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Protection of Electrical Networks

Protection of
Electrical Networks

Christophe Prévé

First published in Great Britain and the United States in 2006 by ISTE Ltd
Apart from any fair dealing for the purposes of research or private study, or criticism or review, as permitted under the Copyright, Designs and Patents Act 1988, this publication may only be reproduced, stored or transmitted, in any form or by any means, with the prior permission in writing of the publishers, or in the case of reprographic reproduction in accordance with the terms and licenses issued by the CLA. Enquiries concerning reproduction outside these terms should be sent to the publishers at the undermentioned address:
ISTE Ltd
6 Fitzroy Square
London W1T 5DX
UK

ISTE USA
4308 Patrice Road
Newport Beach, CA 92663
USA

www.iste.co.uk
© ISTE Ltd, 2006
The rights of Christophe Prévé to be identified as the author of this work have been asserted by him in accordance with the Copyright, Designs and Patents Act 1988.
Library of Congress Cataloging-in-Publication Data
Prévé, Christophe, 1964Protection of electrical networks / Christophe Prévé.
p. cm.
Includes index.
ISBN-13: 978-1-905209-06-4
ISBN-10: 1-905209-06-1
1. Electric networks--Protection. I. Title.
TK454.2.P76 2006
621.319'2--dc22
2006008664
British Library Cataloguing-in-Publication Data
A CIP record for this book is available from the British Library
ISBN 10: 1-905209-06-1
ISBN 13: 978-1-905209-06-4
Printed and bound in Great Britain by Antony Rowe Ltd, Chippenham, Wiltshire.

Table of Contents

Chapter 1. Network Structures . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.1. General structure of the private distribution network . . . . . . . . . . . .
1.2. The supply source . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.3. HV consumer substations . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.4. MV power supply . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.4.1. Different MV service connections . . . . . . . . . . . . . . . . . . . . .
1.4.2. MV consumer substations . . . . . . . . . . . . . . . . . . . . . . . . . .
1.5. MV networks inside the site . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.5.1. MV switchboard power supply modes . . . . . . . . . . . . . . . . . .
1.5.2. MV network structures. . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.6. LV networks inside the site . . . . . . . . . . . . . . . . . . . . . . . . . . .
1.6.1. LV switchboard supply modes . . . . . . . . . . . . . . . . . . . . . . .
1.6.2. LV switchboards backed up by generators . . . . . . . . . . . . . . . .
1.6.3. LV switchboards backed up by an uninterruptible power supply (UPS) .
1.7. Industrial networks with internal generation . . . . . . . . . . . . . . . . .
1.8. Examples of standard networks . . . . . . . . . . . . . . . . . . . . . . . . .

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Chapter 2. Earthing Systems . . . . . . . . . . . . . . . . . . . . . . . .
2.1. Earthing systems at low voltage. . . . . . . . . . . . . . . . . . .
2.1.1. Different earthing systems – definition and arrangements .
2.1.2. Comparison of different earthing systems in low voltage .
2.1.2.1. Unearthed or impedance-earthed neutral (IT system). .
2.1.2.2. Directly earthed neutral (TT system) . . . . . . . . . . .
2.1.2.3. Connecting the exposed conductive parts to the neutral
(TNC – TNS systems) . . . . . . . . . . . . . . . . . . . . . . . . .
2.2. Medium voltage earthing systems . . . . . . . . . . . . . . . . .
2.2.1. Different earthing systems – definition and arrangements .
2.2.2. Comparison of different medium voltage earthing systems
2.2.2.1. Direct earthing . . . . . . . . . . . . . . . . . . . . . . . .
2.2.2.2. Unearthed . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.2.2.3. Limiting resistance earthing. . . . . . . . . . . . . . . . .

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6

Protection of Electrical Networks

2.2.2.4. Limiting reactance earthing . . . . . . . . . . . . . . . . . . . . .
2.2.2.5. Peterson coil earthing . . . . . . . . . . . . . . . . . . . . . . . .
2.3. Creating neutral earthing . . . . . . . . . . . . . . . . . . . . . . . . . . .
2.3.1. MV installation resistance earthing . . . . . . . . . . . . . . . . . .
2.3.2. Reactance or Petersen coil earthing of an MV installation. . . . .
2.3.3. Direct earthing of an MV or LV installation . . . . . . . . . . . . .
2.4. Specific installation characteristics in LV unearthed systems . . . . .
2.4.1. Installing a permanent insulation monitor . . . . . . . . . . . . . .
2.4.2. Installing an overvoltage limiter . . . . . . . . . . . . . . . . . . . .
2.4.3. Location of earth faults by a low frequency generator (2–10 Hz)
2.5. Specific installation characteristics of an MV unearthed system . . .
2.5.1. Insulation monitoring . . . . . . . . . . . . . . . . . . . . . . . . . .
2.5.2. Location of the first insulation fault . . . . . . . . . . . . . . . . . .

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Chapter 4. Short-circuits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.1. Establishment of short-circuit currents and wave form . . . . . . . . . .
4.1.1. Establishment of the short-circuit at the utility’s supply terminals .
4.1.2. Establishment of the short-circuit current at the terminals of a generator . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.2. Short-circuit current calculating method. . . . . . . . . . . . . . . . . . .
4.2.1. Symmetrical three-phase short-circuit. . . . . . . . . . . . . . . . . .
4.2.1.1. Equivalent impedance of an element across a transformer. . . .
4.2.1.2. Impedance of parallel links . . . . . . . . . . . . . . . . . . . . . .
4.2.1.3. Expression of impedances as a percentage and short-circuit voltage as a percentage . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.2.1.4. Impedance values of different network elements . . . . . . . . .
4.2.1.5. Contribution of motors to the short-circuit current value . . . .
4.2.1.6. Example of a symmetrical three-phase short-circuit calculation
4.2.2. Solid phase-to-earth short-circuit (zero fault impedance) . . . . .
4.2.2.1. positive, negative and zero-sequence impedance values of different network elements . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.2.3. The phase-to-phase short-circuit clear of earth . . . . . . . . . . . .
4.2.4. The two-phase-to-earth short-circuit. . . . . . . . . . . . . . . . . . .
4.3. Circulation of phase-to-earth fault currents . . . . . . . . . . . . . . . . .
4.3.1. Unearthed or highly impedant neutral . . . . . . . . . . . . . . . . . .
4.3.2. Impedance-earthed neutral (resistance or reactance) . . . . . . . . .
4.3.3. Tuned reactance or Petersen coil earthing . . . . . . . . . . . . . . .
4.3.4. Directly earthed neutral . . . . . . . . . . . . . . . . . . . . . . . . . .

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Chapter 3. Main Faults Occurring in Networks and Machines .
3.1. Short-circuits . . . . . . . . . . . . . . . . . . . . . . . . . . . .
3.1.1. Short-circuit characteristics . . . . . . . . . . . . . . . . .
3.1.2. Different types of short-circuits . . . . . . . . . . . . . .
3.1.3. Causes of short-circuits . . . . . . . . . . . . . . . . . . .
3.2. Other types of faults. . . . . . . . . . . . . . . . . . . . . . . .

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. 106
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. 114
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Table of Contents

4.3.5. Spreading of the capacitive current in a network with several outgoing feeders upon occurrence of an earth fault. . . . . . . . . . . . . .
4.4. Calculation and importance of the minimum short-circuit current . . .
4.4.1. Calculating the minimum short-circuit current in low voltage in relation to the earthing system . . . . . . . . . . . . . . . . . . . . . . . .
4.4.1.1. Calculating the minimum short-circuit current in a TN system .
4.4.1.2. Calculating the minimum short-circuit current in an IT system without a distributed neutral . . . . . . . . . . . . . . . . . . . . . . . . . .
4.4.1.3. Calculating the minimum short-circuit in an IT system with distributed neutral . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.4.1.4. Calculating the minimum short-circuit in a TT system . . . . . .
4.4.1.5. Influence of the minimum short-circuit current on the choice of circuit-breakers or fuses . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.4.2. Calculating the minimum short-circuit current for medium and high voltages . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
4.4.3. Importance of the minimum short-circuit calculation for protection selectivity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
Chapter 5. Consequences of Short-circuits . . .
5.1. Thermal effect . . . . . . . . . . . . . . . . .
5.2. Electrodynamic effect. . . . . . . . . . . . .
5.3. Voltage drops. . . . . . . . . . . . . . . . . .
5.4. Transient overvoltages . . . . . . . . . . . .
5.5. Touch voltages . . . . . . . . . . . . . . . . .
5.6. Switching surges. . . . . . . . . . . . . . . .
5.7. Induced voltage in remote control circuits.

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7

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Chapter 6. Instrument Transformers . . . . . . . . . . . . . . . . . . . . . . . . .
6.1. Current transformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.1. Theoretical reminder . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.2. Saturation of the magnetic circuit . . . . . . . . . . . . . . . . . . . . .
6.1.3. Using CTs in electrical networks. . . . . . . . . . . . . . . . . . . . . .
6.1.3.1. General application rule . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.3.2. Composition of a current transformer . . . . . . . . . . . . . . . . .
6.1.3.3. Specifications and definitions of current transformer parameters.
6.1.3.4. Current transformers used for measuring in compliance with standard IEC 60044-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.3.5. Current transformers used for protection in compliance with standard IEC 60044-1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.3.6. Current transformers used for protection in compliance with
BS 3938 (class X) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.3.7. Correspondence between IEC 60044-1 and BS 3938 CT specifications . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.1.3.8. Use of CTs outside their nominal values . . . . . . . . . . . . . . .
6.1.3.9. Example of a current transformer rating plate . . . . . . . . . . . .
6.1.4. Non-magnetic current sensors . . . . . . . . . . . . . . . . . . . . . . .

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Protection of Electrical Networks

6.2. Voltage transformers . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2.1. General application rule . . . . . . . . . . . . . . . . . . . . . . . . .
6.2.2. Specifications and definitions of voltage transformer parameters
6.2.3. Voltage transformers used for measuring in compliance with
IEC 60044-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2.4. Voltage transformers used for protection in compliance with
IEC 60044-2. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
6.2.5. Example of the rating plate of a voltage transformer used for measurement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Chapter 7. Protection Functions and their Applications . . . . . . . . . . . . .
7.1. Phase overcurrent protection (ANSI code 50 or 51) . . . . . . . . . . . . .
7.2. Earth fault protection (ANSI code 50 N or 51 N, 50 G or 51 G). . . . . .
7.3. Directional overcurrent protection (ANSI code 67) . . . . . . . . . . . . .
7.3.1. Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.4. Directional earth fault protection (ANSI code 67 N) . . . . . . . . . . . .
7.4.1. Operation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.4.2. Study and setting of parameters for a network with limiting resistance earthing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.4.3. Study and setting of parameters for an unearthed network. . . . . . .
7.5. Directional earth fault protection for compensated neutral networks
(ANSI code 67 N). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.6. Differential protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.6.1. High impedance differential protection . . . . . . . . . . . . . . . . . .
7.6.1.1. Operation and dimensioning of elements . . . . . . . . . . . . . .
7.6.1.2. Application of high impedance differential protection . . . . . . .
7.6.1.3. Note about the application of high impedance differential protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.6.2. Pilot wire differential protection for cables or lines (ANSI code 87 L)
7.6.3. Transformer differential protection (ANSI code 87 T) . . . . . . . . .
7.7. Thermal overload protection (ANSI code 49). . . . . . . . . . . . . . . . .
7.8. Negative phase unbalance protection (ANSI code 46) . . . . . . . . . . .
7.9. Excessive start-up time and locked rotor protection (ANSI code 51 LR)
7.10. Protection against too many successive start-ups (ANSI code 66). . . .
7.11. Phase undercurrent protection (ANSI code 37) . . . . . . . . . . . . . . .
7.12. Undervoltage protection (ANSI code 27) . . . . . . . . . . . . . . . . . .
7.13. Remanent undervoltage protection (ANSI code 27) . . . . . . . . . . . .
7.14. Positive sequence undervoltage and phase rotation direction protection
(ANSI code 27 d – 47) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.15. Overvoltage protection (ANSI code 59) . . . . . . . . . . . . . . . . . . .
7.16. Residual overvoltage protection (ANSI code 59 N) . . . . . . . . . . . .
7.17. Under or overfrequency protection (ANSI code 81) . . . . . . . . . . . .
7.18. Protection against reversals in reactive power (ANSI code 32 Q) . . . .
7.19. Protection against reversals in active power (ANSI code 32 P) . . . . .
7.20. Tank earth leakage protection (ANSI code 50 or 51) . . . . . . . . . . .

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Table of Contents

7.21. Protection against neutral earthing impedance overloads (ANSI code
50 N or 51 N) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
7.22. Overall network earth fault protection by monitoring the current flowing through the earthing connection (ANSI code 50 N or 51 N, 50 G or 51 G) . . .
7.23. Protection using temperature monitoring (ANSI code 38 – 49 T) . . . .
7.24. Voltage restrained overcurrent protection (ANSI code 50 V or 51 V) .
7.25. Protection by gas, pressure and temperature detection (DGPT) . . . . .
7.26. Neutral to neutral unbalance protection (ANSI code 50 N or 51 N) . . .

9

307
308
309
311
314
315

Chapter 8. Overcurrent Switching Devices . . . . . . . . . . . . . .
8.1. Low voltage circuit-breakers . . . . . . . . . . . . . . . . . . .
8.2. MV circuit-breakers (according to standard IEC 62271-100)
8.3. Low voltage fuses . . . . . . . . . . . . . . . . . . . . . . . . . .
8.3.1. Fusing zones – conventional currents . . . . . . . . . . . .
8.3.2. Breaking capacity. . . . . . . . . . . . . . . . . . . . . . . .
8.4. MV fuses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .

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Chapter 9. Different Selectivity Systems . . . . . . .
9.1. Amperemetric selectivity. . . . . . . . . . . . .
9.2. Time-graded selectivity. . . . . . . . . . . . . .
9.3. Logic selectivity . . . . . . . . . . . . . . . . . .
9.4. Directional selectivity. . . . . . . . . . . . . . .
9.5. Selectivity by differential protection . . . . . .
9.6. Selectivity between fuses and circuit-breakers

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Chapter 10. Protection of Network Elements . . . . . . . . . . . . . . . .
10.1. Network protection . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.1.1. Earth fault requirements for networks earthed via a limiting resistance (directly or by using an artificial neutral) . . . . . . . . . .
10.1.2. Earth fault requirement for unearthed networks . . . . . . . .
10.1.3. Requirements for phase-to-phase faults . . . . . . . . . . . . .
10.1.4. Network with one incoming feeder. . . . . . . . . . . . . . . .
10.1.4.1. Protection against phase-to-phase faults. . . . . . . . . . .
10.1.4.2. Protection against earth faults . . . . . . . . . . . . . . . . .
10.1.5. Network with two parallel incoming feeders . . . . . . . . . .
10.1.5.1. Protection against phase-to-phase faults. . . . . . . . . . .
10.1.5.2. Protection against earth faults . . . . . . . . . . . . . . . . .
10.1.6. Network with two looped incoming feeders . . . . . . . . . .
10.1.6.1. Protection against phase-to-phase faults. . . . . . . . . . .
10.1.6.2. Protection against earth faults . . . . . . . . . . . . . . . . .
10.1.7. Loop network . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.1.7.1. Protection at the head of the loop. . . . . . . . . . . . . . .
10.1.8. Protection by section . . . . . . . . . . . . . . . . . . . . . . . .
10.2. Busbar protection . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.2.1. Protection of a busbar using logic selectivity . . . . . . . . . .

. . . . 361
. . . . 361
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362
369
371
372
373
375
381
381
384
390
390
393
399
399
401
412
412

10

Protection of Electrical Networks

10.2.2. Protection of a busbar using a high impedance differential protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.3. Transformer protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.3.1. Transformer energizing inrush current. . . . . . . . . . . . . . . . . .
10.3.2. Value of the short-circuit current detected by the HV side protection during a short-circuit on the LV side for a delta-star transformer . . . . . . . .
10.3.3. Faults in transformers. . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.3.4. Transformer protection . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.3.4.1. Specific protection against overloads . . . . . . . . . . . . . . . .
10.3.4.2. Specific protection against internal phase short-circuits . . . . .
10.3.4.3. Specific protection against earth faults . . . . . . . . . . . . . . .
10.3.4.4. Switch-fuse protection . . . . . . . . . . . . . . . . . . . . . . . . .
10.3.4.5. Circuit-breaker protection . . . . . . . . . . . . . . . . . . . . . . .
10.3.5. Examples of transformer protection . . . . . . . . . . . . . . . . . . .
10.3.6. Transformer protection setting indications . . . . . . . . . . . . . . .
10.4. Motor protection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.4.1. Protection of medium voltage motors . . . . . . . . . . . . . . . . . .
10.4.1.1. Examples of motor protection. . . . . . . . . . . . . . . . . . . . .
10.4.1.2. Motor protection setting indications . . . . . . . . . . . . . . . . .
10.4.2. Protection of low voltage asynchronous motors . . . . . . . . . . . .
10.5. AC generator protection. . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.5.1. Examples of generator protection devices. . . . . . . . . . . . . . . .
10.5.2. Generator protection setting indications . . . . . . . . . . . . . . . . .
10.6. Capacitor bank protection . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.6.1. Electrical phenomena related to energization. . . . . . . . . . . . . .
10.6.2. Protection of Schneider low voltage capacitor banks . . . . . . . . .
10.6.3. Protection of Schneider medium voltage capacitor banks . . . . . .
10.8. Protection of direct current installations . . . . . . . . . . . . . . . . . . .
10.8.1. Short-circuit current calculation . . . . . . . . . . . . . . . . . . . . .
10.8.2. Characteristics of insulation faults and switchgear . . . . . . . . . .
10.8.3. Protection of persons . . . . . . . . . . . . . . . . . . . . . . . . . . . .
10.9. Protection of uninterruptible power supplies (UPS) . . . . . . . . . . . .
10.9.1. Choice of circuit-breaker ratings . . . . . . . . . . . . . . . . . . . . .
10.9.2. Choice of circuit-breaker breaking capacity . . . . . . . . . . . . . .
10.9.3. Selectivity requirements . . . . . . . . . . . . . . . . . . . . . . . . . .

413
414
414
417
423
424
424
424
424
425
432
436
438
439
440
446
448
451
452
457
460
462
463
469
470
479
479
482
483
483
484
485
485

Appendix A. Transient Current Calculation of Short-circuit Fed by Utility Network . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 487
Appendix B. Calculation of Inrush Current During Capacitor Bank
Energization. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 493
Appendix C. Voltage Peak Value and Current r.m.s Value, at the Secondary of a Saturated Current Transformer . . . . . . . . . . . . . . 501
Index . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 507

Chapter 1

Network Structures

Definition
Standard IEC 60038 defines voltage ratings as follows:
– Low voltage (LV): for a phase-to-phase voltage of between 100 V and 1,000 V, the standard ratings are: 400 V - 690 V - 1,000 V (at 50 Hz).
– Medium voltage (MV): for a phase-to-phase voltage between 1,000 V and
35 kV, the standard ratings are: 3.3 kV - 6.6 kV - 11 kV - 22 kV - 33 kV.
– High voltage (HV): for a phase-to-phase voltage between 35 kV and 230 kV, the standard ratings are: 45 kV - 66 kV - 110 kV - 132 kV - 150 kV - 220 kV.
In this chapter we will look at:
– types of HV and MV consumer substations;
– structure of MV networks inside a site;
– structure of LV networks inside a site;
– structure of systems with a back-up power supply.
Six standard examples of industrial network structures are given at the end of the chapter. Each structure is commented upon and divided up so that each functional aspect can be considered.
(NC) means that the switch or circuit-breaker is closed in normal conditions.
(NO) means that the switch or circuit-breaker is open in normal conditions.

12

Protection of Electrical Networks supply source

supply source
HV consumer substation internal production HV

MV main MV distribution switchboard

MV load

MV load

MV load

MV internal distribution network secondary MV distribution switchboards

MV

MV

MV

MV

LV

LV

LV

LV

LV switchboards and LV distribution

LV load LV load Figure 1-1: structure of a private distribution network

Network Structures

13

1.1. General structure of the private distribution network
Generally, with an HV power supply, a private distribution network comprises
(see Figure 1-1):
– an HV consumer substation fed by one or more sources and made up of one or more busbars and circuit-breakers;
– an internal generation source;
– one or more HV/MV transformers;
– a main MV switchboard made up of one or more busbars;
– an internal MV network feeding secondary switchboards or MV/LV substations; – MV loads;
– MV/LV transformers;
– low voltage switchboards and networks;
– low voltage loads.
1.2. The supply source
The power supply of industrial networks can be LV, MV or HV. The voltage rating of the supply source depends on the consumer supply power. The greater the power required, the higher the voltage must be.
1.3. HV consumer substations
The most usual supply arrangements adopted in HV consumer substations are:
Single power supply (see Figure 1-2)
Advantage:
– reduced cost.
Disadvantage:
– low reliability.
Note: the isolators associated with the HV circuit-breakers have not been shown.

