Protection Challenges in Meeting Increasing Electric Power Demand 3030604993, 9783030604998

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Om Hari Gupta Manoj Tripathy Vijay K. Sood

Protection Challenges in Meeting Increasing Electric Power Demand

Protection Challenges in Meeting Increasing Electric Power Demand

Om Hari Gupta • Manoj Tripathy • Vijay K. Sood

Protection Challenges in Meeting Increasing Electric Power Demand

Om Hari Gupta Department of Electrical Engineering National Institute of Technology Jamshedpur Jamshedpur, India

Manoj Tripathy Department of Electrical Engineering Indian Institute of Technology Roorkee Roorkee, India

Vijay K. Sood Department of Electrical, Computer and Software Engineering Ontario Tech University Oshawa, ON, Canada

ISBN 978-3-030-60499-8 ISBN 978-3-030-60500-1 https://doi.org/10.1007/978-3-030-60500-1

(eBook)

© Springer Nature Switzerland AG 2021 This work is subject to copyright. All rights are reserved by the Publisher, whether the whole or part of the material is concerned, specifically the rights of translation, reprinting, reuse of illustrations, recitation, broadcasting, reproduction on microfilms or in any other physical way, and transmission or information storage and retrieval, electronic adaptation, computer software, or by similar or dissimilar methodology now known or hereafter developed. The use of general descriptive names, registered names, trademarks, service marks, etc. in this publication does not imply, even in the absence of a specific statement, that such names are exempt from the relevant protective laws and regulations and therefore free for general use. The publisher, the authors, and the editors are safe to assume that the advice and information in this book are believed to be true and accurate at the date of publication. Neither the publisher nor the authors or the editors give a warranty, expressed or implied, with respect to the material contained herein or for any errors or omissions that may have been made. The publisher remains neutral with regard to jurisdictional claims in published maps and institutional affiliations. This Springer imprint is published by the registered company Springer Nature Switzerland AG The registered company address is: Gewerbestrasse 11, 6330 Cham, Switzerland

Preface

It is obligatory to have robust and accurate protection schemes for generation, transmission, and distribution systems as they are the key components of the power system. As the demand for electric power increases, protection challenges in meeting this demand also increase. Due to the ongoing global concern with climate change and the use of sustainable energy, the power system is undergoing a slow but dramatic change. This is being assisted by technological advances; and the future generation, transmission, and distribution systems will be actively managed to meet the challenges of increasing power demand and efficient and smart use of energy. The consumer will also play an increasingly active role as a prosumer as small-scale renewable energy becomes economically viable. Bulk generation in remote geographical locations will remain an important source, and renewable generation closer to the load centers will emerge. This will shift the paradigm of one-way power flow to two-way power flow, which will have implications for protection systems. Bulk transmission of power will continue as before but with the addition of FACTS technology to enable faster control and more efficient use of the available transmission assets. Again, the use of power electronics will alter the protection requirements, leading to a modification of existing relaying techniques and addition of new methods of protection. At the distribution level, the integration of renewable energy sources with power conversion technology will shift the protection aspects to a whole new level. The formation of microgrids will provide flexibility and improve efficient use of resources but add a new element for the protection system. This book focuses on many of these aspects, that is, requirement of modifications in transmission and distribution systems, existing protection schemes and challenges, and solutions to these protection challenges. A rigorous literature survey on existing protection techniques is also included in this book. This book provides the reader with the protection challenges and their possible solutions. Apart from highlighting these, a rigorous review of previous protection v

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Preface

schemes has been presented that helps in enhancing the reader’s understanding. The protection landscape is quite vast and complex, and we hope that we have assisted the reader in understanding this topic. Jamshedpur, India Roorkee, India Oshawa, Canada August 2020

Om Hari Gupta Manoj Tripathy Vijay K. Sood

Acknowledgments

The completion of this book has become possible with the support of several individuals. Authors would like to express their sincere appreciation to Mr. Jai Prakash Sharma, research scholar, NIT Jamshedpur; Mr. Salauddin Ansari, research scholar, NIT Jamshedpur; Mr. Ravishankar Tiwari, assistant professor, GLA University, Mathura; and Ms. Jayshree, engineer, PRDC Bengaluru, for their help in preparing the book. The authors also express their best wishes to their respective spouses for their understanding and sacrifice while they were away undertaking the task of writing this manuscript.

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Contents

1

Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 General Background . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2 Literature Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.2.1 Protection of FACTS-Compensated Line . . . . . . . . . . . . 1.2.2 Microgrid Islanding Protection . . . . . . . . . . . . . . . . . . . 1.3 Summary and Book Organization . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2

Modifications Required in Power System to Meet Increasing Power Demand . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 Facts to Enhance Power Flow Through Transmission Line . . . . . 2.2.1 Thyristor-Controlled Series Capacitor (TCSC) . . . . . . . . 2.2.2 Static VAR Compensator (SVC) . . . . . . . . . . . . . . . . . . 2.2.3 Static Synchronous Compensator (STATCOM) . . . . . . . 2.3 Power Flow in the Line with Series/Shunt Compensation . . . . . . 2.3.1 Power Flow with Series Compensation . . . . . . . . . . . . . 2.3.2 Power Flow with Shunt Compensation . . . . . . . . . . . . . 2.4 Distributed Generation to Meet Power Demand Close to the Load Center . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 Microgrid Embedded with Renewable-Based Distributed Generation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6 Requirement of DC and Hybrid Microgrids in Future – An Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.7 Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

3

Existing Protection and Challenges . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 Transmission Line Protection . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.1 Distance Relaying . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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1 1 2 2 7 8 9

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19 19 20 20 20 22 23 24 25

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27

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27

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30 31 32

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33 33 33 34 ix

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Contents

3.2.2 Quadrilateral Relay Characteristics . . . . . . . . . . . . . . . . . 3.2.3 Differential Relaying . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2.4 Biased Differential Relaying . . . . . . . . . . . . . . . . . . . . . . 3.2.5 Measurement of Apparent Impedance . . . . . . . . . . . . . . . 3.3 Challenges in the Protection of FACTS-Compensated Line . . . . . . 3.3.1 Influence of FACTS Devices on Protection Schemes . . . . 3.3.2 Series FACTS Devices and Their Impacts on Conventional Protection . . . . . . . . . . . . . . . . . . . . . . . 3.3.3 Shunt FACTS Devices and Their Impacts on Conventional Protection . . . . . . . . . . . . . . . . . . . . . . . 3.3.4 Combination of Series and Shunt FACTS Devices and Their Influences on Conventional Protection Schemes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3.5 Simulated Verification of the Discussed Impact of FACTS Devices on the Conventional Relaying Schemes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4 Distribution System Protection . . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.1 Time-Graded Protection . . . . . . . . . . . . . . . . . . . . . . . . . 3.4.2 Current-Graded Protection . . . . . . . . . . . . . . . . . . . . . . . 3.4.3 Combination of Time- and Current-Graded Protection . . . 3.5 Challenges in the Protection of DG-Embedded Distribution System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.1 Dynamic in the Level of Fault Current . . . . . . . . . . . . . . 3.5.2 Bidirectional Fault Current . . . . . . . . . . . . . . . . . . . . . . . 3.5.3 False Tripping . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.4 Blinding Protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.5 High-Impedance Fault . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.6 Mode of Operation of a Microgrid . . . . . . . . . . . . . . . . . 3.5.7 Distance to a Fault . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.8 Single-Phase Connection . . . . . . . . . . . . . . . . . . . . . . . . 3.5.9 Islanding Problem . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5.10 Loss of Coordination . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6 Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4

Solutions to the Protection Challenges . . . . . . . . . . . . . . . . . . . . . . . 4.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2 Protection of Modern Transmission System . . . . . . . . . . . . . . . . 4.2.1 SSCII-Based Pilot Protection Scheme for SVC-Compensated Line . . . . . . . . . . . . . . . . . . . . . 4.2.2 ERF-Based Fault Detection Method for Shunt-Compensated Line . . . . . . . . . . . . . . . . . . . . 4.2.3 EPE-Based Pilot Relaying Scheme for Series-Compensated Line . . . . . . . . . . . . . . . . . . . .

37 39 41 41 45 45 46 48

51

51 53 54 55 56 56 56 57 57 58 58 58 58 59 59 59 59 60

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63 63 63

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69

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4.2.4

Imaginary Component of Virtual Fault Impedance-Based Relaying . . . . . . . . . . . . . . . . . . . . . . 4.2.5 EC-Based Relaying Scheme for TCSC-Compensated Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.2.6 IRPCs-Based Pilot Protection Scheme for Compensated Line . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 Islanding Detection Scheme for Microgrid . . . . . . . . . . . . . . . . . 4.3.1 Voltage Ripple-Based Islanding Detection Technique (VRBIDT) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.2 Wavelet Transform-Based Islanding Detection Technique (WTBIDT) . . . . . . . . . . . . . . . . . . . . . . . . . 4.3.3 Hybrid Islanding Detection Scheme for Converter-Based DGs . . . . . . . . . . . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

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. 98 . 106 . 106 . 111 . 116 . 121

Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123 5.1 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 123 5.2 Scope for Future Work . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 124

Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 125

About the Authors

Om Hari Gupta is currently an Assistant Professor in the Department of Electrical Engineering, National Institute of Technology Jamshedpur, India. He received the B.Tech. degree (electrical and electronics engineering) from UP Technical University, Lucknow, India, M. Tech. degree (power electronics and ASIC design) from the MN National Institute of Technology Allahabad, Prayagraj, India, and Ph.D. degree (electrical engineering) from the Indian Institute of Technology Roorkee, Uttarakhand, India. He is a recipient of the Canadian Queen Elizabeth II Diamond Jubilee Scholarship for research visiting the University of Ontario Institute of Technology, Oshawa, ON, Canada, in 2017. His major areas of research interests include power system compensation and protection, microgrid control and protection, and control of drives. Dr. Gupta is a reviewer for various international journals including IEEE Transactions on Power Delivery, Electric Power Components and Systems, International Journal of Electrical Power and Energy Systems, etc.

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About the Authors

Manoj Tripathy received his B.E. degree in electrical engineering from Nagpur University, Nagpur, India, in 1999, the M.Tech. degree in instrumentation and control from Aligarh Muslim University, Aligarh, India, in 2002, and the Ph.D. degree from the Indian Institute of Technology Roorkee, Roorkee, India, in 2008. He is currently working as Associate Professor in the Department of Electrical Engineering, Indian Institute of Technology Roorkee, Uttarakhand, India. His fields of interest are wavelets, neural network, optimization techniques, content-based image retrieval, digital instrumentation, digital protective relays, and digital speech processing. Dr Tripathy is a reviewer for various international journals in the area of power systems and speech.

Vijay K. Sood received his Ph.D. degree from the University of Bradford, England. From 1976 to 2007, he was employed as a Senior Researcher at IREQ (Research Institute of Hydro-Québec) in Montreal. Since 2007, he is an Associate Professor at Ontario Tech University, Oshawa, Canada. His research interests are in the monitoring, control, and protection of HVDC and FACTS power systems. He has published widely on HVDC and FACTS transmission systems. He is a member of the Professional Engineers of Ontario, a Life Fellow of the IEEE, a Fellow of the Engineering Institute of Canada, and an Emeritus Fellow of Canadian Academy of Engineers.

List of Acronyms

AC, ac A-G ANN AS CB CDC CT CVT, CCVT DC, dc DG DTOC DWT EC EHV/UHV EMTDC EPE ERF FACTS FCII FCIP HPF HVDC IAP IB IEEE IIRP IRPC IVFI L-G LL

Alternating current Phase-A-to-ground Artificial neural network Alert signal Circuit breaker Compensated differential current Current transformer Capacitor-coupled voltage transformer Direct current Distributed generation Definite time overcurrent Discrete wavelet transform Energy coefficient Extrahigh voltage/ultrahigh voltage Electromagnetic transient and DC Estimated phase error Estimated reactive power factor Flexible AC transmission system Fault component integrated impedance Fault component integrated power High-pass filter High-voltage DC Incremental apparent power Infinite bus Institute of Electrical and Electronics Engineers Incremental integrated reactive power Incremental reactive power coefficient Imaginary value of VFI Line-to-ground or single-line-to-ground Line-to-line xv

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LL-G LoG LPF MOV MTS NDZ PCC PU QF RMS, rms ROCONSPCCV SC SCP SE SFD SI SLD SOFC SPT SSCII STATCOM SVC SVM TCR TCSC THD TL TMS TSC UR/OR VAR VFI VRBIDT VSC WT WTBIDT

List of Acronyms

Line-to-line-to-ground Loss of grid Low-pass filter Metal oxide varistor Manual Trip Signal Non-detectable zone Point of common coupling Per unit Quality factor Root mean square Rate of change of negative-sequence PCC voltage Superimposed component Superimposed complex power Superimposed energy Shunt FACTS device Superimposed impedance Single-line diagram Solid oxide fuel cell Single-pole tripping Superimposed sequence components-based integrated impedance Static synchronous compensator Static VAR compensator Support vector machine Thyristor-controlled reactor Thyristor-controlled series capacitor Total harmonic distortion Transmission line Time multiplier setting Thyristor-switched capacitor Under-reach/Over-reach Volt ampere reactive Virtual fault impedance Voltage ripple-based islanding detection technique Voltage source converter Wavelet transform Wavelet transform-based islanding detection technique

List of Symbols

α α’, β’ β δ ω ϕ ρ or λ τ ΔI ΔId ΔIdth ΔP ΔPIB ΔQ ΔQIB ΔS ΔV ΔVd ΔZ ΔZth ar C Em, En fPCC H Id Idc Idpre Idth If

Angle Constants representing the steepness of the relay characteristic Firing angle Load angle Frequency in rad/sec Phase angle between voltage and current Fault distance in per unit from the sending end Relay torque angle Superimposed current phasor Superimposed differential current phasor Superimposed differential current setting Fault component integrated power (FCIP) Active power mismatch between DG and load Integrated IRP Reactive power mismatch between DG and load Incremental apparent power Superimposed voltage phasor Superimposed integrated voltage phasor Superimposed impedance (SI) Threshold for SI Moving discrete true root mean square Capacitance Voltage phasors of the source at end-m and end-n PCC frequency Relay setting minimum ratio Differential current phasor Direct Current Pre-fault differential current phasor Differential current setting Fault current phasor xvii

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If0, If1, If2 Im, In Ipv I s, I r Is0, Ir0 Is1, Ir1 Is2, Ir2 Ish or ISH Ist Isvc Itcr Itsc K1, K2, K3 K4 KPT, KCT L LIB or L1g Ltcr No Nr P Pdg Pgen PL PWT Qdg QL Rf RIB or R1g Vdc Vf Vf0, Vf1, Vf2 Vgrd Visld Vm, Vn VPCC Vpv Vsh or VSH Vst Vsvc or VSVC X Xcomp XDG XIB

List of Symbols

Zero-, positive-, and negative-sequence fault current phasors Current phasors at end-m and end-n PV current Current phasors at end-s and end-r Zero-sequence current phasors at end-s and end-r Positive-sequence current phasors at end-s and end-r Negative-sequence current phasors at end-s and end-r SFD current phasor STATCOM current phasor SVC current phasor TCR current phasor TSC current phasor Constants Mechanical restraint because of the presence of spring or gravity PT and CT ratios Inductance Utility grid or infinite bus source inductance TCR inductance Number of turns of the operating coil Number of turns of the restraining coil TL power flow DG output active power Generated power Load active power Power from wind turbine DG output reactive power Load reactive power Fault resistance Utility grid or infinite bus source resistance DC voltage Voltage phasor at fault point Zero-, positive-, and negative-sequence voltage phasors at fault point Voltage during grid-connected mode Voltage during islanding mode Voltage phasors of bus-m and bus-n PCC voltage phasor PV voltage SFD tap voltage phasor STATCOM tap voltage phasor SVC tap voltage phasor TL reactance Compensating reactance DG source reactance Utility grid or infinite bus source reactance

List of Symbols

Xm, Xn Xtcr Xtcsc Xtsc Xtssc Z Z0, Z1, Z2 Zapp Zc Zf Zfv ZIB ZL Zs, Zr ZSSCI ZSSCIa Zsh or ZSH Ztcsc Ztcsr Zth

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Source inductive reactances at bus-m and bus-n TCR reactance TCSC reactance TSC reactance TSSC reactance Impedance Zero-, positive-, and negative-sequence impedances Apparent impedance Line shunt charging impedance Fault impedance VFI Utility grid or infinite bus source impedance Load impedance Source impedances at bus-s and bus-r Superimposed sequence components-based integrated impedance SSCII of phase-A SFD (or SVC) impedance TCSC impedance TCSR impedance Setting for SSCII

List of Figures

Fig. 1.1

Fig. 1.2 Fig. 1.3 Fig. 2.1 Fig. 2.2 Fig. 2.3 Fig. 2.4 Fig. 2.5 Fig. 2.6 Fig. 2.7 Fig. 2.8 Fig. 2.9 Fig. 2.10 Fig. 2.11 Fig. 2.12 Fig. 2.13 Fig. 2.14 Fig. 2.15

