protection and Control Group.

Aaron Cooperberg, Licensed Protection Engineer

Is professionally licensed to practice Power System Protection in the Province of Ontario. Upon graduation having specialized in Power Systems he began his career with Ontario Hydro in1977. He was assigned there to the protection engineering group responsible for the specification and design of protection systems. He spent 21 years working alongside Ontario Hydro's top experts in Power System protection engineering carrying out many protection system designs during the period of rapid expansion of Ontario's 500 kV transmission system and the construction of large multi‐unit Nuclear, Thermal and Hydraulic generation sites.

His last 13 years with Ontario Hydro and then Hydro One was focused on the Asset Management of the province's Protection Systems. Here he developed industry‐recognized Asset Management design and business case strategies for the proactive replacement of end‐of‐life protection systems. He has also led the team responsible for developing the technical requirements to connect multi‐tapped generation to Hydro One's Transmission and Distribution systems. He completed his career with Hydro One as a Senior Manager – Protection & Control Planning. In 2011, he became a principal owner of Ciufo & Cooperberg Consulting Inc. a consulting company that specializes in power system protection.

Aaron possesses an in‐depth knowledge of protection systems for transmission as well as generation having designed protection systems for nuclear and hydroelectric generation as well as transmission for the former Ontario Hydro. He provided expert testimony to the U.S–Canada Committee on the August 14th, 2003, blackout. He was on the NERC drafting team developing Protection and Control Standard PRC‐001 for Protection Coordination. He was a speaker at conferences on the topics of protection systems as well as Asset Management and has presented at CEATI and Electric Power Research Institute (EPRI). Aaron continues to be active in the industry providing engineering services to many North American electric utilities.

Preface

This book contains the accumulated experiences and practices used by the authors who have each, practiced protection engineering for over forty years.

Protection engineering is a specialty within the study of power system engineering. It is generally, not taught in engineering programs except for some specialized post‐graduate programs. Considering that every power system big, and small, regardless of voltage level, requires the application of protection systems; the authors felt that there was a gap in the industry, and there is a need for more protection system information and guidance for new protection practitioners.

Protection is a highly complex discipline requiring several years of specialized engineering development following graduation. Utilities typically resort to the recruitment of graduate power system engineers into the field of protection engineering. Historically, these recruits would gain the necessary experience and training while working along with seasoned engineers over many years as they gain confidence. This mentoring approach is becoming more difficult to implement. Specifically, this mentoring approach relies on several years of overlap which is becoming more difficult to attain as many experienced staff with lifelong knowledge have, or are retiring, leaving fewer, and fewer experienced mentors.

New protection practitioners to this field require resources, and the means to gain the necessary know‐how. It is for this reason that we felt compelled to write this book, to provide new protection practitioners with a book they can relate with for Power System Protection Fundamentals and Applications. It is the intent of the authors, that this book facilitates knowledge transfer via the use of a structured set of fundamental protection principles, explanatory illustrations, and applications of these principles.

The authors appreciate the challenges for new protection practitioners. It is a complex field requiring knowledge of electrical engineering, power systems, power equipment, protection engineering, telecommunications, power system analysis, control, and more recently, computer programming, and networks as the industry transforms into a digital world. Protection practitioners are tasked with designing, maintaining, operating, compliance, managing, and diagnosing protection system applications. As such, they are accountable to make these systems work and function per design; they represent the process metaphorically, where “the rubber meets the road.”

This book is written with the approach that in this new and dynamic digital transformation, the understanding of the underlying protection principles is key to the successful development of a protection practitioner. Fundamentally, protection practitioners are held accountable to design, operate, maintain, and implement workable solutions to support the reliable operation of the power system. It is for this purpose; we wrote this book to be a balance between theory and practical applications for the intent of being relatable.

Acknowledgements

John Ciufo

An undertaking of this nature requires a passion for the practice of protection engineering. It also requires dedicating personal time to its development, and as such, I would like to thank my family for their cooperation and understanding.

This book was made possible with the encouragement and support of my dear wife Maria. I would like to also thank my children, Vanessa Lynn and Mark Joseph, for their inspiration during the writing of this book.