14

Protection of Electrical Networks

supply source
NC

HV busbar
HV b

NC

NC

NC

NC

to main MV switchboard

Figure 1-2: single fed HV consumer substation

Dual power supply (see Figure 1-3) source 1

NC

source 2

NC

NC
H
HV busbar

NC

NC

HV

HV

MV

MV

NC

NC

to main MV switchboard

Figure 1-3: dual fed HV consumer substation

Network Structures

15

Operating mode:
– normal:
- Both incoming circuit-breakers are closed, as well as the coupler isolator.
- The transformers are thus simultaneously fed by two sources.
– disturbed:
- If one source is lost, the other provides the total power supply.
Advantages:
– Very reliable in that each source has a total network capacity.
– Maintenance of the busbar possible while it is still partially operating.
Disadvantages:
– More costly solution.
– Only allows partial operation of the busbar if maintenance is being carried out on it.
Note: the isolators associated with the HV circuit-breakers have not been shown.
Dual fed double bus system (see Figure 1-4)
Operating mode:
– normal:
- Source 1 feeds busbar BB1 and feeders Out1 and Out2.
- Source 2 feeds busbar BB2 and feeders Out3 and Out4.
- The bus coupler circuit-breaker can be kept closed or open.
– disturbed:
- If one source is lost, the other provides the total power supply.
- If a fault occurs on a busbar (or maintenance is carried out on it), the bus coupler circuit-breaker is tripped and the other busbar feeds all the outgoing lines.
Advantages:
– Reliable power supply.
– Highly flexible use for the attribution of sources and loads and for busbar maintenance. – Busbar transfer possible without interruption.
Disadvantage:
– More costly in relation to the single busbar system.
Note: the isolators associated with the HV circuit-breakers have not been shown.

16

Protection of Electrical Networks source 1

source 2
NC

NC

NC

NO

NO

NC
BB1

coupler
NC or NO
NO

BB2
NC

NO NC

Out1
NC

NO NO

Out2
NC

NC NO

Out3
NC

HV double busbar NC

Out4
NC

HV

HV

MV

MV
NC

NC to main MV switchboard to main MV switchboard

Figure 1-4: dual fed double bus HV consumer substation

1.4. MV power supply
We shall first look at the different MV service connections and then at the MV consumer substation.
1.4.1. Different MV service connections
Depending on the type of MV network, the following supply arrangements are commonly adopted.
Single line service (see Figure 1-5)
The substation is fed by a single circuit tee-off from an MV distribution (cable or line). Transformer ratings of up to 160 kVA of this type of MV service is very common in rural areas. It has one supply source via the utility.

Network Structures

overhead line
NC

Figure 1-5: single line service

Ring main principle (see Figure 1-6)

NC

NC

underground cable ring main

Figure 1-6: ring main service

NC

17

18

Protection of Electrical Networks

Ring main units (RMU) are normally connected to form an MV ring main or loop (see Figures 1-20a and 1-20b).
This arrangement provides the user with a two-source supply, thereby considerably reducing any interruption of service due to system faults or operational maneuvers by the supply authority. The main application for RMUs is in utility MV underground cable networks in urban areas.
Parallel feeder (see Figure 1-7)

NC

NO

NC

parallel underground-cable distributors

Figure 1-7: duplicated supply service

When an MV supply connection to two lines or cables originating from the same busbar of a substation is possible, a similar MV switchboard to that of an RMU is commonly used (see Figure 1-21).
The main operational difference between this arrangement and that of an RMU is that the two incoming switches are mutually interlocked, in such a way that only one incoming switch can be closed at a time, i.e. its closure prevents that of the other. On loss of power supply, the closed incoming switch must be opened and the
(formerly open) switch can then be closed. The sequence may be carried out manually or automatically. This type of switchboard is used particularly in networks of high load density and in rapidly expanding urban areas supplied by MV underground cable systems.

Network Structures

19

1.4.2. MV consumer substations
The MV consumer substation may comprise several MV transformers and outgoing feeders. The power supply may be a single line service, ring main principle or parallel feeder (see section 1.4.1).
Figure 1-8 shows the arrangement of an MV consumer substation using a ring main supply with MV transformers and outgoing feeders.

NC

NC

NC

NC

MV

NC

NC

MV

CT

NC
VT

LV

LV

MV feeders

Figure 1-8: example of MV consumer substation

1.5. MV networks inside the site
MV networks are made up of switchboards and the connections feeding them.
We shall first of all look at the different supply modes of these switchboards, then the different network structures allowing them to be fed.
1.5.1. MV switchboard power supply modes
We shall start with the main power supply solutions of an MV switchboard, regardless of its place in the network.
The number of sources and the complexity of the switchboard differ according to the level of power supply security required.

20

Protection of Electrical Networks

1 busbar, 1 supply source (see Figure 1-9) source NC
NC
MV busbar
M

MV
MV f feeders d Figure 1-9: 1 busbar, 1 supply source

Operation: if the supply source is lost, the busbar is put out of service until the fault is repaired.
1 busbar with no coupler, 2 supply sources (see Figure 1-10)
Operation: one source feeds the busbar, the other provides a back-up supply. If a fault occurs on the busbar (or maintenance is carried out on it), the outgoing feeders are no longer fed. source 1
NC
NC

source 2

NC
NC
MV busbar

MV feeders
Figure 1-10: 1 busbar with no coupler, 2 supply sources

Network Structures

21

2 bus sections with coupler, 2 supply sources (see Figure 1-11) source 1

source 2

NC
NC

NC
NC

NC or NO
NC or NO

MV busbar

MV feeders
Figure 1-11: 2 bus sections with coupler, 2 supply sources

Operation: each source feeds one bus section. The bus coupler circuit-breaker can be kept closed or open. If one source is lost, the coupler circuit-breaker is closed and the other source feeds both bus sections. If a fault occurs in a bus section (or maintenance is carried out on it), only one part of the outgoing feeders is no longer fed. 1 busbar with no coupler, 3 supply sources (see Figure 1-12) source 1

NC

source 2

NC

source 3

NC
MV busbar

MV feeders
Figure 1-12: 1 busbar with no coupler, 3 supply sources

22

Protection of Electrical Networks

Operation: the power supply is normally provided by two parallel-connected sources. If one of these two sources is lost, the third provides a back-up supply. If a fault occurs on the busbar (or maintenance is carried out on it), the outgoing feeders are no longer fed.
3 bus sections with couplers, 3 supply sources (see Figure 1-13) source 1

NC

source 2

NC
NC or NO

source 3

NC
NC or NO

MV busbar

MV feeders
Figure 1-13: 3 bus sections with couplers, 3 supply sources

Operation: both bus coupler circuit-breakers can be kept open or closed. Each supply source feeds its own bus section. If one source is lost, the associated coupler circuit-breaker is closed, one source feeds two bus sections and the other feeds one bus section. If a fault occurs on one bus section (or if maintenance is carried out on it), only one part of the outgoing feeders is no longer fed.
2 busbars, 2 connections per outgoing feeder, 2 supply sources (see Figure 1-14)
Operation: each outgoing feeder can be fed by one or other of the busbars, depending on the state of the isolators which are associated with it, and only one isolator per outgoing feeder must be closed.
For example, source 1 feeds busbar BB1 and feeders Out1 and Out2. Source 2 feeds busbar BB2 and feeders Out3 and Out4. The bus coupler circuit-breaker can be kept closed or open during normal operation. If one source is lost, the other source takes over the total power supply. If a fault occurs on a busbar (or maintenance is carried out on it), the coupler circuit-breaker is opened and the other busbar feeds all the outgoing feeders.

Network Structures

source source 1 1

source source 2 2

NC

NC

NC

NO

NO

NC
BB1

coupler
NC or NO

BB2
NO

NC NO

Out1

NC NC

NO NC

Out2

MV double busbar NO

Out4

Out3

MV feeders

Figure 1-14: 2 busbars, 2 connections per outgoing feeder, 2 supply sources

2 interconnected double busbars (see Figure 1-15) source source 1 1

source source 2 2

NC

NC

NC

NO

NO

NC

NC or NO

NC or NO
NC

NO NC

Out1

CB1
NC or NO
CB2
NO
NO

Out2

NC NO

Out3

NC

Out4

MV feeders

Figure 1-15: 2 interconnected double busbars

BB1
NC 2 MV double or bus switchboards
NO
BB2

23

24

Protection of Electrical Networks

Operation: this arrangement is almost identical to the previous one (two busbars, two connections per feeder, two supply sources). The splitting up of the double busbars into two switchboards with coupler (via CB1 and CB2) provides greater operating flexibility. Each busbar feeds a smaller number of feeders during normal operation. “Duplex” distribution system (see Figure 1-16) source source 1 1

source source 2 2

NC

NC
BB1

coupler
NC or NO

BB2
NC

NC

Out1

NC

Out2

NC

Out3

MV double busbar Out4

MV feeders

Figure 1-16: “duplex” distribution system

Operation: each source can feed one or other of the busbars via its two drawout circuit-breaker cubicles. For economic reasons, there is only one circuit-breaker for the two drawout cubicles, which are installed alongside one another. It is thus easy to move the circuit-breaker from one cubicle to the other. Thus, if source 1 is to feed busbar BB2, the circuit-breaker is moved into the other cubicle associated with source 1.
The same principle is used for the outgoing feeders. Thus, there are two drawout cubicles and only one circuit-breaker associated with each outgoing feeder. Each outgoing feeder can be fed by one or other of the busbars depending on where the circuit-breaker is positioned.
For example, source 1 feeds busbar BB1 and feeders Out1 and Out2. Source 2 feeds busbar BB2 and feeders Out3 and Out4. The bus coupler circuit-breaker can

Network Structures

25

be kept closed or open during normal operation. If one source is lost, the other source provides the total power supply. If maintenance is carried out on one of the busbars, the coupler circuit-breaker is opened and each circuit-breaker is placed on the busbar in service, so that all the outgoing feeders are fed. If a fault occurs on a busbar, it is put out of service.
1.5.2. MV network structures
We shall now look at the main MV network structures used to feed secondary switchboards and MV/LV transformers. The complexity of the structures differs, depending on the level of power supply security required.
The following MV network supply arrangements are the ones most commonly adopted. Single fed radial network (see Figure 1-17) source 1
NC

source 2
NC

NC or NO

main MV switchboard

switchboard1

switchboard2

MV

LV

MV

LV

Figure 1-17: MV single fed radial network

26

Protection of Electrical Networks

– The main switchboard is fed by 2 sources with coupler.
– Switchboards 1 and 2 are fed by a single source, and there is no emergency back-up supply.
– This structure should be used when service continuity is not a vital requirement and it is often adopted for cement works networks.
Dual fed radial network with no coupler (see Figure 1-18) source 1
NC

source 2
NC

NC or NO
NC

NO

main MV switchboard
NC

NC

switchboard1

MV

NC

NO

LV

switchboard2

MV

LV

MV

LV

Figure 1-18: MV dual fed radial network with no coupler

– The main switchboard is fed by two sources with coupler.
– Switchboards 1 and 2 are fed by two sources with no coupler, the one backing up the other.
– Service continuity is good; the fact that there is no source coupler for switchboards 1 and 2 means that the network is less flexible to use.

Network Structures

27

Dual fed radial network with coupler (see Figure 1-19) source 1
NC

source 2
NC

NC or NO
NC

NC

NC

NO

NO

main MV switchboard
NC

switchboard1

switchboard2

MV

LV

Figure 1-19: MV dual fed radial network with coupler

– The main switchboard is fed by two sources with coupler.
– Switchboards 1 and 2 are fed by 2 sources with coupler. During normal operation, the bus coupler circuit-breakers are open.
– Each bus section can be backed up and fed by one or other of the sources.
– This structure should be used when good service continuity is required and it is often adopted in the iron and steel and petrochemical industries.
Loop system
This system should be used for widespread networks with large future extensions. There are two types depending on whether the loop is open or closed during normal operation.

28

Protection of Electrical Networks

Open loop (see Figure 1-20a) source 1

NC

source 2

NC
NC or NO
A

NC

B

NC NC

NO NC

switchboard switchboard1 1

MV

LV

main MV switchboard

NC

switchboard switchboard2 2

MV

LV

switchboard switchboard3 3

MV

LV

Figure 1-20a: MV open loop system

– The main switchboard is fed by two sources with coupler.
– The loop heads in A and B are fitted with circuit-breakers.
– Switchboards 1, 2 and 3 are fitted with switches.
– During normal operation, the loop is open (in the figure it is normally open at switchboard 2).
– The switchboards can be fed by one or other of the sources.
– Reconfiguration of the loop enables the supply to be restored upon occurrence of a fault or loss of a source (see section 10.1.7.1).
– This reconfiguration causes a power cut of several seconds if an automatic loop reconfiguration control has been installed. The cut lasts for at least several minutes or dozens of minutes if the loop reconfiguration is carried out manually by operators. Network Structures

29

Closed loop (see Figure 1-20b) source 1
NC

source 2
NC

NC ou NO
NC or NO

NC

NC NC

NC NC

switchboard switchboard1 1

MV

LV

main MV switchboard

NC

switchboard switchboard22 MV

switchboard 3 switchboard3 MV

LV

LV

Figure 1-20b: MV closed loop system

– The main switchboard is fed by two sources with coupler.
– All the loop switching devices are circuit-breakers.
– During normal operation, the loop is closed.
– The protection system ensures against power cuts caused by a fault
(see section 10.1.8).
This system is more efficient than the open loop system because it avoids power cuts. However, it is more costly since it requires circuit-breakers in each switchboard and a complex protection system.

30

Protection of Electrical Networks

Parallel feeder (see Figure 1-21)

source 1
NC

source 2
NC

NC or NO
NC

main MV switchboard

NC

NC

switchboard1 switchboard 1
MV

LV

NO
NC
switchboard switchboard22 MV

LV

NO
NO

switchboard33 switchboard MV

LV

NC

Figure 1-21: MV parallel feeder network

– Switchboards 1, 2 and 3 can be backed up and fed by one or other of the sources independently.
– The main switchboard is fed by two sources with coupler.
– This structure should be used for widespread networks with limited future extensions and that require good supply continuity.

Network Structures

31

1.6. LV networks inside the site
We shall first of all study the different low voltage switchboard supply modes.
Next, we shall look at the supply schemes for switchboards backed up by generators or an uninterruptible power supply.
1.6.1. LV switchboard supply modes
We are now going to study the main supply arrangements for an LV switchboard, regardless of its place in the network. The number of supply sources possible and the complexity of the switchboard differ according to the level of supply security required.
Single fed LV switchboards (see Figure 1-22) supply source
MV

LV
S1

S2

S3

Figure 1-22: single fed LV switchboards

Switchboards S1, S2 and S3 have only one supply source. The network is said to be of the arborescent radial type. If a switchboard supply source is lost, the switchboard is put out of service until the supply is restored.

32

Protection of Electrical Networks

Dual fed LV switchboards with no coupler (see Figure 1-23) source 1

source 2

MV

MV

LV

LV

CB1

source 3 3 source CB2
NC

NO

S1

MV

LV
CB3

CB4
NC

NO
S2

Figure 1-23: dual fed LV switchboards with no coupler

Switchboard S1 has a dual power supply with no coupler via two MV/LV transformers. Operation of the S1 power supply:
– one source feeds switchboard S1 and the second provides a back-up supply;
– during normal operation only one circuit-breaker is closed (CB1 or CB2).
Switchboard S2 has a dual power supply with no coupler via an MV/LV transformer and outgoing feeder coming from another LV switchboard.
Operation of the S2 power supply:
– one source feeds switchboard S2 and the second provides a back-up supply;
– during normal operation only one circuit-breaker is closed (CB3 or CB4).

Network Structures

33

Dual fed LV switchboards with coupler (see Figure 1-24) source 1

source 2

MV

MV

LV

LV

CB1
S1

NC

source 3 3 source CB2

NC
NO

MV
CB3

NC
LV
CB4

NC

S2

NC

CB5

NO
CB6

Figure 1-24: dual fed LV switchboards with coupler

Switchboard S1 has a dual power supply with coupler via two MV/LV transformers. Operation of the S1 power supply:
– during normal operation, the coupler circuit-breaker CB3 is open;
– each transformer feeds a part of S1;
– if a supply source is lost, the circuit-breaker CB3 is closed and a single transformer feeds all of S1.
Switchboard S2 has a dual power supply with coupler via an MV/LV transformer and an outgoing feeder coming from another LV switchboard.
Operation of the S2 power supply:
– during normal operation, the circuit-breaker CB6 is open;
– each source feeds part of S2;
– if a source is lost, the coupler circuit-breaker is closed and a single source feeds all of S2.

34

Protection of Electrical Networks

Triple fed LV switchboards with no coupler (see Figure 1-25) source 1

source 2
MV

LV

NC

NO

MV

LV

NC

source 3

NC
S1

Figure 1-25: triple fed LV switchboards with no coupler

Switchboard S1 has a triple power supply with no coupler via two MV/LV transformers and an outgoing feeder coming from another LV switchboard.
During normal operation, the switchboard is fed by two transformers in parallel.
If one or both of the transformers fail, switchboard S1 is fed by the outgoing feeder coming from another switchboard.
Triple fed switchboards with coupler (see Figure 1-26) source 1

source 2
MV

NC

MV

LV

NC

source 3

LV

NC

NC

NO

NO

CB1

CB2

S1

Figure 1-26: triple fed LV switchboards with coupler

Switchboard S1 has a triple power supply with couplers via two MV/LV transformers and an outgoing feeder coming from another LV switchboard.

Network Structures

35

During normal operation, the two coupler circuit-breakers are open and switchboard S1 is fed by three supply sources. If one source fails, the coupler circuit-breaker of the associated source is closed and the incoming circuit-breaker of the source that has been lost is opened.
1.6.2. LV switchboards backed up by generators
Example 1: 1 transformer and 1 generator (see Figure 1-27) source 1
MV

G

LV
NC

S1
CB1

NC

NO

CB2
S2

mains/standby

non-priority circuits non priority circuits

priority circuits

Figure 1-27: 1 transformer and 1 generator

During normal operation CB1 is closed and CB2 is open. Switchboard S2 is fed by the transformer. If the main source is lost, the following steps are carried out:
1. The mains/standby changeover switch is operated and CB1 is tripped.
2. Load shedding, if necessary, of part of the loads on the priority circuit in order to facilitate start-up of the generator.
3. Start-up of the generator.
4. CB2 is closed when the frequency and voltage of the generator are within the required ranges.
5. Reloading of loads which may have been shed during step 2.
Once the main source has been restored, the generator is stopped and the mains/standby changeover device switches the S2 supply to the mains.

36

Protection of Electrical Networks

Example 2: 2 transformers and 2 generators (see Figure 1-28) source 1

source 2

MV

MV

TR1

TR2

LV
CB4

NC

NC

LV
CB5

G

G

S2

S3

NO
CB1

NC

NO
CB2 mains / standby CB3 mains/standby S1

non-priority circuits

non priority circuits

priority circuit priority circuits

Figure 1-28: 2 transformers and 2 generators

During normal operation, the coupler circuit-breaker CB1 is open and the mains/standby changeover device is in position CB2 closed and CB3 open.
Switchboard S1 is fed by transformer TR2.
If source 2 is lost or there is a breakdown on TR2, the S1 (and part of S2) standby supply is given priority by transformer TR1, after reclosing of the coupler circuit-breaker CB1. The generators are only started up after the loss of the two main supply sources. The steps for saving the priority circuit supply are carried out in the same way as in example 1.
1.6.3. LV switchboards backed up by an uninterruptible power supply (UPS)
The main devices that make up a UPS system are shown in Figure 1-29 and
Table 1-1.

network 1

supply network incoming feeders

network 2
(8) switch

NC

~

NO

_

_
~

NC

Figure 1-29: UPS system

(2) battery

(10) battery circuit-breaker

(3) inverter (9) switch

(4) static contactor

(7) switch
(1) rectifieror charger circuit-breaker

NC

(6) insulating transformer (5) manual by-pass

load
Network Structures
37

38

Protection of Electrical Networks
Device
name

Ref. no Function

Rectifiercharger

(1)

Transforms the alternating voltage of a supply network into a direct voltage which will:
– feed the inverter;
– continually provide the charge for the storage battery.

Storage battery (2)

Provides a back-up supply to feed the inverter in case:
– the supply network disappears (power cut);
– the supply network is disturbed
(disturbances leading to insufficient quality).

Inverter

(3)

Transforms the direct voltage from the rectifier-charger or storage battery into three-phase alternating voltage with more severe tolerances than those of the network (supplies an alternating current close to the theoretical sine curve).

Static contactor (4)

Switches over the load supply from the inverter to network 2
(standby) without interruption (no cut due to mechanical switching device changeover time – the switchover is carried out using electronic components in a time < 1 ms).
This switchover is performed if the inverter stops working for one of the following reasons:
– switched off;
– overload beyond the limiting capacities of the inverter;
– internal anomaly.

Manual by-pass (5)

Manual switch which allows the user to be fed by network 2
(standby), while maintenance is being carried out.
Its presence is indispensable when the network frequencies upstream and downstream of the UPS are identical.

Insulating transformer (6)

Provides upstream and downstream insulation when the supply is via network 2.
It is especially used when the upstream and downstream earthing systems are different.

Manual switches Battery circuitbreakers (7)
(8)

Provides insulation of the different parts when maintenance is being carried out.