Projected growth and installed capacity requirement of electric power in India. (a) Projected growth of electric power in India, (b) Projected installed capacity requirement in India . . . . . . . . . . . . . . Single-line representation of a two-terminal TCSC-compensated TL . .. . .. .. . .. . .. .. . .. . .. . .. .. . .. . .. . .. .. . .. . .. . .. Phasor diagrams for (a) voltage reversal and (b) current reversal .. . . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . . .. . . . .. . . . .. . . . .. . A typical TCSC and its characteristics. (a) A typical TCSC circuit diagram, (b) TCSC characteristics . . . . . . . . . . . . . . . . .. . . . . . . . . . An FC-TCR-type SVC module and its characteristics. (a) Module, (b) Characteristics . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Illustration of a STATCOM . . . . . . .. . . . . . . .. . . . . . . .. . . . . . . .. . . . . . . .. . . An illustration of a two-terminal uncompensated TL . . . . . . . . . . . . . . Phasor diagram for a two-terminal uncompensated TL . . . . . . . . . . . . An illustration of series-compensated two-terminal TL . . . . . . . . . . . Phasor diagram for series-compensated two-terminal TL . . . . . . . . . Variations in the active power flow with different levels of series compensation . .. . .. .. . .. . .. .. . .. .. . .. .. . .. . .. .. . .. .. . .. . .. .. . An equivalent single-line diagram of mid-point shuntcompensated TL .. . .. . .. . . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . . .. . .. Phasor diagram for a mid-point shunt-compensated TL . . . . . . . . . . . Variations in the active power flow in TL with shunt compensation . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Modified IEEE-33 bus system with three DGs . . . . . . . . . . . . . . . . . . . . . Solar-based DG connected to utility grid . . . . . . . . . . . . . . . . . . . . . . . . . . . Direct-in-line wind turbine system-based DG connected to utility grid .. .. . .. . .. .. . .. . .. .. . .. . .. . .. .. . .. . .. .. . .. . .. . .. .. . .. . .. .. . DFIG wind turbine system-based DG connected to utility grid . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

2 3 4 21 22 22 23 23 24 24 25 26 26 27 28 29 30 30

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Fig. 3.1 Fig. 3.2 Fig. 3.3 Fig. 3.4 Fig. 3.5 Fig. 3.6 Fig. 3.8 Fig. 3.7 Fig. 3.9 Fig. 3.10 Fig. 3.11 Fig. 3.12 Fig. 3.13 Fig. 3.14 Fig. 3.15 Fig. 3.16 Fig. 3.17 Fig. 3.18 Fig. 3.20 Fig. 3.19 Fig. 3.22 Fig. 3.21 Fig. 3.23 Fig. 3.24 Fig. 3.25 Fig. 3.26 Fig. 3.27 Fig. 3.28 Fig. 3.30 Fig. 3.31 Fig. 3.29 Fig. 3.32 Fig. 3.33 Fig. 4.1 Fig. 4.2 Fig. 4.3 Fig. 4.4 Fig. 4.5

List of Figures

Region of operation for impedance relay . . . . . . . . . . . . . . . . . . . . . . . . . . . Region of operation for impedance relay . . . . . . . . . . . . . . . . . . . . . . . . . . . Operating region for reactance relay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Region of operation for MHO relay . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phase comparison by multi-input comparators . . . . . . . . . . . . . . . . . . . . . Characteristic obtained by phase comparison of various Inputs .. . .. . .. .. . .. . .. .. . .. . .. .. . .. . .. .. . .. . .. .. . .. . .. .. . .. . .. .. . .. . .. .. . Biased differential relay connection arrangement . . . . . . . . . . . . . . . . . . Differential relay connection arrangement . . . . . . . . . . . . . . . . . . . . . . . . . . Operating characteristic of biased differential relaying . . . . . . . . . . . . Two-terminal transmission line connecting two areas . . . . . . . . . . . . . Sequence network connection diagram for an L-G fault . . . . . . . . . . Sequence network connection diagram for an LL fault . . . . . . . . . . . . Sequence network connection diagram for LL-G fault . . . . . . . . . . . . Sequence network diagram for a three-phase fault . . . . . . . . . . . . . . . . . A two-bus TCSC-compensated line system . . . . . . . . . . . . . . . . . . . . . . . . A two-bus TCSR-compensated line system . . . . . . . . . . . . . . . . . . . . . . . . A TSSC-compensated line system to demonstrate voltage inversion phenomenon .. . . .. . .. . .. . .. . . .. . .. . .. . .. . .. . . .. . .. . .. . .. . . .. Phasor for voltage inversion phenomenon . . . . . . . . . . . . . . . . . . . . . . . . . . Phasor for current inversion phenomenon . . . . . . . . . . . . . . . . . . . . . . . . . . A two-bus TSSC-compensated TL system to demonstrate the current inversion phenomenon . . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . (a) Positive-, (b) negative-, and (c) zero-sequence networks respectively of the system shown in Fig. 3.21 . .. . . . . .. . . . . .. . . . . .. . A two-bus mid-point shunt-compensated TL system . . . . . . . . . . . . . . Impedance trajectory (a) without SVC and (b) with SVC . . . . . . . . TCSC-based test systems . . . .. . . . . .. . . . .. . . . .. . . . . .. . . . .. . . . . .. . . . .. . . Impedance characteristics seen by the MHO relay R . . . . . . . . . . . . . . Time-graded scheme for radial feeder protection . . . . . . . . . . . . . . . . . . Instantaneous overcurrent relay for current-graded protection . . . . Combined time and current grading for radial feeder protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equivalent representation of microgrid – bidirectional flow . . . . . . Equivalent representation of microgrid – false tripping . . . . . . . . . . . Equivalent representation of microgrid – fault contribution . . . . . . . Equivalent representation of microgrid – blinding protection . . . . . Equivalent representation of microgrid – islanding . . . . . . . . . . . . . . . . A two-bus mid-point SVC-compensated TL system . . . . . . . . . . . . . . . Flowchart of SSCII scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . SSCII for an A-G fault at different locations in the TL . . . . . . .. . . . . SSCII for an A-G fault with different values of RF . . . . . . . . . . . . . . . . SSCII for a three-phase fault at different locations with unequal source impedance . . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . .. . . ..

34 35 36 37 38 40 41 41 42 42 43 43 44 45 46 47 47 47 48 48 49 49 52 52 53 54 55 55 57 57 57 58 59 64 66 67 68 69

List of Figures

Fig. 4.6 Fig. 4.7 Fig. 4.8 Fig. 4.9 Fig. 4.10 Fig. 4.11 Fig. 4.12 Fig. 4.13 Fig. 4.14 Fig. 4.15 Fig. 4.16

Fig. 4.17 Fig. 4.18 Fig. 4.19 Fig. 4.20 Fig. 4.21 Fig. 4.22 Fig. 4.23 Fig. 4.24

Fig. 4.25 Fig. 4.26 Fig. 4.27 Fig. 4.28 Fig. 4.29

The pre-fault single-line diagram of a shunt-compensated TL section . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equivalent diagram of a shunt-compensated TL section with an internal fault . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . .. . . . . Equivalent diagram of a shunt-compensated TL section with an internal fault . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . .. . . . . . . . . . . .. . . . . Phasor diagram for an internal fault for (a) capacitive and (b) inductive modes of compensation . . . . . . . . . . . . . . . . . . . . . . . . . . Flowchart of ERF-based algorithm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Test system-1 with mid-point STATCOM-compensated TL . . . . . . Acquired ERFs and Ida for an A-G fault at different fault locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Acquired ERFs and Ida for an A-G fault for different Rf values . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A two-bus uncompensated TL system as test system-2 . . . . . . . . . . . ERFs for an AB fault at different line locations in test system-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Single-line diagram (SLD) of a series-compensated TL during (a) pre-fault (b) external fault, and (c) internal fault conditions . . . . . . . . . . . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . Phasor diagram for an internal fault in a series-compensated TL system . . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . .. .. . Flowchart for EPE-based algorithm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Post-fault EPE of phase-A for an A-G fault at different fault locations with 30% compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Post-fault EPE of phase-A for an A-G fault at different fault locations with 70% compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Post-fault EPE of phase-A for an A-G fault for various values of Rf with 30% compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fault EPE of phase-A for an A-G fault for variations in SIR value with 30% compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Fault EPE of phase-A for an A-G fault for variations in SIR value with 30% compensation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (a) SFD-compensated transmission line and (b) its single-phase representation with internal and external fault mechanisms . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . . . .. . Variations in Zfv on real-imaginary plane . . . . . . . . . . . . . . . . . . . . . . . . . . . Flow diagram of IVFI scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IVFI for the SVC-compensated TL with different fault locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IVFI for the SVC-compensated TL with different fault resistances . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IVFI for the STATCOM-compensated TL with different fault locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

xxiii

69 70 71 72 73 73 74 75 75 75

77 79 80 81 82 82 83 83

84 85 87 87 88 89

xxiv

Fig. 4.30 Fig. 4.31 Fig. 4.32 Fig. 4.33

Fig. 4.34 Fig. 4.35 Fig. 4.36 Fig. 4.37 Fig. 4.38 Fig. 4.39 Fig. 4.40 Fig. 4.41 Fig. 4.42 Fig. 4.43

Fig. 4.44 Fig. 4.45 Fig. 4.46 Fig. 4.47 Fig. 4.48 Fig. 4.49 Fig. 4.50 Fig. 4.51 Fig. 4.52 Fig. 4.53

List of Figures

IVFI for the uncompensated TL with different fault locations . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Equivalent diagram of a two-bus TCSC-compensated TL system . . . . . . .. . . . . .. . . . . .. . . . . .. . . . . . .. . . . . .. . . . . .. . . . . .. . . . . . .. . . . . .. . . A two-bus TCSC-compensated TL system with internal fault at F . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phasor diagrams in the case of (a) ZFm is inductive, (b) ZFm is capacitive, and (c) ZFm is resistive for an internal fault . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phasor diagram when TCSC is in inductive mode for an internal fault . .. .. . .. . .. .. . .. .. . .. .. . .. . .. .. . .. .. . .. .. . .. .. . .. . .. A two-bus TCSC-compensated TL system with external fault at F . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Phasor diagram for external fault at F . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flowchart of EC-based algorithm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A two-bus TCSC-compensated TL test system . . . . . . . . . . . . . . . . . . . . ECs for a single-phase fault at different locations . . . . .. . . . . .. . . . .. . ECs for multi-phase fault at different locations . . . . . . . . . . . . . . . . . . . . ECs for different values of Rf for an A-G fault at F1 60 km away from end-s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Single-line diagram of (a) TCSC-compensated and (b) SVC-compensated systems respectively . . . . . . . . . . . . . . . . . . . Diagrams with incremental components for internal fault in (a) series-, (b) shunt-compensated TL system respectively, and for external fault in (c) series-, (d) shunt-compensated TL system respectively . . . . . . . . . . . . . . . . . . . . Flowchart of IRPC-based algorithm . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRPCs for an AB fault at different fault locations with 30% compensation . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRPCs for an AB fault at different fault locations with 70% compensation . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRPCs for an A-G fault at F2 50 km from end-s in test system-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRPCs for an A-G fault at F2 100 km from end-s in test system-2 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . IRPCs for a three-phase fault at different fault locations in test system-2 with load angles δ ¼ 30 and 45 . . . . . . . . . . . . . . . . IRPCs for an A-G fault at different line locations in test system-2 in the presence of weak source at end-s . . . . . . . . . . . .. . . . . . Flow diagram of the VRBIDT scheme . .. . . . . . . . . . . . . . . . . . . .. . . . . . . . Effect of changing operating frequency on averaging block with peak PCC voltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of changing operating frequency on RMS block with peak PCC voltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

89 91 91

92 93 93 93 95 96 96 97 97 99

100 101 102 103 104 104 105 105 107 108 109

List of Figures

Fig. 4.54 Fig. 4.55 Fig. 4.56 Fig. 4.57 Fig. 4.58 Fig. 4.59 Fig. 4.60

Fig. 4.61 Fig. 4.62 Fig. 4.63 Fig. 4.64 Fig. 4.65

Effect of changing active power mismatch on peak PCC voltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Effect of changing reactive power mismatch on peak PCC voltage . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Peak PCC voltage with different non-islanding events . . . . . . . . . . . . DWT technique with db-5 and level-5 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . Test system used for WT-based Scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . Flow diagram of WT-based scheme . . . . . . . . . . . . . . . . . .. . . . . . . . . . . . . . . (a) Voltage at PCC in volts, (b) detailed coefficient of db-5 at level-6, and (c) active and reactive powers absorbed in PU by infinite bus (IB) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (a) Considered test system and (b) corresponding superimposed equivalent circuit diagrams . . . . . . . . . . . . . . . . . . . . . . . . . . Flowchart of ΔZ-based islanding detection algorithm . . . . . . . . . . . . . |ΔZ| and PCC voltage for different load QFs with perfect power match condition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . |ΔZ| and PCC voltage for different load QFs with power mismatch conditions and other concerned conditions . . . . . . . . . . . . . Comparison of THD obtained with SI-based algorithm and existing scheme . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

xxv

109 110 111 112 113 114

115 117 119 120 120 121

List of Tables

Table 3.1 Table 4.1 Table 4.2

Characteristics obtained from different input combinations . . . . . . 39 Performance summary of IVFI-based scheme . . . . . . . . . . . . . . . . . . . . . 90 Tested events during simulation . .. . . .. . . .. . . .. . . .. . . . .. . . .. . . .. . . .. . 115

xxvii

Chapter 1

Introduction

1.1

General Background

Electricity is an essential part of daily life. Annual electric power demand is increasing due to several advantages such as easy transmission over long distances at nearly the speed of light and ease of transformation into other forms of energy, and also because electricity has numerous applications. The projected growth of power demand [1] and the projected installed capacity in India have been included in Figs. 1.1a, b respectively. In a deregulated market, different operators often have to use existing transmission network to carry large power flows through selected transmission lines (TLs). To achieve these goals, the power transfer capability of existing TLs is enhanced by incorporating flexible ac transmission system (FACTS) devices [2]. The FACTS devices are basically of two types, namely, series and shunt devices; each type has its own merits and demerits. Besides increasing the line power transfer capability, FACTS devices also enhance the stability and controllability of the transmission network. Although the FACTS devices have various advantages, they adversely affect TL protection since the devices alter the important transmission system variables such as load angle, voltage, current, and impedance. Therefore, existing protection schemes need to be reviewed in the presence of FACTS devices. Simultaneously, with the use of clean/renewable energy distributed generations (DGs), some part of the demand can be fulfilled. Nowadays, the focus is on the solarand wind-based DG. With the integration of DGs, the modern distribution system has now become an active network, which affects the protection strategies, that is, bi-directional power flow, impacts on power quality, and unintentional islanding. Islanding is a phenomenon in which the utility grid is unavailable and the distribution system is energized by the DGs only. This may lead to excessive voltage and/or frequency fluctuations that in turn may damage sensitive loads connected to the system. Therefore, protection against islanding is an important issue that should be reviewed. © Springer Nature Switzerland AG 2021 O. Hari Gupta et al., Protection Challenges in Meeting Increasing Electric Power Demand, https://doi.org/10.1007/978-3-030-60500-1_1

1

2

1 Introduction

Power Demand

Power (GW)

500 400

437

300

323

200 100 0

218 127 2009

152 2012

2017 Year

2022

2027

(a)

Installed Capacity 700 Power (GW)

600 575

500 400

425

300

306

200 100 0

152 2009

220 2012

2017 Year

2022

2027

(b) Fig. 1.1 Projected growth and installed capacity requirement of electric power in India. (a) Projected growth of electric power in India, (b) Projected installed capacity requirement in India

Next is the literature survey of protection of FACTS-compensated line and microgrid against islanding.

1.2 1.2.1

Literature Review Protection of FACTS-Compensated Line

FACTS devices are utilized to increase the power transmission proficiency and steadiness of the TL [3]. The usage of shunt compensation is an excellent method of regulating the TL voltage profile [2] and, in turn, improving the power transfer

1.2 Literature Review Em

Xm

3 Vm

m

ρX

Im

F (1-ρ)X

Xn

Er

Xtcsc

Fig. 1.2 Single-line representation of a two-terminal TCSC-compensated TL

capability. Leading VARs (capacitive) are utilized to compensate for under-voltages and lagging VARs (inductive) are utilized to compensate for over-voltages. A static VAR compensator (SVC) can provide capacitive as well as inductive VARs. A more versatile static compensator (STATCOM) is also the affiliate of the power electronics-based FACTS family and has also been utilized to recover the voltage profile, thereby forcing increased power transfer [4]. Like an SVC, STATCOM also has the ability to provide both types of compensation, that is, capacitive and inductive. Overall, to improve the voltage shape, SVC and STATCOM inject reactive power into the TL. Though these devices increase the power transfer, they affect the TL protection because system variables, that is, impedance and current, are disturbed by them [2, 5]. They also impose some other issues on the currently installed relaying systems because of their dynamic nature. The influences of the STATCOM and SVC are highlighted in [5–10]. The series type of compensator, that is, thyristor-controlled series capacitor (TCSC), has also been utilized to better the power flow by directly altering the line impedance. Apart from modulating the line impedance, TCSC can also create issues like current or voltage reversals after the inception of fault, and the relaying system may fail for the case of a TCSCcompensated TL [11–18]. Consider a short circuit fault created at F in a two-terminal TCSC-compensated TL as given in Fig. 1.2. The equations of current and voltage at end-m will be as written in (1.1) and (1.2), respectively [19]: Im ¼

Em X m þ ρX  X tcsc

V m ¼ Em

ρX  X tcsc X m þ ρX  X tcsc

ð1:1Þ

ð1:2Þ

Now, voltage reversal takes place when Xtcsc > ρX and Xm + ρX > Xtcsc. Similarly, current reversal exists when Xtcsc > Xm + ρX. Figure 1.3a illustrates the phasor diagram in the case of voltage reversal. Vm(nor) is the voltage during the normal or pre-fault condition, Vm(rev) is the voltage during faulty or voltage reversal condition, and Im is the current at end-m. Similarly, Fig. 1.3b depicts the phasor diagram in the case of the current reversal. In Fig. 1.3b, Im(nor) is the current during the pre-fault condition, Im(rev) is the current during faulty or current reversal condition, and Vm is the voltage at end-m.