Additionally, I would like to thank my colleague and friend, Aaron Cooperberg, for his shared interest and dedication to this subject and for co‐authoring this book.

Aaron Cooperberg

During my career at Ontario Hydro/Hydro One, I was always passionate about sharing my engineering knowledge with co‐workers and particularly with junior protection engineering staff. This passion for sharing knowledge has lead me to co‐author this book.

I would like to acknowledge the encouragement, support, and patience of my wife Rina without whom this book would not be possible.

Additionally, I would like to thank my colleague and friend, John Ciufo for whom I have the utmost respect. John's commitment and determination were instrumental while co‐authoring this book.

John and Aaron

We would like to express our sincere thanks to Ontario Hydro/Hydro One for providing the opportunities to learn and practice power system protection and control engineering. This has allowed us to contribute to Hydro One's success and advancements to the Ontario power grid and ultimately for the betterment of the people of Ontario.

We would like to convey our sincerest gratitude to Murched Ajami, Ian Bradley, Mark Ciufo, and Miroslav Kostic for reviewing our manuscript, providing their direction, and their continued support.

1What Is Power System Protection, Why Is It Required and Some Basics?

1.1 What Is Power System Protection?

Our modern human civilization is dependent on the electric power system to enable all of its critical functions: food, health, sanitation, security, commerce, and progress. The electric power system is dependent on protections. By electric power system, we are referring to power generation and a network of wires that connect generation to the load locations where it is utilized to power the functions above. Protections consist of an assembly of electric components, and consequently, are better referred to as protection systems. Protection systems continuously monitor the equipment that the power system itself is comprised of for abnormal operating conditions. Protections are automatic systems that once an abnormal condition is detected, quickly as possible isolates the abnormal condition by the tripping of circuit breakers or the operation of fuses.

Power system protection systems are referred to as secondary equipment, as the primary equipment is transformers, lines, buses, generators, capacitors, breakers, disconnectors, etc. Primary equipment is directly involved with electric energy supply and delivery. Protection systems are designed and installed to oversee and “protect” primary equipment and the integrity of the power system.

In essence, power system protections “protect” power system primary equipment and, thereby, maintain system integrity and safety.

Protection systems are to a power system as a panel circuit breaker/fuse is to a household electrical circuit panel.

In addition to protecting power system primary equipment, power systems also employ remedial action schemes (RASs), previously known as special protection systems (SPSs), to protect the integrity of the power system. RAS/SPSs can monitor frequency, voltage, and operating contingencies that require immediate system correct actions, among others.

Power system protections are classified as “mission‐critical” assets, as failure to operate or, if they do not operate as intended, have grave consequences to the continued operation of the power system.

A protection system itself is comprised of Individual devices, sub‐systems, and numerous pieces of equipment as follows:

Protection relays that monitor the power system for abnormal conditions.

Communication systems that are used as part of the overall protection system functionality.

Voltage and current sensing equipment that steps down high‐power system values to much lower values capable of being input into the protection relays.

Direct current () auxiliary supply including batteries and their chargers used to power protection relays, auxiliary devices, communication systems and trip circuit breakers.

Control circuitry working with protections to trip circuit breakers or other interrupting devices such as circuit switchers.

Most reliability organizations that oversee the adequacy of protections include the above‐listed components as part of an overall protection system. Batteries are not included just the battery circuits. Also, circuit breakers are not included just the breaker trip coils are. However, batteries and breakers are key components of protection systems but fall under the jurisdiction of station engineering. The consequence of such definitions only impacts compliance and organizational accountability.

A typical protection system consisting of these components is illustrated in Figure 1.1 showing that a protection system consists of many components, or sub‐systems: CTs, PTs, protective relays, auxiliary relays, control wiring, equipment mounting panels, DC power supplies, telecommunications, and breaker trip coils. A protection system, in the general case, is not just one device, or subsystem, it consists of several sub‐systems, each containing several devices that represent the whole. To function correctly, each of the components or sub‐systems must themselves operate correctly … it is a serial operation. Each of these sub‐systems and their functions will be discussed in more detail in Chapter 2, Section 2.1

Figure 1.1 Illustration of a protection system for a transmission line [1].