(9)
(10)

Table 1-1: function of different devices making up a UPS system

Network Structures

39

Network incoming feeder(s)
The terms network 1 and network 2 designate two independent incoming feeders on the same network:
– network 1 (or mains) designates the incoming feeder usually supplying the rectifier-charger; – network 2 (or standby) is said to be a back-up feeder.
The inverter’s frequency is synchronized with network 2, thereby allowing the load to be instantaneously fed by network 1 (in a time < 1 ms) via the static contactor. The connection of a UPS system to a second independent network is recommended since it increases the reliability of the system. It is nevertheless possible to have only one common incoming feeder.
Example 1: LV switchboard backed up by an inverter, with a generator to eliminate the problem of the limited autonomy of the battery (usually about
15 mn) (see Figure 1-30) source MV

G
LV
NO

NC

NC filter non priority circuits non-priority circuits

~

_
_

~

priority circuits

NC

Figure 1-30: LV switchboard backed up by an inverter

The filter allows harmonic currents traveling up the supply network to be reduced. 40

Protection of Electrical Networks

Example 2: LV switchboard backed up by 2 inverters in parallel with no redundancy (see Figure 1-31)

source
MV

G
LV
NC

NO

NC

NC

network 2

network 1 non priority circuits non-priority circuits

filter

filter

~

~

P
2

_
_

~

P
2

_
_

P

~

priority circuits Figure 1-31: LV switchboard backed up by 2 inverters in parallel with no redundancy

This configuration only allows an overall power capacity above that of a single rectifier/inverter unit. The power P to be supplied is also divided between the two inverters. A fault in one of the units leads to the load being switched to network 2 without interruption, except when the network is beyond its tolerance level.

Network Structures

41

Example 3: LV switchboard backed up by 3 inverters, one of which is actively redundant (see Figure 1-32)

source

MV

G
LV
NC

NO

NC

non priority circuits non-priority circuits

NC

filter

filter

filter

~

~

~

P
2

_
_

~

P
2

_
_

~

P
2

_
_

P

~

priority circuits Figure 1-32: LV switchboard backed up by 3 inverters, one of which is actively redundant

Let P be the maximum load rating of the priority circuit. Each inverter has a rated power of

P
, which means that when one inverter breaks down, the other two
2

inverters provide the total load power supply. This is referred to as a parallelconnected unit with 1/3 active redundancy.

42

Protection of Electrical Networks

Example 4: LV switchboard backed up by 3 inverters, one of which is on standby redundancy (see Figure 1-33) source MV

G
LV
NC

NO

NC

NC

non priority circuits non-priority circuits

1

_

~

_

3

~

network 2

network 1

~

3

_
_

1
2

~

~

2

_
_

priority circuits ~ priority circuits

Figure 1-33: LV switchboard backed up by 3 inverters, one of which is on standby redundancy

Inverter 3 is not charged; it is on standby ready to back up inverter 1 or 2 .
There is no power cut during switchover due to static contactors and . Static contactor provides back-up via network 2 in case there is a failure on network 1, or the two inverters break down. This is referred to as a parallel-connected unit with standby redundancy.
1.7. Industrial networks with internal generation
Example (see Figure 1-34)
Network structure:
– MV consumer substation;
– the main MV switchboard is fed by the internal generating station;
– some MV outgoing feeders are fed by the utility and cannot be backed up by the internal generating station;
– an MV loop system and some outgoing feeders are fed during normal operation by the internal generating station. If the generating station breaks down, this loop system and its outgoing feeders can be fed by the utility.

NC

incoming feeders from utility

NC

NC NC

LV
LV

MV

LV

MV

NC

LV

MV

NC

LV

MV

NC

low voltage generator sets

LV

MV

internal production station

MV

NC

Figure 1-34: industrial network with internal generation

LV

LV

NO

MV

NC

MV

NC

feeders with back up supply

NC

main MV switchboard

MV network in a loop system feeding 4 MV/LV substation

feeders without  back up supply

MV consumer substation

NC

Network Structures
43

set up transformer

44

Protection of Electrical Networks

1.8. Examples of standard networks
Example 1 (see Figure 1-35)
Network structure:
– MV consumer substation in a ring main system with two incoming feeders;
– main low voltage switchboard backed up by a generator;
– a priority switchboard fed by a UPS;
– the low voltage network is of the arborescent radial type, and the secondary switchboard and terminal boxes are fed by a single source.
MV consumer substation

MV incoming feeders from utility

LV
G

m

LV meter

main LV switchboard

UPS priority switchboard

secondary LV switchboard terminal box

terminal box

Figure 1-35: example 1

Network Structures

45

Example 2 (see Figure 1-36)
Network structure:
– MV consumer substation;
– the main MV switchboard can be backed up by a generator set and feeds three transformers; – the main low voltage switchboards MLVS1, MLVS2 and MLVS3 are independent and each one has an outgoing feeder to an uninterruptible power supply feeding a priority circuit;
– the low voltage network is of the arborescent radial type, and the motor control centers and terminal boxes are fed by a single source.
Example 3 (see Figure 1-37)
Network structure:
– MV consumer substation;
– the main MV switchboard can be backed up by a generator set and it feeds two
MV/LV transformers;
– the main low voltage switchboard has a dual power supply with coupler;
– each bus section of the main low voltage switchboard has a UPS system feeding a priority circuit;
– the secondary switchboards, terminal boxes and motor control centers are fed by a single source.
Example 4 (see Figure 1-38)
Network structure:
– MV consumer substation;
– the main MV switchboard can be backed up by a generator set. It feeds two
MV/LV transformers in a single line supply system, four MV secondary switchboards in a loop system, and a secondary MV switchboard in a single line supply system;
– the low voltage network is of the arborescent radial type.

motor control center

incoming feeders from utility terminal box UPS

MLVS 1

LV

MV

motor control center

Figure 1-36: example 2

terminal box UPS

MLVS 2

LV

MV

main MV switchboard

terminal box UPS

MLVS 3

LV

MV
LV

MV

3 generators

LV

MV

motor control center

LV

MV

46
Protection of Electrical Networks

Network Structures

47

main MV switchboard

MV

MV

LV

MV

MV

LV

MV

incoming feeders from utility
LV

LV

G

G

2 generators

main LV switchboard

UPS

UPS

terminal box terminal box M

terminal box M

M

M

motor control center M

M

M

motor control
M center

terminal box Figure 1-37: example 3: dual fed switchboard with 2/3 type transfer

incoming feeders from utility
LV

MV

LV

MV

LV

MV

LV

MV

LV

MV

Figure 1-38: example 4

LV

MV

LV

MV

LV

MV

secondary MV switchboard

MV network in loop system

main MV switchboard

LV

MV

LV

MV

LV

MV

G

LV

MV

LV

MV

G

LV

MV

3 generators

G

LV

MV

48
Protection of Electrical Networks

Network Structures

49

Example 5 (see Figure 1-39)
Network structure:
– MV consumer substation;
– two MV ratings: 20 kV and 6 kV;
– the main MV switchboard fed at 20 kV can be backed up by a set of four generators. It feeds:
- an MV 20 kV network in a loop system comprising three secondary switchboards MV4, MV5 and MV6;
- two 20 kV/6kV transformers in a single line supply system;
– the MV main switchboard is made up two bus sections fed at 6 kV by two sources with coupler;
– it feeds three MV secondary switchboards and two 6 kV/LV transformers in a single line supply system;
– the secondary switchboard MV2 is fed by two sources with coupler and is made up of two bus sections. It feeds two 6 kV motors and two 6 kV/LV transformers in a single line supply system;
– the secondary switchboards MV1 and MV3 are fed by a single source. Each feeds a 6 kV/LV transformer and a 6 kV motor;
– the main low voltage switchboard MLVS1 can be backed up by a generator;
– the main low voltage switchboard MLVS2 is fed by two sources with coupler;
– the main low voltage switchboard MLVS3 is fed by a single source;
– the motor control centers 1 and 3 are fed by a single source;
– the motor control center 2 is fed by 2 sources with no coupler.
Example 6 (see Figure 1-40)
Network structure:
– HV consumer substation fed at 90 kV by two HV sources with no coupler
(isolators ISO1 and ISO2 cannot operate when loaded and are in closed position during normal operation);
– the central HV/MV transformer is used as back-up. The transformers can be connected on the MV side via the circuit-breakers (moreover, the on-load tap changers allow the currents supplied by each transformer to be balanced);
– the network has two MV ratings: 20 kV and 6 kV;
– the main MV switchboard is fed at 20 kV by three sources with coupler. It is made up of three bus sections;
– the secondary switchboards MV1, MV2 and MV3 are fed at 6 kV by two sources (transformers) with coupler coming from two different busbars;

50

Protection of Electrical Networks

– the main low voltage switchboards MLVS1, MLVS2, MLVS3 and MLVS4 are fed by two sources with coupler;
– the motor control centers 1, 2, 3 and 4 are fed by two sources with no coupler. sc.40 main MV switchboard: U = 20 kV

CT
CT

MV

MV

MV

MV

MV

MV

MV

MV

LV

LV

LV

LV

VT

main MV switchboard: U = 6 kV

incom ing fe eders from utility

G
MV

LV

LV

G

G

MV
4 generators

M LV S B

M LV S A

secondary M V 1 sw itchboard

MV

MV

M
G

M
LV

UPS

LV
M LVS3

m otor control center 2

M

M

LV
M LV S 2

M LV S 1

m otor control center 1

MV

MV

M
LV

secondary M V 3 sw itchboard

secondary M V 2 sw itchboard

M

m otor control center 3
M

UPS

M

M

M

M V network in a loop system: U = 20 kV secondary M V 4 sw itchboard

seconda ry M V 5 sw itchboard

secondary M V 6 sw itchboard

MV

MV

MV

MV

MV

LV

LV

LV

LV

MV

LV

Figure 1-39: example 5

LV

G

M

motor center control 1

U = 6 kV

MV

MV

MV

M

M

LV
LV
MLVS1

MV

secondary
MV1
switchboard

M

MV

MV

M

MV

MV

motor center control 2

HV consumer substation iso.1 LV

MV

M

M

MV

MV

motor center control 3

M

LV

M

M

MLVS3

LV

MV MV

secondary
MV3
switchboard

HV

Source 2

MV

MV

iso.2

Figure 1-40: example 6

M

MLVS2

LV

MV

secondary
MV2
switchboard

MV

MV

MV

HV

HV

Source 1

M

MV

MV

motor center control 4

M

MV

MV

LV

M

M

MLVS4

LV

MV MV

secondary
MV4
switchboard

main MV switchboard:
U = 20 kV

HV busbar: U = 90 kv

M

MV

MV

Network Structures
51

Chapter 2

Earthing Systems

In any medium or low voltage three-phase system there are three single voltages measured between each phase and a common point called the “neutral point”.
In actual fact, the neutral is the common point of three star-connected windings
(see Figure 2-1).
Ph 3

neutral point

Ph 1

Ph 2
Figure 2-1: neutral point of a three-phase star system

The neutral may or may not be accessible or distributed. Except in specific cases
(e.g. networks in North America and Australia), the neutral is not distributed at medium voltage. However, the neutral is very often distributed at low voltage.
In a medium or low voltage installation, the neutral may or may not be earthed.
This is why we talk about the earthing system.

54

Protection of Electrical Networks

The neutral may be directly connected to earth or connected through a resistor or a reactor. In the first case, we say that the neutral is directly earthed and in the second case we say that it is impedance-earthed.
When a connection has not been made between the neutral point and earth, we say that the neutral is unearthed.
In a network, the earthing system plays a very important role. When an insulation fault occurs or a phase is accidentally earthed, the values taken by the fault currents, the touch voltages and overvoltages are closely linked to the type of neutral earthing connection.
A directly earthed neutral strongly limits overvoltages but it causes very high fault currents, whereas an unearthed neutral limits fault currents to very low values but encourages the occurrence of high overvoltages.
In any installation, service continuity in the event of an insulation fault is also directly related to the earthing system. An unearthed neutral permits service continuity during an insulation fault. Contrary to this, a directly earthed neutral, or low impedance-earthed neutral, causes tripping as soon as the first insulation fault occurs. The extent of the damage to some equipment, such as motors and generators presenting an internal insulation fault, also depends on the earthing system.
In an earthed network, a machine affected by an insulation fault suffers extensive damage due to the large fault currents.
However, in an unearthed or high impedance-earthed network, the damage is reduced, but the equipment must have an insulation level compatible with the level of overvoltages able to cope in this type of network.
The choice of earthing system in both low voltage and medium voltage networks depends on the type of installation as well as the type of network. It is also influenced by the type of loads and service continuity required.
2.1. Earthing systems at low voltage
We shall first of all define the different low voltage earthing systems and then compare the advantages and disadvantages of each one.

Earthing Systems

55

2.1.1. Different earthing systems – definition and arrangements
Earthing systems are governed by standard IEC 60364-3. There are three types of systems: IT, TT and TN.
The first letter defines the neutral point in relation to earth:
T
directly earthed neutral
I
unearthed or high impedance-earthed neutral (e.g. 2,000 Ω)
The second letter defines the exposed conductive parts of the electrical installation in relation to earth:
T
directly earthed exposed conductive parts
N exposed conductive parts directly connected to the neutral conductor
IT system unearthed or impedance-earthed neutral (see Figure 2-2)
Letter I
The neutral is unearthed or connected to earth by a high impedance (an impedance of 1,700 Ω is often used).
Letter T
The exposed conductive parts of the loads are interconnected and earthed.
A group of loads can be individually earthed if it is situated far away from the other loads.
Ph 3
Ph 2
Ph 1
PE

Ps

ZN

load

RN

load

RM

Z N : neutral earthing impedance
Ps : overvoltage limiter
Figure 2-2: unearthed or impedance-earthed neutral
(IT system) in low voltage system

56

Protection of Electrical Networks

Specific characteristics:
– Switching upon occurrence of a double fault is usually generated by phase-tophase fault protective devices (circuit-breakers, fuses, etc.).
– If the short-circuit current is not large enough to activate protection against phase-to-phase faults, notably if the loads are far away, protection should be ensured by residual current devices (RCDs).
– It is not advisable to distribute the neutral (see section 4.4.1.3).
– It is compulsory to install an overvoltage limiter between the MV/LV transformer neutral point and earth. If the neutral is not accessible, the overvoltage limiter is installed between a phase and earth. It runs off external overvoltages, transmitted by the transformer, to the earth and protects the low voltage network from a voltage increase due to flashover between the transformer’s medium voltage and low voltage windings.
– A group of individually earthed loads must be protected by an RCD.
TT system directly earthed neutral (see Figure 2-3)
First letter T
The neutral is directly earthed.
Second letter T
The exposed conductive parts of the loads are interconnected either altogether or by a group of loads. Each interconnected group is earthed. One exposed conductive part can be individually earthed if it is far away from the others.

Ph 3
Ph 2
Ph 1
N
load

load
PE

RN
RM

Figure 2-3: directly earthed neutral (TT system) in low voltage

Earthing Systems

57

Specific characteristics:
– The installation of RCDs is compulsory.
– All exposed conductive parts protected by the same protective device should be connected to the same earth.
– The neutral earth and the exposed conductive part earth may or may not be interconnected or combined.
– The neutral may or may not be distributed.
TN system neutral-connected exposed conductive part
Letter T
The neutral is directly earthed.
Letter N
The exposed conductive parts of the loads are connected to the neutral conductor.
There are two types of systems, possibly depending on whether the neutral conductor and protective conductor (PE) are combined or not:
– Case 1: The neutral and protective conductors are combined in a single conductor called PEN. The system is identified by a third letter C and is called TNC
(see Figure 2-4). Earthing connections must be evenly placed along the length of the
PEN conductor to avoid potential rises in the exposed conductive parts if a fault occurs. This system must not be used for copper cross-sections of less than 10 mm² and aluminium cross-sections of less than 16 mm², as well as downstream of a TNS system (see IEC 60364-5, section 546-2). Nor must it be used for moveable trunkings (see IEC 60364-4, section 413.1.3.2).
– Case 2: The neutral conductor and protective conductor are separate. The system is identified by a third letter S and is called TNS (see Figure 2-5). Earthing connections must be evenly placed along the length of the protection conductor PE to avoid potential rises in the exposed conductive parts if a fault occurs. This system must not be used upstream of a TNC system.
Ph 3
Ph 2
Ph 1
PEN

N load RN

Figure 2-4: TNC system

load

58

Protection of Electrical Networks
Ph 3
Ph 2
Ph 1
N
PE load load

RN

Figure 2-5: TNS system

Specific characteristics of TNS and TNC systems:
– Fault switching is obtained by devices providing protection against phase-tophase faults (circuit-breakers, fuses, etc.).
Note: both TNS and TNC systems can be used in the same installation. The TNC system (4 wires), however, must never be downstream of the TNS system (5 wires).
2.1.2. Comparison of different earthing systems in low voltage
The three earthing systems are different in the way they operate and afford protection. Each has its advantages and disadvantages which we shall now consider.
2.1.2.1. Unearthed or impedance-earthed neutral (IT system) (see Figure 2-2)
Operating technique:
– Permanent insulation monitoring.
– First insulation fault indication.
– Compulsory fault location and clearance.
– Switching if two insulation faults occur at the same time (double fault).
Technique for protecting persons:
– Interconnection and earthing of exposed conductive parts.
– First fault monitoring by a permanent insulation monitor (see section 2.4.1).
– Switching upon occurrence of the second fault by overcurrent protective devices (circuit-breakers or fuses).
Advantages:
– System providing the best service continuity during use.
– When an insulation fault occurs, the short-circuit current is very low.

Earthing Systems

59

Disadvantages:
– Requires maintenance personnel to monitor the system during use.
– Requires a good level of network insulation (which means that the network must be broken up if widespread, and that loads with high leakage current must be supplied by insulating transformers).
– Tripping checks for two simultaneous faults should be carried out if possible when the network is being designed using calculation, and must be performed during commissioning using measurement.
– Overvoltage limiters must be installed.
– Requires all the installation’s exposed conductive parts to be equipotentially bonded; if this is not possible RCDs must be installed.
– Avoid distributing the neutral conductor. In the IT system, it is in fact recommended not to distribute the neutral for the following reasons:
- if the neutral conductor is distributed, a fault affecting it will eliminate the advantages attached to the IT system;
- if the neutral is distributed, it must be protected (except for specific cases);
- the fact of not distributing the neutral facilitates the choice of overcurrent protective devices (see section 4.4.1.3) and fault location.
– Locating faults is difficult in widespread networks.
– When an insulation fault in relation to the earth occurs, the voltage of the two unaffected phases in relation to the earth takes on the value of the phase-to-phase voltage (see section 7.16). Equipment must therefore be selected with this in mind.
2.1.2.2. Directly earthed neutral (TT system)
Operating technique:
– Switching upon occurrence of the first insulation fault.
Technique for protecting persons:
– Earthing of exposed conductive parts combined with the compulsory use of
RCDs (at least one at the head of the installation).
– All exposed conductive parts protected by the same RCD must be connected to the same earth.
– Simultaneously accessible exposed conductive parts must be connected to the same earth.
Advantages:
– The simplest system to design, implement, monitor and use.

60

Protection of Electrical Networks

– Does not require permanent monitoring during use (only a periodic inspection test of the RCDs may be necessary).
– Moreover, the presence of RCDs prevents the risk of fire when their sensitivity is below or equal to 500 mA (see standard IEC 60364-4, section 482.2.10).
– Easy location of faults.
– Upon occurrence of an insulation fault, the short-circuit current is small.
Disadvantages:
– Switching upon occurrence of the first insulation fault.
– Use of an RCD on each outgoing feeder to obtain total selectivity.
– Special measures must be taken for the loads or parts of the installation causing high leakage currents during normal operation in order to avoid spurious tripping (feed the loads by insulating transformers or use high threshold RCDs, compatible with the exposed conductive part earth resistance).
2.1.2.3. Connecting the exposed conductive parts to the neutral (TNC – TNS systems)
Operating technique:
– Switching upon occurrence of the first insulation fault.
Technique for protecting persons:
– Imperative interconnection and earthing of exposed conductive parts.
– Switching on occurrence of the first fault via an overcurrent protective device
(circuit-breaker or fuse).
Advantages:
– The TNC system may be less costly upon installation (elimination of one switchgear pole and one conductor).
– Use of overcurrent protective devices to ensure protection against indirect contact. Disadvantages:
– Switching on occurrence of the first insulation fault.
– The TNC system involves the use of fixed and rigid trunkings (see section
413.1.3.2 of standard IEC 60364-4).
– Requires earthing connections to be evenly placed in the installation so that the protective conductor remains at the same potential as the earth.
– A tripping check on occurrence of the insulation fault should be carried out, if possible, when the network is being designed using calculations, and must be performed during commissioning using measurements; this check is the only

Earthing Systems

61

guarantee that the system operates both on commissioning and during operation, as well as after any kind of work on the network (modification, extension).
– Passage of the protective conductor in the same trunkings as the live conductors of the corresponding circuits.
– Often requires extra equipotential bonding.
– Third and multiples of third harmonics circulate in the protective conductor
(TNC system).
– The fire risk is higher and, moreover, it cannot be used in places presenting a fire risk (TNC system).
– Upon occurrence of an insulation fault, the short-circuit current is high and may cause damage to equipment or electromagnetic disturbance.
2.2. Medium voltage earthing systems
We shall first define the different medium voltage earthing systems and then compare the advantages and disadvantages of each one.
2.2.1. Different earthing systems – definitions and arrangements
Earthing systems in medium voltage (see Table 2-1) can be differentiated according to the neutral point connection method.
Directly earthed neutral

(a)

Ph 1
Ph 2

An electrical connection is made between the neutral point and earth.

Ph 3 neutral Unearthed neutral
There is no electrical connection between the neutral point and earth, except for measuring or protective devices. High impedance earthing
A high impedance is inserted between the neutral point and earth.

(b)

Ph 1
Ph 2

Ph 3 neutral ZN

62

Protection of Electrical Networks

Resistance earthing

(c)

Ph 1
Ph 2

A resistor is inserted between the neutral point and earth.