4

1 Introduction

Fig. 1.3 Phasor diagrams for (a) voltage reversal and (b) current reversal

The conventional protection systems include the unit and non-unit relaying systems. Pilot and communication-aided protection schemes are considered as the unit relaying systems since they provide protection to the entire transmission line, while the distance protection schemes [20–22] are considered as the non-unit protection schemes since they provide protection to nearly 80–90% of the transmission line. The conventional non-unit protection method of TL is distance protection and is the most used method. The FACTS devices create problems for the relaying systems to protect TLs. The issues that come across in distance relaying systems in the existence of shunt FACTS devices (SFD) are reported in [6, 8, 9, 10, 18, 23–27]. It is also reported that the distance relaying system can face the problem of under-reach/ over-reach (UR/OR) [5–10, 28] which depends upon the degree of compensation and location of the fault [8, 9]. When the distance relay is unable to detect the faults inside its zone of protection, then this phenomenon is called under-reach. On the contrary, when a relay mis-detects a fault incepting external to its area of protection, then this phenomenon is called over-reach. Further, the presence of SFD may cause incorrect phase identification [9] and can cause a lack of success of single-pole tripping (SPT). In [6], the effect of SVC on a test system having double-circuit TL has been examined, and it was found that the under-reaching is increased for line-toground (L-G) faults (85% occurrence) and insignificant for line-to-line (LL) faults. Besides, modification in the system arrangement makes relay coordination difficult [29]. To minimize UR/OR effects, adaptive distance schemes [30–34] are chosen than ordinary distance schemes. A discussion of the adaptive zone relaying systems for SFD-compensated TL has been presented, and different formulas for reach point have been acquired in [31, 32, 35, 36] which are fairly accurate and give reliable results. In [30, 32], adaptive distance relaying settings are found utilizing the coordinated phasors of the relay- and mid-point of the TL. Nevertheless, either the fault classification problem is not addressed or simply one-phase fault is considered. Moreover, trip settings rely on the source impedance and need to be changed each time when the source impedance changes. To avoid the adverse effects of UR/OR and dependency on the source impedance, the pilot protection scheme is utilized in TLs [23, 24]. The differential current

1.2 Literature Review

5

relaying system is a pilot protection system in which if the current difference reaches the threshold, a fault is detected [37, 38, 39]. This scheme is easy to implement but finds limitation in detecting high-resistance faults in a long TL in the existence of the FACTS devices [23, 40–42], and therefore, the differential current relaying system is unsafe to high-impedance faults. Pilot-based protection systems are introduced in [23, 40–42] for the detection of faults in TLs that are capable of detecting highimpedance faults too. A fault component integrated impedance-based (FCII-based) relaying system is offered in [40] for a TL without compensation. This concept of the FCII-based relaying system could be utilized for the protection of SFD-compensated TL too. Nonetheless, during an asymmetrical fault in the variable SFD-compensated TL, incremental components are added to the healthy phase(s) too by the SFD that would be treated as fault components by the protection system, and therefore, healthy phases would also be identified as faulty phases. In [42], an integrated impedance-based relaying arrangement is suggested for a TL compensated by a series device. The algorithm successfully identifies all the faults with lower resistances in the existence of SFD. However, it becomes vulnerable to high-resistance faults [24]. Further, the relaying algorithms of [23, 40, 41] are reliant on the source impedance, and more information of transmission network is needed that creates the protection system susceptible to the network variations (since the effective sourceside impedance of the network can vary with time), and settings of the algorithm need to be reorganized for modified source impedance. Moreover, in [40, 42], the mutual coupling impact on the sound phases for unbalanced faults is not testified. A fault component integrated power-based (FCIP-based) protection algorithm has been proposed in [43] lately. The derivations of [43] have been attained utilizing per-phase calculations, and the influence of mutual components has not been included. It has been obtained that for line-to-line-to-ground (LL-G) fault, mutual coupling influence is huge on the algorithm proposed in [43], and therefore, it might be identified as an L-G fault. The directional feature-based communication-aided protection schemes also find limitations in the case of series FACTS-compensated TLs because of the problems of current/voltage reversals. In the case of current/voltage reversals, the relay might identify the wrong direction of the fault and an internal fault may be treated as an external fault [19, 44–46]. Several directional relaying schemes are available [19, 44, 45, 47, 48] which are formed using phase angle variance of some parameters. Nevertheless, the protection algorithms developed in [19, 44, 45, 47, 48] do not categorize fault type which is mandatory for SPT. In one more literature [49], the study of sequence directional features is obtained, and it was determined that the modifications in source impedance might cause mis-operation of the directional unit. The directional protection algorithm could be utilized to detect internal faults in TL when the relaying units at both points of TL converse to one another for a case of a forward fault. Several other directional relaying schemes are proposed in [50– 53]. These schemes require a high sampling rate. In [51], the principle for direction finding has been created using an impulse response. Nonetheless, the period of the

6

1 Introduction

established criteria is small and depends on the inception angle. Furthermore, in [52, 53], the power system is presumed reactive and fault categorizing issue has still not been introduced. Several directional protection algorithms based on superimposed components and energy have been introduced in [26, 54–61]. The energy-based digital algorithms are precise for enormous deviations in the transmission networks. Nevertheless, these algorithms cannot be utilized directly to categorize the type of fault as they depend on fault distance, type, and impedance. Wide area measurement-based schemes are also used for TL protection [62]. Nonetheless, they depend on a lot of data measured at various nodes. Artificial Neural Network (ANN) and Support Vector Machine-based (SVM-based) relaying algorithms are used for the protection of power system [63–70], which provide valuable results. Though such algorithms are fairly precise, they need a lot of computational determinations and wide-ranging training statistics from the power system. A fault distance approximation algorithm for SFD-compensated TL has been introduced in [71] utilizing optimization procedure, and to implement such a procedure, information of fault type is needed, which has not been described in [71]. The impacts of SFD on distance relaying systems are presented in [72], and various channel-aided communication-based soothing methods are utilized. Generally, one-phase faults are high-impedance faults, and a maximum fault impedance of 50 Ω is included in [72], which is relatively lesser than high fault impedances included in the latest articles [23, 42]. An S-transform-based distance relaying algorithm is presented in [73], which identifies the type and distance of the fault. The algorithm is applied for the protection of STATCOM-compensated TL. When the algorithm is applied without STATCOM, it needs alterations in the bias settings. In [74, 75], cross-differential relaying of SFD-compensated TL is proposed by applying Fast Discrete S-transform. Nonetheless, the relaying is merely valid for a double-circuit TL because the relaying utilizes cumulative differential signals (that rely on the difference of current among two parallel TLs). In [76], a traveling-wavebased relaying is applied to obtain the direction of the fault. However, this technique needs very high sampling frequency and can fail because there would be no traveling wave existing if the fault occurs with an inception angle equal to zero. Several other traveling-wave-based schemes are introduced in [77–79] for the protection of TLs. These schemes can have the capability of locating the fault also; nonetheless, separate relays with a high sampling rate would be needed. Lately, a Taylor– Kalman–Fourier filter-based distance protection algorithm has been introduced in [80], which will not have any effect of decaying DC components and harmonics. Nevertheless, distance relaying algorithms find limitations in the presence of series/ shunt FACTS devices [81]. There are algorithms that utilize wavelet methods to protect the TLs [15, 82–84]. However, such algorithms are vulnerable in the presence of FACTS devices because they may vary the frequency spectrum of the obtained signal.

1.2 Literature Review

1.2.2

7

Microgrid Islanding Protection

There are various issues in the control and protection of microgrids. These issues are optimal placement of a DG [85], load transient mitigation [86], power management [87, 88], frequency stabilization [89], and islanding detection [90, 91]. In this study, only the issue of islanding detection is considered. When the utility grid is unavailable, the distribution system becomes an active island. As per IEEE STD 1547-2003 [92], all the DGs should be disconnected within 2 seconds after an islanding has occurred. Generally, four types of islanding detection methods are known, viz., passive methods [93–97], active methods [98–109], communication-based methods [110], and hybrid methods [111–113] (i.e., using both active and passive methods). These are presented next. The under-voltage/over-voltage and frequency relays are the passive relays to detect an islanding event. Moreover, rate-of-change-of-frequency (ROCOF) [114] and rate-of-change-of-voltage-based (ROCOV-based) relays are also passive relays used to detect an islanding condition. Several other passive islanding detection schemes are ROCOF overpower [96], voltage unbalance [115], total harmonic distortion technique [116], and so on. These relays may detect an islanding event if there is a sufficient mismatch between DG output power and load power, that is, there is always a non-detectable zone (NDZ). There are schemes that can reduce the area of NDZ. Several schemes use signal processing techniques such as wavelet transform [117, 118] and S-transform [119, 120] to extract new features of the measured signal. Moreover, intelligent techniques such as Artificial Neural Networks (ANNs) [121, 122] and Fuzzy Logic [94, 123] are also used for islanding detection. However, these schemes either fail to detect when closely matched DG and load powers exist or may find limitation distinguishing the islanding and other types of disturbances. Another simple passive islanding detection technique that uses the rate-of-change-of-voltage-phase-angle (ROCOVPA) [110] is introduced that has comparatively little NDZ. Nevertheless, if the inverter control method is varied from dependent to independent, such a method finds its limits. Moreover, the event of a fault will also be mis-detected as an event of islanding by such a method. To eliminate the problem of NDZ, active methods use intentional disturbance injection which deviates either the point of common coupling (PCC) voltage or frequency from their desirable limits. Although these schemes have the capability of detecting an island during perfectly matching conditions, such schemes seriously degrade the power quality. Several algorithms exist which reasonably decrease the quantity of perturbation injection but not its frequency of injection. Therefore, regular injections still largely degrade power quality. A few active islanding detection methods have been listed below: • • • •

Slip-mode frequency shift [98] Negative sequence current injection [99] Negative sequence voltage injection [102] Active frequency drift [103]

8

• • • • • • • •

1 Introduction

Current injection [104] Virtual capacitor [105] Virtual inductor [106] Sandia frequency shift [107] High-frequency signal injection [108] Sandia voltage shift [109] Phase-locked loop (PLL) perturbation [100] Voltage phase angle feedback-based active method [101]

All the above-mentioned methods inject regular disturbances into the PCC and, therefore, degrade the power quality at the PCC. Communication-based methods detect an islanding event based on communication between utility and DG. These techniques are extra dependable but are very costly in terms of setting up of peripheral signal apparatus. Therefore, such schemes are hardly chosen [110]. There are several hybrid islanding detection techniques that use both passive and active methods to detect an islanding event. In [111], the frequency set point is shifted to observe the deviation in PCC frequency. If the PCC frequency reaches a certain value, an islanding event is detected. The frequency set point is, however, shifted only after observing some voltage unbalance. The method finds its limits when there is no sufficient voltage unbalance. Further, it can take about 1.5 s to identify an event of islanding. Likewise, there should be a small voltage change at the PCC for the successful application of the rate of power shift-based (RPS-based) scheme proposed in [113].

1.3

Summary and Book Organization

A literature review on the protection of TLs and for the detection of an islanding event – in the presence of switching devices – has been presented. The changes required in the power system to meet the increasing power demand will be discussed next. Thereafter, a brief discussion of the existing protection schemes and their challenges is presented. After that, the solutions to the protection challenges – based on normal and superimposed components – will be presented. First, a superimposed sequence components-based integrated impedance, that is, SSCII-based pilot relaying scheme [23] is discussed for the protection of TL in the presence of SVC that gives promising results. After testing the SSCII-based scheme, it is found that the scheme is susceptible to measurement errors, the relay settings depend on the source impedance, and also a knowledge of the SFD is required. To overcome these limitations, there is an estimated reactive power factor, that is, ERFbased scheme, proposed in [124], whose settings are independent of the source impedance and do not require knowledge of SFD. However, the scheme finds limitations for high fault resistances (i.e., Rf > 50 Ω). Another scheme based on estimated phase error (EPE) [125] is discussed that uses the data of both the ends and

References

9

successfully detects the faults under different faulty conditions. Nevertheless, this method cannot classify the fault type since it uses positive sequence phasors only. Then there is imaginary component of the virtual fault impedance, that is, IVFIbased method [126], which too uses the measurements of both the ends and successfully identifies and classifies the faults under different scenarios. Nonetheless, it might not work well for a TCSC TL. To prevail over these problems, another communication-aided, superimposed energy-based scheme [127] is discussed, which is not affected by the measurement errors, which can be applied for series as well as shunt-compensated lines, whose settings do not depend on the source impedance, and for which data of FACTS device are not required. The performance of this scheme is found to be accurate for the detection of an internal fault. Nonetheless, it has found its limitation while identifying the type of fault. A new superimposed reactive power-based improved pilot relaying scheme is proposed in [128, 129] to overpower the limitation of incorrect fault-type identification. This improved pilot relaying is found to be robust, accurate, and selective against various real system scenarios. Second, the islanding detection problem of a microgrid has been discussed, and then three islanding detection methods are discussed including voltage ripple-based method [130, 131], wavelet transform-based method [132], and an islanding detection scheme which uses superimposed component impedance (SI) measured at the PCC [133, 134]. The advantages and limitations of each scheme are discussed. The SI-based scheme has the advantage of having negligible NDZ, and it hardly degrades the power quality of distribution system since it injects only a very small amount of perturbations into the system and that too when an alert signal is generated. Centered on the identified goals or objectives, the rest of the book is organized into several chapters as follows: Chapter 2 presents the modifications required in the power system to meet increasing power demands. Commonly used existing protection schemes and their limitations/challenges in the presence of switching devices are given in Chap. 3. Chapter 4 presents a few solutions to these challenges in protection schemes. For the faults during a variety of the adverse/stressed transmission and distribution system conditions, the analysis of the results obtained using PSCAD/EMTDC and MATLAB is included. Chapter 5 presents the conclusion and scope for future work, and then Chap. 6 includes references.

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1 Introduction

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95. Shooshtari, B. A., Golshan, M. E. H., & Sadeghkhani, I. (2014, November). A combined method to efficiently adjust frequency-based anti-islanding relays of synchronous distributed generation. International Transactions on Electrical Energy Systems, 25(11), 3042–3059. 96. Pai, F.-S., Huang, S.-J., Pai, F. S., & Huang, S. J. (2001, December). A detection algorithm for islanding-prevention of dispersed consumer-owned storage and generating units. IEEE Transactions on Energy Conversion, 16(4), 346–351. 97. Padhee, M., Dash, P. K., Krishnanand, K. R., & Rout, P. K. (2012, September). A fast gaussnewton algorithm for islanding detection in distributed generation. IEEE Transactions on Smart Grid, 3(3), 1181–1191. 98. Liu, F., Kang, Y., Zhang, Y., Duan, S., & Lin, X. (2010, January). Improved SMS islanding detection method for grid-connected converters. IET Renewable Power Generation, 4(1), 36. 99. Karimi, H., Yazdani, A., & Iravani, R. (2008, January). Negative-sequence current injection for fast islanding detection of a distributed resource unit. IEEE Transactions on Power Electronics, 23(1), 298–307. 100. Velasco, D., Trujillo, C., Garcera, G., & Figueres, E. (2011, April). An active anti-islanding method based on phase-PLL perturbation. IEEE Transactions on Power Electronics, 26(4), 1056–1066. 101. Pourbabak, H., & Kazemi, A. (2014, May). A new technique for islanding detection using voltage phase angle of inverter-based DGs. International Journal of Electrical Power & Energy Systems, 57, 198–205. 102. Sul, S.-K. K. (2012). Anti-islanding detection method using negative sequence voltage. In Proceedings of the 7th international power electronics and motion control conference (Vol. 1, pp. 604–608). 103. Hanif, M., Basu, M., & Gaughan, K. (2011). A discussion of anti-islanding protection schemes incorporated in a inverter based DG. In 2011 10th international conference on environment and electrical engineering (pp. 1–5). 104. Hernandez-Gonzalez, G., & Iravani, R. (2006, July). Current injection for active islanding detection of electronically-interfaced distributed resources. IEEE Transactions on Power Delivery, 21(3), 1698–1705. 105. Chiang, W.-J., Jou, H.-L., & Wu, J.-C. (2012, November). Active islanding detection method for inverter-based distribution generation power system. International Journal of Electrical Power & Energy Systems, 42(1), 158–166. 106. Jou, H. L., Chiang, W. J., & Wu, J. C. (2007, September). Virtual inductor-based islanding detection method for grid-connected power inverter of distributed power generation system. IET Renewable Power Generation, 1(3), 175. 107. Zeineldin, H. H., & Conti, S. (2011, March). Sandia frequency shift parameter selection for multi-inverter systems to eliminate non-detection zone. IET Renewable Power Generation, 5 (2), 175–183. 108. Reigosa, D., Briz, F., Blanco, C., Garcia, P., Manuel Guerrero, J., & Guerrero, J. M. (2014, March). Active islanding detection for multiple parallel-connected inverter-based distributed generators using high-frequency signal injection. IEEE Transactions on Power Electronics, 29 (3), 1192–1199. 109. Stevens, J., Bonn, R., Ginn, J., Gonzalez, S., & Kern, G. (2000). Development and testing of an approach to anti-islanding in utility-interconnected photovoltaic systems. Sandia National Laboratories. 110. Ghanbari, T., Samet, H., & Hashemi, F. (2015, November). Islanding detection method for inverter-based distributed generation with negligible non-detection zone using energy of rate of change of voltage phase angle. IET Generation Transmission and Distribution, 9(15), 2337–2350. 111. Menon, V., & Nehrir, M. H. (2007, February). A hybrid islanding detection technique using voltage unbalance and frequency set point. IEEE Transactions on Power Apparatus and Systems, 22(1), 442–448.