It is not possible to design an electric power system that is immune to equipment failures and abnormal operating conditions. Therefore, all power systems must deploy highly reliable protection systems that can quickly detect abnormal conditions and take appropriate actions to mitigate abnormalities.

In the normal state of a power system, there is a balance of electric energy sufficient to meet the needs of the connected load, in real‐time, and the power system operating quantities such as voltages, currents, and frequency, are all within the design ratings of the primary equipment.

Abnormal conditions result when system faults occur that cause these operating quantities to deviate beyond equipment ratings. Protection systems are designed to monitor power system quantiles for such abnormalities and operate to isolate these fault events that cause abnormal quantities. One prominent operating quantity that is drastically impacted by such events is current. System faults also referred to as disturbances, can cause normal load current to increase from several hundred amps to 70,000 A which can cause major damage if not cleared in fractions of a second. Currents of such high quantities can cause thermal damage, mechanical damage, forces are so high that metal bus bars can bend, equipment failures, fires, safety issues, and a collapse of the power system if not cleared within the short‐time ratings of primary equipment.

Some examples of system events that cause abnormal conditions are as follows: lightning strikes (Figure 1.2), wind, ice storms, animal contact, equipment failures (Figure 1.3), car accidents knocking down electrical poles/equipment, etc., that cause short circuits or broken connections. Such events are also referred in the industry, as faults. Faults and their types, causes, and how to calculate fault values will be further discussed in Chapter 6.

Figure 1.2 Environmental risk lightning strike – Dallas Tx.

Source: NOAA Photo Library / Flickr / CC BY 2.0.

Figure 1.3 Failed transformer on fire – Thessaloniki Greece.

Source: Konstantinos Stampoulis / Firefighters.gr / Wikimedia Commons / CC BY‐SA 3.0 GR.

1.2 Why Is Power System Protections Required?

Power systems are designed, planned, and constructed to limit failure modes and equipment damage and thereby enhance overall system reliability.

The power system is designed to balance performance and minimize the cost of energy delivery. The planning, design, and implementation of a power system is a balance of initial capital costs and ongoing maintenance costs with the potential cost impact of power system equipment failure.

Power systems are exposed and subjected to environmental elements such as rain, snow, ice, lightning (Figure 1.2), storms, and other such environmental risks. These risks cause, power system's primary equipment components to make unwanted contact with other components, referred to as faults which result in fault currents in the order of 10–100 times normal load currents. Transmission lines have the highest risk of environmental elements due to their increased natural exposure to the environment.

It should be noted that protection systems cannot prevent faults or equipment failures. They detect an abnormality by monitoring quantities such as increased currents, depressed voltages resulting from failures. A limited number of protection devices can respond to failures without directly monitoring electrical quantities example are gas, temperature, and light‐sensing devices.

1.2.1 Minimize Primary Equipment Damage

Power system equipment is designed and constructed to limit failure modes. However, power system's primary equipment can and does fail for the following reasons:

(1) Soon after installation, due to either a design or manufacturing flaw.

(2) Equipment failures due to prolonged operation beyond the equipment's rated design parameters.

(3) Equipment failures due to adverse environmental conditions such as salt pollution, animal contact, or high wind and lightning strikes during storms.

(4) Equipment operated beyond their normal expected life span.

Primary equipment is designed to withstand a certain level of fault exposure. Protection systems operating within that exposure period will minimize damage to the equipment and possibly prevent catastrophic failure thereby, also decreasing equipment outage time. It should be noted the cost and installation of some primary equipment such as generators and large power transformers are in the order of US$10's of millions of dollars each. More significant than the cost is the time needed to manufacture as it can take up to one to two years as this type of equipment is only made by custom order.

1.2.2 Provide Continuity of Service by Minimizing Outage Time and Service

Power systems are classified as critical infrastructure due to the 24/7 dependence on electric power for modern‐day life. Automatic protection systems are designed to detect faulted equipment and remove the minimal primary equipment required to remove the abnormal condition and maintain a continued supply of electric power to as many customers as possible.