Ph 3 neutral rN

Reactance earthing

(d)

Ph 1
Ph 2

A reactor is inserted between the neutral point and earth.

Ph 3 neutral L

Petersen coil earthing
A reactor L tuned to the network capacities is inserted between the neutral point and earth so that if an earth fault occurs, the fault current is zero. Ph 1
Ph 2

(e)

Ph 3

neutral

If

C C C

L

IL

IC

I f = I L + IC
I f : fault current

I L : current in the neutral earthing

reactor

I C : current in the phase-earth capacitances Table 2-1: neutral point connection methods

Earthing Systems

63

2.2.2. Comparison of different medium voltage earthing systems
The various earthing systems in medium voltage systems are different in the way they operate and each has its advantages and disadvantages, which we shall now consider. 2.2.2.1. Direct earthing (see Table 2-1(a))
Operating technique:
– Compulsory switching on occurrence of the first insulation fault.
Advantages:
– Reduces the risk of overvoltages occurring.
– Authorizes the use of equipment with a normal phase to earth insulating level.
Disadvantages:
– Compulsory tripping upon occurrence of the first fault.
– Very high fault currents leading to maximum damage and disturbance
(creation of induced currents in telecommunication networks (see section 5.7) and auxiliary circuits).
– The risk for personnel is high while the fault lasts; the touch voltages which develop being high.
– Requires the use of differential protection devices (see section 7.6) so that the fault clearance time is not long. These systems are costly.
2.2.2.2. Unearthed (see Table 2-1(b))
Operating technique:
– No switching on occurrence of the first insulation fault – it is thus compulsory:
- to carry out permanent insulation monitoring;
- to indicate the first insulation fault;
- to locate and clear the first insulation fault;
- to switch upon occurrence of the second insulation fault (double fault).
Advantages:
– Provides continuity of service by only tripping upon occurrence of the second fault, subject to the network capacity not leading to a high earth fault current that would be dangerous for personnel and loads on occurrence of the first fault.

64

Protection of Electrical Networks

Disadvantages:
– The unearthed neutral involves:
- the use of equipment whose phase-to-earth insulation level is at least equal to that of the phase-to-phase level; indeed, when a permanent phase-earth fault occurs, the voltage of both unaffected phases in relation to earth takes on the value of the phase-to-phase voltage if tripping is not triggered on occurrence of the first fault
(see section 7.16); cables, rotating machines, transformers and loads must therefore be chosen with this in mind;
- the risk of high internal overvoltages making it advisable to reinforce the equipment insulation;
- the compulsory insulation monitoring, with visual and audible indication of the first fault if tripping is not triggered until the second fault occurs;
- the presence of maintenance personnel to monitor and locate the first fault during use;
- some difficulties implementing selective protection devices upon occurrence of the first fault (see section 7.4.3, directional earth fault protection);
- the risk of ferro-resonance.
2.2.2.3. Limiting resistance earthing (see Table 2-1(c))
Operating technique:
– Switching upon occurrence of the first fault.
Advantages:
– Limits fault currents (reduced damage and disturbance).
– Dampens overvoltages of internal origin in that the limiting current I is twice as high as the capacitive current I C giving I > 2 I C .
– Does not require the use of equipment, and in particular cables, having a special phase/earth insulation level.
– Allows the use of simple selective protection devices.
Disadvantages:
– Tripping on the first fault.
2.2.2.4. Limiting reactance earthing (see Table 2-1(d))
Operating technique:
– Switching upon occurrence of the first insulation fault.

Earthing Systems

65

Advantages:
– Limits the fault currents (reduced damage and disturbance).
– Allows the implementation of simple selective protection devices if I L >> I C .
– The coil, being of low resistance, does not have to dissipate a high heat load.
Disadvantages:
– May cause high overvoltages during earth fault clearance.
– Compulsory tripping upon occurrence of the first fault.
2.2.2.5. Petersen coil earthing (see Table 2-1(e))
Operating technique:
– No switching upon occurrence of the first fault.
Advantages:
– If the reactance is such that 3 L0 C0 ω2 = 1 is respected, the phase-earth fault current is zero:
- spontaneous clearance of non-permanent earth faults;
- the installation continues to operate in spite of there being a permanent fault, with tripping necessarily occurring on the second fault;
- the first fault is indicated by the detection of the current flowing through the coil. The coil is dimensioned so that permanent operation is possible.
Disadvantages:
– Difficulties establishing the condition 3 L0 C0 ω2 = 1 due to uncertain knowledge of the network’s capacity: the result is that throughout the duration of the fault, a residual current circulates in the fault. Care must be taken to make sure this current is not dangerous for personnel and equipment.
– The risk of overvoltages occurring is high.
– Requires the presence of monitoring personnel.
– Impossible to provide selective protection upon occurrence of the first fault if the coil has been tuned to 3 L0 C0 ω2 = 1 ; if it is systematically out of tune

(3 L0 C0 ω2 ≠ 1) selective protection upon occurrence of the first fault is complex

and costly (see section 7.5, directional earth fault protection for compensated neutral systems). – Risk of ferro-resonance.

66

Protection of Electrical Networks

2.3. Creating neutral earthing
2.3.1. MV installation resistance earthing
Earthing when the neutral is accessible
A resistor is inserted between the neutral outlet terminal and the earthing connection, either directly (see Figure 2-6(a)), or via a single-phase transformer connected to the secondary via an equivalent resistor (see Figure 2-6(b)). This system is applied when the network is fed by a transformer with a star-connected secondary and an accessible neutral, or by a generator with an accessible neutral.

R

(a) direct connection

r

(b) connection via single-phase transformer Figure 2-6: earthing when the neutral is accessible

Earthing by creating an artificial neutral
When the source neutral is not accessible (delta winding), the system is earthed by creating an artificial neutral (also referred to as an earthing transformer).
The artificial neutral can also be used when there are several parallel sources.
The earthing transformer can be made in various ways:
– using a star-delta transformer, the limiting resistor is connected between the primary neutral point and earth, the delta being closed in on itself (see Figure
2-7(a));
– sing a star-delta transformer whose primary neutral point is directly earthed, a fault current limiting resistor is inserted in the secondary delta (see Figure 2-7(b)).
This system is economically preferable in case (a) since the resistor is in LV and not in MV;
– using a zig-zag coil, the limiting resistor being connected between the neutral point of the coil and earth (see Figure 2-7(c));

Earthing Systems

67

– using a neutral point transformer, this type of earthing transformer includes an extra winding which creates a power outlet: for example, a primary star winding with earthed neutral, a secondary delta winding closed by a fault current limiting resistor and another secondary star winding allowing the loads as well as the auxiliaries of an HV/MV substation to be fed (see Figure 2-7(d)).
– the systems adopted the most often are (b) and (c).

R
R
(a) Use of a star-data
(c) Use of a transformer with zig-zag coil neutral earthing resistor (b) Use of a star-data
(d) Neutral point transformer with resistor transformer in the delta with compensation delta

A

B

C

Z

neutral

R

a
(c) Use of zig-zag coil

b

c

(d) Neutral point transformer with compensation delta

Figure 2-7: main methods for creating an artificial neutral point at medium voltage

68

Protection of Electrical Networks

Problem of resistance earthing when several transformers operate in parallel on one busbar
Case 1: Each transformer has a non-disconnectable earthing resistor.
The earth fault current varies according to the number of transformers in service
(see Figure 2-8a), which may pose difficulties for the motors or for setting the threshold of earth fault protection devices. Moreover, directional earth fault protection devices must be used (see section 7.4) to locate faults coming from connections linking the transformers to the busbars (see section 10.1.5.2).

Figure 2-8a: direct earthing of each neutral point

Case 2: Each transformer has a disconnectable earthing resistor.
A switching device makes it possible to have a single earthed neutral point whatever the number of transformers in service (see Figure 2-8b). The protective system is complex since it uses logical selectivity, taking into account the position of the switching devices and the state of the different earth fault protection devices.
This system is used very little.

R

R
L

R
L

L

L: control logic taking into account the network configuration
Figure 2-8b: earthing of each neutral point using a switching device

Earthing Systems

69

Case 3: No transformer has an earthing resistor.
An artificial neutral point is created on the main switchboard busbar (see
Figure 2-9). This method eliminates the problems of cases 1 and 2. Indeed, the fault current is constant, whatever the number of transformers in service; the protection devices to be implemented are simple since they do not require the use of directional or complex logic protection devices (see section 10.1.5.2).

main busbar

R

Figure 2-9: earthing transformer on main busbar

Note: the problem is identical when an internal generation set is made up of several generators.
Problem of resistance earthing when several transformers operate in parallel on two busbars
The two busbars may or may not be coupled depending on the operating mode.
It is therefore necessary to install an artificial neutral on each busbar. When the busbars are separate, the two neutral points are in service. When the two busbars are coupled, only one artificial neutral must be connected (see Figure 2-10) so that the fault current is not doubled. A control logic must then be installed to put one of the two artificial neutrals out of service when the coupler circuit-breaker is closed. This logic may be indispensable when some loads, especially motors, cannot withstand high fault currents.

70

Protection of Electrical Networks

G

TR1

G

TR2

busbar n° 1 coupler circuit-breaker

busbar n° 2

When the coupler circuit-breaker is closed,the couplerneutral points
When one of the circuit-breaker disappearsone of the neutral points is closed, disappears neutral point n° 1

neutral point n° 2

Figure 2-10: artificial neutral point switching

2.3.2. Reactance or Petersen coil earthing of an MV installation
The method of using an accessible neutral or creation of an artificial neutral is identical to that used for resistance earthing except that a reactor is used instead of a resistor (see Figures 2-6 and 2-7).
2.3.3. Direct earthing of an MV or LV installation
The neutral must be accessible and is directly earthed.
2.4. Specific installation characteristics in LV unearthed systems
As we saw in section 2.1.2.1, the LV unearthed system requires permanent insulation monitoring, first fault location and an overvoltage limiter. We shall now look at how this is done.

Earthing Systems

71

2.4.1. Installing a permanent insulation monitor (see Figure 2-11)
In an unearthed system, a device must permanently monitor the insulation level so that a fault does not last indefinitely. This is necessary to avoid any partial deterioration of equipment over the course of time and avoid tripping if a second insulation fault occurs (this would constitute a phase-to-phase fault). The first fault must be located and cleared by operating personnel.
The permanent insulation monitor ensures insulation monitoring.
It applies a direct voltage between the neutral and earth, or on a phase if the neutral is not accessible, which creates a leakage current in the insulation resistors whatever the cable capacities (with direct current, the capacitors have an infinite impedance). If an insulation fault occurs, a direct current flows through the monitor and causes an alarm to go off.
2.4.2. Installing an overvoltage limiter (see Figure 2-11)
The job of an overvoltage limiter is to run off to earth dangerous overvoltages that are likely to occur, such as a lightning impulse or flashover between the MV and LV windings of a transformer.
It is installed between the neutral and earth of a transformer or between a phase and earth if the neutral is not accessible.
Ph 1
Ph 2

Ph 3

overvoltage limiter permanent insulation monitor

Figure 2-11: installation of an overvoltage limiter and a permanent insulation monitor in an IT system

2.4.3. Location of earth faults by a low frequency generator (2–10 Hz)
This device allows earth faults to be located while energized (see Figure 2-12).

72

Protection of Electrical Networks

A low frequency generator between 2 and 10 Hz (1) injects a current between the network and the earth. When an insulation fault occurs on an outgoing feeder, a low frequency leakage current is run off to earth. This current can be detected:
– manually using a clip-on ammeter (2) connected to a selective amplifier (3) tuned to the generator frequency. Each feeder is thus tested until the amplifier detects a current.
– by Tore transformers (4) (see section 7.2) installed on each outgoing feeder.
These are connected to a selective switch (5) which determines the faulty feeder.
– The switch is connected to a selective amplifier (3) tuned to the generator frequency. Note: an injection of direct current cannot be used to locate an earth fault since a tore transformer or clip-on ammeter can only detect alternating current. The selective amplifier is generally able to discriminate between a resistive current due to an insulation fault and the capacitive current of a healthy feeder (if a fault occurs, the healthy feeders have a capacitive current proportional to the cable capacity
(see section 4.3)). If the selective amplifier cannot perform this task, the capacitive currents of some healthy feeders (the longer ones) are likely to be as great as the fault current, thereby making it difficult to locate the fault. The Vigilohm range from Schneider can perform this task and furthermore it is insensitive to harmonic disturbances. switch

~

4

5

4

4

1
3

LF

fixed system selective amplifier LF
3

2

portative system Figure 2-12: location of an insulation fault using a low frequency generator

Earthing Systems

73

2.5. Specific installation characteristics of an MV unearthed system
As shown in section 2.2.2.1, the MV unearthed system must be fitted with insulation monitoring and first insulation fault location.
2.5.1. Insulation monitoring
This can be done using residual overvoltage protection or an insulation monitor.
Insulation monitoring via residual overvoltage protection (see section 7.16)
This detects a rise in neutral point potential which is characteristic of an earth fault. Insulation monitoring via an insulation monitor
The insulation monitor applies a direct voltage between the neutral and earth, or between a phase and earth if the neutral is not accessible. If an insulation fault occurs, a direct current goes through the monitor, causing an alarm to go off.
The monitor is connected to the network via voltage transformers, so that the voltage applied to it is not too high.
In the case of an accessible neutral, it is connected to the voltage transformer primary measuring the neutral potential (see Figure 2-13).

VT

R

r

C

insulation monitor overvoltage limiter Figure 2-13: installation of an insulation monitor in the case of an accessible neutral

74

Protection of Electrical Networks

In the case of an inaccessible neutral, it is connected to the primary, on the neutral point of the three voltage transformers (see Figure 2-14).

VT

R

r

r

r

C

insulation monitor overvoltage limiter Figure 2-14: installation of an insulation monitor in the case of an inaccessible neutral

For Schneider equipment, a standard plate is connected in parallel and is made up of:
– a capacitor allowing the neutral potential of the voltage transformers to be fixed to earth without the direct current injected by the monitor being shunted;
– an overvoltage limiter allowing overvoltages to be run off to earth;
– a resistor allowing the voltage withstood by the monitor to be reduced.
Note: the voltage transformers must be loaded to avoid ferro-resonance phenomena from occurring in an unearthed system. This is what the secondary-connected r resistors are used for (see Figures 2-13 and 2-14).

Earthing Systems

75

If there are other star-connected voltage transformers in the same network, the following must be installed:
– a capacitor between the neutral of the voltage transformers and earth so that the monitor does not deliver a direct current via the voltage transformers (if this was the case, it would continually detect a fault). The advisable value of the capacitor is
2.5 µF with an insulation voltage of 1,600 V.
– an overvoltage limiter allowing overvoltages to be run off to earth.
When two networks with an insulation monitor can be coupled, a logic must be made so that the two monitors cannot operate in parallel because, if they did, one would deliver current into the other and they would continually detect a fault.
2.5.2. Location of the first insulation fault
This can be done in one of two of the following ways:
– by an efficient selectivity system (see sections 10.1.4.2, 10.1.5.2 and 10.1.6.2);
– by successive tripping of each feeder until the fault is cleared.
The latter method is not recommended as it leads to switching on the healthy feeders and overvoltages able to generate a double fault.

Chapter 3

Main Faults Occurring in
Networks and Machines

3.1. Short-circuits
3.1.1. Short-circuit characteristics
Short-circuits can be defined according to three main characteristics:
– Their origin:
- they may be mechanical: breakdown of conductors or accidental electrical connection between two conductors via a foreign body such as a tool or animal;
- they may be electrical: following the degradation of the insulation between phases, or between phase and frame or earth, or resulting from internal overvoltages
(switching surges) or atmospheric overvoltages (stroke of lightning);
- they may be due to an operating error: earthing of a phase, connection between two different voltage supplies or different phases or closing of a switching device by mistake.
– Their location:
- the short-circuit may be generated inside equipment (cable, motor, transformer, switchboard, etc.), and it generally leads to deterioration;
- the short-circuit may be generated outside equipment (cable, motor, transformer, switchboard, etc.). The consequences are limited to disturbances which may, in the course of time, lead to deterioration of the equipment in question and thereby cause an internal fault.

78

Protection of Electrical Networks

– Their duration:
- self-extinguishing: the fault disappears on its own;
- fugitive: the fault disappears due to the action of protective devices and does not reappear when the equipment is started up again (the fault is “burnt out” after reenergization);
- permanent: these faults require de-energization of a cable, machine, etc., and intervention by the operating personnel.
3.1.2. Different types of short-circuits
Phase-to-earth: 80% of cases* (see Figure 3-1)
L3
L2
L1

earth

Figure 3-1: phase-to-earth short-circuit

Phase-to-phase: 15% of cases* (see Figures 3-2 and 3-3)
These faults often degenerate into three-phase faults.
L3
L2
L1

earth

Figure 3-2: phase-to-phase short-circuit clear of earth

Main Faults Occurring in Networks and Machines

79

L3
L2
L1

earth

Figure 3-3: two-phase-to-earth short-circuit

Three-phase: 5% of cases (originating as such)* (see Figure 3-4)
L3
L2
L1

earth

Figure 3-4: three-phase short-circuits

See Chapter 4 for the method of calculating short-circuit currents.
3.1.3. Causes of short-circuits
– Degradation of insulating materials due to:
- degradation in surface quality (pollution);
- excessive temperature;
- partial discharge in the vacuoles (micropockets) inside the insulating materials. * The percentages given are for guidance only. They come from fault statistics on public distribution networks. The order of magnitudes must be approximately equivalent in industrial networks. It may be observed therefore that phase-to-earth short circuits are the ones most frequently occurring and that three-phase faults are fairly rare.

80

Protection of Electrical Networks

– Accidental reduction in electrical insulation (presence of animals, tree branches, tools left by carelessness on a busbar, etc.).
– Destruction due to external causes (hit by a shovel, etc.).
– Overvoltages causing a breakdown in equipment insulation (switching surges or lightning strike).
3.2. Other types of faults
– On motors:
- too many successive start-ups leading to overheating and mechanical shocks on couplings;
- excessive start-up time or rotor locking leading to the same result;
– On generators:
- loss of excitation due to a fault in the rotor circuit (cut, short-circuit, etc.), leading to overheating of the rotor and stator and loss of synchronism with the network; - variations in frequency due to an overload or faulty operation of a frequency regulator (for a generator operating cut-off from the utility network).
– Phase opposition connection of a generator with the network or of two parts of a network coming from different sources.
– Overvoltages due to a lightning strike.
– Switching surges (of a switch or circuit-breaker).
– Overloads on cables, transformers, motors or generators.
– Reversal of the direction of energy flow in the absence of an electrical fault. In the event of a power cut or a drop in voltage caused by the utility, an internal generation plant may supply energy to the utility.
– Variations in voltage due to faulty operation of the on-load tap changers of a transformer, or network under or overload.
– The presence of a negative-phase component due to a non-symmetrical voltage source, a large single-phase consumer, a connection error or phase cutting leads to overheating of the motors or generators, and a loss in generator synchronism.

Chapter 4

Short-circuits

All electrical installations must be protected against short-circuits every time there is an electrical connection, which is generally when there is a change in conductor cross-section. The short-circuit current value must be calculated at every stage of installation for different possible network configurations. This is done to determine the characteristics of the equipment that must withstand or switch the fault current.
In order to choose the appropriate switching devices (circuit-breakers or fuses) and set the protection functions, four short-circuit values must be known:
The root mean square value of the maximum short-circuit current (symmetrical three-phase short-circuit)
This determines:
– the breaking capacity of the circuit-breakers and fuses;
– the temperature stress that the equipment must withstand.
It corresponds to a short-circuit in the immediate vicinity of the downstream terminals of the switching device. It must be calculated to include a good safety margin (maximum value).
The peak value of the maximum short-circuit current (value of the first peak of the transient period)
This determines:
– the making capacity of the circuit-breakers and switches;
– the electrodynamic withstand of the trunkings and switchgear.

82

Protection of Electrical Networks

The minimum phase-to-phase short-circuit current
This must be known in order to choose the tripping curve of the circuit-breakers or fuses or set the thresholds of the overcurrent protection devices, especially when:
– the cables are long or when the source has a relatively high internal impedance
(e.g. generators);
– protection of persons relies on the phase overcurrent protective devices operating. This is essentially the case in low voltage for TN or IT earthing systems;
– the network requires a study of protection selectivity.
The value of the phase-to-earth short-circuit current
It mainly depends on the earthing system and determines the setting of earth fault protections.
4.1. Establishment of short-circuit currents and wave form
The network upstream of a short-circuit can be shown in the form of an equivalent diagram having one constant alternating voltage source E and a series impedance Z sc (see Figure 4-1).

Z sc represents the sum of cable, line and transformer impedances through which

the short-circuit current flows. Each impedance must be recalculated for voltage E basis. X

I sc
Z sc

E

A

network

R

E
B

E : r.m.s. single-phase voltage
Figure 4-1: equivalent diagram of the network upstream of the short-circuit

Short-circuits

83

A negligible impedance fault between A and B gives rise to a short-circuit current I sc limited by impedance Z sc :
Z sc = R 2 +X 2 where X = Lω

In steady-state conditions, the short-circuit current is: I sc =

E
Z sc

The real short-circuit current I sc is established according to a transient state having a non-periodic component and a higher amplitude than during the steady state. We shall consider two cases because the transient state differs according to whether the short-circuit is located on the power utility’s supply (in this case the generators are far enough apart for their effects to be ignored), or whether it is located at the terminals of a generator.
4.1.1. Establishment of the short-circuit at the utility’s supply terminals
A voltage of e= E 2 sin(ωt +α ) is applied to a circuit comprising a resistor and reactor in series.