16

1 Introduction

112. Khodaparastan, M., Vahedi, H., Khazaeli, F., & Oraee, H. (2015, February). A novel hybrid islanding detection method for inverter-based DGs using SFS and ROCOF. IEEE Transactions on Power Delivery, In Press, 1–9. 113. Mahat, P., Bak-Jensen, B., & Jensen, B. B. (2009, April). A hybrid islanding detection technique using average rate of voltage change and real power shift. IEEE Transactions on Power Delivery, 24(2), 764–771. 114. Freitas, W., Xu, W., Affonso, C. M., & Huang, Z. (2005, April). Comparative analysis between ROCOF and vector surge relays for distributed generation applications. IEEE Transactions on Power Delivery, 20(2), 1315–1324. 115. Sadeh, J., & Kamyab, E. (2013, June). Islanding detection method for photovoltaic distributed generation based on voltage drifting. IET Generation Transmission and Distribution, 7(6), 584–592. 116. Jang, S. I., & Kim, K. H. (2004, April). An islanding detection method for distributed generations using voltage unbalance and total harmonic distortion of current. IEEE Transactions on Power Delivery, 19(2), 745–752. 117. Karegar, H. K., & Sobhani, B. (2012, February). Wavelet transform method for islanding detection of wind turbines. Renewable Energy, 38(1), 94–106. 118. Hsieh, C.-T. T., Lin, J.-M. M., & Huang, S.-J. J. (2008, December). Enhancement of islandingdetection of distributed generation systems via wavelet transform-based approaches. International Journal of Electrical Power & Energy Systems, 30(10), 575–580. 119. Ray, P. K., Kishor, N., Mohanty, S. R., Member, S., Kishor, N., & Mohanty, S. R. (2012, September). Islanding and power quality disturbance detection in grid-connected hybrid power system using wavelet and s-transform. IEEE Transactions on Smart Grid, 3(3), 1082–1094. 120. Ray, P. K., Mohanty, S. R., & Kishor, N. (2011, March). Disturbance detection in gridconnected distributed generation system using wavelet and S-transform. Electric Power Systems Research, 81(3), 805–819. 121. Samantaray, S. R., Babu, B. C., & Dash, P. K. (2011, January). Probabilistic neural network based islanding detection in distributed generation. Electric Power Components and Systems, 39(3), 191–203. 122. ElNozahy, M. S., El-Saadany, E. F., & Salama, M. M. A. (2011). A robust wavelet-ANN based technique for islanding detection. In 2011 IEEE power and energy society general meeting (pp. 1–8). 123. Hashemi, F., Ghadimi, N., & Sobhani, B. (2013, February). Islanding detection for inverterbased DG coupled with using an adaptive neuro-fuzzy inference system. International Journal of Electrical Power & Energy Systems, 45(1), 443–455. 124. Gupta, O. H., & Tripathy, M. (2016). ERF-based fault detection scheme for STATCOMcompensated line. International Transactions on Electrical Energy Systems. 125. Gupta, O. H., & Tripathy, M. (2018, July). EPE-based pilot relaying scheme immune to SIR variations. IETE Journal of Research. 126. Gupta, O. H., Tripathy, M., & Sood, V. K. (2017). Digital relaying scheme for protection of shunt-compensated transmission lines. In 2017 IEEE electrical power and energy conference (EPEC) (pp. 1–6). 127. Gupta, O. H., & Tripathy, M. (2016, June). Superimposed energy-based fault detection and classification scheme for series-compensated line. Electric Power Components and Systems, 44(10), 1095–1110. 128. Gupta, O. H., & Tripathy, M. (2017, December). An improved pilot relaying scheme for shunt compensated transmission line protection based on superimposed reactive power coefficients. Electric Power Components and Systems, 45(20), 2228–2245. 129. Gupta, O. H., & Tripathy, M. (2018, February). Universal pilot relaying scheme for series and shunt-compensated lines. IET Generation Transmission and Distribution, 12(4), 799–806. 130. Ansari, S., & Gupta, O. H. (2020). Voltage ripple based islanding technique on modified IEEE-13 bus test feeder for photovoltaic inverter. In O. H. Gupta & V. K. Sood (Eds.), Recent advances in power system - select proceedings of EPREC 2020. Cham: Springer Nature.

References

17

131. Guha, B., Haddad, R. J., & Kalaani, Y. (2016). Voltage ripple-based passive islanding detection technique for grid-connected photovoltaic inverters. IEEE Power and Energy Technology Systems Journal, 3(4), 143–154. 132. Ansari, S., Gupta, O. H., & Tripathy, M. (2020). An islanding detection methodology for SOFC-based static DG using DWT. In Electric power and renewable energy conference (EPREC - 2020). 133. Gupta, O. H., Tripathy, M., & Sood, V. K. (2020). Hybrid event classification scheme for converter-based DG with improved power quality. In Microgrid: operation, control, monitoring and protection (pp. 1–30). Springer. 134. Gupta, O. H., Tripathy, M., & Sood, V. K. (2019, December). Islanding detection scheme for converter-based DGs with nearly zero non-detectable zone. IET Generation Transmission and Distribution, 13(23), 5365–5374.

Chapter 2

Modifications Required in Power System to Meet Increasing Power Demand

2.1

Introduction

The emerging power demand can be fulfilled by installing the new power-generating stations with larger capacities. The transmission of this bulk power can take place either with the help of new transmission lines or by incorporating FACTS devices. However, building new transmission lines is not always feasible or economical, and therefore, the use of FACTS devices is encouraged. The line parameters such as current, voltage, and effective impedance can be manipulated with the use of FACTS devices. The manipulation of these parameters helps to push more power through existing transmission infrastructures. Apart from enhancing the power flow, FACTS devices can also improve system stability by applying proper control. There are different types of FACTS devices available such as thyristor-controlled series capacitor (TCSC), static VAR compensator (SVC), and static synchronous compensator (STATCOM). Another way to meet the growing electric demand is to add distributed generations (DGs) to the system. This mainly provides better energy surety with the reduction in transmission losses, thereby making it a more preferred choice nowadays. Also, the autonomous operation of the distribution system with embedded DGs (i.e., microgrid) increases the reliability of supply. Most of the DGs are based on renewable energy such as solar, biomass, and wind. This chapter presents modifications/changes required in the power system to provide the desired power to the load centers (distribution side).

© Springer Nature Switzerland AG 2021 O. Hari Gupta et al., Protection Challenges in Meeting Increasing Electric Power Demand, https://doi.org/10.1007/978-3-030-60500-1_2

19

20

2.2

2 Modifications Required in Power System to Meet Increasing Power Demand

Facts to Enhance Power Flow Through Transmission Line

If different parameters of the transmission lines are modulated, power flow through the transmission line (TL) can be controlled allowing the system operator to use it either for enhanced power flow or for stabilizing the system. Out of the many types of series/shunt FACTS devices available, only the commonly used FACTS devices such as thyristor-controlled series capacitor (TCSC), static VAR compensator (SVC), and static synchronous compensator (STATCOM) are discussed in this chapter.

2.2.1

Thyristor-Controlled Series Capacitor (TCSC)

It is a series-FACTS device that offers an economical solution to improve power transfer capability and stability. TCSC can be preferred where parameters of existing TLs are to be adjusted for parallel operation of newly added TLs. It is a parallel combination of a capacitor and thyristor-controlled reactor (TCR) where TCR is a series combination of an inductor and a pair of anti-parallel thyristors. The circuit diagram of a typical TCSC is depicted in Fig. 2.1a. TCSC is placed in series with the transmission line. It can work in capacitive as well as inductive modes. The capacitive mode of operation is generally required to improve the power flow, while the inductive mode can be used to limit the fault current. Figure 2.1b shows the TCSC characteristics. For the values of firing angle, β between “0” and βL(lim), TCSC acts as a variable inductor. Similarly, for the values of β between βC(lim) and π/ 2, TCSC acts as a variable capacitor. The TCSC operation is inhibited between βL (lim) and βC(lim) since TCSC can resonate and can possess a very high impedance between these values of firing angle.

2.2.2

Static VAR Compensator (SVC)

SVC is a variable susceptance-type shunt compensator. Such compensators can be preferred to improve the voltage profile of the TL. The thyristors along with the basic reactive elements (i.e., inductor and capacitor) are used in SVC. It injects or absorbs the reactive power to/from a transmission line to improve the voltage profile by varying its susceptance. In other words, it can operate in either of two modes, that is, production and absorption modes. The basic circuit diagram of a single-phase SVC is shown in Fig. 2.2a. It consists of a fixed capacitor (FC) and a TCR. In place of an FC, thyristor-switched capacitor (TSC) can also be used. To protect the thyristors

2.2 Facts to Enhance Power Flow Through Transmission Line

21

C

T1 Ltcr T2

(a) 1/(ωC)=ωL(β) XTCSC Inductive

Operation inhibited for βL(lim) XTSSC) and lags Vs by 90 . However, in the case of fault at F, the fault current If seen by the relay R is capacitive and leads Vs by 90 , and hence there is a 180

48

3 Existing Protection and Challenges

Is Es

Zs

Is R

ρX

F

Vs

Xtssc

Ir (1-ρ)X

Zr

Er

Vr

If If

Fig. 3.19 A two-bus TSSC-compensated TL system to demonstrate the current inversion phenomenon

If

180

o

90 90

o

o

Vs

Is Fig. 3.20 Phasor for current inversion phenomenon

phase difference between Is and If as shown in Fig. 3.20, that is, the current inversion case. The relay will not operate for the fault as it detects the fault behind its protection zone.

3.3.3

Shunt FACTS Devices and Their Impacts on Conventional Protection

Shunt FACTS devices provide voltage control, stability under transient and dynamic conditions of the system, voltage stability, damping of oscillations, and so on, by controlling reactive power flow through the connected TL [18]. Following are the shunt FACTS devices: • • • • •

Static synchronous compensator (STATCOM) Thyristor-controlled reactor (TCR) Thyristor-switched capacitor (TSC) Thyristor-switched reactor (TSR) Static VAR compensator (SVC)

The aforementioned shunt FACTS controllers also cause under/overreach problems, similar to series FACTS controllers, and may lead to failure or mal-operation of conventional distance relaying scheme for the protection of the TL system. In

3.3 Challenges in the Protection of FACTS-Compensated Line

Es

Is

Zs

R

(ρ-a)Z

aZ

Vs

F

(1-ρ)Z If

Ish Zsh

Rf

49

Ir

Zr

Er

Vr

Fig. 3.21 A two-bus mid-point shunt-compensated TL system

Es

Zs1

Is1 R

Vs1

aZ1

(ρ-a)Z1

Ish1 Zsh1

Ir1 Zr1 F (1-ρ)Z1 If1 Vr1 Rf

Er

(a)

Zs2

Is2 R

aZ2

(ρ-a)Z2

Ish2

Vs2

Zsh2

Ir2 Zr2 F (1-ρ)Z2 If2 Vr2 Rf

(b)

Zs0

Is0

Vs0

R

aZ0

(ρ-a)Z0

Ish0 Zsh0

Ir0 Zr0 F (1-ρ)Z0 If0 Vr0 Rf

(c) Fig. 3.22 (a) Positive-, (b) negative-, and (c) zero-sequence networks respectively of the system shown in Fig. 3.21

order to understand the aforesaid impact of shunt FACTS controller, a two-bus mid-point shunt-compensated TL system has been considered, as shown in Fig. 3.21, where: a ¼ 0.5 (constant) ISH ¼ Current injected by the shunt controller ZSH ¼ Equivalent impedance of the shunt controller Rf ¼ Fault resistance If ¼ Fault current For the fault analysis, the corresponding sequential networks for the fault at F of the considered system are shown in Fig. 3.22. For a line-ground (L-G) fault, all three

50

3 Existing Protection and Challenges

sequential networks are connected in series, and the voltage seen by the relay R is given by (3.17): Vs ¼ Vs1 þ Vs2 þ Vs0

ð3:17Þ

On the basis of sequential networks, as shown in Fig. 3.22, we have Vs1 ¼ Is1 ðaZ 1 Þ þ ðρ  aÞZ 1 ðIs1 þ ISH1 Þ þ If1 Rf Vs2 ¼ Is2 ðaZ 2 Þ þ ðρ  aÞZ 2 ðIs2 þ ISH2 Þ þ If2 Rf Vs0 ¼ Is0 ðaZ 0 Þ þ ðρ  aÞZ 0 ðIs0 þ ISH0 Þ þ If0 Rf

ð3:18Þ

Putting values of Vs1, Vs2, and Vs0 from (3.18) to (3.17), we get Vs ¼ aðIs1 Z 1 þ Is2 Z 2 þ Is0 Z 0 Þ þ ðρ  aÞ½Z 1 ðIs1 þ ISH1 Þ þ Z 2 ðIs2 þ ISH2 Þ þ Z 0 ðIs0 þ ISH0 Þ þðIf1 þ If2 þ If0 ÞRf

Since, for TL, the positive- and negative-sequence line impedances are equal to each other, that is, Z1 ¼ Z2 and If1 + If2 + If0 ¼ If, the above equation can be written as: ) Vs ¼ a½ðIs1 þ Is2 ÞZ 1 þ Is0 Z 0  þ ðρ  aÞ½Z 1 ðIs1 þ Is2 þ ISH1 þ ISH2 Þ þ Z 0 ðIs0 þ ISH0 Þ þ If Rf " # Z 1 ðIs1 þ Is2 þ Is0 þ ISH1 þ ISH2 þ ISH0 Þ ¼ a½ðIs1 þ Is2 þ Is0 ÞZ 1 þ Is0 ðZ 0  Z 1 Þ þ ðρ  aÞ þ If R f þðZ 0  Z1 ÞðIs0 þ ISH0 Þ ¼ a½Is Z 1 þ Is0 ðZ 0  Z 1 Þ þ ðρ  aÞ½Z 1 ðIs þ ISH Þ þ ðZ 0  Z1 ÞðIs0 þ ISH0 Þ þ If Rf

) Vs ¼ aZ 1 ½Is þ c0 Is0  þ ðρ  aÞZ 1 ½ðIs þ ISH Þ þ c0 ðIs0 þ ISH0 Þ þ If Rf Z  Z1 where, c0 ¼ 0 Z1

ð3:19Þ

The impedance seen by the relay R is given by Z seen ¼

Vs Is

ð3:20Þ

Substituting the value of Vs from (3.19) in (3.20), we get (3.21): aZ 1 ½Is þ c0 Is0  þ ðρ  aÞZ 1 ½ðIs þ ISH Þ þ c0 ðIs0 þ ISH0 Þ þ If Rf Is   ½Is þ c0 Is0  ½ðIs þ c0 Is0 Þ ½ðI þ c0 ISH0 Þ I ¼ aZ 1 þ ðρ  aÞZ 1 þ Rf f þ ðρ  aÞZ 1 SH Is Is Is Is

Z seen ¼

ð3:21Þ The presence of shunt FACTS device in the system has an impact on the impedance seen by the relay R when the fault has occurred after the controller. This may lead to under/overreach problems, and the relay may not operate or mal-operate for the fault inside or outside of its protection zone correspondingly.

3.3 Challenges in the Protection of FACTS-Compensated Line

3.3.4

51

Combination of Series and Shunt FACTS Devices and Their Influences on Conventional Protection Schemes

The combination of series and shunt FACTS devices provides voltage control, active and reactive power flow, stability under the transient and dynamic conditions of the system, voltage stability, damping of oscillations, and so on, by controlling active and reactive power flow through the connected TL. Following devices are the combination of series and shunt FACTS devices: • Unified power flow controller (UPFC) • Thyristor-controlled phase shifting transformer (TCPST) Aforesaid controllers have merits of both series and shunt controllers. However, they also have the limitations of both controllers, as they suffer from under/overreach problems [19] and may cause ambiguity to conventional distance relaying schemes.

3.3.5

Simulated Verification of the Discussed Impact of FACTS Devices on the Conventional Relaying Schemes

The apparent impedance for different types of faults can be calculated using (3.11), (3.15), and (3.16). Normally, during the fault, the calculated apparent impedance should lie within the tripping region of the relay. For high-voltage AC (HVAC) transmission lines, the MHO relay is preferred, as it is a directional relay and less affected by power surges and other disturbances. FACTS devices severely affect conventional distance protection schemes. Consider a 300 km transmission system, as depicted in Fig. 3.21, having a mid-point SVC compensation of 167/100 MVAR (TSC/TCR) [20]. Figure 3.23a depicts the impedance trajectory for an A-G fault at 200 km in a transmission line without SVC. The trajectory lies inside the MHO circle and thus detects an internal fault. A similar fault is created in a mid-point SVC-compensated line, and the impedance trajectory is depicted in Fig. 3.23b. It can be observed that the impedance trajectory lies outside the MHO circle. Therefore, the MHO relay fails to protect the line (in the presence of SVC) even though the relay is supposed to protect the line up to 240 km (80% of 300 km). In order to investigate the overreach problem associated with a TCSCcompensated TL, a two-bus, 750 kV, 50 Hz, mid-point TCSC-compensated, 550 km long TL has been simulated in PSCAD/EMTDC environment, as shown in Fig. 3.24. Line-1, line-2, and line-3 are 50 km, 450 km, and 50 km long, respectively. A distance relaying scheme has been used for the protection of line-2

52

3 Existing Protection and Challenges

Fig. 3.23 Impedance trajectory (a) without SVC and (b) with SVC

Es

Zs

Line-1

Line-2

Is R

Vs

Fig. 3.24 TCSC-based test systems

Z/2

Z/2 ZTCSC

Ir Vr

Line-3 F

Zr

Er

3.4 Distribution System Protection

53

Fig. 3.25 Impedance characteristics seen by the MHO relay R

with MHO relay characteristics, that is, relay R shown in Fig. 3.24 is an MHO relay. An L-G fault is introduced at F, and the corresponding impedance plot is presented in Fig. 3.25. It can be seen from Fig. 3.25 that the impedance seen by the MHO relay R has crossed the threshold and mal-operated for the fault beyond its reach (overreach problem) and may lead to failure of the system.