α represents a switching angle defining the voltage phase upon occurrence of the fault (the voltage sinusoidal phase the moment the fault occurs).
If ϕ is the phase angle between the voltage and the current, then tgϕ =
The current expression is shown to be (see Appendix A):
I sc =

R

− ωt ⎤
E 2⎢ sin(ωt + α − ϕ )−sin(α − ϕ )e X ⎥

Z sc ⎢



where:

Z sc = R2 + X 2 tgϕ =

X
R

X
.
R

84

Protection of Electrical Networks

Ia

I sin

t

Ic

R
R ωt
Xt
e L

I sin

I sc

Ia

Ic

moment fault occurs
Figure 4-2: breakdown of the short-circuit current established at the utility’s supply terminals

The current I sc is the sum of a sinusoidal current:
I a=

E 2
Z sc

sin(ωt +α −ϕ )

and an aperiodic current tending towards 0 exponentially (see Figure 4-2):
R

− ωt
E 2
I c =− sin(α −ϕ )e X
Z sc

If α = ϕ at the moment the fault occurs, the aperiodic component is zero and the state is said to be symmetrical.
If α − ϕ =

π
2

at the moment the fault occurs, the aperiodic component is at its

maximum and the state is referred to as a maximum asymmetrical state, which is the condition that leads to the highest current peak value, thus:
R


E 2⎢ ⎛ π ⎞ −Xω t ⎥ sin ⎜ ωt + ⎟−e
I sc =

2⎠
Z sc ⎢ ⎝



π

The current value is peak for sin (ωt + )=− 1 hence ωt = π.
2
The peak value of the current is thus:
ˆ
I=

⎡ − Rπ ⎤
⎢1+e X ⎥


R 2+ X 2 ⎣

E 2

Short-circuits

85

Let us define the coefficient K which characterizes the ratio of the peak transient current to the steady-state r.m.s. current:
E
ˆ
I = K I a where I a = steady-state r.m.s. current
Z sc

R

− π

K = 2 ⎜1+e X









Note: the factor 2 comes from the fact that a peak current is being compared to a steady-state root mean square current.
It is interesting to define K in relation to the ratio

R
, which characterizes the
X

network (see Table 4-1 and Figure 4-3).
R
is:
X
– between 0.05 and 0.3 for HV or MV;

Generally the ratio

– between 0.3 and 0.6 for LV (near transformers).

R
X

K
K
2
Table 4-1:

0

0.05

0.1

0.2

0.3

0.4

0.5

0.6



2.83 2.62 2.45 2.17 1.97 1.82 1.71 1.63 1.41
2

1.85 1.73 1.53 1.39 1.29 1.21 1.15

1

K values, ratio between the peak transient current and the steady-state current, according to

R
X

86

Protection of Electrical Networks

K

2.8
2.4
2.0
1.6
1.4
1.2
0.8
0.4
0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

R
X

Figure 4-3: development of K, ratio between the peak transient current and the steady-state current, with respect to

R
X

Example
Development of the current peak values, ratio

ˆ
I
Ia

in relation to time (see Table

4-2). I a is the steady-state r.m.s. current:
R

ˆ
− ωt ⎤
I
⎢sin ⎛ ωt + π ⎞ − e X ⎥
= 2

⎢ ⎜

Ia
2⎠




The peak values occur at time:
⎛ 1⎞ t =⎜ p+ ⎟T
⎝ 2⎠

2π where p is an integer and T = is voltage period (T = 20 ms for f = 50 Hz), thus:

ω

R
R


ˆ
− ωt ⎤
− ( 2 p + 1)π ⎤
I
= 2 ⎢1 + e X ⎥ = 2 ⎢1 + e X

Ia









Short-circuits t (ms)
R/X

10
(p = 0)

30
(p = 1)

50
(p = 2)

70
(p = 3)



0.05

2.62

2.30

2.06

1.89

1.41

0.1

2.45

1.97

1.71

1.57

1.41

0.2

2.17

1.63

1.48

1.43

1.41

0.3

1.97

1.50

1.43

1.42

87

1.41

Table 4-2: development of

ˆ
I
R in relation to the time for ratios equal Ia
X

to 0.05, 0.1, 0.2 and 0.3

Conclusion
When a short-circuit occurs in an installation fed by a distribution network (far from the generators), a transient current occurs which lasts for several periods, i.e. between 20 and 80 ms. However, when circuit-breakers are not time-delayed, they generally have a lower tripping time than the duration of the aperiodic current and should therefore be able to break the aperiodic component (see section 8.2 for MV circuit-breakers and section 8.1 for LV circuit-breakers). For LV circuit-breakers,
R
the breaking capacity is defined in relation to cos ϕ =
(Table 8-2).
2
X + R2

The peak value of the transient current is 1.6 to 2.5 times higher than the shortcircuit current value in steady-state conditions. It determines the electrodynamic forces that the trunkings and switchgear must withstand and the making capacity of the switching devices (see section 5.2).
4.1.2. Establishment of the short-circuit current at the terminals of a generator

It is assumed that the short-circuit is close enough to the generator for the cable impedance to be ignored compared with the generator impedance.
Calculations on transient states of synchronous machines show that the current is expressed by:
⎡⎛ 1
1
i (t ) = E 2 ⎢⎜ " − '
⎜X
⎢⎝ d X d



⎛ 1
'
"
1 ⎞ −t/Td
1 ⎤
E 2
+
⎥ Cos (ω t + α ) −
⎟ e −t/Td + ⎜ ' −
⎟ e
"

⎜X
Xd ⎟
Xd ⎥
Xd

⎝ d



e − t/Ta

cos α

α represents a switching angle defining the voltage phase upon occurrence of the fault (the voltage sine curve phase at the moment the fault occurs). Current i ( t ) is maximum for α = 0.

88

Protection of Electrical Networks

Thus:
⎡⎛ 1
1
i (t ) = E 2 ⎢⎜

'
⎜ X"
⎢⎝ d X d



⎛ 1
"
1 ⎞ − t/T '
1 ⎤
E 2 −t/Ta
⎥ cos ωt −
⎟ e −t/Td + ⎜
⎟e d + e "

⎜ X'

Xd ⎥
Xd

⎝ d Xd ⎠


E : single-phase r.m.s. voltage at the generator terminals
"
Xd : subtransient reactance
'
Xd : transient reactance
Xd : synchronous reactance

"
Td : subtransient time constant

Td' : transient time constant
Ta : aperiodic time constant

The current is the sum of the aperiodic current: ic =−

E 2 − t/Ta e "
Xd

and of a damped sinusoidal current:
⎡⎛ 1
1
− ia = E 2 ⎢⎜
'
⎜ X"
⎢⎝ d X d



⎛ 1
"
1

⎟ e −t/Td + ⎜

⎜ X'
Xd

⎝ d


'
1 ⎤
⎥ cos ωt
⎟ e −t/Td +

Xd ⎥



The aperiodic component has a high value but a very short duration, from 10 to
60 ms (see Tables 4-3, 4-4 and 4-5 showing the aperiodic time constant values Ta ).
For the damped sinusoidal component, the electrical variables evolve as if the machine reactance was variable and developed according to the three following periods: "
– subtransient ( Xd ): lasting 10 to 20 ms after the start of the fault;
'
– transient ( Xd ): lasting up to 100 to 400 ms;
– synchronous ( Xd ): synchronous reactance to be considered after the transient period. Let us note that in the order given, this reactance takes a higher value for each period: "
'
Xd < Xd < Xd

This leads to a gradual decrease in the short-circuit current.
The short-circuit current is thus the sum of four components (see Figure 4-4).

Short-circuits

⎛ 1
1
E 2 ⎜ '' − '
⎜X
Xd
⎝ d



⎟e



t
− ''
Td

89

sin ωt

1
''
Xd

t

⎛ 1
1 ⎞ − Td'
E 2⎜ ' −
⎟ e sin ωt
⎝ Xd Xd ⎠


1
'
Xd

E 2 sin ωt
Xd

E 2
X "d

e



t
Ta

Figure 4-4: contribution to the total short-circuit current I sc of a) subtransient reactance;
b) transient reactance; c) steady-state or synchronous reactance; d) aperiodic component

90

Protection of Electrical Networks

It should be noted that the decrease in generator reactance is faster than that of the aperiodic component. This rare case may raise switching difficulties for the circuit-breakers and saturation problems for the magnetic circuits as the current does not reach zero until after several periods.
Standard electrical characteristics of generators
"
'
The values Xd , X d and Xd are expressed as percentages (see section 4.2.1.3).

S (kVA)

75

200

400

800

1,600

2,500

"
Xd (%)

10.5

10.4

12.9

10.5

18.8

19.1

'
Xd (%)

21

15.6

19.4

18

33.8

30.2

Xd (%)

280

291

358

280

404

292

Ta (ms)

9

15

22

28

47

65

"
Td (ms)

6

10

14

18

22

23

Td' (ms)

80

30

140

160

235

320

Table 4-3: electrical characteristics of Leroy-Somer 75 to 2,500 kVA three-phase, four-pole generators with a phase-to-phase voltage of 400 V and frequency of 50 Hz

S (kVA)

2,200

2,800

3,500

"
Xd (%)

15.5

14

13

'
Xd (%)

25.5

24.5

23

X d (%)

235

230

225

Ta (ms)

50

54

57

"
Td (ms)

22

24

26

Td' (ms)

240

260

280

Table 4-4: electrical characteristics of Leroy-Somer 2,200, 2,800 and 3,500 kVA threephase, four-pole generators with a phase-to-phase voltage of 6 kV and frequency of 50 Hz

Short-circuits

S (kVA)

1,500

2,500

3,250

"
X d (%)

15.5

14.5

14

'
Xd (%)

27.5

26.5

25.5

Xd (%)

255

255

250

Ta (ms)

37

46

52

"
Td (ms)

21

24

26

Td' (ms)

230

260

91

280

Table 4-5: electrical characteristics of Leroy-Somer 1,500, 2,500 and 3,250 kVA three-phase, four-pole generators with a phase-to-phase voltage of 11 kV and frequency of 50 Hz

Development of short-circuit current peak values,

ˆ
I
2In

in relation to the time

(see Table 4-6)

I n is the nominal current of the generator.
⎛ 1⎞
The peak values occur at times t =⎜ p+ ⎟T
⎝ 2⎠

where p is an integer and T = is voltage period (T = 20 ms for f = 50 Hz), thus:

ω

⎡⎛ 100 100 ⎞
⎟ − t / Td"
= ⎢⎜

"
' ⎟e
2 I n ⎢⎜ X d X d ⎠
⎣⎝


⎛ 100 100 ⎞
⎟ e − t / Td' + 100 ⎥ + 100 e−t / Ta
+⎜

'
"

⎜X
Xd ⎥ Xd
⎝ d Xd ⎠


ˆ
I

"
'
where the values X d , X d and X d are expressed as percentages (see section 4.2.1.3).

10

30

50

90

150

310

610



75

8.3

3.8

2.8

1.8

1

0.45

0.36

0.36

200

10.81

4.04

1.86

0.67

0.39

0.344

0.344

0.344

400

11

6.5

4.6

3

2

0.81

0.34

0.28

800

14.2

8.7

6

3.7

2.4

1.1

0.47

0.36

t(ms)
S (kVA)

Table 4-6: development of

ˆ
I
2In

in relation to the time for the 75, 200, 400 and 800 kVA

generators defined in Table 4-3

92

Protection of Electrical Networks

Holding the short-circuit current at approximately 3 I n for several seconds

When the subtransient and transient periods are over, i.e. after a time of 0.5 to
1 second, the short-circuit current is lower than the nominal current, i.e. from 0.3 to
0.5 In (see Table 4-6).
The values given above are design values.
In practice, manufacturers like Leroy-Somer have methods for holding the shortcircuit current at approximately 3 In for several seconds to allow the protective devices to operate when they are time-delayed, for selectivity reasons, for a time
'
greater than Td ≈ 100 ms. The holding value 3 In is close to the current value during the transient period where:
E
'
I sc ≈ where Xd ≈ 30%
'
Xd

I sc is thus close to 3 In .
When the current is not held at 3 In , protection against short-circuits may be provided by voltage restrained overcurrent protection (see section 7.24).
Note: the method generally used to hold the short-circuit current at 3 In is compound excitation, i.e. series-parallel excitation. The parallel voltage drops when a short-circuit occurs, leading to a drop in parallel excitation; the short-circuit current, however, is higher than the nominal current and the series excitation increases. Combined, the two phenomena lead to a short-circuit current held at 3 In for several seconds.
4.2. Short-circuit current calculating method

The short-circuit current calculating method presented in this document is the impedance method. It is applied to calculations by hand and produces sufficiently accurate results for most applications.
It helps with the understanding of more accurate methods, such as IEC 60909, which are generally applied using computer software programs.
The aim of this section is to give all the elements needed to calculate the following short-circuits:
– symmetrical three-phase fault;

Short-circuits

93

– phase-to-earth fault;
– phase-to-phase fault clear of earth;
– two-phase-to-earth fault; at any point in a network.
A detailed calculation of the symmetrical three-phase short-circuit at different points in a network is provided as an example at the end of section 4.2.1.
4.2.1. Symmetrical three-phase short-circuit

This fault corresponds to that shown in Figure 3-4.
In general, it causes the greatest fault currents. It must therefore be calculated for the appropriate equipment to be chosen (maximum current and electrodynamic stress to be withstood).
The three-phase short-circuit current calculation is simple due to the symmetrical nature of the short-circuit. The short-circuit current has the same value in each phase. A calculation can thus be made using an equivalent single-phase diagram of the network upstream of the short-circuit (see Figure 4-5), as can be done under normal operating conditions.
Z sc

Un

short-circuit

3

Figure 4-5: equivalent single-phase diagram of the network upstream of the short-circuit

The three-phase short-circuit value I sc 3 is thus: I sc3=

Un
3 Z sc

where:

U n : phase-to-phase voltage

Z sc : impedance equivalent to all the impedances through which the fault current flows, from the source up to the presumed fault

94

Protection of Electrical Networks
2
2
Z sc= (ΣR ) +(ΣX )

ΣR : sum of series resistances through which the fault current flows
ΣX : sum of series reactances through which the fault current flows
In practice, the equivalent supply source impedance is calculated first (power supply provided by the utility or generator), then the impedances of each transformer, cable or line through which the fault flows.
Each impedance must be recalculated for the voltage level of the presumed fault
(see section 4.2.1.1).
Note: in medium and high voltage, standard IEC 60909 (Table 1) applies a coefficient of 1.1 to the nominal voltage in order to calculate the maximum shortcircuit current, thereby giving:
I sc3 =

1.1U n

(in MV and HV)

3 Z sc

4.2.1.1. Equivalent impedance of an element across a transformer
For example, for a low voltage fault, the contribution of a cable upstream of the
MV/LV transformer will be:
⎛ U LV
R LV = R HV ⎜
⎜U
⎝ HV

2






and
2

⎛ U LV
X LV = X HV ⎜
⎜U
⎝ HV






⎛ U LV
Z LV = Z HV ⎜
⎜U
⎝ HV

2

thus:





This formula can be applied whatever the cable voltage level, i.e. even across several transformers in series.

Short-circuits

95

Example (see Figure 4-6) n cable R2 , X 2

cable R1 , X 1

supply source

Ra , X a
RT , X T
(impedance seen from the primary)

short-circuit

Figure 4-6: equivalent impedance of elements across a transformer

n : transformation ratio
Impedance seen from the short-circuit perspective:

∑ R = R2 +

RT n ∑ X =X 2 +

2

+

XT n 2

R1 Ra
+
n2 n2
+

X1 X a
+
n2 n2

4.2.1.2. Impedance of parallel links
If the fault current flows through two parallel links with impedances Z1 and Z2 , the equivalent impedance is:

Zeq =

Z1 Z2
Z1 + Z2

If impedances Z1 and Z2 are different, a complex numerical calculation should then be made.
If:

Z1 = Z2 then: Z Z
Zeq = 1 = 2
2
2

96

Protection of Electrical Networks

Example (see Figure 4-7)
MV busbar

ZT

Z

ZT

Z

Figure 4-7: equivalent impedance of two identical parallel links

ZT : impedance of transformers seen by the secondary
Z : impedance of links
The total impedance Zeq is:

Z +Z
Zeq = T
2
For n parallel links of the same impedance Z , Zeq =

Z
.
n

4.2.1.3. Expression of impedances as a percentage and short-circuit voltage as a percentage Transformers

Instead of giving the impedance value of transformers in ohms, the manufacturer gives the short-circuit voltage U sc expressed as a percentage.
This short-circuit voltage represents the primary voltage which, when applied to the secondary short-circuited transformer, gives a current equal to the nominal current. Thus:

U sc (%)
Vn = Z I n
100

Short-circuits

97

hence:

U sc (%) Vn
100 I n

Z=

Vn : single-phase nominal voltage
Transformer manufacturers give the apparent nominal power Sn in kVA:

Sn = 3 Vn I n
Z=

U sc (%) 3Vn2
100
Sn

Z=

2
U sc (%) U n
100 Sn

Un : phase-to-phase nominal voltage = 3 Vn
Note: for transformers fitted with tap changers, the voltage U n is that obtained for the main position of the changer (see IEC 60909, section 8.3.2.2).
Rotating machines
'

"

Instead of giving the characteristic impedance values ( X d , Xd , X d ) of motors and generators in ohms, manufacturers give them as a percentage ( Xd (%),
'
"
X d (%), X d (%)). By definition, the following relation applies:

X (Ω) =

X (%)
100

Vn
In

Manufacturers of rotating machines give the apparent nominal power Sn in kVA: Sn = 3 Vn I n
3Vn2 X (%)
X (Ω) =
Sn 100
X (Ω) =

2
U n X (%)
Sn 100

98

Protection of Electrical Networks

Un : nominal phase-to-phase voltage
X d (Ω) =

2
U n X d (%)
Sn 100

'
X d (Ω) =

2
'
U n X d (%)
Sn 100

"
X d (Ω) =

Thus:

2
"
U n X d (%)
Sn 100

4.2.1.4. Impedance values of different network elements
Upstream network impedance

Knowledge of the upstream network is generally limited to the indications supplied by the utility, i.e., the short-circuit power S sc (in MVA) only:

Za =

U n2
S sc

U n : network nominal phase-to-phase voltage
The upstream network is generally considered to be a pure reactance, i.e.

Za ≅ Xa .

We saw in section 4.1.1 that the ratio

Ra is between 0.05 and 0.3 for MV.
Xa

Let us take, for example Ra = 0.3, thus:
Xa

(

)

Za2 = Ra2 + X a2 = ( 0.3) + 1 X a2 = 109 X a2
.
2

hence:

X a = 0.96 Za
As a first approximation, we shall thus take Za = X a .
Note: the approximation Za = X a is better the lower the ratio

Ra is. Xa

Short-circuits

99

Generator power supply impedance

In section 4.1.2, we saw that the short-circuit current developed in the following three periods:
"
i) subtransient ( Xd ): lasting 10 to 20 ms after the start of the fault;
'
ii) transient ( X d ): lasting up to 100 to 400 ms; iii) synchronous ( X d ): synchronous reactance to be considered after the transient period;
– To check electrodynamic stress, the maximum short-circuit current is calculated on the basis of the subtransient reactance:

I sc 3 =

Un
"
3 Xd

U n : nominal phase-to-phase voltage
– To check heat stress in equipment, the maximum short-circuit current is calculated on the basis of the transient reactance:

I sc 3 =

Un
'
3 Xd

– To set the threshold of phase overcurrent protective devices, notably when the generator is able to operate cut-off from the utility network, the minimum shortcircuit current (see section 4.4.2) is calculated on the basis of the transient reactance and the negative sequence reactance X ( 2) (see section 4.2.2.1).