3.4

Distribution System Protection

The protection of the distribution system conventionally involves overcurrent relays with/without directional features, depending upon the requirements. The relay operating time [21] can be described using the formula given in (3.22): TMS  β0 t op ¼  α0 I 1 I pickup

ð3:22Þ

where TMS ¼ time multiplier setting, I ¼ current, Ipickup ¼ pickup current, α’ and β’ represent the steepness of the relay characteristic. For example, for a normally inverse relay, α’ and β’ are 0.02 and 0.14; for a very inverse relay, α’ and β’ are 1 and 13.5; for an extremely inverse relay, α’ and β’ are 2 and 80; and for a long-time inverse relay, α’ and β’ are 1 and 120, respectively. Overcurrent protection is one of the simplest and popularly used methods for protecting distribution lines by using two or more overcurrent relays. Each line section is protected using two or more relays, with one relay for each section. Figure 3.26 illustrates the overcurrent protection of radial feeders consisting of primary and backup protection schemes. Any fault beyond bus 3 results in tripping of the relay at bus 3 so as to operate the circuit breaker at bus 3 and disconnect the faulty part only. However, if breaker at bus 3 fails to operate, the relay at bus 2 acts as

54

3 Existing Protection and Challenges

1

Tripping time in sec.

Source

2

B1 R1

F1

3

B2 R2

1.2sec.

F2

B3 R3

0.8sec.

F3

0.4sec.

Radial feeder section

Fig. 3.26 Time-graded scheme for radial feeder protection

backup protection leading to operation of the breaker at 2 to disconnect the line section beyond bus 2. Similarly, the overcurrent relays at bus 1 act as the primary protection for line between buses 1 and 2 and as backup protection for line section beyond bus 2. So, the main concern of overcurrent feeder protection is selectivity in relays for correct operation. The following are the schemes used to enhance the relay selectivity for overcurrent protection schemes: • Time-graded protection • Current-graded protection • Combination of time- and current-graded protection

3.4.1

Time-Graded Protection

A definite time overcurrent (DTOC) relay is used to implement this scheme where relay operation is independent of fault current magnitude. The timing units in each relay start with the fault event and operate the associated circuit breaker after a preset time to clear the fault. The relay having minimum set time beyond a pickup value should operate first. The relay selectivity, based on operating time, is achieved by increasing the delay of 0.4 to 0.3 sec. between the adjacent units away from the far end. The delay time between adjacent relays is to take care of breaker operating time, relay error, and error in CT. In Fig. 3.26, R1, R2, and R3 are the relays and B1, B2, and B3 are the circuit breakers at buses 1, 2, and 3, respectively. Any fault beyond bus 3 initiates the timing circuit of all the three relays R1, R2, and R3. R3, having minimum operating time, will send tripping signal to breaker B3 after 0.4 sec; however, if breaker B3 fails to operate, R2 will send the tripping signal to B2 after 0.8 sec. If the breaker B2 also fails to operate, then after 1.2 s, breaker B1 at bus 1 will trip. This scheme has the disadvantage of taking the highest clearing time for the most destructive fault near the source end, which is undesirable. So, this scheme is used where the source impedance is higher than the impedance of the protected line section.

3.4 Distribution System Protection

55

2

1

80 %

80 %

R1

F1

80 %

B3

B2

B1

Source

3

R2

F2

R3

F3

Time

Fig. 3.27 Instantaneous overcurrent relay for current-graded protection

1

2

3

Radial feeder section

Fig. 3.28 Combined time and current grading for radial feeder protection

3.4.2

Current-Graded Protection

Instantaneous overcurrent relays are used to implement the protection scheme where the relay operating time is set to be constant for relays of each section of the feeder. The relay pickup current is set for progressively higher current magnitudes toward the source; settings are based on the fault level of protected line sections. Ideally, the relay at bus 2 should trip for a fault between buses 2 and 3 and restrain for any fault beyond bus 2 as given in Fig. 3.28. Similarly, the relay at 1 should trip for a fault between buses 1 and 2 and restrain for outside faults. But the ideal relay operation is affected due to following reasons: (i) A small difference in fault current for faults close to a bus on either side causes a dilemma in discriminating the fault zone. A fault in feeder 2-3, close to bus 2, may be picked up by relay R1 which leads to an undesirable tripping of feeder 1-2 as well. (ii) Fault current magnitude cannot be determined accurately because of certain inaccurate parameter estimation. (iii) Operation of relay is affected due to transients during faults. To avoid the above causes of mal-operation, the relays are set to protect only 80% of the feeder length, as depicted in Fig. 3.27. To provide protection for complete 100% of feeder length, an IDMT relay is always used.

56

3.4.3

3 Existing Protection and Challenges

Combination of Time- and Current-Graded Protection

The combination of time and current grading is used to increase the selectivity and discrimination of the protection scheme. An IDMT relay having time as well as current settings is used to implement the scheme as shown in Fig. 3.28. The relay is set to pick up for a gradually higher magnitude of fault current toward the source. Time setting is also applied, in the increasing order toward the source, with the different operating times of 0.4 s between two successive relays. The inverse time relays are advantageous for conditions with smaller source impedance ZS compared to line impedance Zl because of appreciable difference in fault current between a fault near to substation (I ¼ ES/ZS) and fault at the remote end, I ¼ ES /(ZS + Zl). Since the fault current near the source is with a very high magnitude, a relay with inverse characteristics trips faster for faults close to the source – which is always desirable. Similarly, for a system with higher source impedance ZS as compared to line impedance ZL, definite time characteristics are desirable. An IDMT characteristic is a compromise between inverse and definite characteristics; a smaller fault current gives inverse characteristics, and a higher-magnitude fault current gives definite characteristics.

3.5

Challenges in the Protection of DG-Embedded Distribution System

A distribution system when operated with one or more distributed generations (DGs), depending upon the requirements, is called a microgrid. The presence of DGs creates new issues for ordinary protection schemes because the distribution system is now an active network. Apart from protection issues, a new challenge is to identify the disconnection of the main or utility grid. This is also referred to as lossof-mains (LoM), loss-of-grid (LoG), islanding, and so on. A few of the challenges that have been reported are discussed below.

3.5.1

Dynamic in the Level of Fault Current

In a microgrid network, fault levels [22] for grid-connected mode are higher in comparison with an islanded mode of operation. This difference between fault levels and loading levels causes problems with relay tripping. In the case of islanded mode of operation, a fault current is only contributed by the main grid, whereas in the case of grid-connected mode, fault current is contributed by the main grid as well as distributed generation (DG). From Fig. 3.29 it clear that without DG, fault current If ¼ Igf, whereas with DG, the fault current is If ¼ Igf + Idf.

3.5 Challenges in the Protection of DG-Embedded Distribution System

57

Igf Idf

Main Grid

Fault

Load

DG

Fig. 3.29 Equivalent representation of microgrid – fault contribution

R1

R2

Main Grid

Fault Fault

Load

DG

Fig. 3.30 Equivalent representation of microgrid – bidirectional flow

R1

Feeder-1 Fault

Main Grid

R2 Feeder-2 DG

Load

Fig. 3.31 Equivalent representation of microgrid – false tripping

3.5.2

Bidirectional Fault Current

With the integration of DGs, networks become complex and meshed, and as a result of this, fault current becomes bidirectional [23]. In such a case, an overcurrent relay is unable to detect a fault, so a directional relay has to be used. From Fig. 3.30 it is clear that on the integration of DG, fault current in relay R2 is bidirectional in nature.

3.5.3

False Tripping

This problem occurs when DG, connected in a healthy feeder, contributes to fault current adjacent to the feeder. When fault current contributed by DG exceeds the current setting, then relay R2 will be tripped before the faulted feeder relay R1. As a result, unnecessary power interruption will have occurred for loads connected to the healthy feeder-1. Figure 3.31 illustrates the false tripping [24] phenomenon in the microgrid network.

58

3 Existing Protection and Challenges Igf R Main Grid

Idf DG

Fault

Load

Fig. 3.32 Equivalent representation of microgrid – blinding protection

3.5.4

Blinding Protection

The main grid contribution to the fault current is decreased due to the contribution from DG sources because the fault current remains constant at a particular location. Due to this, the feeder relay R is unable to detect the faulty condition. This phenomenon is known as “blinding protection” [25], and it is demonstrated in Fig. 3.32.

3.5.5

High-Impedance Fault

These types of problems arise if either one overhead conductor is connected to ground with a high impedance or two- or three-phase conductors are connected through a high impedance. In such cases, the level of fault current is very small which is not enough to be detected by ordinary protection relays. High-impedance fault [26] causes random behavior in which the current is unstable and fluctuates greatly, causing higher-order frequency content in the current.

3.5.6

Mode of Operation of a Microgrid

Changing from grid-connected mode of operation to off-grid mode significantly decreases the fault current, especially in the case of inverter-based DG (PV-based and/or wind turbine-based DG) where fault current is restricted to twice that of the rated current. So, depending on operating modes of microgrid, current setting of relay should be used.

3.5.7

Distance to a Fault

In a grid network with sources at the end of the network, as the impedance increases, the fault current decreases with increasing distance. For island microgrids with inverter-based DG, the fault is limited to a low value, so traditional current protection schemes that use changes in the magnitude of the fault current to differentiate do not work well.

3.6 Discussion

3.5.8

59

Single-Phase Connection

Some DG sources, such as PV systems, introduce single-phase power into the grid. This causes an adverse effect on the balancing of the three-phase currents because the unbalanced current in the neutral wire will rise and result in a flow of stray currents to the earth. The stray current must be restricted to avoid overload.

3.5.9

Islanding Problem

Referring to Fig. 3.33, if the fault current level detected by the relay R1 connected to the DG is sufficient for a trip, DG islanding will occur with the locally connected load. Power imbalances in isolated networks can destabilize the operation of island networks.

3.5.10 Loss of Coordination False tripping and blind protection of the relay from the downstream to upstream feeders result in the continuous false behavior of the relay. This kind of false tripping of relays in a cascaded manner is called a loss of coordination [27].

3.6

Discussion

This chapter describes some of the existing protection schemes for transmission lines and microgrids. Also, the impact of FACTS controllers on the conventional relaying schemes has been included. Under/overreach problems, voltage, and current inversion problems are discussed with mathematical proofs. It has been seen that the presence of FACTS devices modifies the impedance seen by the relay assigned for the protection. If the controller is in the fault loop, it may lead to mal-operation of the protection scheme available for the compensated TL. Moreover, overreach problems

R1 LD-2 Main Grid

Fault

R2 Load

DG

Fig. 3.33 Equivalent representation of microgrid – islanding

LD-1

60

3 Existing Protection and Challenges

in the case of TCSC-compensated TL are investigated in PSCAD/EMTDC domain, and corresponding acquired results are discussed. It has been proved that after the modifications required in the transmission line and microgrid to meet the increasing electric power demand, conventional protection schemes find limitations although these schemes worked well before the modernization of the power system, that is, integrating FACTS in the transmission system and distributed generation in a microgrid. Now, there must be protection methodologies that could accurately provide the required protection for transmission lines and microgrids – obviously, in the presence of the devices that alter the system’s electrical parameters. The next chapter discusses these aspects.

References 1. Thute, R. S., Bahirat, H. J., Khaparde, S. A., Lubicki, P., Kodle, S., & Dabeer, V. (2019, May). Line distance protection in the presence of SCFCL. IET Generation Transmission and Distribution, 13(10), 1960–1969. 2. Ameli, A., Hooshyar, A., & El-Saadany, E. F. (2019, January). Development of a cyber-resilient line current differential relay. IEEE Transactions on Industrial Informatics, 15(1), 305–318. 3. Jia-li, H., Yuan-hui, Z., & Nian-ci, Y. (1984). New type power line carrier relaying system with directional comparison for EHV transmission lines. IEEE Transactions on Power Apparatus and Systems, PAS-103(2), 429–436. 4. Panigrahi, B. K., Samantaray, S. R., & Dubey, R. (2016, January). Adaptive distance protection scheme for shunt-FACTS compensated line connecting wind farm. IET Generation Transmission and Distribution, 10(1), 247–256. 5. Lakshmanan, S. A. (2019). Islanding detection for grid connected solar PV system. In India international conference on power electronics. IICPE. 6. Albasri, F. A., Sidhu, T. S., & Varma, R. K. (2007, October). Performance comparison of distance protection schemes for shunt-FACTS compensated transmission lines. IEEE Transactions on Power Delivery, 22(4), 2116–2125. 7. Barve, G. (2014). Application study of FACTS devices in Indian Power System. 8. Zhang, X.-P., Rehtanz, C., & Pal, B. (2012). FACTS-devices and applications. Power System, 11, 1–30. 9. Albasri, F., Sidhu, T. S., & Varma, R. (2006). Impact of shunt-FACTS on distance protection of transmission lines. In 2006 power systems conference: Advanced metering, protection, control, communication, and distributed resources (pp. 249–256). 10. Khederzadeh, M., & Sidhu, T. S. (2006, January). Impact of TCSC on the protection of transmission lines. IEEE Transactions on Power Delivery, 21(1), 80–87. 11. Sidhu, T. S., & Khederzadeh, M. (2005). TCSC impact on communication-aided distanceprotection schemes and its mitigation. IEE Proceedings – Generation, Transmission and Distribution, 152(5), 714. 12. Zellagui, M. & Chaghi, A.. (2013). Impact of series FACTS devices (GCSC, TCSC and TCSR) on distance protection setting zones in 400 kV transmission line. In An Update on Power Quality, InTech. 13. Jamali, S., Kazemi, A., & Shateri, H. (2006). Voltage inversion due to presence of TCSC on adjacent lines and distance relay mal-operation. In 41st international universities power engineering conference, UPEC 2006, conference Procedings (Vol. 3, pp. 809–813).

References

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14. Jamali, S., Kazemi, A., & Shateri, H. (2008). Voltage inversion due to TCSC presence on second circuit of double circuit line and distance relay mal-operation considering MOV operation. In 2008 IEEE region 5 conference. 15. Tang, C., Yin, X., Qi, X., Zhang, Z., & Wen, M. (2014). The effects of the reverse current caused by the series compensation on the current differential protection. Scientific World Journal, 2014. 16. Singh, S., & Vishwakarma, D. N. (2015). Impact of series FACTS controllers on distance protection-A review. In 2015 international conference on recent developments in control, automation and power engineering, RDCAPE 2015 (pp. 129–134). 17. Arif, S., Shah, U., Wang, J., Taylor, N., Li, Y., & Hans, E. (2017). The impacts of series compensated EHV lines on distance protection, and a proposed new mitigation solution. 18. Pratap. (2018). Protection and control issues associated with shunt compensated transmission lines. 19. Dash, P. K., Pradhan, A. K., & Panda, G. (2000, June). Distance protection in the presence of unified power flow controller. Electric Power Systems Research, 54(3), 189–198. 20. Gupta, O. H., & Tripathy, M. (2017, December). An improved pilot relaying scheme for shunt compensated transmission line protection based on superimposed reactive power coefficients. Electric Power Components and Systems, 45(20), 2228–2245. 21. Distribution Automation Handbook: Section 8.2 Relay Coordination, ABB Oy, Distribution A u t o m a t i o n , 2 0 1 1 . [ O n l i n e ] . Av ai l a b l e : h t t p s : / / l i b r ar y . e . ab b . co m / p u b l ic / eccfd9ab4d23ca1dc125795f0042c8db/DAHandbook_Section_08p02_Relay_Coordination_ 757285_ENa.pdf. Accessed 10 Jul 2020. 22. Telukunta, V., Pradhan, J., Agrawal, A., Singh, M., & Srivani, S. G. (2017, December). Protection challenges under bulk penetration of renewable energy resources in power systems: A review. The CSEE Journal of Power and Energy Systems, 3(4), 365–379. 23. Salam, A. & Mohamed, A. (2011). M. H.-A. Journal of engineering and, and undefined 2008, Technical challenges on microgrids. 24. Babu, S., Hilber, P., Shayesteh, E., & Enarsson, L. E. (May 2018). Reliability evaluation of distribution structures considering the presence of false trips. IEEE Transactions on Smart Grid, 9(3), 2268–2275. 25. Coffele, F., Booth, C., Dyśko, A., & Burt, G. (2012). Quantitative analysis of network protection blinding for systems incorporating distributed generation. IET Generation Transmission and Distribution, 6(12), 1218–1224. 26. Subramaniam, K., & Illindala, M. S. (2019, May). High impedance fault detection and isolation in DC microgrids. In Conference Record - Industrial and Commercial Power Systems Technical Conference, 2019. 27. Najy, W. K. A., Zeineldin, H. H., & Woon, W. L. (2013). Optimal protection coordination for microgrids with grid-connected and islanded capability. IEEE Transactions on Industrial Electronics, 60(4), 1668–1677.

Chapter 4

Solutions to the Protection Challenges

4.1

Introduction

Many relaying techniques are available for the protection of transmission lines (TLs) with or without FACTS devices – a few techniques are included in this chapter. Similarly, tremendous research has been carried out on the protection of distribution system in the presence of distributed generations (DGs) – called a microgrid. There are two aspects to the protection of microgrids. One aspect is the protection against faults, and the second is the protection against islanding. Out of these two aspects, this chapter focuses on a few schemes for the protection against islanding.

4.2

Protection of Modern Transmission System

This chapter describes a few different schemes for the identification/classification of faults in transmission lines with or without FACTS devices. These schemes utilize the data extracted from voltage and current measurements at both ends of the line.

4.2.1

SSCII-Based Pilot Protection Scheme for SVC-Compensated Line

Superimposed sequential components incorporated integrated impedance (SSCII) pilot relaying scheme is proposed in [1] for a two-bus SVC-compensated TL system, as shown in Fig. 4.1. The performance of this scheme has been investigated for the variation of fault resistance (Rf), source impedance, and location of SVC in PSCAD/ EMTDC domain. © Springer Nature Switzerland AG 2021 O. Hari Gupta et al., Protection Challenges in Meeting Increasing Electric Power Demand, https://doi.org/10.1007/978-3-030-60500-1_4

63

64

4 Solutions to the Protection Challenges Is Es

Vs

Zs

Zc

Ir Z/2

Vsvc

Z/2

Zsh

Vr

Zr

Er

Zc

Fig. 4.1 A two-bus mid-point SVC-compensated TL system

As discussed earlier in the previous section, the influence of shunt compensation on a conventional relaying scheme is mainly because of its static/dynamic impedance (Zsh). SVC tries to inject more reactive power by varying its susceptance during a fault, and thereby for better fault identification, this SVC injection should be discarded. To do so, modified pre-fault components are used in [1] to calculate the overall superimposed components (SC). The SSCII of a particular phase is defined in (4.1): Z SSCIx ¼

ΔV dx ΔI dx

ð4:1Þ

where x denotes a, b, and c for the phases A, B, C, respectively, and ΔVdx and ΔIdx are the sums of modified superimposed voltage and current respectively, acquired from both ends of the protected TL.

4.2.1.1

Working Principle

First, SVC impedance is calculated using VI-characteristics of the SVC, from an estimation of pre-fault components of SVC. For end-side compensation, bus components are used for the pre-fault components estimation of SVC. For mid-point SVC location, the voltage distribution method is used for a PI-modeled TL, as per (4.2):
 V xγ seq: seq: V xγsvc ¼ V xγ seq:  I xγ seq:  0:5Z seq: Zc

ð4:2Þ

seq where Zseq is the sequence impedance of TL, V xγ seqis the sequence voltage, and V xγsvc is the sequence SVC voltage of phase x at end γ, seq. ¼ 0, 1, and 2 (i.e., zero, positive, and negative sequences), and γ denotes relay side, that is, s or r (sending or receiving end). The SVC voltage can be obtained as in (4.3):

4.2 Protection of Modern Transmission System

 X  seq: V xγsvc

V xγsvc ¼

65

ð4:3Þ

seq:¼0, 1, 2

Both (4.2) and (4.3) should be implemented from the end with larger magnitude of voltage, that is, the end with larger distance from the fault, that is, if the fault is at left of SVC then the calculation should be done from the receiving end or vice versa. The pre-fault injected SVC current (Isvc) is obtained by using (4.3) and VI-characteristics of SVC. These obtained Vsvc and Isvc are used to calculate Zsh, which is further used for the estimation of pre-fault SVC components by using (4.2) and (4.3). Using superposition theorem in the equivalent circuit shown in Fig. 4.1, the current at the sending end, because of Es only, is given by (4.4): I s ¼

Es Z s þ Z rcm

ð4:4Þ

where Zrcm ¼ Zck(0.5Z + Zrhc), Zrhc ¼ Zshk(0.5Z + Zrc), and Zrc ¼ ZckZr. Similarly, considering Er only, the current at the receiving end can be calculated as per (4.5): I r ¼

Er Z r þ Z scm

ð4:5Þ

where Zscm ¼ Zck(0.5Z + Zshc), Zshc ¼ Zshk(0.5Z + Zsc), and Zsc ¼ ZckZs. The modified pre-fault currents at the sending and receiving end busses will be as given in (4.6) and (4.7), respectively: I sp ¼ I s  I r

Z scm Z shc Z   sc ð0:5Z þ Z shc Þ ð0:5Z þ Z sc Þ Z s

ð4:6Þ

I rp ¼ I r  I s

Z rcm Z rhc Z   rc ð0:5Z þ Z rhc Þ ð0:5Z þ Z rc Þ Z r

ð4:7Þ

Modified pre-fault voltages at the sending and receiving end busses will be as per (4.8) and (4.9), respectively: V sp ¼ E s  Z s I sp

ð4:8Þ

V rp ¼ E r  Z r I rp

ð4:9Þ

where suffix p signifies the modified pre-fault values. The modified pre-fault data are used to calculate modified SC (i.e., ΔVd and ΔId). Then ΔVd and ΔId components are compared with corresponding threshold values, that is, Vth and Ith, respectively; if ΔVd or ΔId is less than the respective threshold, then it is safe to assume that there is no fault, and as a result, no need for the

66

4 Solutions to the Protection Challenges

Fig. 4.2 Flowchart of SSCII scheme

Start

Obtain voltages and currents of each end Estimate SVC voltage, effective SVC impedance, and modified prefault data Estimate modified superimposed components Sum of modified superimposed end voltages and currents (i.e.ΔVd & ΔId)

ΔId Idth for an internal fault. Hence the ERF-based algorithm is found to be selective and accurate.

4.2.2.2.2

Performance for Different Values of Rf

In order to see the impact of different values of Rf, an A-G fault is created at F2, as shown in Fig. 4.11, and the acquired results are presented in Fig. 4.13. It can be seen that the algorithm remains valid for the first two cases, that is, for Rf ¼ 5 Ω and 50 Ω but fails for resistances of 250 Ω and 350 Ω. Hence, the ERF-based algorithm is not selective in the case of fault resistance above 50 Ω.

4.2.2.2.3

Performance for Uncompensated TL

In order to examine the performance of the ERF scheme for uncompensated TL, test system-1, without mid-point compensation, is reconfigured as test system-2, as shown in Fig. 4.14. F1 and F3 are considered as external faults and F2 is considered an internal fault. An AB fault is created at different TL lengths, and the corresponding results are presented in Fig. 4.15. The performance of the ERF scheme for an uncompensated line is found to be both selective and accurate.

4.2 Protection of Modern Transmission System

ERF_r

Ida (kA)

50 Ω

0.16

0.81

0.84

0.73

250 Ω

350 Ω

-0.08

-0.79

-0.59

5Ω

0.71

0.16

0.75

2.81

4.85

ERF_s

75

Fig. 4.13 Acquired ERFs and Ida for an A-G fault for different Rf values

Es

Line-B

Vs

Vr

Line-A Is

Ir Line-C

End-s

Er

End-r

F1

F2

F3

Fig. 4.14 A two-bus uncompensated TL system as test system-2

Fig. 4.15 ERFs for an AB fault at different line locations in test system-2

0.99

0.86

300 KM

-0.98

-0.99

-0.88

250 KM

-0.97

100 KM

-0.97

-0.94

0 KM

0.99

ERF_r

0.88

ERF_s

EXTERNAL

76

4.2.2.3

4 Solutions to the Protection Challenges

Summary

The ERFs-based relaying scheme with modified Id shows promising results in the case of different fault locations, fault resistances, and uncompensated TL system. However, the scheme fails in the case of high fault résistance (i.e., Rf > 50 Ω), which makes the ERF relaying scheme not suitable for practical applications.

4.2.3

EPE-Based Pilot Relaying Scheme for Series-Compensated Line

Estimated phase error (EPE) pilot relaying scheme has been proposed in [4] for series-compensated or uncompensated EHV/UHV TL system. The performance of the EPE scheme has been investigated on three test systems for variations in fault locations (with/without compensation), values of Rf, source impedance, fault types, and compensation levels. Test systems considered are simulated in PSCAD/EMTDC software with algorithm written in MATLAB domain. Based on the acquired data it has been found that the EPE algorithm is uninfluenced by the variations in source-toline impedance (SIL), and immune to under/overreach problems in the case of series-compensated TL system. EPE is defined in (4.19):  EPE yx ¼ 90o  ∠I dx  ∠V m

 yx

ð4:19Þ

where suffix x ¼ a, b, and c for phases A, B, and C, respectively, suffix y ¼ s and r for relay end-s and -r, respectively, Idx is the differential fault, and Vm_yx is the mid-point voltage calculated from end-y of phase x respectively. For an external fault, EPE will be small (i.e., EPEyx ! 0 ) or equal to pre-fault EPE value. However, for an internal fault, EPE is very high (i.e., EPEyx ! 180 ) as compared to pre-fault value. This characteristic of EPE can be used for the fault detection and to trigger corresponding relaying actions for the protection of TL system.

4.2.3.1

Working Principle of EPE Scheme

A single-line diagram (SLD) of a series-compensated TL in between relay end-s and end-r is shown in Fig. 4.16. Fault F1 is considered as an external fault, whereas F2 and F3 are considered as internal faults. Series FACTS controller with metal-oxide varistor (MOV) is assumed to be connected near end-s. An equivalent T-model of the TL system has been considered for simplicity. Further, only positive-sequence components are considered due to their availability in all concerned cases for the

4.2 Protection of Modern Transmission System Fig. 4.16 Single-line diagram (SLD) of a seriescompensated TL during (a) pre-fault (b) external fault, and (c) internal fault conditions

77

(a) Vs

Is

Ir

Vm

Vr

Zc

End-s

End-r

Im

(b) Vs Ism

F1

Irm

Vm

Vr

IF_rs Im

End-s

End-r

(c) Vs Ism

Vm

F2

IF_s End-s

IF_r Im

F3

IF_s

Irm

Vr

IF_r

End-r

protection of TL system. The characteristics of EPE for pre-fault, external fault, and internal fault cases are discussed next.

4.2.3.2

EPE for Pre-fault Condition

The SLD of the considered TL system for pre-fault case is shown in Fig. 4.16a. The positive-sequence differential current Id is defined as in (4.20): I d ¼ I s þ I r  I m ¼ jI m j∠V m þ 90∘

ð4:20Þ

The mid-point voltage Vm can be calculated using (4.21) for both relay ends as: V m  V s  I s ðZ=2 þ Z c Þ  V r  I r Z=2 ¼ jV m j∠V m

ð4:21Þ

78

4 Solutions to the Protection Challenges

So, the EPE from both relay ends can be calculated using (4.19) to (4.21) as EPEs  EPEr  0o (or tends to zero).

4.2.3.3

EPE for External Fault Condition

The SLD of considered TL system for an external fault at F1 is shown in Fig. 4.16b. The acquired currents at both ends can be expressed as in (4.22): I s ¼ I sm  I F

rs

and I r ¼ I rm þ I F

ð4:22Þ

rs

And corresponding positive-sequence Id can be given as in (4.23): I d ¼ I sm þ I rm  I m ¼ jI m j∠V m þ 90∘

ð4:23Þ

The measured Vm from both ends can be expressed as in (4.24):  V m  V s  I sm  I F ¼ jV m j∠V m

 rs

 ðZ=2 þ Z c Þ  V r  I rm þ I F

 rs

Z=2 ð4:24Þ

Similarly, for an external fault, EPE measured from both relay ends is found to be EPEs  EPEr  0o (or tends to zero) as in the case of pre-fault condition.

4.2.3.4

EPE for Internal Fault Condition

The SLD of considered TL system for an internal fault is shown in Fig. 4.16(c), as there are two possibilities to have a fault at F2 (i.e., between end-s and mid-point) or F3 (i.e., between end-r and mid-point). These two situations have been considered as subroutine-I and subroutine-II for the EPE method. Vm is calculated from one end only of each case (i.e., for subroutine-I, Vm is calculated from end-r and vice versa). The corresponding EPEs are calculated as shown below. • Subroutine-I In this case, the currents from both relay ends are acquired, and positive-sequence Id can be given as follows in (4.25): Id  Im þ

VF k V ejα ¼ Im þ F m Rf Rf

¼ I m ð∠V m þ 90∘ Þ þ

kF j V m j ð∠V m  αÞ Rf

ð4:25Þ

where, the value of α ranges from –δ/2 to +δ/2 depending on the value of Rf (i.e., α ¼ 90 for Rf ¼ 0 Ω) [3] and location of fault in TL, where δ is the pre-fault load angle (the angle between Vs and Vr).

4.2 Protection of Modern Transmission System

79

Fig. 4.17 Phasor diagram for an internal fault in a series-compensated TL system

Id Im

IF +α -α

Id Vm IF

The measured Vm from end-r can be expressed as in (4.26):   V m ¼ V r  j I rm þ I F r Z=2 ¼ V r  jI r Z=2

ð4:26Þ

The obtained EPE will tend toward 180 as ∠Id  ∠ Vm !  90o, because of the small value of Im as depicted in Fig. 4.17. • Subroutine-II In this case the expression of positive-sequence Id will be same as in (4.25); however, Vm is measured from end-s and expressed as given in (4.27):   V m ¼ V s  j I sm þ I F s ðZ=2 þ Z c Þ ¼ V s  jI s ðZ=2 þ Z c Þ

ð4:27Þ

Again EPE ! 180 , for a fault at F3, and it can be concluded that for internal fault, EPE measured from either ends of the protected TL tends to 180 (ideally EPE ¼ 180 ). Hence this feature of EPE can be used for fault detection and classification for desired relaying actions. Figure 4.18 presents the flowchart of the EPE-based algorithm. First, voltage and current time-tagged sampled data are acquired from both relay ends. Fast Fourier Transform (FFT) is used for acquiring the required positive-sequence components for further processing. EPEs are calculated from both end data and compared with the threshold value (EPEth). If max(EPEsx, EPErx) > EPEth, then the fault is detected as an internal fault, and trip signal is generated for corresponding phase-x; else fault is categorized as an external fault, where EPEth is defined as in (4.28):   EPE th ¼ relay setting  EPE internalð min Þ  EPE externalð max Þ

ð4:28Þ

The relay setting can be selected in the range between 0.5 and 1, EPEinternal(min) is the minimum value of EPE for an internal fault, and EPEexternal(max) is the maximum value of EPE for an external fault. However, for all test systems, the EPEth ¼ 10 has been selected, based on the rigorous simulation results.

80

4 Solutions to the Protection Challenges

Start Acquiring of voltage and current sampled data for both relay ends Positive sequence voltage and current phasors calculation using FFT

Obtain EPEsx and EPErx

External fault

No

Is max (EPEsx,EPErx) > EPEth

Yes Internal fault Trip Phase-x Fig. 4.18 Flowchart for EPE-based algorithm

4.2.3.5

Analysis of Simulation Results

The performance of the EPE scheme has been investigated on three test systems for variations in fault locations (with/without compensations), values of Rf, source impedance, fault types, and compensation levels. The descriptions of the test systems are as follows: Test system-1: A two-bus, 750 kV, 50 Hz, Z1 ¼ 2.86 + j32.40 Ω, Z0 ¼ 6.14 + j57.48 Ω, 550 ckm series-compensated TL system. Test system-2: A two-bus, 400 kV, 50 Hz, Z1 ¼ 1.43 + j16.20 Ω, Z0 ¼ 3.07 + j28.74 Ω, 320 ckm series-compensated TL system. Test system-3: A two-bus, 750 kV, 50 Hz, Z1 ¼ 2.86 + j32.40 Ω, Z0 ¼ 6.14 + j57.48 Ω, 550 ckm uncompensated TL system. TL parameters: positive-sequence series inductance, resistance, and capacitance are 1.1783 mH/km, 0.018 Ω/km, and 14.02 nF/km respectively. And zero-sequence series inductance, resistance, and capacitance are 3.8853 mH/km, 0.36 Ω/km, and 9.22 nF/km respectively.

4.2 Protection of Modern Transmission System

4.2.3.5.1

81

Performance for Different Fault Locations with Variation in Compensation Level

For the aforementioned case, test system-1 is considered. An A-G fault is created at different locations with 30% and 70% compensation levels, and acquired results are shown in Figs. 4.19 and 4.20 respectively. It can be seen that algorithm is selective, accurate, and unaffected by the compensation-level variations.

4.2.3.5.2

Performance for Various Value of Rf

For investigation in this category, test system-1 is considered, and an A-G fault is created at 200 km from end-s with 30% compensation, and acquired results are manifested in Fig. 4.21. It can be seen that up to Rf ¼ 500 Ω, the EPE scheme is found to be reliable and accurate.

4.2.3.5.3

Performance for Variations of SIR

For investigation in this category, test system-2 is considered, and an A-G fault is created at 120 km from end-s with 30% compensation level, and acquired results are shown in Fig. 4.22. It can be observed that with high SIR values, the EPE scheme is selective.