I sc 2 ,min =

Un
X + X (2)
'
d

The steady state is not generally taken into account, assuming that the protective devices switch the current during the transient state or that the short-circuit current is held at 3 In (see section 4.1.2). The protection threshold is therefore set below this value. If this is not the case, restrained voltage overcurrent protection is used
(see section 7.24):
– To determine the breaking capacity of low voltage circuit-breakers, the maximum short-circuit current is calculated on the basis of the subtransient
Un
reactance I sc 3 =
. It is generally lower than the short-circuit current supplied
"
3 Xd by the utility.
– To determine the breaking capacity of high voltage circuit-breakers, the periodic component value and the aperiodic component value must be calculated

100

Protection of Electrical Networks

during the minimum opening time of the circuit-breaker, to which is added a half period of the rated frequency. These values must be passed on to the manufacturer for approval or tests (see section 8.2).
Standard generator subtransient, transient, synchronous and negative-sequence impedance values (Tables 4-7, 4-8 and 4-9)
S (kVA)
"
Xd (%)
'
Xd (%)

X d (%)
X ( 2)

(%)

75

200

400

800

1,600

2,500

10.5

10.4

12.9

10.5

18.8

19.1

21

15.6

19.4

18

33.8

30.2

280

291

358

280

404

292

13.1

11.3

15.1

11.7

22.2

21.2

Table 4-7: subtransient, transient, synchronous and negative-sequence impedances of LeroySomer four-pole generators with a phase-to-phase voltage of 400 V and frequency of 50 Hz

S (kVA)
"
Xd (%)
'
Xd (%)

2,200

2,800

3,500

15.5

14

13

25.5

24.5

23

X d (%)
X ( 2)

235

230

225

17

15.5

14.5

(%)

Table 4-8: subtransient, transient, synchronous and negative-sequence impedances of LeroySomer four-pole generators with a phase-to-phase voltage of 6 kV and frequency of 50 Hz

S (kVA)
"
Xd (%)
'
Xd (%)

1,500

2,500

3,250

15.5

14.5

14

27.5

26.5

25.5

X d (%)
X ( 2)

255

255

250

17.5

16.5

16

(%)

Table 4-9: subtransient, transient, synchronous and negative-sequence impedances of LeroySomer four-pole generators with a phase-to-phase voltage of 11 kV and frequency of 50 Hz

Short-circuits

101

Note: the resistance of the windings is negligible compared with the reactance
'
"
R 400

159

0.1

(*) These values are based on IEC 60038.
(1) These values are not valid in premises containing a bath tub or shower.
Table 4-21: maximum switching times in the TN system (Table 41A of IEC 60364-4-41)

The protection rule consists therefore in making sure that the fault current I f causes the fuse to blow in less than the time stipulated in Tables 4-20 and 4-21.
In practice, for a given fuse blowing curve (see Figure 4-25): time fuse

current

t0 : specified switching time to ensure protection of persons t1 : fuse blowing time for fault current If
Figure 4-25: protection of persons using a fuse

160

Protection of Electrical Networks

If t1 is less than or equal to t0 , protection is ensured.
Note 1: if t1 is higher than t0 , but less than 5 seconds, protection is said to be ensured by IEC 60364-4-41, section 413.1.3.5 in the following cases:
– in distribution circuits when the protective conductor at the downstream end of the circuit is linked directly to the main equipotential bonding;
– in terminal circuits only supplying stationary equipment whose protective conductor is linked to the main equipotential bonding and which is located in the main equipotential bonding influence zone.
Note 2: in a TT system, protection of people is generally provided by residual current devices whose setting must satisfy the following condition (see IEC 603644-41, section 413.1.4.2):
R A I A ≤ 50 V

RA : resistance of the earth of the exposed conductive parts
IA : rated residual current of the circuit-breaker
If selectivity is judged to be necessary, an operating time of the residual protection at the most equal to 1 second is admissible in distribution circuits.
Note 3: in an IT system, when the exposed conductive parts are earthed individually or in groups, the TT system conditions given in Note 2 must be respected (see IEC 60364-4-41, section 413.1.5.3).
4.4.2. Calculating the minimum short-circuit current for medium and high voltages The method applied is the impedance method.
The procedure is carried out in the following steps:
– Step 1: determine the furthest point downstream of the switching device giving the lowest short-circuit current for which protection must be in place.
– Step 2: determine the upstream network configuration giving the minimum short-circuit current:
- the lowest short-circuit current supply source which can be configured is determined. This is generally the standby generator if there is one;
- the network configuration giving the longest link length up to the source is determined. Short-circuits

161

– Step 3: the type of short-circuit giving the lowest value is determined. For medium and high voltages, phase-to-earth short-circuits are cleared by the earth fault or directional earth fault protective devices. The neutral is not distributed, which implies that the short-circuit is minimum for a phase-to-phase fault clear of earth. – Step 4: the length of the longest fault loop is determined, i.e. when a single phase-to-phase fault occurs at the point the furthest away in the protected zone, e.g. the furthest away load (see Figure 4-26).
Ph 1
Ph 2
Ph 3
ZN

L

load

L' load - L > L'

short-circuit current circulation
Figure 4-26: fault loop for a phase-to-phase short-circuit clear of earth

L is the longest length of the protected circuit from the circuit-breaker.
– Step 5: the short-circuit current is calculated.

We saw in section 4.2.3 that the phase-to-phase fault clear of earth is:

I sc 2 min =

3 Vn
Z(1) + Z( 2)

Vn : single-phase voltage

Z(1) : positive-sequence impedance
Z( 2 ) : negative sequence impedance

Z(1) is the impedance equivalent to the positive-sequence impedance device through which the short-circuit current flows (length L and upstream network).
Z( 2 ) is the impedance equivalent to the negative-sequence impedance device through which the short-circuit current flows (length L and upstream network).

162

Protection of Electrical Networks

Note 1: if the network cannot be fed by a generator:
Z (1) = Z ( 2)

I sc 2 min =

3V n
.
2Z (1)

Note 2: for the cable or line, the following always applies: section 4.2.2.1).

Z(1) = Z(2) (see

Note 3: in the case where the network is fed by a generator, the minimum shortcircuit current may be the three-phase short-circuit (see section 7.24).
Using the minimum short-circuit current calculation for protection setting

The minimum short-circuit current calculation allows the opening of switching devices to be ensured in the event of a phase-to-phase short-circuit in the protected zone: – the phase overcurrent protection threshold (see section 7.1) must be such that
I r ≤ 0.8 I sc 2, min ;
– a fuse must be chosen such that its switching time for I sc 2, min is lower than a specified value.
4.4.3. Importance of the minimum short-circuit calculation for protection selectivity

For amperemetric type selectivity, the minimum and maximum short-circuit currents at the location point of each switching device must be known
(see section 9.1).

Chapter 5

Consequences of Short-circuits

5.1. Thermal effect

When a short-circuit occurs, a much larger current than the nominal current flows (10 to 100 times its value). This results in cables overheating which may damage the insulating material. The current must therefore be switched by a circuitbreaker or a fuse in a short enough time t s for the cable temperature not to reach a critical value.
The thermal losses per unit of length is proportional to the square of the current:
P(t)= R L I 2 (t ) in single-phase

RL : resistance per unit length of the cable
If the current is not sinusoidal, the energy stored by the cable is: t E = RL ∫os I 2 (t )dt

t s : switching time of the switching device
If we take the approximate value of a short-circuit sinusoidal current I sc , then:
2
E = RL I sc t s

I sc : r.m.s. value of the short-circuit current
In practice, the energy able to be stored in the cable depends on the conductor cross-section, the material of the core and the maximum temperature admissible in the insulating material.

164

Protection of Electrical Networks

A coefficient k , a function of the core material and the type of insulating material, is defined in LV (see Table 5-1) and can be applied in MV as follows:
2
k 2 S 2 ≥ I sc t s hence: S≥ ts

or where t s ≤

I sc k k2S2
2
I sc

where:

I sc : short-circuit current at A

t s : switching time of the switching device in seconds
S : conductor cross-section in mm2
Insulating material
Conductor
Copper
Aluminum

PVC or PE

PR or EPR

115
74

135
87

Table 5-1: coefficient k value in compliance with IEC 60364-4-43

Example 1

Let us take a 120 mm2 PR-insulated copper cable protected by a circuit-breaker fitted with time-delayed magnetic trip relay which can be set at 0.1 second or 0.2 second. The short-circuit current at the terminals downstream of the circuit-breaker is 45 kA.
The maximum time for which the cable is able to withstand a short-circuit current is: tmax =

k 2 A2
2
I sc

=

(135)2 × (120 )2
( 45, 000 )2

= 0.130 s

The circuit-breaker time delay must therefore be set at 0.1.
Example 2

Let us take an installation with a short-circuit current of 55,000 A downstream of the supply transformer. We want to install a circuit-breaker with a magnetic trip relay set at 0.2 second (in compliance with load requirements, e.g. of a motor).

Consequences of Short-circuits

165

We want to install a PVC-insulated aluminum cable. The minimum cable crosssectional area must be:
Smin = ts

Isc
0.2 × 55, 000
=
= 332 mm 2 k 74

A 400 mm2 cross-section must therefore be used.
5.2. Electrodynamic effect

The maximum peak value of the current creates the maximum electrodynamic force observed in the network equipment.
This force, an electromagnetic effect, is referred to as the “Laplace force”.
For example, the force per unit of length generated by two parallel conductors through which an identical current I flows is (see Figure 5-1):
F = 2 ×10−8

I2
D

daN/m

F : in daN/m
I : in amperes
D : distance in meters between the two conductors

I

F

D

I

F

Figure 5-1: force per unit of length generated by two parallel conductors through which an identical current I flows

The forces are attractive if both currents flow in the same direction and repulsive if they do not.

166

Protection of Electrical Networks

In sinusoidal operating conditions, the equipment must be dimensioned in relation to the peak value of the short-circuit current. This is 1.6 to 2.5 times higher than the value of the steady-state short-circuit current (see section 4.1.1).
Example

Let us consider two bus sections of a low voltage switchboard, 10 cm apart, over
ˆ
a length of 30 cm and through which an identical short-circuit current I sc = 100 kA
ˆ is the peak value of the short-circuit current and flows in the same direction. 100 kA corresponds, for example, to a steady-state short-circuit current of 50 kA for a coefficient K = 2 (see section 4.1.1).
The maximum attractive force applied to each bus when a short-circuit occurs is:
F = 2 ×10

−8

×

(100, 000 )2
0.1

× 0.3 = 600 daN

If the bus sections are held by two supports, one on each side of the bus, the force applied to each support and to the bus connection system will be 300 daN.
This may possibly result in parts being deformed or broken.
Effect on switching devices (circuit-breakers, switches or contactors)

The separable contacts of the switching devices tend to open under the effect of this so-called repulsive electrodynamic force. This is why it is necessary to define the short-circuit making capacity of circuit-breakers or switches (see sections 8.1 and 8.2).
According to section 4.1.1, for an installation fed by a distribution network, the peak value of the short-circuit current is equal to K times the value of the steadystate short-circuit current where 1.41 < K < 2.83 .
The circuit-breaker or switch must be able to withstand this peak current, which occurs if the device is closed on a solid symmetrical three-phase short-circuit.
Low voltage circuit-breakers
In low voltage, standard IEC 60947-2, section 8.3.2.2.4 stipulates that equipment must have a ratio n between the short-circuit making capacity and the nominal short-circuit breaking capacity, in relation to the nominal short-circuit breaking


R


capacity for a cos ϕ specified by the standard ⎜ cos ϕ =
⎟ : see Table 5-2.

R2 +X 2 ⎟



Consequences of Short-circuits nominal short-circuit breaking capacity I sn (A)

specified

cos ϕ

167

n

4,500

<

I sn

≤ 6,000

0.7

1.5

6,000

<

I sn

≤ 10,000

0.5

1.7

10,000 <

I sn

≤ 20,000

0.3

2

20,000 <

I sn

≤ 50,000

0.25

2.1

<

I sn

0.2

2.2

50,000

Table 5-2: ratio n between making capacity and breaking capacity
(according to IEC 60947-2)

High voltage circuit-breakers
For high voltages, IEC 62271-100, section 4.103 stipulates a making capacity equal to at least 2.5 times the rated short-circuit breaking capacity; in a network where the coefficient K is greater than 2.5 (rare), a circuit-breaker with a breaking
K
capacity greater than
× I sc (see section 8.2) must be installed.
2.5

I sc :

maximum short-circuit current.

Note 1: the short-circuit making capacity is also referred to as the electrodynamic withstand.
Note 2: standard Schneider equipment complies with these standards, both in low voltage and high voltage. Any specific requirements must be checked for nonstandard equipment or equipment to be used in special conditions.
5.3. Voltage drops

A fault in the installation or on the utility network results in a voltage drop in the network’s healthy elements which is often less than the allowable load voltage.
This voltage drop may lead to difficulties which do not necessarily disappear when the fault is cleared.

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Protection of Electrical Networks

Effect on contactors

For certain manufacturers, the coils designed to close the contacts of the circuit are directly fed by a voltage supply from the network; the contacts may open upon occurrence of the fault and may not close when normal operating conditions are restored. Effect on asynchronous motors

The maximum torque of asynchronous motors is approximately proportional to the square of the supply voltage. A drop in voltage may therefore lead to the motor stopping if the fault lasts too long.
Furthermore, if several motors have greatly slowed down or stopped, once the voltage is restored, these motors create a high pick-up current (same principle as for start-up), and may trigger the protective devices or cause a drop in voltage themselves. It is sometimes necessary to provide a load shedding and reloading program after a fault has occurred to prevent high pick-up currents from being generated. Effect on generators

When a serious fault in the utility network or internal network occurs, the active power exchanges are disturbed. This results in modification of the internal angles of the machines and risk of loss of synchronism with the utility network. Indeed, while the short-circuit lasts, the generator does not supply any active power but receives the power from the driving machine thus forcing the rotor to accelerate. A dynamic stability study of the behavior of generators upon occurrence of a fault may show the need to separate them from the network if the fault is not quickly cleared.
Abnormal operation of power electronics

Rectifiers or inverters use thyristors which need a temporal reference allowing switching to take place at predetermined times. This temporal reference comes from the three-phase voltage system.
If the voltage almost reaches zero during a fault, the reference disappears which may lead to disturbances upon re-initialization of the process.
5.4. Transient overvoltages

When a phase-to-earth fault occurs in an unearthed or limiting impedance earthed network (see section 2.2), the voltage between the healthy phases and earth becomes equal to the phase-to-phase voltage (see Figure 5-2). Consequently, so far

Consequences of Short-circuits

169

as earthing insulation is concerned, the network must be dimensioned for a phaseto-phase voltage and be able to withstand transient overvoltages so that a phase-tophase fault is not generated. This problem is especially relevant in unearthed or
Petersen coil earthed networks where, due to supply continuity requirements, phaseto-earth faults are detected but not immediately cleared (see section 2.2).
E1

E1
N

v1

E2
E3

v2 v3 ZN

N

v1

E3

v2 v3 ZN

E1 , E2 , E3 v1 , v2 , v3

E2

0

: phase-to-neutral voltages
: phase-to-earth voltages
: earthing impedance

Figure 5-2: transient overvoltages in an unearthed or limiting impedance-earthed network when a phase-to-earth fault occurs

5.5. Touch voltages

When a fault occurs between a phase and an exposed conductive part or two phases and an exposed conductive part, a voltage coming from the current flowing in the earth conductor occurs between the exposed conductive part and earth or between two neighboring exposed conductive parts.
This voltage must not be dangerous. To make sure of this, the specifications provided in IEC 60364-5-54 concerning earthing of exposed conductive parts and of the neutral conductor should be followed. In particular, equipotential bonding must be installed between two simultaneously accessible exposed conductive parts.
5.6. Switching surges

The clearance of a fault means that a current in a generally inductive circuit is switched. This causes overvoltages referred to as “switching surges”, the maximum peak value of which is generally estimated to be two or three times the r.m.s. value of the nominal voltage (see section 10.1.1).

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Protection of Electrical Networks

5.7. Induced voltage in remote control circuits

A high single-phase current in a power cable (a phase-to-earth fault, for example) induces a disturbing voltage on telecommunication lines located nearby.
Owing to their symmetry, three-phase short-circuits induce a zero sum of voltage, except when the layout of the remote control circuits is dissymmetrical in relation to the different phases; the induced voltage in this case is only rarely a problem. Calculating the induced voltage on a remote control circuit

This is given in the following formula:
Ei = M ω I L , Volts

where ω = 2π × frequency
L : length of parallelism between the power cable and remote control cable in meters I : short-circuit current value in the power cable at A
M : mutual inductance between the two cables in H/m
Calculating the mutual impedance M between the two cables

This is made up of two current loops opposite each other, the power conductor and the ground, the telecommunication conductor and the ground (see Figure 5-3).
Earth may be considered to be a resistance conductor Ro located at a distance D from the surface of the ground.
Remote control cable a Power cable

D

R0

Ro =

Ground: fictitious
Ground: fictive conduc conductor ωµ o
= 0.05 Ω/km (for f = 50 Hz)
8
Figure 5-3: mutual impedance between two cables

For a ground resistivity of 100Ωxm and a frequency of 50 Hz, then D = 935 m.

Consequences of Short-circuits

171

The mutual impedance is determined using the following formula:
M = 0.1

π2
4

400 ⎞

+ ⎜1 + 2 Ln

x ⎠


2

µH/m

where: x =a

f

ρ

a : distance in meters between the cables

f : power cable current frequency ρ : electrical resistivity of the ground in Ωxm. In the absence of precise information, a value ρ = 100Ωxm can be used as a first approximation for normal

ground in a temperate area

Note: when an earth conductor accompanies the power cable, the fault current circulates in this conductor rather than earth. This results in a decrease in mutual impedance and thus a reduction in induced voltage. The value of the reduction factor is difficult to determine and it is therefore difficult to take it into account.
Example

Let us take the example of a power and remote control cable installed in the same trench, 30 cm apart, and in parallel over a length of 100 meters.
For a phase-to-earth short-circuit of 5,000 A, then:
1 0.3 f = 0.3
=
x=a ρ 2
2
π2
M = 0.1
4

2


2 ⎞
+ ⎜ 2 Ln 400
+ 1⎟ = 1.62 µH/m

0.3 ⎟



E = 1.62 × 10 -6 × 100 × π × 5,000 × 100 = 253 V

Note: the CCITT (International Consultative Telegraph and Telephone
Committee) specifies that the calculation is not required when all of the following conditions apply:
– nominal voltage of the power line ≤ 20 kV
– length of parallelism < 10 km
– average gap between cables > 10 m
Note: the presence on telecommunication lines of an earthed metal shield efficiently prevents induced voltages.

Chapter 6

Instrument Transformers

Instrument transformer is the standard term used for current and voltage transformers. 6.1. Current transformers
They provide a current proportional to the current flowing through the cable in order to perform energy metering or to analyze this current through a protection device. 6.1.1. Theoretical reminder
Current transformers have similar compositions to “conventional” transformers.
A magnetic circuit (generally made of an iron alloy) in the shape of a torroid is surrounded by n1 turns on the primary and n2 turns on the secondary (see
Figure 6-1).
The primary can be reduced to a simple conductor passing through the torroid
( n1 = 1 ) (see Figure 6-2).

174

Protection of Electrical Networks

Ip

dl
H

Is magnetic circuit

Figure 6-1: n1 > 1 wound primary type current transformer

Ip

Is magnetic circuit

Figure 6-2: n1

= 1 ring type current transformer

Let Ip be the current flowing through the n1 primary turns and I s be the current flowing through the n2 secondary turns.
According to Ampere’s theorem, the sum of ampere-turns is equal to the circulation of the magnetic field vector H : n1 I p + n2 I s =

∫ H . dl

torroid

dl : vectorial element tangent to the circle generated by the torroid (see Figure 6-1)
The magnetic circuit channels the magnetic field, which is thus tangential to the circle created by the torroid, thus H is parallel to dl (see Figure 6-1).

Instrument Transformers

175

Hence:

n1 I p + n2 I s = HL where: H=

B

µo µr

µo : magnetic vacuum permeability µr : relative permeability of the magnetic circuit (for iron µr ≈ 1,000)
L : length of the torroid (2π x torroid radius)

n1 I p + n2 I s =

B

µo µr

L

The magnetic induction B is created by the windings and allows the transfer of energy from the primary to the secondary. We can see that when µr is very high
(efficient magnetic core):

B

µo µr

L → 0 and I s ≈ −

n1 n2 Ip .

and we obtain the equation of the ideal transformer.
In the real transformer, we take

B
L = n2 Im µo µ r

Im : magnetizing current
The introduction of Im allows a mathematical model of the transformer to be established. n
If we call n = 2 the transformation ratio, we obtain n1 Ip n + Is = Im

The current transformer can thus be represented by the electrical diagram in
Figure 6-3.

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Protection of Electrical Networks
Ip
n

Ip

Is

Rct

Im n1 turns

n2 turns Vs
Lm

R load

ideal transformer Rct :
:

represents the primary and secondary winding resistance represents the magnetic circuit leakage inductances, generally

ω B sat , then B > Bsat , the peak induction rises above the saturating limit induction, the exciting current Im becomes very high (see Figure 6-4), the current transformer saturates and the equation
Ip
+ I s = I m shows us that the current I s drops when Im increases. n Instrument Transformers

179

A time curve in the form of peaks (see Figure 6-5) can thus be observed for I s .
The peaks represent the period during which the current transformer is not saturated. Figure 6-5: secondary current of a current transformer operating under saturated conditions

The r.m.s. value of the current I s formed of peaks is calculated in Appendix C.
In spite of the saturation, the r.m.s. value of the secondary current increases when the primary current increases. Overcurrent protection, measuring the r.m.s. value, will thus be activated even if the current transformer saturates.

180

Protection of Electrical Networks

On the other hand, for an accurate measurement of the current, saturation must be avoided. This requires that:

k R I p < Bsat where k =

2 n2 n1


and I p = peak value of the primary current.

Maximum load at the CT terminals

– The value Bsat is determined by the construction of the magnetic circuit.
– Let us take the nominal (primary) current I pn for the CT.
This gives us the condition:
R<

Bsat
ˆ
kI

pn

or
ˆ B
Vs < sat kn since
ˆ
ˆ
ˆ
RI pn = RnI s = nVs

It can thus be seen that for a CT with a nominal current I pn , there is a maximum operating load that does not saturate the magnetic circuit and which produces an accurate measurement of the current. It can be observed that as a consequence, the
CT has a maximum secondary voltage above which it becomes saturated.
This is why CT manufacturers, in compliance with IEC 60044-1, specify an accuracy power P in VA, which stipulates a maximum load by the relation
2
Z max I n = P . As for the British standard BS 3938, this gives a knee-point voltage
VK characterizing the limit voltage before saturation.

Zmax is the maximum load of the CT. It includes the cable impedance linking the CT to the relay and the input impedance of the relay.
It is thus obvious that the distance between the CT and the relay must not be too great and that the connecting cable cross-section must sometimes be made bigger in order to reduce the total load impedance Zl . This solution is generally less costly than increasing the accuracy power (IEC 60044-1) or the knee-point voltage
(BS 3938).