166.11

1.64 0 KM

100 KM

200 KM

300 KM

400 KM

500 KM

0.74

112.72

177.44

175.09

157.86

EPEra

152.9

142.8

138.71

131.5

130.48

125.42

110.85

EPEsa

EXTERNAL

Fig. 4.19 Post-fault EPE of phase-A for an A-G fault at different fault locations with 30% compensation

82

4 Solutions to the Protection Challenges

168.02

165.53

2.74 0 KM

100 KM

200 KM

300 KM

400 KM

500 KM

0.67

139.72

134.98

118.81

115.2

115.38

115.24

112.04

113.86

172.4

EPEra

170.44

EPEsa

EXTERNAL

Fig. 4.20 Post-fault EPE of phase-A for an A-G fault at different fault locations with 70% compensation EPEra

100 Ω

300 Ω

17.19

18.46

25.27

26.13

60.93

62.2

EPEsa

500 Ω

Fig. 4.21 Post-fault EPE of phase-A for an A-G fault for various values of Rf with 30% compensation

4.2.3.5.4

Performance for Different Fault Locations in an Uncompensated TL System

In order to examine the performance of the EPE-based algorithm in an uncompensated TL system, test system-3 is used. An A-G is created at different

83

EPEsa

EPEra

0.1368

15

30

148.24

147.65

149.03

148.18

150.03

150.86

159.4

160.22

4.2 Protection of Modern Transmission System

45

SIR Fig. 4.22 Fault EPE of phase-A for an A-G fault for variations in SIR value with 30% compensation

153.9

0.09 0 KM

100 KM

200 KM

300 KM

400 KM

500 KM

0.47

95.751

160.95

162.17

154.07

152.47

138.3

138.3

138.25

134.14

EPEr

89.423

131.72

EPEs

EXTERNAL

Fig. 4.23 Fault EPE of phase-A for an A-G fault for variations in SIR value with 30% compensation

TL locations, and acquired post-fault EPE of phase-A is presented in Fig. 4.23. It can be observed that for an uncompensated TL system, the EPE-based algorithm remains selective, accurate, and reliable.

84

4.2.3.6

4 Solutions to the Protection Challenges

Summary

The performance of EPE pilot relaying scheme has been investigated on three test systems for variations in fault locations (with/without compensation), values of Rf, source impedance, fault types, and compensation levels. Based on the rigorous PSCAD/EMTDC simulations and results acquired from the EPE-based algorithm in MATLAB domain, the method is found to be selective, robust, and accurate up to Rf ¼ 500 Ω.

4.2.4

Imaginary Component of Virtual Fault Impedance-Based Relaying

Another pilot-based relaying scheme which uses the imaginary component of the virtual fault impedance (VFI) is proposed in [5]. The method has been applied to the shunt-FACTS device-compensated (SFD-compensated) TL as illustrated in Fig. 4.24(a). The VFI is the ratio of the fault voltage, Vf, to the adjusted difference current, Id (i.e., eliminating SFD-current), as given in (4.29): Z fv ¼

Vf Id

ð4:29Þ

When the imaginary value of VFI (i.e., IVFI) is below threshold Zth, fault is within the protected area. On the contrary, when IVFI is more than Zth, there is no fault within the protected zone. A multi-phase fault is identified if more than one phase is detected as faulty phases. To avoid the false operations, the IVFI will be checked only when the magnitude of Id crosses 1.1-times the pre-fault value. (a)

x

y F1

F2 Ex

Zx

Zy

Ey

SFD

(b)

Vx Zx Ex

F2 S2

Rf

Ix

Z -jXc

Isfd

F1

(1-)Z

S1

Iy

Vy

Zy Ey

Rf

Fig. 4.24 (a) SFD-compensated transmission line and (b) its single-phase representation with internal and external fault mechanisms

4.2 Protection of Modern Transmission System

4.2.4.1

85

VFI for Internal Fault

In the single-phase illustration of a faulty line – added to Fig. 4.24b – a virtual capacitance (representing the shunt charging components) is placed in parallel with the fault resistance, Rf. Now, utilizing the synchronized voltage and current phasors of both the ends (i.e., end-x and end-y), the VFI can be obtained which is written as given in (4.30). Z fv ¼

Vf Vf ¼ ¼ Id Ic þ Ir

Vf Vf jX c

þ

Vf Rf

¼

jX c R f R f  jX c

ð4:30Þ

where Ic is the current due to line shunt charging reactance and Ir is the current flowing through S1 and Rf. It is clear from (4.30) that Zfv is independent of the fault distance, fault location, and source impedance. The Zfv depends on the Rf and Xc – a function of TL length. Now, to observe the influence of Rf on Zfv, the variations of Zfv in a real-imaginary plane are plotted in Fig. 4.25. The Xc is normally of large value, and for a 300-km TL, it is nearly 770 Ω [6]. The imaginary part of Zfv is limited between 0 and 240 Ω. On the basis of pre-fault and during-fault values of Zfv, the use of IVFI is recommended – large changes in IVFI are found from pre-fault to faulty conditions.

50 Xc =750 Xc =1000

0

Xc =1500

-50

IVFI in W

Rf = 0 Ω -100 -150 -200 -250

Rf = 500 Ω -300

0

100

200 300 real(VFI) in W

Fig. 4.25 Variations in Zfv on real-imaginary plane

400

500

86

4.2.4.2

4 Solutions to the Protection Challenges

VFI for External Fault

For an external fault – switch S2 is closed and S1 is open – the internal TL circuit remains intact just like pre-fault situation, and therefore, the IVFI will be high and approximately equal to –jXc.

4.2.4.3

Application of the Scheme

From the aforementioned details, it is observed that the internal faults could be spotted by looking at the magnitude of IVFI. If it is more than IVFI, then an internal fault is identified; else either there is no fault or an external disturbance is indicated. The threshold could be found by assuming a 50% margin of safety as provided in (4.31).  
   jX c R f   Zth ¼ 1:5imag  R f  jX c R f ¼500  

ð4:31Þ

The flowchart of the IVFI-based scheme is given in Fig. 4.26. First, just after obtaining the voltages and currents in synchronized phasor forms, a compensated differential current (CDC) “Id” is calculated. Then if CDC is below 1.1 times of its pre-fault CDC, nothing will happen, and it returns to the start position. When CDC is more than 1.1 times of its pre-fault CDC, calculation and comparison of VFI and threshold (Zth) are obtained. Now if IVFI is found to be more than Zth for 10 ms, then it is considered to be an internal fault; otherwise it is an outside disturbance.

4.2.4.4

Simulation Study

The performance of IVFI-based scheme is investigated on a three-phase, 50 Hz, 300 km, 400 kV transmission system [5]. This investigation is carried out for different systems including SVC-compensated TL, STATCOM-compensated TL, and an uncompensated TL. The complete system details and data are given in [7].

4.2.4.4.1

Performance for SVC-Compensated Line

The pre-fault CDC is 0.43 kA. Therefore, VFI is calculated only if compensated differential current exceeds 1.1 times the pre-fault-compensated differential current (i.e., 0.473 kA). The threshold value Zth obtained using (4.31) is 360 Ω. Now, the internal fault is detected if any phase possesses the magnitude of IVFI less than this value. For different fault locations, Fig. 4.27 shows the results in terms of IVFI; this shows that all the internal faults are successfully spotted while the external faults are clearly discarded and reflects healthy internal conditions.

4.2 Protection of Modern Transmission System

87

Start Synchronized measurement of voltage and current phasors Calculation of CDC No

|Id| > 1.1*|Idpre| Yes Calculation of Zfv and Zth

External fault

No

|imag(Zfv)| Z and Zc > Z, so Zequi.sr > Zr, and it can be concluded thatX equi:sr ΔI 2s > X r ΔI 2r . Hence, for the external fault IIRP is positive. This

4.2 Protection of Modern Transmission System

101

Start Acquiring voltages and currents at both the ends Calculate incremental differential current of each phase

External fault

max(I dx )

No

 0.5Idpre W Yes Calculate IRPC for each phase

Is IRPCa V dthðveÞ ROCONSPCCV ¼   dt

ð4:46Þ

where VPCC(ve) ¼ ve-sequence PCC voltage and Vdth(ve)  4 X (maximum value of ROCONSPCCV during grid-connected mode). When AS is high (i.e., AS ¼ 1), a perturbation has been introduced by reducing the DG output by 0.01 PU, and ΔZ will be calculated, which is discussed next.

4.3.3.1.2

Calculation of ΔZ and Its Characteristics Analysis

The test system is shown in Fig. 4.61a, and the corresponding superimposed equivalent diagram is shown in Fig. 4.61b. So ΔZ is defined as in (4.47):

118

4 Solutions to the Protection Challenges

ΔZ ¼

ΔV PCC AS ΔI dg

ð4:47Þ

The DG is connected to utility grid when CB1 is closed; else microgrid is in standalone mode. CB2 has been used to connect/disconnect the DG from PCC. CBf, when closed, is used to simulate a fault near PCC. Depending on the state of these three circuit breakers (CBs), we have three different values for ΔZ, which are given in (4.48): 8 > < Z L jZ IB ,when CB1 ¼ CB2 ¼ close &CBf ¼ open ðGrid  connected modeÞ ,when CB1 ¼ CBf ¼ open&CB2 ¼ close ðIslanded modeÞ ΔZ ¼ Z L > : Z L jZ IB jZ f ,when CB1 ¼ CB2 ¼ CBf ¼ close ðFault modeÞ ð4:48Þ where ZL ¼ local load impedance, ZIB ¼ grid impedance and Zf ¼ fault impedance. As can be seen from (4.48), |ΔZ| ¼ |ZLkZIB| for grid-connected mode. In general, | ZIB| is very small as compared to |ZL|, so the parallel combination of these two will be less than |ZIB|, that is, very small. However, in the case of islanded mode, |ΔZ| ¼ |ZL|, which is very high as compared to grid-connected mode. Moreover, in fault mode |ΔZ| ¼ |ZLkZIBkZf|, which is again very small as compared to islanded mode. This feature of superimposed impedance can be used for islanding detection with a proper threshold value.

4.3.3.1.3

Threshold Selection (|ΔZth|)

After analyzing simulation results obtained in MATLAB/Simulink platform, the threshold is defined as in (4.49) to identify the islanded mode in the SI-based algorithm: j ΔZth j¼ B:jΔZ jcmode

ð4:49Þ

where |ΔZ|c-mode ¼ |ΔZ| during grid-connected mode and B is defined as B  jΔZj

jΔZj

imode cmode ðSafety margin valueÞ  , where |ΔZ|i-mode ¼ |ΔZ| during jΔZjimode islanded mode. As |ΔZ|i-mode > > |ΔZ|c-mode and taking safety margin value of 3 (based on rigorous simulations result), B  3 and the resultant threshold |ΔZth| ¼ 3|ΔZ|c-mode ¼ 3 PU.

4.3.3.1.4

Implementation of the SI-Based Islanding Detection Algorithm

The flowchart of the algorithm is shown in Fig. 4.62. First, three-phase PCC voltage and DG current are acquired. Any disturbance in the microgrid is identified by

4.3 Islanding Detection Scheme for Microgrid

119

Start

Transient event detected

3-phase voltages at PCC and DG current are acquired

Is ROCONSPCCV >Vdth(negative)

No

Yes Reduce DG output by 0.01 p.u. after 0.14 s and set AS = 1

Calculate ΔZ

No

|ΔZ|>|ΔZth|

Yes Islanding Detected

Fig. 4.62 Flowchart of ΔZ-based islanding detection algorithm

comparing ROCONSPCCV with Vdth(ve); if ROCONSPCCV is found greater than threshold value, then an AS is set to high (i.e., AS ¼ 1); else AS ¼ 0. After getting alert signal, a perturbation of 0.01 PU is introduced in the microgrid, and |ΔZ| is calculated. Obtained |ΔZ| is then compared with |ΔZth|, and if |ΔZ| is found to be greater than threshold, the disturbance is categorized as an islanded mode, else identified as a transient in the system.

4.3.3.2 4.3.3.2.1

Analysis of Simulation Results Performance Investigation for Variation in Load Quality Factor (QF) with Perfect Power-Match Conditions Including UL1741SA Standard Test Conditions

UL1741SA includes the condition of perfect power match with QF ¼ 0.3 and 1.8. It can be observed from Fig. 4.63 that the PU value of |ΔZ| is almost same for all three cases. So, the SI-based algorithm is able to detect islanded event with variation in load QF as |ΔZ| > 3 PU in all three cases, successfully.

120

4 Solutions to the Protection Challenges

Islanding during perfect match with different quality factor PCC voltage (PU)

0.99

12.12 0.99

0.99

12.3

12.18

Superimposed impedance (PU)

Quality factor of 0.3

Quality factor of 1.8

Quality factor of 2.5

Fig. 4.63 |ΔZ| and PCC voltage for different load QFs with perfect power match condition

Superimposed impedance (PU)

PCC voltage (PU)

12.18 9.84

0.88

1.04

1.04 0.99

1 0

Islanding during Active power mismatch (25%)

Islanding during Reactive power mismatch (22%)

Load switching (50% increased)

0.99

0

Three phase fault at PCC

DG output variation (20% reduced)

Fig. 4.64 |ΔZ| and PCC voltage for different load QFs with power mismatch conditions and other concerned conditions

4.3.3.2.2

Performance Investigation for Power Mismatch Conditions and Other Concerned Conditions

It can be seen from Fig. 4.64 that with power mismatch of 25% active and 22% reactive, the SI-based algorithm remains reliable for the detection of islanded mode. Also, for load switching up to +50%, three-phase fault scenario, and DG output variation (reduced to 20%), the scheme remains selective, accurate, and robust.

References

121

Existing scheme

Proposed scheme

0.24 439.88

1

65.55

437.34

1.09

64.81

Fundamental PCC voltage (V)

THD of DG current (%)

0.49

THD of PCC voltage (%)

Fundamental DG current (A)

Fig. 4.65 Comparison of THD obtained with SI-based algorithm and existing scheme

4.3.3.2.3

Comparison with Existing Scheme

As the perturbation in the SI-based scheme is introduced only when AS is high irrespective of regular injections to DG system as in [16], it will avoid prospect of degradation of microgrid power quality. It can be seen from Fig. 4.65 that Total Harmonic Distortion (THD) obtained with offered algorithm is less as compared to Scheme SI-based in [16] and verifies aforementioned statement.

4.3.3.3

Summary

The performance of the SI-based islanding detection algorithm has been investigated for different concern cases including UL1741SA standard test conditions for variation in load QF with perfect power-match, with power-mismatch, output variations, and fault conditions. Based on the MATLAB/Simulink simulation results, scheme found to be reliable and accurate with nearly zero NDZ with improved power quality of microgrid as compared to existing schemes.

References 1. Gupta, O. H., & Tripathy, M. (2015, June). An Innovative Pilot Relaying Scheme for ShuntCompensated Line. IEEE Transactions on Power Delivery, 30(3), 1439–1448. 2. Gupta, O. H., & Tripathy, M. (2016). ERF-based fault detection scheme for STATCOMcompensated line. International Transactions on Electrical Energy Systems, 27(6), 1–22.

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3. Gupta, O. H., & Tripathy, M. (2016). Positive sequence phasor estimation-based pilot relaying scheme for shunt-compensated line. In 2016 National Power Systems Conference (NPSC). Roorkee: IEEE. 4. Gupta, O. H., & Tripathy, M. (2018, July). EPE-Based Pilot Relaying Scheme Immune to SIR Variations. IETE Journal of Research, 66, 359–369. 5. Gupta, O. H., Tripathy, M., & Sood, V. K. (2017). Digital relaying scheme for protection of shunt-compensated transmission lines. In 2017 IEEE Electrical Power and Energy Conference (EPEC) (pp. 1–6). Piscataway: IEEE. 6. Jena, P., & Pradhan, A. K. (2013, April). Directional relaying in the presence of a thyristorcontrolled series capacitor. IEEE Transactions on Power Delivery, 28(2), 628–636. 7. Suonan, J., Liu, K., & Song, G. (2011). A novel UHV/EHV transmission-line pilot protection based on fault component integrated impedance. IEEE Transactions on Power Delivery, 26(1), 127–134. 8. Gupta, O. H., & Tripathy, M. (2016). Superimposed energy-based fault detection and classification scheme for series-compensated line. Electric Power Components & Systems, 44(10), 1095–1110. 9. Gupta, O. H., & Tripathy, M. (2018). Universal pilot relaying scheme for series and shuntcompensated lines. IET Generation Transmission and Distribution, 12(4), 799–806. 10. Ansari, S., & Gupta, O. H. (2020). Voltage ripple based islanding technique on Modified IEEE13 bus test feeder for photovoltaic inverter. In O. H. Gupta & V. K. Sood (Eds.), Recent advances in power system – Select proceedings of EPREC 2020. Cham: Springer Nature Switzerland AG. 11. (2011). Distribution automation handbook: Section 8.2 relay coordination. In ABB Oy, Distribution automation. [Online]. Available: https://library.e.abb.com/public/ eccfd9ab4d23ca1dc125795f0042c8db/ DAHandbook_Section_08p02_Relay_Coordination_757285_ENa.pdf. Accessed 10 July 2020. 12. Transmission and distribution in India: A report. A joint initiative of WEC-IMC and Power Grid Corporation of India Limited. [Online]. Available: http://npti.gov.in/sites/default/files/ download-document/world_energy_council_report.pdf. Accessed 22 Nov 2020. 13. Ansari, S., Gupta, O. H., & Tripathy, M. (2020). An islanding detection methodology for SOFC-based Static DG using DWT. In Electric Power and Renewable Energy Conference (EPREC – 2020). Singapore: Springer Singapore. 14. Gupta, O. H., Tripathy, M., & Sood, V. K. (2019, December). Islanding detection scheme for converter-based DGs with nearly zero non-detectable zone. IET Generation Transmission and Distribution, 13(23), 5365–5374. 15. Bahrani, B., Karimi, H., & Iravani, R. (2011). Nondetection Zone Assessment of an Active Islanding Detection Method and its Experimental Evaluation. IEEE Transactions on Power Delivery, 26(2), 517–525. 16. Yu, B. G., Matsui, M., & Yu, G. J. (2011). A correlation-based islanding-detection method using current-magnitude disturbance for PV system. IEEE Transactions on Industrial Electronics, 58(7), 2935–2943.

Chapter 5

Conclusion

5.1

Conclusion

Starting with a literature review of the subject topic, this book highlighted grid improvements to meet the increased load demand with inclusion of FACTS devices and distributed generation (DG). Both of these items add power electronics-based devices to the system. These devices are, namely, thyristor-controlled series capacitor (TCSC), static VAR compensator (SVC), static synchronous compensator (STATCOM), and renewable energy-based distributed generation. These power electronics-based devices possess characteristics that may degrade power quality and cause mal-operation/failure of existing protection mechanisms. Chapter 3 presents the conventional way of protecting transmission and distribution systems and possible mal-operation/failure of existing protection mechanisms due to inclusion of FACTS devices and distributed generation. To overcome the difficulties possessed by the FACTS devices and DGs in transmission and distribution system protections, several recent and advanced schemes are included in Chap. 4 and can be concluded as follows. Transmission system protection – superimposed sequence components-based integrated impedance (SSCII)-based scheme can identify line faults up to 500 Ω but requires complete system knowledge including SVC data. Estimated reactive power factor (ERF)-based scheme has no such limitations but cannot classify the fault. Similarly, estimated phase error (EPE)-based and imaginary component of the virtual fault impedance (IVFI)-based schemes also cannot classify the fault. Another scheme, that is, EC-based scheme, can classify the fault and can be used for both series- and shunt-compensated transmission lines (TLs). However, may mis-detect LL-G fault as an L-G fault. The scheme based on Incremental reactive power coefficient (IRPC) can successfully detect and classify the faults in series- as well as shunt-compensated TLs. Distribution system protection – voltage ripple-based scheme may mal-function in identifying islanding and non-islanding events if the voltage gets disturbed as it © Springer Nature Switzerland AG 2021 O. Hari Gupta et al., Protection Challenges in Meeting Increasing Electric Power Demand, https://doi.org/10.1007/978-3-030-60500-1_5

123

124

5 Conclusion

solely depends on the voltage profile. The wavelet-based scheme gives better results, but proper selection of the mother wavelet is necessary for different system models. Another scheme, which is based on the superimposed impedance, is a kind of hybrid islanding detection scheme and works better in varying system conditions to identify islanding events.

5.2

Scope for Future Work

When the microgrids are attached to the transmission network, it would be interesting to know what will be the behavior of TL relays/protection schemes and what will be the effect of higher penetration of DGs on TLs, its stability, and control issues. Also, with the next generation advancements in the technology, a lot of modifications are expected in the transmission and distribution systems. One of the examples – not new but at the development stage – is high-voltage direct current (HVDC) system protection. In a DC system, the protection becomes more difficult, as there is no current zero crossing unlike an AC system. Similarly, there is a lot of interest in DC distribution systems with incorporated DGs. Therefore, with these expected future developments, the scenario will be totally different, and the currently available/implemented protection schemes may not provide satisfactory performance. So new protection schemes would be needed as the transmission and distribution systems evolve.

Index

A Active power mismatch, 109, 110 AC-to-DC converters, 30 Anti-islanding, 106 Apparent impedance L-G fault, 42, 43 LL fault, 42–44 LL-G fault, 42, 44 three-phase fault, 44, 45 two-terminal transmission line, 41, 42 Approximations, 112 Artificial Neural Networks (ANNs), 6, 7

B Biased differential relaying, 41, 42 Bidirectional fault current, 57 Blinding protection, 58 Breaker operating time, 54 Buck–boost converter, 29

C Capacitor switching, 106, 110, 111, 115, 116 Circuit breakers (CBs), 118 Communication-based methods, 8 Compensating devices, 23 Conventional protection, 46–48, 51 Conventional relaying schemes, 33, 45, 51–53, 59 Converter-based DGs, 116–121 Current-graded protection, 55

D DC distribution systems, 124 DC microgrids, 31 DC-to-AC converters, 31 Definite time overcurrent (DTOC) relay, 54 DFIG wind turbine system, 29 DGs-embedded distribution system bidirectional fault current, 57 blinding protection, 58 distance to fault, 58 false tripping, 57 grid-connected mode, 56 high-impedance fault, 58 islanding, 59 LoG, 56 LoM, 56 loss of coordination, 59 microgrid, 56, 57 single-phase connection, 59 Differential current, 39 Differential relaying, 39, 41 Directional relaying schemes, 5 Discrete wavelet transform (DWT), 112–114, 116 Distance relaying impedance, 34, 35 implementation, 34 MHO, 36–37 operation, 34 reactance, 36 torque equation, 34

© Springer Nature Switzerland AG 2021 O. Hari Gupta et al., Protection Challenges in Meeting Increasing Electric Power Demand, https://doi.org/10.1007/978-3-030-60500-1

125

126 Distributed generations (DGs), 1, 19, 27, 28, 63, 109, 112–114, 117, 118, 120, 121 Distribution systems, 1, 7, 9, 45, 123 current-graded protection, 55 overcurrent, 53, 54 relay characteristic, 53 relay operating time, 53 time- and current-graded protection, 55, 56 time-graded protection, 54 Doubly fed induction generator (DFIG), 29

E EC-based scheme, 123 Electricity, 1 Energy coefficients (ECs) scheme definition, 90 different fault locations multi-phase fault, 96, 97 single-phase fault, 96 different Rf values, 97 flowchart, 95 in MATLAB domain, 90 protected line, 96 PSCAD/EMTDC, 90 SEs characteristics, 91–93 external fault, 93–95 fault detection, 90 internal fault, 91 TCSC-compensated TL system, 90 TCSC in capacitive mode, 91, 92 TCSC in inductive mode, 92, 93 two-bus TCSC-compensated TL system, 90, 91 single- and multi-phase faults, 90, 96 ERF-based scheme, 8 Estimated phase error (EPE), 8, 123 analysis of simulation descriptions of test systems, 80 different fault locations in uncompensated TL, 82, 83 different fault locations with compensation-level variations, 81 variations of SIR, 81, 83 various value of Rf, 81, 82 characteristics, 76 definition, 76 external fault, 76, 78 flowchart, 80 internal fault, 76, 78–80 pre-fault condition, 77–78

Index series-compensated/uncompensated EHV/UHV TL system, 76 SIL, 76 working principle, 76, 77 Estimated reactive power factor (ERF) scheme, 123 analysis of simulation different fault locations, 72–74 different Rf values, 74, 75 uncompensated TL, 74, 75 flowchart, 73 real-time simulator, 69 STATCOM-compensated TL system, 69 working principle external fault, 70, 71 internal fault, 71, 72 normal operating conditions, 70 operating conditions, 70 pre-fault single-line diagram, 69 voltage of shunt controller, 70

F FACTS-compensated line protection conventional protection systems, 4 directional protection algorithms, 6 directional relaying schemes, 5 distance protection, 4 double-circuit TL, 6 FCIP-based protection algorithm, 5 LL-G, 5 measurement-based schemes, 6 phasor diagrams, 3 SFD, 4–6 shunt compensation, 2 SPT, 4 STATCOM, 3 Taylor–Kalman–Fourier filter-based distance protection algorithm, 6 TLs, 5 traveling-wave-based relaying, 6 TSTC, 3 UR/OR, 4 FACTS-compensated TLs, 5 FACTS devices, 1, 9, 19, 31, 123 False tripping, 57, 59 Fault component integrated power (FCIP), 5 Fault contribution, 57 Fault distance approximation algorithm, 6 Fault point, 35 Faulty condition, 35 Flexible ac transmission system (FACTS), 1

Index G Generation system, 45 Graded overcurrent protection, 54 Grid-connected and islanding waves, 107 Grid-connected mode, 118 Grid-connected PV microgrid, 28

H High-frequency band, 112 High-impedance fault, 58 High-pass filter (HPF), 112 High-resistance faults, 5 High-voltage AC (HVAC) transmission lines, 51 High-voltage direct current (HVDC), 124 Hybrid islanding detection scheme analysis of simulation performance investigation, 120 power mismatch conditions, 120 vs. THD, 121 UL1741SA, 119, 120 microgrid, 116 NDZ, 116 working principle calculation, 117, 118 characteristics analysis, 117, 118 generation, 117 implementation, 118, 119 SI-based scheme, 116 test system, 116 threshold selection, 118 Hybrid microgrids, 30, 31 Hysteresis current control mode, 116

I IDMT characteristic, 56 IDMT relay, 55, 56 IEEE 33-bus system, 27 IEEE 1547 guidelines, 111 Imaginary value of VFI (IVFI), 9 analysis of simulation STATCOM-compensated TL, 88, 89 SVC-compensated line, 86–88 uncompensated TL, 88–90 application, 86 external fault, 86 flow diagram, 87 internal fault, 85 multi-phase fault, 84 protected area, 84 SFD-compensated TL, 84

127 Impedance relaying, 34, 35 Impedance trajectory without SVC, 52 with SVC, 52 Incremental apparent powers (IAP), 98 Incremental reactive power coefficients (IRPCs) scheme analysis of simulation different fault locations with compensation, 102, 103 high source impedance, 103–105 load-level variations, 103–105 parameters, 102 values of Rf, 103, 104 definition, 98 phase, 98 in PSCAD/EMTDC, 98 working principle characteristics, 98 external fault, 99–102 flowchart, 101 internal fault, 98–100 shunt-compensated TL systems, 98 single-line diagram, 99 Inverse time relays, 56 Inverter-based DG, 58 Islanding detection, 56, 59 Islanding detection scheme, microgrid anti-islanding, 106 hybrid islanding detection scheme (see Hybrid islanding detection scheme) loss of grid (LoG), 106 loss of mains (LoM), 106 VRBIDT (see Voltage ripple-based islanding detection technique (VRBIDT)) WTBIDT (see Wavelet transform-based islanding detection technique (WTBIDT))

L Line-to-ground (L-G) fault, 42, 43, 49 Line-to-line (LL) fault, 42–44 Line-to-line-to-ground (LL-G), 5 LL-G fault, 42, 44 Load angle, 23 Load-level variations, 103–105 Load switching, 111 Loss of coordination, 59 Loss-of-grid (LoG), 56 Loss-of-mains (LoM), 56

128 Low-frequency signal, 112 Low-pass filter (LPF), 112

M MATLAB-based simulation, 111 MATLAB domain, 9, 76 MATLAB/Simulink environment, 116 Maximum power point, 29 Maximum power point tracking (MPPT), 28 Measurement-based schemes, 6 Metal-oxide varistor (MOV), 76 MHO relaying, 36–38, 51, 53 Microgrid, 56, 63, 124 islanding detection scheme (see Islanding detection scheme, microgrid) mode of operation, 58 Microgrid islanding protection communication-based methods, 8 frequency relays, 7 methods, 7 optimal placement, 7 passive and active methods, 8 PCC, 7 ROCOF, 7 ROCOVPA, 7 voltage ripple-based method, 9 wavelet transform, 7 Microgrid protection bidirectional flow, 57 blinding protection, 58 false tripping, 57 fault contribution, 57 inverter-based DG, 58 islanding, 59 network, 56 and TLs, 59 MPPT algorithm, 29 Multi-input phase comparators, 38

N Negligible detection zone (NDZ), 116 Non-detection zones (NDZ), 106, 107, 121 Non-directional relays, 35 Non-islanding conditions, 106, 108, 110, 111

O Over reach, 33, 41, 45–48, 50, 51, 59 Overcurrent protection, 53, 54

Index P Perfect power-match conditions, 119, 120 Permanent magnet synchronous generator (PMSG), 29 Phase-to-ground faults, 37 Phasor diagrams, 3, 4 Pilot-based protection systems, 5 Point of common coupling (PCC), 7, 106–113, 115–118, 120 Power flow through the TL STATCOM, 22 SVC, 20, 21 system operator, 20 TCSC, 20 Power-generating stations, 19 Power mismatch conditions, 120 Power system protection, 6 Power transmission systems, 31 Protection of FACTS-compensated line advantages, 45 distribution system, 45 generation system, 45 in power system, 45 protection schemes, 45, 46 series and shunt FACTS devices, 51 series FACTS devices, 46–48 shunt FACTS devices, 48–50 simulated verification, 51–53 transmission system, 45 PSCAD/EMTDC environment, 9, 51, 63, 69, 76, 84, 90, 97, 98

Q Quadrilateral relay, 37–40 Quality factor (QF), 119, 120

R Radial feeder protection, 54 Rate-of-change-of-frequency (ROCOF), 7 Rate-of-change-of-voltage-phase-angle (ROCOVPA), 7 Rate-of-change-of-voltage (ROCOV), 7 Rate of power shift-based (RPS-based) scheme, 8 Reactance relaying, 36 Reactive power mismatch, 110 Real-time simulator, 69 Relay error, 54 Relay point, 35

Index Renewable-based generations, 30 conventional source-based generations, 27 DFIG, 29 distribution system, 28 grid-connected PV microgrid, 28 MPPT technique, 28, 29 PMSG, 29 solar-based DG, 28 solar-based energy generation, 28 solar energy, 29 Resistance faults, 38

S Series and shunt FACTS devices, 51 Series-compensated TL system, 76, 77, 79, 80, 99 Series-compensated/uncompensated EHV/UHV TL system, 76 Series compensation equivalent reactance, 24 levels, 25 phasor diagram, 24 power flow, 24 two-terminal TL, 24 variations, 25 Series FACTS devices SSSC, 46 TCSC-compensated line system, 46 TCSR-compensated line system, 46, 47 TSSC, 46 TSSR, 46 under/overreach, 46–48, 50, 51, 59 voltage and current inversion problem, 47, 48 SFD-compensated TL, 4–6 Shunt compensation, 2 midpoint voltage, 25 phasor diagram, 26 power flow in TL, 26, 27 single-line diagram, 25, 26 TL loading, 26 Shunt FACTS devices (SFD), 4, 48–50 SI-based algorithm, 116, 118–121 SI-based islanding detection algorithm, 118, 119 Simulated verification, 51–53 Single-line diagram (SLD), 76–78 Single-phase connection, 59 Single-phase RMS voltage, 108 Single-pole tripping (SPT), 4 Solar-based DG, 28, 29 Solar-based energy generation, 28 Solid oxide fuel cell (SOFC), 111 Source-to-line impedance (SIL), 76

129 SSCII-based scheme, 8 Stand-alone mode, 116, 118 STATCOM-compensated TL system, 69, 73, 86, 88, 89 Static synchronous compensator (STATCOM), 3, 19, 20, 22, 31, 48, 123 Static synchronous series compensator (SSSC), 46 Static VAR compensator (SVC), 19–22, 48 S-transform-based distance relaying algorithm, 6 Superimposed component impedance (SI), 9 Superimposed energy-based scheme, 9 Superimposed sequential components incorporated integrated impedance (SSCII) scheme, 123 analysis of simulation different fault locations, 67 different fault locations with unequal source impedances, 68, 69 different value, 67, 68 definition, 64 different fault locations, 68 fault resistances, 68 in PSCAD/EMTDC domain, 63 shunt compensation, 64 two-bus SVC-compensated TL system, 63, 64 unequal source impedances, 68 working principle flowchart, 66 healthy phases/non-faulty phases, 67 modified pre-fault currents, 65 modified pre-fault data, 65 modified pre-fault voltages, 65 pre-fault injected SVC current, 65 superposition theorem, 65 VI-characteristics, 64 voltage distribution method, 64 Superposition theorem, 65 Support Vector Machine-based (SVM-based) relaying algorithms, 6 Surge impedance loading, 26 SVC-compensated TL, 67, 86–88, 102, 104 SVC-injected components, 68 System-based DG, 29, 30

T Taylor–Kalman–Fourier filter-based distance protection algorithm, 6 TCSC-based test systems, 52 TCSR-compensated line system, 47, 89 Thevenin’s equivalent, 41 Three-phase faults, 44, 45, 111

130 Thyristor-controlled phase shifting transformer (TCPST), 51 Thyristor-controlled reactor (TCR), 20, 48 Thyristor-controlled series capacitor (TCSC), 3, 19–21, 46, 123 Thyristor-controlled series reactor (TCSR), 46 Thyristor-switched capacitor (TSC), 20, 48 Thyristor-switched reactor (TSR), 48 Thyristor-switched series capacitor (TSSC), 46 Thyristor-switched series reactor (TSSR), 46 Time- and current-graded protection, 55, 56 Time delay, 106 Time-domain spectral analysis, 106 Time-graded protection, 54 TL relays/protection schemes, 124 Transmission lines (TLs), 1 advantages and disadvantages, 33 apparent impedance, 41–45 biased differential relaying, 41, 42 differential relaying, 39, 41 distance relaying, 34–37 identification/classification, 63 quadrilateral relay, 37–40 Transmission system, 1, 45 Traveling-wave-based relaying, 6 TSSC-compensated TL system, 47, 48 Two-terminal TCSC-compensated TL, 3 Two-terminal uncompensated TL, 23

U Uncompensated TL, 74, 75, 80, 82, 83, 86, 88–90 Under reach, 33, 41, 45–48, 50, 51, 59

Index Under-reach/over-reach (UR/OR), 4 Unified power flow controller (UPFC), 51

V Voltage and current inversion problem, 47, 48 Voltage-based technique, 111 Voltage distribution method, 64 Voltage ripple-based islanding detection technique (VRBIDT) analysis of simulation active power mismatch, 109, 110 changing frequency of averaging and RMS blocks, 108, 109 non-islanding events, 110, 111 reactive power mismatch, 110 flow diagram, 108 grid-connected PV-based inverters, 106 NDZ, 106 working principle, 106–108 Voltage ripple-based method, 9 Voltage source converter (VSC), 22

W Wavelet transform-based islanding detection technique (WTBIDT) analysis of simulation, 113–115 DWT, 112 SOFC, 111 tested events, 115, 116 tested system, 112, 113 WT-based scheme, 113, 114