Instrument Transformers

181

6.1.3. Using CTs in electrical networks

6.1.3.1. General application rule
Current transformers feed measuring, control and monitoring devices. Galvanic insulation electrically separates the primary circuit from the secondary circuit. It provides earthing of the electrical measuring device and thus ensures the safety of operating personnel.
The current transformer is designed to give the secondary a current that is proportional to the primary current. The secondary is connected to a low impedance
(used in practically short-circuited conditions).
In a CT, the primary current/secondary current ratio is constant.
The secondary current is thus independent of the load as long as saturation is not reached (see section 6.1.2).
Let us consider the simplified electrical diagram of the current transformer (see
Figure 6-6).

Is
Us

Z

Figure 6-6: simplified electrical diagram of the current transformer

If Z is the secondary load impedance of the current transformer, then:
2
P = Z × Is

and
Us = Z × Is

P : power flowing to the secondary
I s : secondary current
U s : secondary voltage
If Z decreases, then P decreases.

182

Protection of Electrical Networks

If we short-circuit the secondary of a CT, Z = 0, P = 0, Vs = 0 and there is no risk of destruction.
We can short-circuit the secondary of a CT without any risk.
On the other hand, if the secondary circuit remains open, Z tends towards infinity and the power and voltage would be theoretically infinite but are fortunately limited by the magnetic and copper losses of the CT.
Nevertheless, the voltage may reach peaks of several kV. It is therefore dangerous to leave a CT in an open circuit arrangement as this may generate overvoltages at its terminals which would be dangerous for both personnel and equipment under such conditions.
Never leave the secondary circuit of a CT open.
6.1.3.2. Composition of a current transformer
The CT is made up of one or more primary windings around one or more secondary windings each having a magnetic circuit and the entire assembly being sealed in an insulating resin.
To guarantee a given level of accuracy, the product of N1 × I p (number of primary turns x primary current) must always be above a certain value.
If N1 = 1, then the device is:
– bushing type: the primary is reduced to a copper bar going through the secondary winding (see Figure 6-7). We find this type of CT in MV cubicles.

Figure 6-7: bushing type transformer

Instrument Transformers

183

– Bar primary type: it is the compartment conductors of the MV cubicle that act as primary turns (see Figure 6-8).

Figure 6-8: bar primary type transformer

– Ring type: this is a CT though LV-designed to be installed on a medium voltage cable or on a bushing (see Figure 6-9).

Figure 6-9: ring type transformer

If N1 > 1, then the device is said to be of the wound type (see Figure 6-10).

Figure 6-10: wound type current transformer

6.1.3.3. Specifications and definitions of current transformer parameters
The current transformer must meet requirements relating to protective, measuring and metering devices.
The specified use of the current transformer will help to determine the rated primary and secondary currents, the power and accuracy class.
The specifications of current transformers are only valid for normal conditions of use. A derating must be provided for in accordance with the ambient temperature and altitude.

184

Protection of Electrical Networks

Rated primary current: this is defined by the standard and it should be chosen from among the following values: 10 - 12.5 - 15 - 20 - 25 - 30 - 40 - 50 - 60 - 75 and their multiples or decimal factors.
Rated secondary current: this is equal to 1 A or 5 A.
Transformation ratio ( Kn ): this is the ratio between the rated primary current and the rated secondary current. example: 100/5 A
I pn
Kn =
= 20
Isn
Accuracy power: this is the apparent power (in VA at a specified power factor) that the transformer can supply to the secondary circuit for the rated secondary current and the accuracy load on which are based the accuracy conditions.
The standardized values are: 1 - 2.5 - 5 - 10 - 15 - 30 VA.
The accuracy power will be chosen according to the actual requirement.
Overcalibrating an accuracy power is costly and may be dangerous for the measuring device as the saturation voltage is higher.
Accuracy class: this defines the guaranteed transformation ratio and phase displacement error limits under specific power and current conditions.
Transformation ratio error: this is the error as a percentage that the transformer introduces into the current measurement: current error (%) =

( Kn I s − I p ) × 100
Ip

Phase or phase displacement error: this is the phase difference between the primary and secondary current. It is expressed in minutes.
Rated thermal short-circuit current ( I th ) : this is the r.m.s. value of the primary current that the transformer can withstand for one second, its secondary being shortcircuited.
'
To determine a thermal short-circuit current I th for a period T that is different from 1 second, the following formula may be used:

Instrument Transformers

(I )

' 2 th 185

× T = ( I th ) × 1
2

A time T = 3 seconds is sometimes required by users and in this case it is difficult to obtain wound current transformers that withstand the short-circuit current for 3 seconds. It is thus preferable to use bar primary transformers

( )

Rated dynamic current I dyn : this is the peak value of the primary current (see section 4.1) that the transformer can withstand, its secondary being short-circuited.
The normal value of the rated dynamic current is: I dyn = 2.5 I th .
6.1.3.4. Current transformers used for measuring in compliance with standard IEC
60044-1
There are two requirements for measuring CTs. They must:
– have a level of accuracy suitable to the application for the normal operating current; – protect the devices in the event of a fault current.
The accuracy is defined by the accuracy class determining the permissible phase and current amplitude error over a range of 5% to 120% of the rated primary current The standardized IEC accuracy classes are: 0.1 - 0.2 - 0.5 - 1 - 3 - 5.
Classes 0.5 and 1 are used in the majority of cases.
Class 0.2 is only used for precision metering.
Classes 0.1 - 3 - 5 are never used in medium voltage.
Specific case: wide range current transformers are devices that can be used permanently with a primary current of 120, 150 or 200% of the rated current. The rise in temperature and transformer accuracy are guaranteed.
Protection of metering devices in the event of a fault is defined by the safety factor SF

This is the ratio between the rated primary limit current ( I pl ) and the rated primary current ( I pn ). I pl is the value of the primary current for which the secondary current error is equal to 10% (see Figure 6-11).
The preferred SF values are 5 and 10.

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Protection of Electrical Networks

Is

ideal current transformer Kn

real current transformer 10 %

Is

SF

I pl
I pn
Ip

I pl

Figure 6-11: safety factor (SF) of measuring CTs

IEC 60044-1 gives the maximum current and phase displacement errors in relation to the accuracy class and rated primary current percentage (see Table 6-1).
Accuracy
class
0.2

0.5

1
3
5

Rated primary current
%
5
20
10
120
5
20
100
120
5
20
100
120
50
120
50
120

Current error ±%
0.75
0.35
0.2
0.2
1.5
0.75
0.5
0.5
3
1.5
1
1
3
3
5
5

Phase displacement error ± mn
30
15
10
10
90
45
30
30
180
90
60
60 no limit no limit

Table 6-1: maximum current and phase displacement errors in relation to the accuracy class for measuring CTs

Instrument Transformers

187

Example of a measuring current transformer

500/1 A 15 VA cl 0.5
Rated primary current 500 A.
Rated secondary current 1 A.
Accuracy class: 0.5.
Accuracy power: 15 VA.
For a current between 100% and 120% of the nominal current, the current error is lower than ± 0.5% and the phase displacement error is lower than ± 30 mn.
For a current between 20% and 100% of the nominal current, the current error is lower than ± 0.75% and the phase displacement error is lower than ± 45 mn.
6.1.3.5. Current transformers used for protection in compliance with standard IEC
60044-1
There are two requirements for protective current transformers: they must have an accuracy limit factor and an accuracy class suitable to the application.
Accuracy limit factor (ALF) suited to the application

The accuracy limit factor is the ratio between:
– the accuracy limit current for which the error is guaranteed to be lower than 5 or 10% as long as the accuracy class is 5P or 10P (see Table 6-2);
– the rated primary current.
The larger the ALF the less likely the device is to become saturated:
ALF =

I pl
I pn

The IEC ALF values are: 5 - 10 - 15 - 20 - 30.

Accuracy class Composite error at accuracy limit current

Current error at I n

Phase displacement error for rated current

5P

5%

± 1%

± 60 mn

10P

10%

± 3%

no limit

Table 6-2: maximum current and phase displacement errors in relation to the accuracy class for protective CTs

188

Protection of Electrical Networks

Accuracy suited to the application

Accuracy is defined by the accuracy class.
The IEC accuracy classes are 5P and 10P. The choice between one or the other will depend on the device connected; for an example, see Table 6-3.
Application

Accuracy class

high impedance differential protection (see section 7.6.1)

5P

phase overcurrent protection (see section 7.1)

10P

Table 6-3: example of accuracy class choices for protective CTs

Example of a protective current transformer

100/1 A 15 VA 5P10
Rated primary current ( I pn ): 100 A.
Rated secondary current ( Isn ): 1 A.
Accuracy power: 15 VA.
Accuracy class: 5P.
Accuracy limit factor (ALF): 10.
For a power supplied of 15 VA under 1 A, the maximum error on the secondary current will be:
– less than 1% at I pn = 100 A (see Table 6-2), thus ( Isn × 1%) = 1 A × 1% = ± 0.01 A on the secondary;
– less than 5% at ( I pn × ALF) = 100 A × 10 = 1,000 A (see Table 6-2), thus ( Isn × 10 × 5%) = 1 A × 10 × 5% = ± 0.5 A on the secondary.
The secondary current is thus between 9.5 and 10.5 A for a primary current of
1,000 A (i.e. 10 times I pn ).
6.1.3.6. Current transformers used for protection in compliance with BS 3938
(class X)
BS 3938 specifically defines current transformers designed for protection under the heading class X.

Instrument Transformers

189

According to the British Standard, class X is defined by the rated secondary current, the minimum knee-point voltage, the maximum resistance of the secondary winding and the maximum magnetizing current at the rated knee-point voltage.
Rated knee-point voltage (VK ): at the rated frequency this is the voltage value applied to the secondary terminals, which, when increased by 10%, causes a maximum increase of 50% in magnetizing current (see Figure 6-12).
Maximum resistance of the secondary winding ( Rct ): this is the maximum resistance of this winding, corrected at 75°C or at the maximum operating temperature if this is greater.
Maximum magnetizing current ( Im ): this is the value of the magnetizing current at the rated knee-point voltage, or at a specified percentage of this current
(see Figure 6-12).
E

Vk

10%
10 %

50%
50 %

I

Im

1.5 I m

Figure 6-12: knee-point voltage and magnetizing current of a CT according to BS 3938 (class X)

6.1.3.7. Correspondence between IEC 60044-1 and BS 3938 CT specifications
Consider the electrical diagram of the CT in Figure 6-13.

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Protection of Electrical Networks
Ip

Ip

Is

n

Rct

Im
Vs

Rn

Pn
( I sn )

2

Rct : maximum resistance of the secondary winding
Figure 6-13: CT electrical diagram

Note: the leakage inductances defined in the electrical diagram of Figure 6-3 are neglected since they are low compared with Rct , ω VS1 for a given magnetic circuit.
Note 2: for a valid CT specification, it is important to know the value of Rct given by the CT manufacturer. The value of Rct is highly variable, from 0.02 Ω to 15 Ω depending on the CT specifications.
Standard BS 3938

This defines the rated knee-point voltage VK . . This voltage, when applied to the terminals of the secondary increased by 10%, causes a maximum increase in magnetizing current of 50%.
The knee-point voltage VK corresponds to the saturation of the magnetic circuit.
Thus, similarly to the CTs defined by the IEC:

VK = ( Rct + R ) Is

R : load resistance
Is : secondary current
Correspondence between voltages VK and VS1 or VS 2

We can see that voltages VK and VS1 or VS 2 are of the same sort and correspond to a limit voltage before saturation of the magnetic circuit. These three voltages are different as the saturation knee-point has in fact an approximate value
VK ≠ VS1 ≠ VS 2 (see Figure 6-14).

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Protection of Electrical Networks
Vs

VS 2
VS1
VK

Is

Figure 6-14: correspondence between voltages VK and VS1 or VS 2

In fact, these three voltages are defined differently: 5% error for class 5P, 10% error for class 10P and a 50% increase in magnetizing current for a voltage 10% higher than VK .
Let us take the CTs manufactured by Schneider as an example. With the material used for the magnetic circuit of these CTs, tests show that:
– VS1 corresponds to an induction of 1.6 teslas.
– VS 2 corresponds to an induction of 1.9 teslas.
– VK corresponds to an induction of 1.4 teslas.
Thus
VS1 1.6
=
VS 2 1.9

VK 1.4
V
1.4
=
and K =
VS 2 1.9
VS1 1.6

6.1.3.8. Use of CTs outside their nominal values
We have seen that a CT is limited by a maximum secondary voltage before saturation. Instrument Transformers

193

For standard IEC 60044-1:

Pn
VS1 = ⎜ Rct +

( I sn )2


Pn
VS 2 = ⎜ Rct +

( I sn )2


where


⎟ K I sn for class 5P



⎟ K I sn for class 10P



VS1 1.6
=
VS 2 1.9

For a given accuracy class, the stipulated condition of use is thus:

Pn
⎜ Rct +

( I sn )2


(1)


⎟ K I sn = constant




Pn
⎜ Rct I sn +
I sn



⎟ K = constant


Rct : is fixed by the construction of the CT
Isn : is the rated secondary current, which is also fixed by the construction of the
CT, allowing the CT to operate without a rise in temperature
We thus have an infinity of pairs P , Ki enabling the operation of the CT to be ni defined. In practice, the number of pairs possible is limited by the nominal values to be used, as we shall see in the following examples.
Let us take the example of the following device: .../5 A 15 VA 5P 20.
The manufacturer has given us the value of Rct (secondary winding resistance at 75°C).
Rct :
0.2 Ω

Pn1 :
K1 :

15 VA
20

Case 1: we want to use it with an accuracy power of Pn 2 = 30 VA . What is its accuracy limit factor K 2?

194

Protection of Electrical Networks

According to the relation (1):


Pn1 ⎞
Pn 2 ⎞
⎜ Rct I sn +
⎟ K1 = ⎜ Rct I sn +
⎟ K2
I sn ⎠
I sn ⎠


15 ⎞
30 ⎞


⎜ 0.2 × 5 + ⎟ 20 = ⎜ 0.2 × 5 + ⎟ K 2
5⎠
5 ⎠



K2 =

4 × 20
= 11.4
7

The standardized value to be used is that immediately less than K 2 , i.e. 10.
We can therefore say that a 15 VA 5P 20 CT is suitable for a 30 VA 5P 10 use when Rct = 0.2 Ω .
Case 2: we want to use it with an accuracy limit factor K 2 = 10 . What is its accuracy power?
According to the relation (1):


Pn1 ⎞
Pn 2
⎜ Rct I sn +
⎟ K1 = ⎜ Rct I sn +
I sn ⎠
I sn




⎟ K2


Pn 2 ⎞
15 ⎞


10
⎜ 0.2 × 5 + ⎟ 20 = ⎜ 0.2 × 5 +
5⎠
5 ⎟



P ⎞

4 × 20 = 10 ⎜1 + n 2 ⎟
5 ⎠

⎛ 80 ⎞
Pn 2 = ⎜ −1⎟ × 5 = 35 VA
⎝ 10 ⎠

The standardized value to be used is that immediately less than Pn 2 , i.e. 30 VA.
We can therefore say that 15 VA 5P 20 is suitable for a 30 VA 5P 10 requirement when R ct = 0 .2 Ω .

Instrument Transformers

195

Case 3: we want to use it with an accuracy class of 10P and an accuracy power of 30 VA. What is its accuracy limit factor?
We have seen that in class 10P the CT operates with a higher saturation level than in class 5P and
VS (10 P )
VS ( 5 P )

=

1.9
1.6

Thus:

Pn 2 ⎞
Pn1 ⎞
1.9 ⎛
⎜ Rct I sn +
⎟ K2 =
⎜ Rct I sn +
⎟ K1
I sn ⎠
I sn ⎠
1.6 ⎝


30 ⎞
1.9 ⎛ 15 ⎞

⎜1 + ⎟ K 2 =
⎜ 1 + ⎟ 20
5 ⎠
1.6 ⎝
5⎠

K 2 = 13.6

The standardized value to be used is that immediately less than K 2 , i.e. 10. We can therefore say that a 15 VA 5P 20 CT is suitable for a 30 VA 10P 10 requirement. Case 4: we want to use it with an accuracy class of 10P and an accuracy limit factor of K 2 = 10. What is its accuracy power?
We have seen that in class 10P the CT operates with a higher saturation level than in class 5P and
VS (10 P )
VS ( 5 P )

=

1.9
1.6

Thus:

Pn 2
⎜ Rct I sn +
I sn



Pn1 ⎞
1.9 ⎛
⎟ K2 =
⎜ Rct I sn +
⎟ K1
I sn ⎠
1.6 ⎝


196

Protection of Electrical Networks

Pn 2 ⎞
1.9 ⎛ 15 ⎞

⎜1 + 5 ⎟ 10 = 1.6 ⎜ 1 + 5 ⎟ 20




⎛ 1.9 ⎛ 15 ⎞ 20

Pn 2 = ⎜
− 1⎟ 5
⎜1 + ⎟
1.6 ⎝
5 ⎠ 10



Pn 2 = 42.5

The standardized value to be used is that immediately less than Pn 2 , i.e. 30 VA.
We can therefore say that a 15 VA 5P 20 CT is suitable for a 30 VA 10P 10 requirement. Case 5: the application requirement is expressed in VK knee-point voltage according to BS 3938. What is the knee-point voltage of the 15 VA 5P 20 CT?
We have seen that the knee-point voltage defined by standard BS 3938 is related to the maximum voltage VS (5P) of a class 5P CT by the relation
VS ( 5P )
VK

=

1.6 for Schneider Electric CTs.
1.4

Thus:

Pn ⎞
1.6
VK
⎜ Rct I sn +
⎟K=
I sn ⎠
1.4

1.6
⎛ 15 ⎞
VK
⎜1 + ⎟ 20 =
5⎠
1.4

VK = 70 V

The knee-point voltage VK defined by the British Standard is thus 70 V for a 15
VA 5P 20 CT where Rct = 0.2 Ω .

Instrument Transformers

197

6.1.3.9. Example of a current transformer rating plate (see Figure 6-15) network voltage specifications rated voltage: 17.5 kV power frequency withstand: 38 kV 1 min. 50 Hz impulse wave withstand: 95 kV peak type of CT

CT serial n° with year of manufacture

standard defining the CT network current specifications Ith: 25 kA/1 s
Idyn: 62.5 kA peak

safety factor (SF)

transformation ratio accuracy limit factor (ALF) accuracy class
1 primary circuit
1 measuring secondary circuit 1S1 - 1S2
1 protection secondary circuit 2S1 - 2S2

accuracy power Figure 6-15: example of a current transformer rating plate

6.1.4. Non-magnetic current sensors

Non-magnetic current sensors emit an output signal in the form of a voltage proportional to the primary current derived (see Figure 6-16).
Ip
r

E
Rn

r

: adjustment resistance

E : output voltage
Figure 6-16: non-magnetic current sensor

198

Protection of Electrical Networks

Non-magnetic current sensors used by Schneider Electric operate according to the Rogowski principle and supply their secondary with a voltage that is proportional to the primary current derived.
In the absence of a magnetic core, the coil winding technique gives the sensor the following properties:
– absence of saturation, hysteresis and remnant flux;
– perfect response in transient state operating conditions;
– ideal linearity.
All phenomena are faithfully reproduced.
Non-magnetic current sensors are designed to form a coherent protection and measuring unit with the Sepam relay of Schneider. At present they cannot be used for rate metering.
6.2. Voltage transformers

The electrical operation theory of voltage transformers is analogous to that of power transformers. We shall not cover it in this discussion.
6.2.1. General application rule

The voltage transformer is a transformer connected to a very high impedance
(used on an almost open circuit).
A voltage transformer is designed to give the secondary a voltage proportional to that applied to the primary. For a VT, the primary voltage/secondary voltage ratio is constant. The secondary voltage is independent of the load.
Let us consider the simplified electrical diagram of the voltage transformer
(see Figure 6-17).

Is
Us

Z

Figure 6-17: simplified electrical diagram of the voltage transformer

Instrument Transformers

199

If Z is the secondary load impedance of the VT (voltage transformer), then:
P=

U
U s2 and I s = s
Z
Z

P : power flowing to the secondary
Is : secondary current
U s : secondary voltage (imposed by the primary circuit)
If Z increases, then P and Is decrease.
At the terminals of a VT, it is thus possible to install an impedance with a value ranging between the VTs nominal impedance and infinity without any risk.
A VT can thus be left in an open circuit arrangement without any risk.
On the other hand, if Z is reduced, the current supplied is too high and the VT will deteriorate.
Never short-circuit a VT.
IEC 60044-2 defines the requirements which voltage transformers must meet.
The VT comprises a primary winding, a magnetic circuit, one or more secondary windings, the whole assembly being sealed in an insulating resin.
6.2.2. Specifications and definitions of voltage transformer parameters

The voltage transformer must comply with the network specifications.
As with any device, the voltage transformer must meet requirements relating to the voltage, current and frequency.
Voltage transformer specifications are only valid for normal conditions of use. A derating should be provided for in accordance with the ambient temperature and the altitude. Rated voltage factor: this is the factor by which the rated primary voltage must be multiplied in order to determine the maximum voltage for which the transformer must attain the required levels of heating and accuracy.
The voltage factor is determined by the maximum operating voltage, which depends on the network earthing system and the way the VT’s primary winding is

200

Protection of Electrical Networks

connected. The voltage transformer must be able to withstand this maximum voltage for the time necessary to clear the fault (see Table 6-4).

Rated voltage Rated time factor Primary winding connection method

1.2

continuous

phase to phase

any

1.2

continuous

between the neutral point of a star transformer and earth

any

1.2

continuous

1.5

30 seconds

phase to earth 1.2

Continuous

1.9

30 seconds

1.2

continuous

1.9

8 hours

1.2

continuous

1.9

phase to earth 8 hours

phase to earth phase to earth Network earthing system

directly earthed neutral limiting resistance earthing with automatic earth fault clearance (tripping upon first fault) earthed neutral without automatic earth fault clearance (no tripping upon first fault) tuned limiting reactance
(or Petersen coil) earthing without automatic earth fault clearance (no tripping upon first fault)

Note: smaller time ratings are permissible by agreement between manufacturer and user.
Table 6-4: normal values of the rated voltage factor

Rated primary voltage (Up): depending on their design, voltage transformers will be connected either:
– between phase and earth (see Figure 6-18(a)); or
– between phases (see Figure 6-18(b)).
3, 000 100
/
3
3

Up =

U
3

3, 000 / 100

Up =U

Instrument Transformers

a)

Phase 1

201

b)

U

U
Phase 2
Phase 3
P

P

S
S

Figure 6-18: voltage transformer connection

The voltage transformer must be suited to requirements relating to protection and measuring devices.
The foreseen application of the voltage transformer is used to determine the rated secondary voltage, the accuracy power, the accuracy class and the thermal power limit.
Rated secondary voltage: this is equal to 100 or 110 V for phase/phase VTs. For single-phase transformers designed to be connected between a phase and earth, the rated secondary voltage is divided by 3 .
For example:
100
3

Accuracy power: this is expressed in VA and it is the apparent power that the voltage transformer can supply to the secondary when it is connected under its rated primary voltage and connected to its accuracy load. It must not introduce an error in excess of the values guaranteed by the accuracy class.
The standardized values are:
10 - 15 - 25 - 30 - 50 - 75 - 100 - 150 - 200 - 300 - 400 - 500 - VA.
Accuracy class: this defines the guaranteed transformation ratio and phase error limits in specified power and voltage conditions.
Voltage ratio error: this is the error that the transformer introduces in the voltage measurement: voltage error (%) =

( Kn U s − U p ) × 100
Up

202

Protection of Electrical Networks

Phase or phase displacement error: this is the phase difference between the primary and secondary voltages and is expressed in minutes.
Rated thermal limiting output: this is the apparent power that the transformer can permanently supply at its rated secondary voltage without exceeding the heating limits stipulated in the standards.
6.2.3. Voltage transformers used for measuring in compliance with IEC 60044-2

Table 6-5 gives the accuracy class generally used in accordance with the corresponding application.
Application

Accuracy class not used in industry

0.1

precision metering

0.2

usual metering

0.5

statistical metering and/or measurement

1

measurement not requiring high accuracy 3

Table 6-5: accuracy class in accordance with the application for measuring VTs

The accuracy class is guaranteed if the voltage is between 80 and 120% of the rated primary voltage and for any load between 25 and 100% of the rated accuracy power with an inductive power factor of 0.8.
The standardized IEC accuracy classes are: 0.1 - 0.2 - 0.5 - 1 - 3.
– Classes 0.1 and 0.2 are only used for laboratory devices.
– Classes 0.5 and 1 are used in the majority of cases.
– Class 3 is used very little.
IEC 60044-2 gives the maximum voltage and phase displacement errors in accordance with the corresponding accuracy class (see Table 6-6).

Instrument Transformers

Accuracy class Voltage error (of ratio) in
±%

Phase displacement ± minutes

Phase displacement ± centiradians

0.1

0.1

5

0.15

0.2

0.2

10

0.3

0.5

0.5

20

0.6

1.0

1.0

40

1.2

3.0

3.0

not specified

203

not specified

Table 6-6: maximum voltage and phase displacement errors in accordance with the accuracy class for measuring VTs

Example of a measuring voltage transformer
20, 000 110
/
3
3

100 VA cl 1

Primary voltage = 20,000 V/ 3
Secondary voltage = 110 V/ 3
Accuracy power = 100 VA
Accuracy class = 1
This means that for a load between 100/4 = 25 VA and 100 VA, and a primary voltage between:
20, 000 ×

80
120
= 16, 000 V and 20, 000 ×
= 24, 000 V
100
100

The voltage error will be more or less 1% and the phase displacement error will not exceed 40 minutes.
6.2.4. Voltage transformers used for protection in compliance with IEC 60044-2

The IEC accuracy classes are 3P and 6P. In practice, only class 3P is used.
The accuracy class is guaranteed for the following values:
– voltages between 5% of the primary voltage and the maximum value of this voltage which is the product of the primary voltage and the rated voltage factor
( kT × U n ) (see Table 6-7);

204

Protection of Electrical Networks

– for a secondary load between 25% and 100% of the accuracy power with an inductive power factor of 0.8.
Accuracy
class

Voltage error in ±%

Phase displacement in minutes between 5% of U n

and kT × U n

between 2% and 5% of U n

and kT × U n

between 2% and 5% of U n

3P

3

6

120

240

6P

6

12

240

480

between 5% of U n

U n : rated voltage kT : voltage factor
Table 6-7: maximum voltage and phase displacement errors in accordance with the accuracy class for protective VTs

Example of a protective voltage transformer
20, 000 110
/
100 VA cl 3P
3
3

kT = 1.9 rated duration = 8 hours
The maximum voltage error will be 3% and the maximum phase displacement will last 120 minutes for a load between 25% × 100 = 25 VA and 100 VA with an inductive power factor of 0.8.
The maximum voltage that the VT can withstand is:
1.9 ×

20, 000
3

= 21.9 kV for 8 hours

Note: for earth faults, an assembly of three single-phase voltage transformers is used to make up an open delta so that the residual voltage can be measured (see
Figure 7-15). In this case, the nominal secondary voltages generally used are:
100
110
V and
V
3
3

Instrument Transformers

205

6.2.5. Example of the rating plate of a voltage transformer used for measurement
(see Figure 6-19) frequency serial n°: 91 81763

year of manufacture

VT type
VT definition according to standard voltage factor

rated primary voltage

transformation ratio

accuracy class accuracy power

heating power
1 primary circuit
1 secondary circuit

Figure 6-19: example of the rating plate of a measuring voltage transformer

Chapter 7

Protection Functions and their Applications

Protection functions are provided by relays or multifunctional devices like the
Schneider Sepam.
Protective relays (or multifunctional devices) are devices that permanently compare the electrical variables of networks (such as current, voltage, frequency, power, and impedances) with predetermined values, and then automatically emit orders for action (usually the opening of a circuit-breaker) or give off an alarm when the monitored value goes above the threshold.
The role of protective relays is to detect any kind of abnormal phenomena that may arise in an electrical circuit, such as short-circuits, variation in voltage, machine faults, etc.
The relay may be:
– without auxiliary power (autonomous) when the energy required for it to operate is supplied directly by the monitored circuit (see Figure 7-1). The actuator must be sensitive because the energy supplied by the circuit is limited;
– with auxiliary power supply when the energy required for it to operate is supplied by an auxiliary voltage source (AC or DC) independent of the circuit monitored (see Figure 7-2).

208

Protection of Electrical Networks

CT (current monitoring)

Switching device

Sensitive actuator Protective relay Figure 7-1: connection of an overcurrent relay without auxiliary power

CT (current monitoring)

Switching device

Sensitive actuator Protective relay Auxiliary supply voltage
Figure 7-2: connection of an overcurrent relay with auxiliary power

7.1. Phase overcurrent protection (ANSI code 50 or 51)
The function of this protection is to detect single-phase, two-phase or threephase overcurrents.

Protection Functions and their Applications

209

Protection is activated when one, two or three of the currents concerned rise above the specified setting threshold.
This protection can be time delayed and in this case will only be activated if the current monitored rises above the setting threshold for a period of time at least equal to the time delay selected. This delay can be an independent (definite) time or inverse time delay.
Independent time protection (see Figure 7-3) t operating zone
T

I

Is

I set

T

: operating current threshold
: protection operation time delay
Figure 7-3: independent time delay

The current threshold and the time delay are generally set by the user.
Inverse time protection
The time delay depends on the ratio between the current measured and the operating threshold. The higher the current means the shorter the time delay (see
Figure 7-4). t operating zone

T
1 1.2

10

20

I / Is

I set

: operating current threshold corresponding to the vertical asymptote of the curve

T

: operating delay for 10

I set

Figure 7-4: inverse time protection

210

Protection of Electrical Networks

Inverse time protection operation is defined by standards IEC 60255-3 and
BS 142. These standards define several types of inverse time protection that are distinguished by the gradient of their curves: standard inverse, very inverse or extremely inverse time protection. For example, the Schneider Sepam 2000 proposes the curves in Figure 7-5 set for a time delay of 1 second (implies an operating delay of 1 second for I = 10 I set ).
1,000.00

Figure 7-5: standard inverse, very inverse and extremely inverse curves at T = 1 second

7.2. Earth fault protection (ANSI code 50N or 51N, 50G or 51G)
This function is used to protect the network against earth faults.
The protection is activated if the residual current I rsd = I1 + I 2 + I 3 rises above the setting threshold. The residual current corresponds to the current flowing through earth (see section 4.3.5). The protection operates in a similar way to the phase overcurrent protection as far as the curves are concerned t = f (I rsd ) (see
Figures 7-3, 7-4 and 7-5).

Protection Functions and their Applications

211

The protection is set so that it is as sensitive as possible in order to detect low earth fault currents.
Residual current measurement
The residual current characterizing the earth fault current is obtained in one of the following two ways:
– by a core balance transformer through which the three phase conductors pass.
The toroid turns encircle a magnetic flux φrsd such that φrsd = φ 1 + φ 2 + φ 3 (see
Figure 7-6). φ1,φ2 and φ3 are proportional to the phase currents I1, I2 and I3, and φrsd is thus proportional to the residual current.
The earthing strap shown in Figure 7-6 must go through the toroid so that an internal cable fault (core-shield) can be detected. Indeed, in the opposite case, the short-circuit current circulates in the cable core and comes back via the shield. It is therefore not detected by the toroid;
– by three current transformers whose neutrals are connected, thus making the sum I rsd = I1 + I 2 + I 3 , which is the system generally used in MV and HV (see
Figure 7-7). link origin

toroid

I rsd relay earthing straps

I rsd

load

Figure 7-6: residual current measuring instrument using a core balance

Figure 7-7: residual current measuring instrument using three current transformers

Minimum threshold setting of earth protection
There is a risk of spurious tripping of the protection due to measurement error of the residual current, specifically in the presence of transient currents. In order to prevent this risk, protection setting must be above:
– approximately 12% of the nominal rating of the CTs when measurement is carried out using three current transformers;

212

Protection of Electrical Networks

– 1 A for a time delay of 0.1 second when measurement is carried out using a core balance.
Making protection insensitive to third and multiples of third harmonics
Protection must be made insensitive to third and multiples of third harmonics that may come from the network or from the saturation of the CTs during high pickup currents or transient operating conditions including aperiodic components.
Indeed, third and multiples of third harmonics are detected by the protection as a residual current because they are in phase.
Let us take three balanced currents i1, i2 and i3 with a phase displacement of 1/3 of a period:
ˆ
i1 (t ) = I cos ω t
T⎞

ˆ
i2 (t ) = I cos ω ⎜ t + ⎟
3⎠

2T ⎞

ˆ i3 (t ) = I cos ω ⎜ t +

3 ⎠


where T =



ω

signal period

Note: the phase displacement of the currents is temporal and must therefore be written as shown above.
By replacing ω by 3 ω, the third harmonics of these three currents are:
ˆ
i1h3 (t ) = I h3 cos 3 ω t
⎛ T⎞ ˆ
ˆ
ˆ
ˆ
i2 h3 (t ) = I h3 cos 3 ω ⎜ t + ⎟ = I h3 cos ( 3 ω t + ω T ) = I h3 cos ( 3 ω t + 2π ) = I h3 cos 3 ω t
⎝ 3⎠
⎛ 2T ⎞ ˆ
ˆ
ˆ
ˆ
i3h3 (t ) = I h3 cos 3 ω ⎜ t +
⎟ = I h3 cos ( 3 ω t + 2 ω T ) = I h3 cos ( 3 ω t + 4π ) = I h3 cos 3 ω t
3 ⎠


thus:
ˆ
I1h3 (t ) + I 2 h3 (t ) + I 3h3 (t ) = 3 I h3 cos 3ω t

We can also see graphically that the third harmonics are in phase (see Figure
7-8). The same applies for all multiples of the third harmonics.

Protection Functions and their Applications

213

In the absence of an earth fault, the residual current is equal to three times the sum of third and multiples of third harmonics that circulate in each phase.
It is thus important to make protection insensitive to third and multiples of third harmonics so as not to cause spurious tripping.
I1

t
3rd harmonic

the three current harmonics are in phase

I2
3rd harmonic

t

I3

3rd harmonic

t

Figure 7-8: the third harmonics of a three-phase system are in phase

214

Protection of Electrical Networks

7.3. Directional overcurrent protection (ANSI code 67)
This has a phase overcurrent function defined in section 7.1 associated with a
“current direction” detection function. It is used, for example, when a busbar is fed by two sources (see Figure 7-9).

source 1

source 2

I sc1
I SC1

I sc 2
I SC2

CB4
CB4

CB1
CB1
P1
P1

P4
P4

A
P3
P3

P22
P
CB2
CB2

VT
VT

CB3
CB3
sc 2
IISC2

CB5
CB5

CB6
CB6

short-circuit current circulation short-circuit current circulation directional protection detection direction direction directional protection detection

P1 , P4
P2 , P3

I sc1
I sc 2

: overcurrent protection devices
: directional protection devices
: short-circuit current fed by source 1
: short-circuit current fed by source 2

Figure 7-9: dual fed busbar

Protection Functions and their Applications

215

When a fault occurs at A, the two short-circuit currents I sc1 and I sc 2 are simultaneously established. A fault current flows through the four protection devices: P1, P2, P3 and P4. Now in order to clear the fault without interrupting th,e power supply to the feeders, only circuit-breakers CB1 and CB2 must trip.
In order to do this, directional phase overcurrent protection devices are installed at P2 and P3:
– Protection P3 is not activated when a current circulating in the opposite direction to its detection direction flows through it.
– Protection P2 is activated when a current circulating in its detection direction flows through it. It causes the circuit-breaker CB2 to trip and the current I sc 2 is interrupted. An inter-tripping system causes CB1 to trip and the current I sc1 is interrupted. – Protection P4, which is time delayed, is not activated.
The faulty section is thus isolated.
It is said that the protection detects the “direction of the current”; in reality it detects the sign of the active power. Thus, the phase displacement ϕ sc between the voltage and the short-circuit current must be known.
The directional protection at P3 detects a short-circuit current circulating from the transformer towards the busbar. The active power detected by the protection is positive: −

π
2

≤ ϕ sc, P 3 ≤

π
2

and cos ϕ sc , P 3 ≥ 0 .

The directional protection at P2 detects a short-circuit current circulating from the busbar towards the transformer. The active power detected by the protection is negative: π
2

≤ ϕ sc , P 2 ≤

3π and cos ϕcc , P 2 ≤ 0 .
2

To determine the phase displacement ϕ sc , the current of one phase must be compared in relation to a polarizing voltage.
For a current in phase 1, the most frequently applied polarizing voltage is the phase-to-phase voltage between phases 2 and 3, i.e. the voltage perpendicular to the current I1 for zero phase displacement (see Figure 7-10).

216

Protection of Electrical Networks

Similarly, for a current in phase 3, the polarizing voltage chosen is the phase-tophase voltage between phases 1 and 2 (see Figure 7-11).
I1 ( for

=0)

V1

U 21

V1
90°

polarising
Polarizing
voltage voltage V3
V3

V2

90°

polarising
Polarizing
voltage voltage U 32

Figure 7-10: phase 1 polarizing voltage

V2

I3 ( for

=0)

Figure 7-11: phase 3 polarizing voltage

The protection connection angle is said to be 90°.
Two relays are sufficient for the balanced three-phase short-circuit and the three phase-to-phase short-circuits to show up, for example, on phase 1 and on phase 3.
Indeed, whatever the phase-to-phase short-circuit, it will concern either phase 1 or 3.
The choice of polarizing voltage is explained as follows.
For the current on phase 1:
– when a three-phase short-circuit occurs, the voltage detected by the protection is low, so it is better to use a phase-to-phase voltage;
– when a phase-to-phase short-circuit occurs between phases 1 and 2, the voltage U12 is very low, possibly zero, if the fault occurs close to the protection.
Similarly, when a short-circuit between phases 1 and 3 occurs, the voltage U13 may be low and the phase-to-phase voltage U32 must therefore be taken to guarantee a sufficient voltage amplitude.
For the current on phase 3:
– using the same reasoning, the polarizing voltage is U21.

Protection Functions and their Applications

217

7.3.1. Operation
Directional phase overcurrent protection is activated if the following two conditions apply to a time equal to the time delay chosen:
– the current is higher than the setting threshold;
– the current phase in relation to the polarizing voltage is in a range referred to as the tripping zone.
The protection tripping zone is a half plane. This half plane is defined by a characteristic angle θ, which is the angle of the line perpendicular to the boundary line between the two zones and the polarization vector (see Figure 7-12 for θ = 45°).
a) phase 1
I1
tripping zone

tripping zone
45

1

90°

non-tripping zone non-tripping zone

U 32

b) phase 3
U 21

tripping zone θ = 45 °45

90°
3

non-tripping zone

I3

Figure 7-12: tripping zones of the directional protection for phases 1 and 3 with a characteristic angle θ = 45 °

218

Protection of Electrical Networks

The usual characteristic angle values are 30°, 45° and 60°. The value generally used is 45° and we shall see why as follows.
We can see that the current I1 is:
– in the tripping zone for θ - 90° < β1 < θ + 90°
– in the non-tripping zone for θ + 90° < β1 < θ + 270°

β1 is the angle between I1 and U 32 and it corresponds to a phase displacement ϕ1 between I1 and V1 such that: ϕ1 = β1 + 90° .
Similarly, the current I 3 is:
– in the tripping zone for θ - 90° < β3 < θ + 90°
– in the non-tripping zone for θ + 90° < β3 < θ + 270°

β3 is the angle between I 3 and U 21 and it corresponds to a phase displacement ϕ3 between I 3 and V3 such that: ϕ3 = β3 + 90°.
Why is a characteristic angle θ introduced?
This angle is related to the natural phase displacement of the current in relation to the voltage when a short-circuit occurs. We shall study this phase displacement for two types of possible short-circuits: the symmetrical three-phase, and the phaseto-phase short-circuits.
Phase displacement upon occurrence of a symmetrical three-phase short-circuit
The network upstream of the short-circuit is equivalent to a resistor R in series
R
with a reactor X and the ratio is between 0.05 and 0.3 in MV (see section
X
4.1.1). The natural phase displacement ϕ between the voltage and the current for
X ⎛
X
⎞ each phase is such that tg ϕ =
⎜ 3.3 < < 20 ⎟ , hence 73°< ϕ < 87° .
R ⎝
R

With the connection angle at 90°, the phase displacement β1 between I1 and
U 32 is:

β1 = ϕ − 90 °



3 < β1 < 17

β1 is negative and I1 therefore leads U 32 .

Protection Functions and their Applications

219

Phase displacement upon occurrence of a phase-to-phase short-circuit
The electrical diagram of the network when a phase-to-phase short-circuit occurs between phases 1 and 2 is shown in Figure 7-13.

X

R

X

R

X

Vn

R

I1

r

x

B

A
2

a Vn

aVn

I2

x

x

I3

r

r

V M 3 V M 2 V M1

X, R: upstream network impedance x, r: protected circuit impedance
VM 1 , VM 2 , VM 3 : voltages of phases 1, 2 and 3 measured by the voltage transformers located near the circuit-breaker
Figure 7-13: electrical diagram of the network when a phase-to-phase short-circuit occurs between phases 1 and 2

Mathematical reminder: let the rotation operator be

2π such that V2 = a 2 V1
3

and V3 = aV1 a=e j 2π
3

=−

j 4π
1
3
1
3
+ j and a 2 = e 3 = − − j
2
2
2
2

giving the following relations:
1 + a + a2 = 0

and

a3 = 1

j 2 = -1

and

1
=−j
j

220

Protection of Electrical Networks

Case 1: short-circuit at A (see Figure 7-13)
With the short-circuit being located just downstream of the voltage transformers, the voltages measured VM 1 and VM 2 are equal and therefore:
VM 1 = VM 2 =

I1 = − I 2 =

Vn + a 2 Vn
V
= −a n
2
2

Vn − a 2 Vn
V (1 − a 2 )
= n
2 ( R + jX )
2 ( R + jX )

VM 3 = aVn

thus:
U 32 = VM 2 − VM 3 = −

3 a Vn
2

hence:
U 32
− 3a
−3
−3
=
( R + jX ) = 2 ( R + jX ) =
( R + jX ) = 3 ( − j R + X )
2
I1
1− a a −a
−j 3

The phase displacement β1 between U 32 and I1 is thus β1 = − Arctg where 0.05 <

R
X

R
< 0.3
X

then
3° < |β1| < 17°

β1 is negative and I1 therefore leads U 32 .
We find that the phase displacement is identical to the symmetrical three-phase short-circuit. Case 2: short-circuit at B (see Figure 7-13)
Let us take the extreme case where B is the point furthest away from the circuitbreaker and the voltage measuring devices. It is then assumed that X…...

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